FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
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, 2012

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 website, 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 29, 2012, was $33.0 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, 2013, is shown below:

 

Title of Class    Number of Shares Outstanding
Common Stock, par value $0.10 per share    500,565,966

Documents Incorporated By Reference

Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 14, 2013 (to be filed with the Securities and Exchange Commission prior to April 4, 2013), are incorporated by reference into Part III of this Form 10-K.


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

    10   
     

Proved Reserves

    13  
     

Sales Volumes, Prices, and Production Costs

    18  
     

Delivery Commitments

    19  
     

Properties and Leases

    19  
     

Drilling Program

    19  
     

Drilling Statistics

    20  
     

Productive Wells

    21  
   

Midstream Properties and Activities

    21  
   

Marketing Activities

    23  
   

Competition

    24  
   

Segment Information

    24  
   

Employees

    24  
    Regulatory Matters, Environmental, and Additional Factors Affecting Business     24  
   

Title to Properties

    31  
   

Executive Officers of the Registrant

    31  

Item 1A.

 

Risk Factors

    33  

Item 1B.

 

Unresolved Staff Comments

    49  

Item 3.

 

Legal Proceedings

    49  

Item 4.

 

Mine Safety Disclosures

    49  

PART II

   

Item 5.

 

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

    50  

Item 6.

  Selected Financial Data     53  

Item 7.

 

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

    54  

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk     86  

Item 8.

  Financial Statements and Supplementary Data     88  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure

    160  

Item 9A.

  Controls and Procedures     160  

Item 9B.

  Other Information     160  

PART III

   

Item 10.

  Directors, Executive Officers, and Corporate Governance     161  

Item 11.

  Executive Compensation     161  

Item 12.

 

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

    161  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    161  

Item 14.

 

Principal Accountant Fees and Services

    161  

PART IV

   

Item 15.

 

Exhibits, Financial Statement Schedules

    162  


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PART I

Items 1 and 2.  Business and Properties

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates, and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See Risk Factors under Item 1A of this Form 10-K.

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with approximately 2.6 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2012. Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for 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 U.S. onshore with high-potential worldwide offshore exploration and development activities.

Anadarko’s asset portfolio includes U.S. onshore resource plays in the Rocky Mountains area, 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 high-potential basins located in Algeria, Mozambique, Ghana, China, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, Brazil, Alaska, New Zealand, and other countries.

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, people and passion, commercial focus, and open communication in all business activities.

Anadarko’s business segments are managed separately due to distinct operational differences and unique technology, 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 engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The Company owns and operates gathering, processing, treating, and transportation systems in the United States for natural gas, crude oil, and NGLs.

Marketing—This segment sells much of Anadarko’s production, as well as third-party purchased volumes. The Company actively markets oil, natural gas, and NGLs in the United States, and 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, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1216 or (800) 262-9361.

 

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The public may also 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 significant oil and natural-gas exploration and production operations.

 

LOGO

 

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United States

Overview  Anadarko’s U.S. operations include oil and natural-gas exploration and production onshore in the Lower 48 states, the deepwater Gulf of Mexico, and onshore Alaska. The Company’s U.S. operations accounted for 89% of total sales volumes during 2012 and 90% of total proved reserves at year-end 2012.

Rocky Mountains Region  Anadarko’s Rocky Mountains Region (Rockies) properties are located in Colorado, Utah, and Wyoming. The assets 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 13,100 wells and owns an interest in approximately 10,000 non-operated wells in the Rockies. Anadarko operates fractured carbonate/shale reservoirs, tight-gas assets, coalbed methane (CBM) natural-gas assets, and enhanced oil recovery (EOR) projects within the region. The Company also has fee ownership of mineral rights under approximately 8 million acres that pass through Colorado, Wyoming, and into Utah (known as the Land Grant). Management considers the Land Grant a significant competitive advantage for Anadarko as it offers drilling opportunities for the Company in liquids-rich areas and allows the Company to capture incremental royalty revenue from third-party activity on Land Grant acreage.

The Company believes the competitive advantages provided by mineral ownership in the Land Grant, its liquids-rich reservoirs, strong well performance, low development costs, and a large expandable midstream infrastructure each provide tangible benefits and position the Company to accelerate its Wattenberg horizontal drilling program. Activities in the Rockies focus on expanding existing fields to increase production and adding proved reserves through horizontal drilling, infill drilling, and down-spacing operations.

In 2012, total-year Rockies sales volumes increased 6% over 2011, with an 11% increase in liquids volumes. The Company drilled 794 wells and completed 846 wells during 2012. The Company plans to increase the number of horizontal wells drilled from 181 in 2012 to approximately 325 in 2013, with continued focus on liquids-rich plays.

 

LOGO

 

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Wattenberg  The Wattenberg field is a liquids-rich area where Anadarko operates over 5,500 wells. The field contains the Niobrara and Codell naturally fractured carbonate formations that hold liquids and natural gas. During 2012, the Company drilled 136 vertical/directional wells and 176 horizontal wells. Sales volumes in the Wattenberg field increased 25% compared to 2011, with a year-over-year 30% increase in liquids volumes. Horizontal drilling results in the Wattenberg field have shown strong initial production rates with average liquids yields of approximately 65%. The Company also has identified approximately 4,000 potential drilling locations in the Niobrara and Codell formations that provide substantial opportunity for expanding Anadarko’s activity. In 2013, the Company plans to increase its activity in the Wattenberg field by deploying eleven horizontal rigs.

Greater Natural Buttes  The Greater Natural Buttes area in eastern Utah is one of the Company’s major tight-gas assets where the Company utilizes refrigeration and cryogenic processing facilities to extract NGLs from the gas stream. Anadarko has expanded the cryogenic facilities at its Chipeta plant to increase contracted cryogenic processing capacity, which is capable of recovering an additional 15,000 barrels of NGLs per day.

The Company operates over 2,400 wells in the Greater Natural Buttes area, drilled 341 wells in 2012, and increased year-over-year operated sales volumes from the area by 19%. Anadarko drilled and completed 70 new development wells in the lower Mesaverde Blackhawk formation during 2012 and has identified more than 8,000 potential locations in this formation for future development. Many of these locations are infill drilling opportunities focused on down-spacing from 40-acre well density to 10-acre well density.

Powder River  The Company drilled nine horizontal wells in the Powder River basin during 2012 as part of a multi-objective horizontal exploration program targeting liquids-rich plays. Anadarko controls over 350,000 acres of deep rights within the Powder River basin.

Coalbed Methane Properties  Anadarko operates approximately 2,400 low-cost CBM wells and owns an interest in approximately 4,100 non-operated CBM wells in the Rockies, primarily located in the Powder River basin in Wyoming and the Helper and Clawson fields in Utah. Anadarko controls over 650,000 acres of shallow rights within the Powder River basin. 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. In 2012, Anadarko sold its interest in the Atlantic Rim field and reduced development activity in its CBM program as the Company continued to focus capital spending on liquids-rich opportunities. Reduced activity is expected to continue in 2013 as a result of low natural-gas prices.

Salt Creek and Monell  During 2012, the Company continued development of its Rockies EOR assets at the Salt Creek and Monell fields in Wyoming. 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. In April 2012, the Company entered into a carried-interest arrangement where a third party agreed to fund $400 million of development costs in exchange for a 23% interest in the Company’s EOR development at the Salt Creek field in Wyoming. At December 31, 2012, $201 million of the $400 million obligation had been funded. In 2013, the Company will continue development at the Monell field with a small drilling program planned to enhance carbon-dioxide flooding operations.

 

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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 4.5 million gross acres throughout the Southern and Appalachia Region. This area includes the Eagleford/Pearsall shales in South Texas, the Marcellus shale in north-central Pennsylvania, the Permian basin of West Texas, the Haynesville shale in East Texas and Louisiana, and the Utica shale in eastern Ohio.

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. Similar cost reductions and efficiencies were gained on completion operations. Due to lower natural-gas prices, the Company continued its focus on liquids-rich opportunities, executing on its substantial liquids-rich inventory while significantly reducing project costs.

In 2012, total-year sales volumes in the Southern and Appalachia Region increased 36% over 2011, with a 35% increase in liquids volumes. The Company drilled 513 operated horizontal wells and brought 453 wells online in 2012. The Company expects to drill approximately 455 horizontal wells in 2013.

 

LOGO

Eagleford  The Eagleford shale continues to be one of the Company’s most prolific plays, capable of generating returns in excess of 100%. The Eagleford shale also benefits from a carried-interest arrangement entered into in 2011 that conveyed 33.3% of the Company’s Eagleford and Pearsall shale assets to a third party in exchange for the funding of $1.6 billion of Anadarko’s then-future development costs. Third-party funding pursuant to the carried-interest arrangement began in the second quarter of 2011 and provided the Company $500 million of funding for 2011 and $650 million of funding for 2012. The third-party funding is expected to cover 90% of development costs until the commitment is fulfilled, which is expected to occur by year-end 2013.

 

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Anadarko currently holds 413,000 gross acres in this area. During 2012, the Company operated an average of nine rigs, spud 292 horizontal wells, and fracture stimulated 239 wells. The Company increased sales volumes by 93% year over year. During 2012, Anadarko also expanded its infield gathering-system capacity from 225 million cubic feet per day (MMcf/d) to 350 MMcf/d and sanctioned a new high-efficiency Company-operated cryogenic gas plant that is scheduled to come online in 2013. The 200 MMcf/d plant is expected to increase processing capacity and is capable of recovering approximately 30,000 barrels per day (Bbls/d) of NGLs.

Marcellus  In the Marcellus shale of the Appalachian basin, where the Company holds 760,000 gross acres, 78 operated horizontal wells were spud and 77 wells were brought online utilizing a fleet that averaged five rigs during the year. Anadarko also participated as a non-operating partner in 117 horizontal wells and 154 wells that were brought online in 2012. Anadarko’s sales volumes in the Marcellus shale increased 133% over 2011.

In 2010, Anadarko entered into a carried-interest arrangement where a third party earned a 32.5% interest 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 its 2011 development costs. The funding obligation was completed during July 2012.

Permian  Anadarko holds an interest in over 575,000 gross acres in the Delaware basin. Anadarko’s 2012 drilling activity primarily targeted the liquids-rich Bone Spring formation and Avalon shale. In 2012, Anadarko spud 58 operated wells, participated in 31 non-operated wells, and completed 55 operated and 29 non-operated wells in the area. Significant infrastructure was added in 2012 to allow for increased natural-gas and liquids processing. The Company had three operated rigs drilling in the Bone Spring formation and two operated rigs drilling in the Avalon shale at year-end 2012.

East Texas/Haynesville  Anadarko increased its capital program in the East Texas Carthage area in 2012, taking advantage of a liquids-rich area in the Haynesville shale. In 2012, Anadarko operated seven rigs, drilling 67 wells in the Haynesville and Cotton Valley formations and converting 60 wells to production. The Company increased sales volumes from the area by 41% year over year, while also achieving organic reserves growth.

Utica  In late 2011, the Company began an exploration program in eastern Ohio targeting the liquids-rich Utica shale. In 2012, five exploration wells were drilled throughout the Company’s 411,000 gross acres. Seven wells were completed and are currently in the production testing and evaluation phase.

 

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Gulf of Mexico  In the Gulf of Mexico, Anadarko owns an average 64% working interest in 479 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. During 2012, the Company continued an active deepwater exploration and appraisal program in the Gulf of Mexico and is continuing to take advantage of existing infrastructure to accelerate development activities at reduced cost.

 

LOGO

The following includes the significant production, development, appraisal, and exploration activity during 2012.

Production  In March 2012, Anadarko began production at the Caesar/Tonga field (33.75% working interest) where it is currently producing from three wells. The Company is drilling a fourth development well at Caesar/Tonga, which is expected to begin producing in the second quarter of 2013.

Development Anadarko continues to advance the Lucius development with construction of the spar underway. During the third quarter of 2012, Anadarko entered into a carried-interest arrangement for the Lucius development, where a third-party partner agreed to fund $556 million of development costs to earn a 7.2% working interest. The amount of the carry obligation represents 100% of the Company’s expected future capital costs through first production. The Company holds a 27.8% working interest in the Lucius development. In December 2012, the Company drilled a successful development well, confirming and extending the Lucius field along its western flank. During 2013, the Company plans to drill four additional development wells and begin completion operations. First production from Lucius is expected in 2014.

 

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Appraisal  During 2012, Anadarko participated in drilling two appraisal wells in the Gulf of Mexico. The successful Heidelberg-2 appraisal well (44.25% working interest) encountered oil pay in high-quality Miocene sands. The Heidelberg-2 was drilled about 1.3 miles south of and 550 feet up-dip from the Heidelberg discovery. Pre-front-end engineering and design work has been finalized and Anadarko anticipates sanctioning this project in mid-2013. Another successful appraisal well was drilled at the Vito discovery (18.67% working interest) in Mississippi Canyon Block 940 and encountered oil pay in the Miocene-age reservoirs approximately 1.5 miles from the discovery well. A follow-up appraisal well was drilling at year-end 2012.

At year end, the Company-operated Shenandoah appraisal well (30% working interest) was drilling in Walker Ridge Block 51. The appraisal well is delineating the extent of the Lower Tertiary reservoirs found by the 2009 Shenandoah discovery well.

Exploration  At year end, two exploration wells were drilling in Walker Ridge within the same mini-basin as the 2009 Shenandoah discovery. The Coronado exploration well (15% working interest) was spud during the second quarter of 2012 and the Yucatan exploration well (15% working interest) was spud during the third quarter of 2012. Both wells will test the Lower Tertiary section.

The Phobos exploration well (30% working interest) was spud in December 2012 and is a multiple-objective test of the Pliocene, Miocene, and Upper and Lower Wilcox sections. The Phobos well is located approximately 12 miles south of the Lucius field. Anadarko expects to be fully carried on the estimated capital cost of the Phobos well as the result of two separate farmout agreements, the latest of which was finalized during the third quarter of 2012.

During 2012, the Company drilled the Spartacus exploration well (63.3% working interest) approximately 15 miles from the Lucius discovery in the Gulf of Mexico. The well was unsuccessful.

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 2012 with eight additional wells drilled in the Alpine and its satellite fields. In the fourth quarter of 2012, the Company sanctioned the Alpine West development, a 15- to 20-well extension of the Alpine field. In 2013, the Company anticipates participating in approximately 10 additional development wells.

 

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International

Overview  Anadarko’s significant international oil and natural-gas production and development operations are located in Mozambique, Algeria, Ghana, and China. The Company also has exploration acreage in Ghana, Mozambique, Liberia, Sierra Leone, Kenya, Côte d’Ivoire, China, New Zealand, Brazil and other countries. International locations accounted for 11% of Anadarko’s total sales volumes and 27% of sales revenues during 2012, as well as 10% of total proved reserves at year-end 2012. Anadarko drilled 51 wells in international areas in 2012, resulting in new natural-gas discoveries in Mozambique and oil discoveries in Ghana and Côte d’Ivoire. In 2013, the Company expects to drill approximately 40 development and 20 exploration wells at various international locations.

 

LOGO

Mozambique  Anadarko operates two blocks (one onshore and one offshore) in Mozambique totaling approximately six million gross acres.

In 2012, the Company drilled two natural-gas discoveries, Golfinho and Atum, in a reservoir complex located entirely within Offshore Area 1 of the Rovuma basin, where Anadarko is the operator and holds a 36.5% working interest. The Golfinho and Atum discovery wells encountered natural-gas pay in two high-quality Oligocene fan systems. These discoveries subsequently were appraised with four successful wells (Golfinho 2, 3, and 4 and Atum 2), which confirmed the southern and down-dip extent of the reservoir. Future appraisal drilling will focus on confirming the northern and up-dip extent of the reservoir, which is age-equivalent to, but geologically distinct from, the Company’s 2010 and 2011 discoveries in the Prosperidade field. The Company drilled the Perola Negra and Barracuda exploration wells, both of which were unsuccessful.

 

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The Company also completed the appraisal-drilling and well-testing program in the Prosperidade field where Anadarko is the operator and holds a 36.5% working interest. The reservoir straddles Offshore Areas 1 and 4 and contains the Windjammer, Lagosta, Barquentine, and Camarão discoveries. The Prosperidade field appraisal program consisted of the drilling of three successful wells (Lagosta 2 and 3 and Barquentine 4) and a comprehensive testing program. In addition, the Company signed a Heads of Agreement (HOA) with Eni S.p.A. (Eni), establishing foundational principles for the coordinated development of the common natural-gas reservoirs spanning both Offshore Area 1 (operated by Anadarko) and Offshore Area 4 (operated by Eni). The HOA is designed to facilitate a work program whereby the two operators will conduct separate, yet coordinated, offshore development activities, while jointly planning and constructing common onshore liquefaction facilities in the form of a liquefied natural gas (LNG) park in the Cabo Delgado Province of northern Mozambique.

During 2012, the government of Mozambique awarded the site for the LNG processing facilities. Also, Anadarko and its partners awarded Front-End Engineering and Design contracts related to the development of four 5-million tonnes per annum LNG trains, including 10 million metric tons per annum (mmtpa) for Area 1 and 10 mmtpa for Area 4. The first LNG train is expected to be completed with first delivery in 2018.

Algeria  Anadarko is engaged in production and development operations in Algeria’s Sahara Desert in Blocks 404 and 208 that are governed by a Production Sharing Agreement (PSA) between Anadarko, two other parties, and Sonatrach, the national oil and gas company of Algeria. The Company is responsible for 24.5% of the development and production costs on these blocks. At December 31, 2012, all production was from fields located in Block 404, which produce through the Hassi Berkine South and Ourhoud central processing facilities. Initial production from the El Merk project in Block 208 is expected in the first quarter of 2013, with peak volumes expected to be achieved at the El Merk central processing facility during 2013. The Company drilled 20 development wells in 2012. During 2013, the Company expects to drill 18 to 20 wells.

Exceptional Profits Tax Resolution  In 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. The Company disagreed with Sonatrach’s collection of the exceptional profits tax and initiated arbitration against Sonatrach in 2009. In March 2012, the Company and Sonatrach resolved this dispute. The resolution provides for delivery of crude oil to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income in the first quarter of 2012 to reflect the effect of this agreement on previously recorded expenses. Additionally, the parties amended the existing PSA to increase the Company’s sales volumes and to lower the effective exceptional profits tax rate. The amendment confirmed the length of each exploitation license to be 25 years from the date the license was granted under the PSA with expiration dates ranging from December 2022 to December 2036.

Ghana  Anadarko’s exploration and development activities in Ghana are located offshore in the West Cape Three Points Block and the Deepwater Tano Block.

During 2012, the Company and its partners drilled four of eight Phase 1A wells in the Jubilee field (24% non-operated unit interest), which is included in the West Cape Three Points and the Deepwater Tano Blocks. In addition, seven existing producing wells were successfully acidized to enhance production levels and the Company exited the year with record gross production volumes for the field of more than 110,000 Bbls/d. In 2013, the Company and its partners plan to drill the remaining four Phase 1A wells in the Jubilee field.

West Cape Three Points  Jubilee tie-back development options are being evaluated in the West Cape Three Points Block (31% non-operated working interest) to maximize the value from the Teak and Akasa discoveries. During 2012, the Teak 4 appraisal well was drilled and was unsuccessful.

 

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Deepwater Tano  During 2012, the Company participated in four exploration and appraisal wells in the Deepwater Tano Block where Anadarko holds an 18% non-operated working interest.

Successful operations in the Tweneboa/Enyenra/Ntomme (TEN) complex were completed through the drilling of two appraisal wells (Enyenra 4A and Ntomme 2A) and a testing program. During the fourth quarter of 2012, the Company and its partners submitted the Plan of Development (POD) for the TEN fields to the Government of Ghana. In 2013, the Company and its partners plan to sanction and begin development of the TEN fields upon approval of the POD. The TEN development will utilize a standalone floating production, storage, and offloading vessel for production from subsea wells.

The Okure-1 exploration well targeted a slightly deeper section than the pay sections encountered in the TEN complex. The well encountered a low net-to-gross oil bearing sandstone interval in a secondary Turonian objective. The well was deemed non-commercial and was plugged and abandoned.

The Company also made an additional discovery in the Deepwater Tano Block at the Wawa exploration well, which encountered oil pay and gas-condensate pay in Turonian-aged reservoirs. Pressure data indicate that this discovery is an accumulation separate and distinct from the adjacent TEN complex and extends the presence of hydrocarbon-bearing formations more than six miles north. In 2013, the Company and its partners plan to conduct an appraisal program for the Wawa discovery.

China  Anadarko’s production and development activities in China are located offshore in Bohai Bay. Drilling resumed in the fourth quarter of 2012, with four new sidetrack wells drilled and brought online. Drilling will continue through 2013. Preparation of a development plan for the next major field expansion and project sanction are expected to be completed in the third quarter of 2013. Consistent with the terms of the petroleum contract, the Company transferred operatorship of the Bohai Bay development to CNOOC China Limited at the end of 2012. The Company maintained its average working interest of approximately 35%.

Drilling is also expected to resume on the Company’s exploration acreage in the South China Sea in the second quarter of 2013. The Liwan 21-1-1 exploration well (50% working interest) in the South China Sea spud in August 2012 and was suspended after setting surface casing due to rig commitments and weather considerations. The Company is fully carried on the well.

Liberia  The Company operates two blocks, Block 10 (80% working interest) and Block 15 (48% working interest), offshore Liberia totaling approximately 1.3 million exploration acres in the Liberian basin. Multiple Cretaceous stratigraphic prospects, similar to the Jubilee Mahogany fan, have been identified on these blocks. Block 10 exploration drilling is planned for 2013.

Sierra Leone  Anadarko operates a 55% participating interest in Block SL-07B-11 offshore Sierra Leone, which encompasses approximately 1.3 million gross acres. Multiple Upper Cretaceous fan-type prospects have been identified in the lightly explored Liberian basin. The Jupiter #1 discovery well, spud in the fourth quarter of 2011, reached total depth in 2012 and encountered hydrocarbon pay. The wellbore has been preserved for possible re-entry, as the area requires additional evaluation. The Mercury #2 appraisal well, drilled 7.5 miles northwest and approximately 1,300 feet lower than the Mercury discovery well, was unsuccessful. Data from the wells is being evaluated to determine future drilling plans.

Kenya  Anadarko owns and operates a 45% participating interest in five deepwater blocks offshore Kenya, encompassing approximately six million gross acres. The Company completed 2D and 3D seismic programs and two exploration wells are planned for 2013. Evaluation of the Company’s exploration position will commence with the Kiboko and Kubwa prospects, which will test both stratigraphic and structural play types. The Company will be largely carried on these two wells.

 

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Côte d’Ivoire  Anadarko owns working interests in three blocks offshore Côte d’Ivoire (Blocks CI-515 and CI-516 with a 45% operated working interest and Block CI-103 with a 40% non-operated working interest). Two exploration wells were drilled in 2012 on Blocks CI-105 and CI-103. The Kosrou well on Block CI-105 was unsuccessful. Anadarko and its partners elected not to enter the next phase of exploration outlined in the production sharing contract license for Block CI-105 and no longer hold a working interest in the block. The Company announced a discovery at the Paon exploration well on Block CI-103, which encountered light oil pay in a single Cretaceous fan interval. The discovery confirms that the Upper Cretaceous fan play present in Ghana extends westward into Côte d’Ivoire. Several additional prospects have been identified and an extensive exploration and appraisal program is being planned for the area.

New Zealand  Anadarko operates approximately 10 million gross exploration acres in New Zealand, with a 50% working interest in the Taranaki and Canterbury basins and a 100% working interest in the recently acquired Pegasus basin. 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. An exploration well is planned for the end of 2013 subject to rig availability.

Brazil  Anadarko holds exploration interests in approximately 750,000 gross acres in six blocks located offshore Brazil in the Campos and Espírito Santo basins. The Wahoo-4 appraisal well on Block BM-C-30 (30% working interest) encountered oil pay on the western side of the structure in which the Wahoo-1 discovery well is located. Additional appraisal on the northeastern side of the structure is planned for 2013. The Ituana appraisal well on Block BM-C-29 was plugged and abandoned and the Company is evaluating the results of the well to determine the future plans for the block. Also during 2012, the Company drilled the Requeijao and Provolone exploration wells, both of which were unsuccessful. The Company is marketing its Brazilian properties.

Indonesia  In 2012, Anadarko owned participating interests in approximately 3.4 million gross exploration acres in Indonesia through three production sharing contracts, one operated and two non-operated. In December 2012, the Company agreed to sell the Indonesian properties to a third party. The sale closed in early 2013.

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

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 reserves volumes.

Disclosures by geographic area include the United States and International. The International geographic area consists of 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.

 

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Summary of Proved Reserves

 

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

December 31, 2012

       

Proved

       

Developed

       

United States

    6,445       318       283       1,675  

International

          208             208  

Undeveloped

       

United States

    1,884       193       110       617  

International

          48       12       60  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total proved

    8,329       767       405       2,560  
 

 

 

   

 

 

   

 

 

   

 

 

 

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  
 

 

 

   

 

 

   

 

 

   

 

 

 

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  
 

 

 

   

 

 

   

 

 

   

 

 

 

The Company’s year-end 2012 product mix for proved reserves was 54% natural gas, 30% oil and condensate, and 16% NGLs; compared to a year-end 2011 product mix of 55% natural gas, 30% oil and condensate, and 15% NGLs; and a year-end 2010 product mix of 56% natural gas, 31% oil and condensate, and 13% NGLs.

The Company’s estimates of proved developed reserves, proved undeveloped reserves (PUDs), and total proved reserves at December 31, 2012, 2011, and 2010, 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, 2012. Annually, Anadarko reports gross proved reserves for U.S.-operated properties to the U.S. Department of Energy. These reported reserves are derived from the same database used to estimate and report proved reserves in this Form 10-K.

 

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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  Revisions of prior estimates include updates to prior PUDs, the addition of new PUDs associated with current development plans, the transfer of PUDs to unproved categories due to development plan changes, and the impact of changes in economic conditions, including lower commodity prices. These PUD changes reflect Anadarko’s ongoing evaluation of its asset portfolio and current-year changes to development plans. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years unless specific circumstances warrant a longer development time horizon. Significant changes to PUDs occurring during 2012 are summarized in the table below:

 

MMBOE

 

PUDs at January 1, 2012

    728  

Revisions of prior estimates

    102  

Extensions, discoveries, and other additions

    37  

Conversion to developed

    (171

Purchases

    3  

Sales

    (22
 

 

 

 

PUDs at December 31, 2012

            677  
 

 

 

 

PUD Conversion  In 2012, the Company converted 171 MMBOE, or 23% of total year-end 2011 PUDs to developed status. Approximately 79% of PUD conversions occurred in onshore U.S. assets, 15% in international assets, and the remaining 6% in Gulf of Mexico assets.

The majority of the onshore U.S. PUD conversions, approximately 133 MMBOE, occurred as a result of development activities in the Rockies and the Southern and Appalachia Regions. The remaining onshore U.S. PUD conversions were a result of development activity in Alaska. International PUD conversions, approximately 25 MMBOE, were primarily associated with ongoing development of the El Merk project located in Block 208 of the Berkine basin in Algeria where initial production is expected to occur in the first quarter of 2013. The Gulf of Mexico PUD conversions, approximately 11 MMBOE, were associated with development of the Nansen field.

Anadarko spent $1.0 billion to develop PUDs in 2012, of which approximately 69% related to domestic development programs in the Rockies and the Southern and Appalachia Regions, 28% to development of international projects, and the remaining 3% to Alaska and Gulf of Mexico development projects.

In 2011, the Company converted 171 MMBOE, or 23% of the total year-end 2010 PUDs to developed status. Approximately 58% of PUD conversions occurred in onshore U.S. assets, 26% in international assets, and the remaining 16% in Gulf of Mexico assets. Anadarko spent $900 million on PUD development in 2011. Approximately 68% of total 2011 PUD-development 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 PUD-development spending was associated with Alaska and other international development projects.

 

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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, but projects such as EOR, arctic development, deepwater development, and international programs may take longer. All of the Company’s onshore U.S. PUDs at December 31, 2012, were scheduled to be developed within five years, 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.

At December 31, 2012, the Company had 91 MMBOE of pre-2008 PUDs that remain undeveloped five years or more after initial disclosure as PUDs. Approximately 40% of these PUDs are associated with the El Merk development project and are being developed according to an Algerian government-approved plan. Site preparation was initiated in 2008 and construction of the El Merk central processing facility is progressing, with commissioning of the first train in its final stages. At year-end 2012, 89 wells of the Reservoir Development Plan’s estimated 119 total wells have been drilled. First oil production from the El Merk fields is expected to occur in the first quarter of 2013.

Another 33% of the Company’s pre-2008 PUDs are associated with the Salt Creek EOR single-development project located in the Rockies. Since 2003, Anadarko has invested an average of $74 million per year to develop various phases of the Salt Creek EOR project and will continue significant spending levels in the future to complete the development. In 2012, the Company demonstrated its continued interest in developing the project by entering into a carried-interest arrangement with a third party to fund $400 million of the costs associated with ongoing development activities.

All remaining pre-2008 PUDs are associated with Gulf of Mexico opportunities where longer development times are primarily a result of moratorium-related delays. The Company expects to develop its pre-2008 Gulf of Mexico PUDs over the next three years.

Technologies Used in Proved Reserves Estimation  The Company’s 2012 proved reserves additions were based on estimates generated through the integration of relevant 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.

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’ reserves estimates. All QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group (CRG).

 

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Index to Financial Statements

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 reserves 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 President and 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 the results of procedures and methods reviews as discussed below, as well as other 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 26 years of experience in the oil and gas industry, including over 12 years as either a reserves estimator or manager. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserves training, and asset evaluation and management. The principal engineer is a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers, where he has been a member for over 26 years. In addition, the principal engineer is an active participant in industry reserves seminars and professional industry groups.

Third-Party Procedures and Methods Reviews  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, 2012. 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 87% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2012. 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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Sales Volumes, Prices, and Production Costs

The Company’s sales volumes were 268 MMBOE for 2012, 248 MMBOE for 2011, and 235 MMBOE for 2010. 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. Information on major customers is contained in Note 21—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. 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:

 

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

2012

               

United States

               

Greater Natural Buttes

    163       1       5       33     $     2.26     $   81.34     $   40.43     $     8.75  

Wattenberg

    95       12       5       33       3.00       92.16       40.72       8.05  

Other United States

    655       42       20       171       2.73       99.36       40.37       8.76  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total United States

    913       55       30       237       2.68       97.46       40.44       8.66  
 

 

 

   

 

 

   

 

 

   

 

 

         

International

           31              31              111.11              10.89  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total

    913       86       30       268       2.68       102.35       40.44       8.92  
 

 

 

   

 

 

   

 

 

   

 

 

         

2011

               

United States

               

Greater Natural Buttes

    135       1       4       27     $ 3.58     $ 84.13     $ 51.50     $ 9.48  

Wattenberg

    79       9       5       27       4.17       91.91       53.85       7.58  

Other United States

    638       38       18       163       3.90       99.28       54.55       9.80  
 

 

 

   

 

 

   

 

 

   

 

 

         

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     $ 66.61     $ 40.31     $ 9.56  

Wattenberg

    74       7       3       22       4.28       76.07       43.44       6.79  

Other United States

    648       40       16       164       4.14       74.91       43.69       8.82  
 

 

 

   

 

 

   

 

 

   

 

 

         

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  
 

 

 

   

 

 

   

 

 

   

 

 

         

 

Bcf—billion cubic feet

Mcf—thousand cubic feet

Bbl—barrel

 

(1) 

Excludes the impact of commodity derivatives.

 

(2) 

Excludes ad valorem and severance taxes.

 

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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, 2012, Anadarko was contractually committed to deliver approximately 1,150 Bcf of natural gas to various customers in the United States through 2031. These contracts have various expiration dates with approximately 45% of the Company’s current commitment to be delivered in 2013, and 70% by 2017. At December 31, 2012, Anadarko also was contractually committed to deliver approximately 10 MMBbls of crude oil to ports in Algeria and Ghana through 2013. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves.

Properties and Leases

The following schedule shows the developed lease, undeveloped lease, and fee mineral acres in which Anadarko held interests at December 31, 2012:

 

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

United States

               

Onshore

    5,081       3,098       5,556       2,592       10,285       8,438       20,922       14,128  

Offshore

    300       151       2,410       1,620                   2,710       1,771  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total United States

    5,381       3,249       7,966       4,212       10,285       8,438       23,632       15,899  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

International

    362       88       68,474       46,096                   68,836       46,184  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    5,743       3,337       76,440       50,308       10,285       8,438       92,468       62,083  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

At December 31, 2012, the Company had approximately 3 million net undeveloped lease acres scheduled to expire by December 31, 2013, 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.

Drilling Program

The Company’s 2012 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 2012 consisted of 222 gross completed wells, which included 212 onshore U.S. wells, 1 offshore Gulf of Mexico well, and 9 international wells. Development activity in 2012 consisted of 1,390 gross completed wells, which included 1,379 onshore U.S. wells, 1 offshore Gulf of Mexico well, and 10 international wells.

 

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Drilling Statistics

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

 

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

2012

             

United States

    79.5       1.0             80.5       923.7       11.3           935.0        1,015.5  

International

    0.5       3.0       3.5       2.1             2.1       5.6  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    80.0       4.0       84.0       925.8       11.3       937.1       1,021.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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, 2012:

 

    Wells in the process
of drilling or
in active completion
    Wells suspended or
waiting on completion  (1)
 
    Exploration     Development     Exploration     Development  

United States

       

Gross

    12       90       178       658  

Net

    5.0       56.3       63.9       431.9  

International

       

Gross

    2       5       40       1  

Net

    0.7       1.1       13.8       0.1  

Total

       

Gross

    14       95       218       659  

Net

    5.7       57.4       77.7       432.0  

 

(1) 

Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

 

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Index to Financial Statements

Productive Wells

At December 31, 2012, the Company’s ownership interest in productive wells was as follows:

 

    Oil Wells (1)     Gas Wells (1)  

United States

   

Gross

    4,222       28,476  

Net

    3,094.2       17,851.6  

International

   

Gross

    347        

Net

    87.9        

Total

   

Gross

    4,569       28,476  

Net

    3,182.1       17,851.6  

 

(1)       Includes wells containing multiple completions as follows:

   

Gross

    401       2,609  

Net

    356.2       2,058.6  

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 improves its ability to manage costs, controls the timing of bringing on new production, and enhances the value received for gathering, processing, treating, and transporting the Company’s production. Anadarko’s midstream business also 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 2012, Anadarko had 31 gathering systems and 26 processing and treating plants located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania, and Texas. In 2012, the Company’s midstream activity was concentrated in liquids-rich growth areas such as Greater Natural Buttes, Wattenberg, Delaware basin, and the Eagleford shale, as well as in the Marcellus shale dry-gas play. In 2013, the Company plans to continue midstream investments in these core areas along with further expansion in the Carthage area in East Texas.

Greater Natural Buttes  A second cryogenic processing train was put in service at the Chipeta processing complex in 2012, increasing aggregate cryogenic processing capacity to 550 MMcf/d and total processing capacity to 970 MMcf/d. The Company received Federal Energy Regulatory Commission approval to expand its wet-gas-gathering system to the Chipeta plant in 2012 and expects to begin transporting gas on the new lines in the first half of 2013.

Wattenberg  The Company is currently constructing the 300 MMcf/d Lancaster cryogenic processing plant, with expected completion in early 2014. The plant will support increasing production from horizontal drilling in the Niobrara development, helping to relieve processing constraints in the basin. Prior to the Lancaster plant completion, the Company plans to install interim refrigeration capacity of 180 MMcf/d that is expected to be fully deployed by mid-2013, allowing the Company’s production growth to continue throughout the year.

 

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Anadarko and joint-venture partners plan to build a 435-mile NGLs pipeline (Front Range Pipeline) with initial capacity of 150,000 Bbls/d and ability to expand the capacity to 230,000 Bbls/d. The pipeline will transport NGLs from Weld County, Colorado to Skellytown, Texas, where it will connect with other pipelines, including the Texas Express Pipeline (TEP). During 2011, Anadarko and its partners agreed to design and construct the TEP to originate from Skellytown, Texas and to extend approximately 580 miles to NGLs fractionation and storage facilities in Mont Belvieu, Texas. Initial capacity of the TEP will be approximately 280,000 Bbls/d that can be expanded to approximately 400,000 Bbls/d. Subject to regulatory approvals, the TEP is expected to be in service in the third quarter of 2013 and the Front Range Pipeline is expected to be in service in the fourth quarter of 2013. The Front Range Pipeline and TEP are expected to enhance the value of the Company’s production by providing additional NGLs takeaway capacity and access to the Gulf Coast NGLs market.

Permian  In the Delaware basin in West Texas, the Company expanded its midstream infrastructure for Bone Spring and Avalon production. The Avalon Express, a 200 MMcf/d high-pressure gas pipeline system, was placed in service in August 2012 and includes 40 MMcf/d of compression and treating capacity. Three central processing facilities were commissioned with a total liquids (oil and water) handling capacity of 42,000 Bbls/d. In the third quarter of 2012, a 25 MMcf/d refrigeration plant was placed in service to process Bone Spring natural-gas production. A second-phase 100 MMcf/d cryogenic plant was placed in service in January 2013 to maximize Bone Spring liquids recoveries.

Eagleford  In the Eagleford shale in South Texas, gas-gathering capacity was expanded from 225 MMcf/d in 2011 to 350 MMcf/d in 2012 and crude-oil gathering capacity remained flat at 45,000 Bbls/d. The system is expected to expand to 600 MMcf/d of gas gathering and 75,000 Bbls/d of crude-oil gathering capacity by the end of 2013. Construction is underway for a new Company-operated cryogenic processing plant (Brasada) in the Eagleford shale with capacity of 200 MMcf/d, including a 15,000 Bbls/d condensate stabilization plant. The Company expects the Brasada plant to be operational in the second quarter of 2013. The Company also has secured approximately 38,000 Bbls/d of transportation and fractionation capacity on a new 200-mile raw-mix pipeline from Cotulla, Texas to Mont Belvieu, Texas. The Company has the right to expand to 75,000 Bbls/d of transportation and fractionation capacity on this pipeline.

Marcellus  In the Marcellus shale in Pennsylvania, Anadarko’s gas-gathering capacity increased from 500 MMcf/d in 2011 to over 1,500 MMcf/d in 2012. The Company commissioned the 24-inch Seely trunkline in the second quarter of 2012 and the 24-inch Warrensville trunkline in the fourth quarter of 2012. The Company also commissioned over 10,000 horsepower of compression in 2012.

East Texas/Haynesville  In the Carthage area of East Texas, Anadarko entered into a firm processing agreement with a third party for 120 MMcf/d of processing capacity at a cryogenic processing plant that was placed in service in late 2012. The plant supports the Company’s growing liquids-rich production in the Haynesville shale and Cotton Valley formations in East Texas and Louisiana.

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. WES’s general partner is owned by Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own Anadarko’s partnership interests in WES, as well as WES’s general partner. In December 2012, WGP completed its initial public offering of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit. At December 31, 2012, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire general partner interest. WGP’s ownership interest in WES consisted of a 46.2% limited partner interest, the entire 2.0% general partner interest, and all of the WES incentive distribution rights.

 

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Index to Financial Statements

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

 

Area

 

Asset Type

  Miles of
Gathering
Pipelines
    Total
Horsepower
    2012
Average
Throughput
(MMcf/d)
 

Rocky Mountains

  Gathering, processing, and treating     10,000       1,150,200       3,800  

Mid-Continent and other

  Gathering     2,500       114,000       500  

Texas

  Gathering and treating     2,800       307,600       900  
   

 

 

   

 

 

   

 

 

 

Total

      15,300       1,571,800       5,200  
   

 

 

   

 

 

   

 

 

 

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 so that the Company is positioned to utilize transportation and storage capacity fully, 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 Commodity Price Risk under Item 7A of this Form 10-K.

Natural Gas  Anadarko markets its natural-gas production to maximize 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 stores natural gas in contracted storage facilities to minimize operational disruptions to its ongoing operations and to take advantage of seasonal price differentials. Normally, the Company will have forward contracts in place (physical-delivery or financial derivative instruments) to sell stored natural gas at a fixed price.

 

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Index to Financial Statements

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, diesel, and jet 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, diesel, and jet fuel. The Company also purchases and sells third-party-produced crude oil, condensate, and NGLs, 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 21—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 5,200 employees at December 31,  2012.

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, regional, state, and local environmental and occupational health and safety laws and regulations. These laws and regulations pertain to the discharge of materials into the environment; the generating, 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 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

 

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Index to Financial Statements
   

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. 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 impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment

 

   

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

 

   

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

 

   

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

 

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Index to Financial Statements

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, stored, 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 related to 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 involving diesel 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 a final draft report expected to be available for public comment and peer review by 2014. The EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities for shale gas by 2014. Certain other governmental reviews have been recently conducted or are underway 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 has from time to time 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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Index to Financial Statements

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. For example, on August 16, 2012, the EPA published final rules under the federal Clean Air Act that subject oil and natural-gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from fractured and refractured gas wells for which well-completion operations are conducted. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012, and from pneumatic controllers and storage vessels, effective October 15, 2013. In addition, 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 U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, 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 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 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, penalties or fines under the CWA. For additional information, see Note 17—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Index to Financial Statements

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 stringently applied 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 the Bureau of Safety and Environmental Enforcement (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. The 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, one 95-foot skimming vessel, four 46-foot skimming vessels, four 56-foot skimming vessels, three Marco skimmers, and two Egmopol skimmers. Additional available equipment includes the following: fast response units, rope mop, barges, skimming arms, skim packages, and tanks. In addition, 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 one 95–foot fast response vessel and is scheduled to receive delivery on or about the end of the second quarter of 2014.

 

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Index to Financial Statements

CGA has executed a support contract with T&T Marine to coordinate bareboat charters and provides for expanded response support. T&T Marine is responsible for inspecting, maintaining, storing, and calling out CGA equipment. T&T Marine has positioned CGA’s equipment and materials in a ready state at various staging areas around the Gulf of Mexico.

T&T Marine also handles the maintenance and mobilization of CGA non-marine equipment. T&T Marine 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, T&T Marine 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.

Anadarko is also a member of the Marine Preservation Association, which provides full access to the Marine Spill Response Corporation (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. 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 can be 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 (EDRC) of approximately 562,408 barrels. The California Region has approximately 278,330 barrels EDRC and the Pacific Northwest Region has approximately 335,253 barrels EDRC. Additional available equipment includes the following: OSRVs, fast response vessels, barges, storage bladders, work boats, ocean boom, and dispersant.

The Company has also entered into a contractual commitment to access subsea intervention, containment, capture, and shut-in capacity for deepwater exploration wells. Marine Well Containment Company (MWCC) is open to all oil and gas operators in the 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 thousand barrels per day (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 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 currently scheduled for delivery by mid-2013.

 

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Anadarko retains geospatial and satellite imagery services through the MDA Corporation (MDA) to provide coverage over the Company’s Gulf of Mexico operations. MDA owns and maintains two radar satellite’s, RADARSAT-1 and RADARSAT-2, that provide all-weather surveillance and imagery available to assist in identifying areas of concern on the surface waters of the Gulf of Mexico. The Company has agreements with Waste Management, Inc. and Clean Harbors to assist in the proper disposal of contaminated and hazardous waste soil and debris. In addition, Anadarko has agreements with HDR Engineering, Inc. (HDR) for assistance with Subsea Dispersant applications. Staff members of HDR are recognized as worldwide experts in the proper use of dispersants in a subsea application, developing scientific methods for determining the proper injection, and monitoring of the dispersant while maintaining the environmental and ecosystem integrity and health. The Company also has agreements with TDI-Brooks International for its scientific research vessels to properly monitor the effectiveness of the dispersant application and the health of the ecosystem. The Company also has agreements with Scientific and Environmental Associates, Inc. (SEA) for assistance with surface-dispersant applications. SEA is a scientific support consulting firm providing subject matter experts, and is renowned for its expertise in surface-dispersion applications and efficacy monitoring.

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 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 (OSRL), a global emergency and oil spill-response organization headquartered in London. OSRL maintains specialized equipment in a ready state for deployment in the event such equipment is needed by one of its members. OSRL is mainly available for response internationally, but its equipment is registered with the U.S. Coast Guard for domestic use if needed.

OSRL 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. OSRL has three ADDS Packs: one in the United Kingdom, one in Bahrain, and one in Singapore. If additional aircraft are needed, OSRL retains an aircraft broker so that an aircraft can be chartered. For international operations, the majority of equipment will be air freighted.

OSRL 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.

OSRL also provides 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. OSRL also has a wide range of oiled wildlife equipment in conjunction with the Sea Alarm Foundation.

In addition to Anadarko’s membership in or access to CGA, MSRC, OSRL, and MWCC, the Company participates 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.

 

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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 at
February 19,
2013
 

Position

James T. Hackett

  59   Executive Chairman

R. A. Walker

  55   President and Chief Executive Officer

Robert P. Daniels

  54   Senior Vice President, International and Deepwater Exploration

Robert G. Gwin

  49   Senior Vice President, Finance and Chief Financial Officer

Charles A. Meloy

  52   Senior Vice President, U.S. Onshore Exploration and Production

Robert D. Lawler

  46   Senior Vice President, International and Deepwater Operations

Robert K. Reeves

  55   Senior Vice President, General Counsel and Chief Administrative Officer

M. Cathy Douglas

  56   Vice President and Chief Accounting Officer

Mr. Hackett was named Executive Chairman of Anadarko effective May 2012. Prior to this position, he served as Chief Executive Officer and as a director of the Company from 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, Cameron International Corporation, and The Welch Foundation. Mr. Hackett served as director of Temple-Inland Inc. from 2000 to 2008 and as a director of Halliburton Company from 2008 to 2011.

Mr. Walker was named Chief Executive Officer and a director of Anadarko in May 2012, in addition to the role of President, which he assumed in February 2010. Mr. Walker previously served as Chief Operating Officer from March 2009 until his appointment as Chief Executive Officer. He also served as Senior Vice President, Finance and Chief Financial Officer from September 2005 to March 2009. Since August 2007, he also has served as director of Western Gas Holdings, LLC (WGH), the general partner of WES, and served as its Chairman of the Board from August 2007 to September 2009. Mr. Walker has served as a director of Western Gas Equity Holdings, LLC (WGEH), the general partner of WGP, since September 2012. 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.

 

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Mr. Daniels was named Senior Vice President, International and Deepwater Exploration in July 2012. Prior to this position, he served as Senior Vice President, Worldwide Exploration since December 2006 and served as Senior Vice President, Exploration and Production since May 2004. 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 has served as Chairman of the Board of WGH since October 2009 and as a director since August 2007. Additionally, Mr. Gwin has served as Chairman of the Board of WGEH, the general partner of WGP, since September 2012, and served as President of WGH from August 2007 to September 2009 and as Chief Executive Officer of WGH 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. He has served as a director of LyondellBasell Industries N.V. since May 2010.

Mr. Meloy was named Senior Vice President, U.S. Onshore Exploration and Production in July 2012. Prior to this position, he served as Senior Vice President, Worldwide Operations since December 2006 and served as Senior Vice President, Gulf of Mexico and International Operations since the acquisition of Kerr-McGee Corporation (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 Deepwater from 2000 to 2002. Mr. Meloy has served as a director of WGH since February 2009 and as a director of WGEH since September 2012.

Mr. Lawler was named Senior Vice President, International and Deepwater Operations in July 2012. Prior to this position, he served as Vice President, Operations for the Southern and Appalachia Region in the U.S. onshore since March 2009 and International Operations since December 2011. Prior to that, Mr. Lawler served as Vice President, Corporate Planning since August 2008. Mr. Lawler has held a variety of positions with increasing responsibility within operations, business planning and analysis departments since the acquisition of Kerr-McGee in August 2006. He began his career in 1988 with Kerr-McGee.

Mr. Reeves was named Senior Vice President, General Counsel and Chief Administrative Officer in February 2007 and assumed the additional role of Chief Compliance Officer in July 2012. He also 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, as a director of WGH since August 2007 and as a director of WGEH since September 2012.

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 each year at the first meeting of the Board of Directors following the annual meeting of stockholders, the next of which is expected to occur on May 14, 2013, and hold office until their successors are duly elected and 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

Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this report, and may from time to time 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,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” 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

 

   

reserves levels

 

   

operating results

 

   

competitive conditions

 

   

technology

 

   

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

 

   

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

 

   

weather

 

   

inflation

 

   

availability of goods and services, including unexpected changes in costs

 

   

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

 

   

inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects

 

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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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

civil or political unrest or acts of terrorism in a region or country

 

   

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

 

   

volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity and interest-rate risk

 

   

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

 

   

physical, digital, internal, and external security breaches

 

   

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

 

   

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 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 in the U.S. Bankruptcy Court for the Southern District of New York. 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. 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 $18.9 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.

For additional information regarding the nature and status of these and other material legal proceedings, see Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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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 is fully indemnified by BP 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 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-on 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. In November 2012, BP settled all criminal and securities claims brought by the United States against BP, with BP agreeing to pay $4.0 billion over five years to the U.S. Department of Justice with respect to the criminal claims and further agreeing to pay another $525 million over three years to the Securities and Exchange Commission (SEC) with respect to the securities claims. BP represents that it is prepared to vigorously defend itself against remaining civil claims. 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 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 securities 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.

 

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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. The markets for oil, natural gas, and NGLs have been volatile historically 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

 

   

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

 

   

level of global crude-oil and natural-gas inventories

 

   

weather conditions

 

   

potential U.S. exports of liquefied natural gas

 

   

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

 

   

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

 

   

effect of worldwide energy conservation and environmental protection efforts

 

   

price and availability of alternative and competing fuels

 

   

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

 

   

domestic and foreign governmental regulations and taxes

 

   

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

 

   

general economic conditions worldwide

 

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The long-term effect of these and other factors on the prices of oil, natural gas, and NGLs is 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

 

   

limiting our access to, or increasing the cost of, sources of capital, such as equity and long-term debt

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, from time to time, legislation has been proposed that could adversely affect our business, financial condition, results of operations, or cash flows related to the following:

 

   

Climate Change.    A number of state and regional efforts have emerged that are aimed at tracking and/or reducing emissions of green-house gases (GHGs). In addition, 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. We may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs.

 

   

Deficit Reduction or Tax Reform.    Congress may undertake significant deficit reduction or comprehensive tax reform in the coming year. Proposals include provisions that would, if enacted, (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) eliminate the manufacturing deduction for oil and gas qualified production activities, and (iii) eliminate the acceleration of depreciation for tangible property.

 

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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 has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels with the public comment period expiring in August 2012. 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 and the agency currently projects to issue an Advance Notice of Proposed Rulemaking in May 2013 that would seek public input on the design and scope of such disclosure regulations. In May 2012, the Department of the Interior (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 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 is 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, Ohio, 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 currently conduct operations, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements. These costs may be significant in nature, and we may 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.

 

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There are also certain governmental reviews recently conducted or underway 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 the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review 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 for shale gas by 2014. In addition, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods and, in August 2011, issued a report on immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale-gas development. Also, as discussed above, the DOI is pursuing regulations governing hydraulic fracturing on federal and Indian oil and gas leases. These studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

The additional deepwater drilling laws and regulations, both domestically and internationally, 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 response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), each agencies of the DOI, issued directives in May and July 2010 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. In addition, the agencies issued a series of rules and Notices to Lessees and Operators (NTLs) imposing new and more stringent regulatory safety and performance requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. The federal government may issue further safety and environmental laws and regulations regarding operations in the Gulf of Mexico.

Compliance with these new and more stringent rules and regulations, uncertainties or inconsistencies in current decisions and rulings by governmental agencies, 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, and possible additional regulatory initiatives could adversely affect or 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, increase the risk of expired leases due to the time required to develop new technology, result in increased costs and limit activities in certain areas of the Gulf of Mexico, or cause us to incur penalties, fines, or shut-in production at one or all of our facilities. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations in the Gulf of Mexico.

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, Africa, 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.

 

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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 Deepwater Horizon incident 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, despite the Company’s oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Deepwater Horizon incident.

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.

The enactment of derivatives legislation 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 (Dodd-Frank Act), enacted in 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC 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. The position-limits rule was vacated by the U.S. District Court for the District of Colombia in September 2012 and the CFTC recently stated that it will appeal the District Court’s decision. The CFTC also finalized other regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to predict when this will be accomplished. Depending on the Company’s classification and the particular nature of its derivative activities, the Dodd-Frank Act and regulations may require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities. The Dodd-Frank Act and regulations may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and 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 Dodd-Frank Act 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 Dodd-Frank Act 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 Dodd-Frank Act 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.

 

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

Our total debt was $13.3 billion at December 31, 2012. 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, the following:

 

   

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

 

   

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.

At December 31, 2012, our debt was rated “BBB-” with a positive outlook by Standard and Poor’s (S&P), “BBB-” with a negative outlook by Fitch Ratings (Fitch), and “Baa3” with a stable outlook 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, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy. If our credit rating were 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 certain contractual arrangements and derivative agreements. See Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or assumptions underlying our reserves 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 reserves 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 reserves 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. These factors and assumptions may include, but are not limited to, the following:

 

   

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

 

   

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

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

A portion of our leasehold acreage is currently undeveloped. Unless production in sufficient quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based on various factors: drilling results, oil and natural-gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

 

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

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

As a result of mergers and acquisitions, we had approximately $5.5 billion of goodwill on our Consolidated Balance Sheet at December 31, 2012. 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 governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:

 

   

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

 

   

protection of endangered species

 

   

amounts and types of emissions and discharges

 

   

generation, management, and disposition of waste materials

 

   

offshore oil and gas operations and decommissioning of abandoned facilities

 

   

reclamation and abandonment of wells and facility sites

 

   

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 restriction against emission of pollutants from previously unregulated activities or 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 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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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, Liberia, Sierra Leone, Kenya, Côte d’Ivoire, 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 the following:

 

   

hurricanes and other adverse weather conditions

 

   

oilfield service costs and availability

 

   

compliance with environmental and other laws and regulations

 

   

terrorist attacks, such as piracy

 

   

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

 

   

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 reserves 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 foreign countries and are subject to political, economic, and other uncertainties.

Our operations outside the United States are based primarily in Algeria, Brazil, China, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, New Zealand, and Sierra Leone. As a result, we face political and economic risks and other uncertainties with respect to our international operations. These risks may include the following, 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 laws and 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

 

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

 

   

foreign-exchange restrictions

 

   

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, Ghana and Côte d’Ivoire are currently engaged in a dispute regarding the international maritime and land boundaries between the two countries. As a result, Côte d’Ivoire claims to be entitled to the maritime area which covers a portion of the Deepwater Tano Block where we are currently conducting exploration and appraisal activities. In the event Côte d’Ivoire is successful in its maritime border claims, our operations in the block could be materially impacted.

Outbreaks of civil and political unrest and acts of terrorism have occurred in several countries in Africa and the Middle East, including countries where we conduct operations, such as Algeria and Tunisia. As exhibited by the events in Tunisia, Egypt, and Libya, outbreaks of civil and political unrest have resulted in established governing bodies being overthrown. Continued or escalated civil and political unrest and acts of terrorism in the countries in which we operate could result in our curtailing operations. In the event that countries in which we operate experience civil or political unrest or acts of terrorism, especially in events where such unrest leads to an unseating of the established government, our operations in such countries 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 the following occur:

 

   

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

 

   

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

 

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Deterioration in the credit or equity markets could adversely affect us.

We have exposure to different counterparties. For example, 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. Moreover, to the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time.

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, 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 the following:

 

   

project approvals by joint-venture partners

 

   

timely issuance of permits and licenses by governmental agencies

 

   

weather conditions

 

   

availability of personnel

 

   

civil and political environment of the country or region in which the project is located

 

   

manufacturing and delivery schedules of critical equipment

 

   

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.

 

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

The oil and gas business is highly competitive in the search for and acquisition of reserves and in the gathering and marketing of oil and gas production. Our competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. Some of our competitors may have greater and more diverse resources on 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 oilfield 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 oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

Our drilling activities may not be productive.

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

 

   

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

 

   

difficulty identifying and retaining qualified personnel

 

   

title problems

 

   

other adverse weather conditions

 

   

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.

 

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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.

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.

 

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Item 1B.  Unresolved Staff Comments

None.

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, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. 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 17—Contingencies 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 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

At January 31, 2013, there were approximately 12,800 holders of record 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 2012 and 2011:

 

                                                                   
    First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
 

2012

       

Market Price

       

High

  $ 88.70     $ 79.85     $ 76.63     $ 76.95  

Low

  $ 75.90     $ 56.42     $ 64.19     $ 65.82  

Dividends

  $ 0.09     $ 0.09     $ 0.09     $ 0.09  

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  

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—Common Stock Dividends and Distributions to Noncontrolling Interest Owners 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, 2012:

 

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

    9,356,783     $ 58.66       29,652,758  

Equity compensation plans not approved by security holders

                 
 

 

 

   

 

 

   

 

 

 

Total

    9,356,783     $ 58.66       29,652,758  
 

 

 

   

 

 

   

 

 

 

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 2012:

 

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

    725     $ 69.17          

November 1-30

    152,359     $ 70.90          

December 1-31

    966     $ 74.19          
 

 

 

     

 

 

   

 

 

 

Fourth Quarter 2012

    154,050     $ 70.91            $   
 

 

 

     

 

 

   

 

 

 

 

(1) 

During the fourth quarter of 2012, 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 15—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 of 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

Copyright© 2013 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the S&P 500 Index, and in the peer group on December 31, 2007, and its relative performance is tracked through December 31, 2012.

 

                                                                 
Fiscal Year Ended December 31       2007         2008         2009         2010         2011         2012  

Anadarko Petroleum Corporation

  $ 100.00     $ 59.08     $ 96.41     $ 118.37     $ 119.21     $ 116.63  

S&P 500

    100.00       63.00       79.67       91.67       93.61       108.59  

Peer Group

    100.00       69.66       81.71       100.68       107.25       109.37  

 

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Index to Financial Statements

Item 6.  Selected Financial Data

 

    Summary Financial Information (1)  
millions except per-share amounts   2012     2011     2010     2009     2008  

Sales Revenues

  $ 13,307     $ 13,882     $ 10,842     $ 8,210     $ 14,079  

Gains (Losses) on Divestitures and Other, net

    104       85       142       133       1,083  

Reversal of Accrual for DWRRA Dispute

                      657        
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues and Other

    13,411       13,967       10,984       9,000       15,162  

Algeria Exceptional Profits Tax Settlement

    (1,797                        

Deepwater Horizon Settlement and Related Costs

    18       3,930       15              

Operating Income (Loss)

    3,727       (1,870     1,769       377       5,601  

Income (Loss) from Continuing Operations

    2,445       (2,568     821       (103     3,220  

Income from Discontinued Operations, net of taxes

                            63  

Net Income (Loss) Attributable to Common Stockholders

    2,391       (2,649     761       (135     3,260  

Per Common Share (amounts attributable to common stockholders):

         

Income (Loss) from Continuing Operations—Basic

  $ 4.76     $ (5.32   $ 1.53     $ (0.28   $ 6.79  

Income (Loss) from Continuing Operations—Diluted

  $ 4.74     $ (5.32   $ 1.52     $ (0.28   $ 6.78  

Income from Discontinued Operations—Basic

  $     $     $     $     $ 0.13  

Income from Discontinued Operations—Diluted

  $     $     $     $     $ 0.13  

Net Income (Loss)—Basic

  $ 4.76     $ (5.32   $ 1.53     $ (0.28   $ 6.92  

Net Income (Loss)—Diluted

  $ 4.74     $ (5.32   $ 1.52     $ (0.28   $ 6.91  

Dividends

  $ 0.36     $ 0.36     $ 0.36     $ 0.36     $ 0.36  

Average Number of Common Shares Outstanding—Basic

    500       498       495       480       465  

Average Number of Common Shares Outstanding—Diluted

    502       498       497       480       466  

Cash Provided by Operating Activities—Continuing Operations

  $ 8,339     $ 2,505     $ 5,247     $ 3,926     $ 6,447  

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

                            (5

Net Cash Provided by Operating Activities

    8,339       2,505       5,247       3,926       6,442  

Capital Expenditures

  $ 7,311     $ 6,553     $ 5,169     $ 4,558     $ 4,881  

Current Portion of Long-term Debt

  $     $ 170     $ 291     $     $ 1,472  

Long-term Debt

    13,269       15,060       12,722       11,149       9,128  

Midstream Subsidiary Note Payable to a Related Party

                      1,599       1,739  

Total Debt

  $ 13,269     $ 15,230     $ 13,013     $ 12,748     $ 12,339  

Total Stockholders’ Equity

    20,629       18,105       20,684       19,928       18,795  

Total Assets

  $ 52,589     $ 51,779     $ 51,559     $ 50,123     $ 48,923  

Annual Sales Volumes:

         

Natural Gas (Bcf)

    913       852       829       809       750  

Oil and Condensate (MMBbls)

    86       79       74       68       67  

Natural Gas Liquids (MMBbls)

    30       27       23       17       14  

Total (MMBOE) (2)

    268       248       235       220       206  

Average Daily Sales Volumes:

         

Natural Gas (MMcf/d)

    2,495       2,334       2,272       2,217       2,049  

Oil and Condensate (MBbls/d)

    233       217       201       187       182  

Natural Gas Liquids (MBbls/d)

    83       74       63       47       39  

Total (MBOE/d)

    732       680       643       604       563  

Proved Reserves:

         

Natural-Gas Reserves (Tcf)

    8.3       8.4       8.1       7.8       8.1  

Oil and Condensate Reserves (MMBbls)

    767       771       749       733       709  

Natural-Gas Liquids Reserves (MMBbls)

    405       374       320       277       217  

Total Proved Reserves (MMBOE)

    2,560       2,539       2,422       2,304       2,277  

Number of Employees

    5,200       4,800       4,400       4,300       4,300  
(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 met or exceeded its key operational objectives in 2012. The Company increased sales volumes by approximately 8% over 2011 and added 370 million barrels of oil equivalent (BOE) of proved reserves. Additionally, the Company continued its offshore exploration and appraisal drilling success with an approximate 67% success rate for wells completed in 2012. Anadarko fully repaid $2.5 billion of borrowings under the Company’s five-year $5.0 billion senior secured revolving credit facility ($5.0 billion Facility) with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute. The Company ended 2012 with $2.5 billion cash on hand, availability of the $5.0 billion Facility, and 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 developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:

 

   

explore in high-potential, proven basins

 

   

identify and commercialize resources

 

   

employ a global business development approach

 

   

ensure financial discipline and flexibility

Exploring in high-potential, proven, and emerging basins worldwide provides the Company with growth opportunities. Anadarko’s exploration success has created value by increasing its future resource potential, while providing the flexibility to mitigate risk by monetizing discoveries.

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.

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 investing 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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Significant 2012 operating and financial activities include the following:

Overall

 

   

Anadarko’s total-year sales volumes were 732 thousand barrels of oil equivalent per day (MBOE/d), representing an 8% increase over 2011.

 

   

Anadarko’s liquids sales volumes were 316 thousand barrels per day (MBbls/d), representing a 9% increase over 2011.

 

   

The Company achieved an approximate 67% success rate from offshore exploration and appraisal drilling completed in 2012.

U.S. Onshore

 

   

The Rocky Mountains Region (Rockies) total-year sales volumes were 321 MBOE/d, representing a 6% increase over 2011, primarily from the Wattenberg field and the Greater Natural Buttes area.

 

   

The Southern and Appalachia Region total-year sales volumes were 198 MBOE/d, representing a 36% increase over 2011, primarily from the Marcellus, Eagleford, and Haynesville shales.

Gulf of Mexico

 

   

Gulf of Mexico total-year sales volumes were 116 MBOE/d, representing an 11% decrease from 2011, primarily due to natural production declines.

 

   

The Company achieved first production from the Caesar/Tonga development (33.75% working interest) in the Green Canyon area during March 2012, utilizing Anadarko’s Constitution spar floating production facility.

 

   

The Company entered into a carried-interest arrangement that requires a third-party partner to fund $556 million of Anadarko’s capital costs to earn a 7.2% working interest in the Lucius development.

International

 

   

International total-year sales volumes were 84 MBOE/d, representing a 2% decrease from 2011.

 

   

The Company drilled five successful exploration wells: two in Mozambique and one each in Ghana, Côte d’Ivoire, and Sierra Leone.

 

   

The Company drilled ten successful appraisal wells: seven in Mozambique, two in Ghana, and one in Brazil.

Financial

 

   

Anadarko’s net income attributable to common stockholders for 2012, including $1.8 billion related to the favorable resolution of the Algeria exceptional profits tax dispute and $845 million of certain unproved property impairments, totaled $2.4 billion. In 2011, Anadarko’s net loss attributable to common stockholders was $2.6 billion, and included the effect of the $4.0 billion settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement).

 

   

The Company generated $8.3 billion of cash flows from operations in 2012, including $1.0 billion collected related to the resolution of the Algeria exceptional profits tax dispute, and ended 2012 with $2.5 billion of cash on hand. Anadarko’s $2.5 billion of cash flows from operations in 2011 included the effect of the $4.0 billion payment made as a result of the Settlement Agreement.

 

   

The Company fully repaid $2.5 billion of borrowings under its $5.0 billion Facility.

 

   

Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own Anadarko’s partnership interests in Western Gas Partners, LP (WES), also a consolidated subsidiary of Anadarko, completed its initial public offering (IPO) of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit.

 

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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, 2012” refer to the comparison of the year ended December 31, 2012, to the year ended December 31, 2011. Similarly, 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. 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 reserves; the cost of finding such reserves; and operating costs.

RESULTS OF OPERATIONS

Selected Data

 

millions except per-share amounts and percentages   2012     2011     2010  

Financial Results

     

Oil and condensate, natural-gas, and NGLs sales

  $ 12,396     $ 12,834     $ 10,009  

Gathering, processing, and marketing sales

    911       1,048       833  

Gains (losses) on divestitures and other, net

    104       85       142  
 

 

 

   

 

 

   

 

 

 

Total revenues and other

    13,411       13,967       10,984  

Costs and expenses (1)

    9,684       15,837       9,215  

Other (income) expense

    162       1,554       128  

Income tax expense (benefit)

    1,120       (856     820  

Net income (loss) attributable to common stockholders

  $ 2,391     $ (2,649   $ 761  

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

  $ 4.74     $ (5.32   $ 1.52  

Average number of common shares outstanding—diluted

    502       498       497  

Operating Results

     

Adjusted EBITDAX (2)

  $ 8,966     $ 8,869     $ 7,146  

Total proved reserves (MMBOE)

    2,560       2,539       2,422  

Annual sales volumes (MMBOE)

    268       248       235  

Capital Resources and Liquidity

     

Cash provided by operating activities

  $ 8,339     $ 2,505     $ 5,247  

Capital expenditures

    7,311       6,553       5,169  

Total debt

    13,269       15,230       13,013  

Stockholders’ equity

  $ 20,629     $ 18,105     $ 20,684  

Debt to total capitalization ratio

    39.1%        45.7%        38.6%   

 

MMBOE—million barrels of oil equivalent

(1) 

Includes Deepwater Horizon settlement and related costs of $18 million in 2012, $3.9 billion in 2011, and $15 million in 2010, and a credit of $1.8 billion for previously recorded expenses related to the favorable resolution of the Algeria exceptional profits tax dispute in 2012.

(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 income attributable to common stockholders for 2012 totaled $2.4 billion, or $4.74 per share (diluted), compared to a net loss attributable to common stockholders for 2011 of $2.6 billion, or $5.32 per share (diluted). Anadarko’s net income attributable to common stockholders in 2010 was $761 million, or $1.52 per share (diluted). Anadarko’s net income for 2012 included $1.8 billion related to the favorable resolution of the exceptional profits tax dispute and $845 million related to certain unproved property impairments. Anadarko’s net loss for 2011 included the effect of the $4.0 billion Settlement Agreement with BP Exploration & Production Inc. (BP) related to the Deepwater Horizon events.

Sales Revenues and Volumes

 

                                                                                    
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Sales Revenues

         

Natural-gas sales

  $ 2,444       (26 )%    $ 3,300       (4 )%    $ 3,420  

Oil and condensate sales

    8,728       8       8,072       44       5,592  

Natural-gas liquids sales

    1,224       (16     1,462       47       997  
 

 

 

     

 

 

     

 

 

 

Total

  $ 12,396       (3   $ 12,834       28     $ 10,009  
 

 

 

     

 

 

     

 

 

 

Anadarko’s total sales revenues for the year ended December 31, 2012, decreased primarily due to lower average natural-gas and NGLs prices, partially offset by higher sales volumes for all products. 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.

 

                                                                                                   
millions   Natural
Gas
    Oil and
Condensate
    NGLs     Total  

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  

Changes associated with prices

    (1,094     9       (409     (1,494

Changes associated with sales volumes

    238       647       171       1,056  
 

 

 

   

 

 

   

 

 

   

 

 

 

2012 sales revenues

  $ 2,444     $ 8,728     $ 1,224     $ 12,396  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table provides Anadarko’s sales volumes for the years ended December 31, 2012, 2011, and 2010:

 

                                                                          
Sales Volumes   2012     Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

Barrels of Oil Equivalent

         

(MMBOE except percentages)

         

United States

    237       9     217       4     209  

International

    31       (2     31       20       26  
 

 

 

     

 

 

     

 

 

 

Total

    268       8       248       6       235  
 

 

 

     

 

 

     

 

 

 

Barrels of Oil Equivalent per Day

         

(MBOE/d except percentages)

         

United States

    648       9     595       4     572  

International

    84       (2     85       20       71  
 

 

 

     

 

 

     

 

 

 

Total

    732       8       680       6       643  
 

 

 

     

 

 

     

 

 

 

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 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K 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

 

                                                                                    
    2012     Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

United States

         

Sales volumes—Bcf

    913       7     852       3     829  

                            MMcf/d

    2,495       7       2,334       3       2,272  

Price per Mcf

  $ 2.68       (31   $ 3.87       (6   $ 4.12  

Natural-gas sales revenues (millions)

  $ 2,444       (26   $ 3,300       (4   $ 3,420  

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes increased 161 MMcf/d for the year ended December 31, 2012, primarily due to higher sales volumes in the Southern and Appalachia Region of 220 MMcf/d as a result of bringing wells drilled in previous years online at Eagleford and Marcellus shales due to infrastructure expansions during 2012 and new wells drilled in the Haynesville shale. Also, the Company had higher sales volumes in the Rockies of 52 MMcf/d associated with drilling in the Greater Natural Buttes area and the Wattenberg field. These increases were partially offset by reduced sales volumes in the Gulf of Mexico of 111 MMcf/d primarily due to natural production declines.

The Company’s natural-gas sales volumes increased 62 MMcf/d for the year ended December 31, 2011, primarily due to higher 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 higher 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 that did not apply in 2011 and natural production declines.

 

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The average natural-gas price Anadarko received decreased for the year ended December 31, 2012, due to continued growth in U.S. natural-gas production, reduced U.S. natural-gas demand as a result of mild winter temperatures, and above-average U.S. natural-gas storage levels in 2012. Anadarko’s average natural-gas price received decreased for the year ended December 31, 2011, primarily due to the industry’s supply growing at a faster pace than demand in 2011.

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

 

                                                                                    
    2012     Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

United States

         

Sales volumes—MMBbls

    55       14     48       1     48  

                            MBbls/d

    149       14       132       1       130  

Price per barrel

  $ 97.46           $ 97.70       30     $ 74.96  

International

         

Sales volumes—MMBbls

    31       (2 )%      31       20     26  

                            MBbls/d

    84       (2     85       20       71  

Price per barrel

  $ 111.11       2     $ 109.20       39     $ 78.52  

Total

         

Sales volumes—MMBbls

    86       8     79       8     74  

                            MBbls/d

    233       8       217       8       201  

Price per barrel

  $ 102.35           $ 102.24       34     $ 76.22  

Oil and condensate sales revenues (millions)

  $ 8,728       8     $ 8,072       44     $ 5,592  

 

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, 2012. Increased horizontal drilling in the Wattenberg field led to a 9 MBbls/d sales-volume improvement in the Rockies. Horizontal drilling in the Eagleford shale and Bone Spring/Avalon formations also contributed to increased sales volumes in the Southern and Appalachia Region of 8 MBbls/d.

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/Avalon formations 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, and natural production declines.

Anadarko’s average crude-oil price received increased for the years ended December 31, 2012 and 2011, primarily due to supply disruption concerns associated with political and civil unrest in the Middle East and North Africa, and steady global demand growth. Additionally, average realized crude-oil prices for 2012 and 2011 were enhanced by the wide differential between West Texas Intermediate and Brent crude, as approximately 70% of Anadarko’s crude-oil sales volumes were based on prices that were either directly indexed to, or highly correlated to, Brent crude. The price increase for the year ended December 31, 2012, was offset by downward price pressure caused by macroeconomic concerns in Europe and China.

 

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

 

                                                                                                        
    2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

United States

         

Sales volumes—MMBbls

    30       12     27       17     23  

                                   MBbls/d

    83       12       74       17       63  

Price per barrel

  $ 40.44       (25   $ 53.95       25     $ 43.07  

Natural-gas liquids sales revenues (millions)

  $ 1,224       (16   $ 1,462       47     $ 997  

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 9 MBbls/d for the year ended December 31, 2012, as a result of drilling in liquids-rich areas, primarily in the Eagleford and Haynesville shales in the Southern and Appalachia Region.

Anadarko’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 acquisition of an additional 93% interest in a natural-gas processing plant (Wattenberg Plant).

Anadarko’s average NGLs price decreased for the year ended December 31, 2012, primarily due to lower market prices for ethane and propane. Ethane demand was reduced by down-time for maintenance and conversion upgrades at petrochemical facilities. Mild winter temperatures across much of the United States in 2011 reduced demand for propane and contributed to above-average levels of propane stockpiles. Also, increased production from continued liquids-rich development has created further downward pricing pressures for NGLs. The average NGLs price increased for the year ended 2011, primarily due to higher crude-oil prices and sustained global petrochemical demand.

Gathering, Processing, and Marketing Margin

 

                                                                                                        
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Gathering, processing, and marketing sales

  $ 911       (13)   $ 1,048       26   $ 833  

Gathering, processing, and marketing expenses

    763       (4)         791       29       615  
 

 

 

     

 

 

     

 

 

 

Margin

  $ 148       (42)       $ 257       18     $ 218  
 

 

 

     

 

 

     

 

 

 

For the year ended December 31, 2012, the gathering, processing, and marketing margin decreased $109 million. This decrease was due primarily to lower commodity prices, which led to reduced natural-gas processing margins and decreased marketing margins on sales from inventory. Also, for the year ended December 31, 2012, transportation expenses increased primarily due to higher unutilized demand fees. These decreases for the year ended December 31, 2012, were partially offset by additional margin provided by midstream assets acquired in February 2011 and May 2011, and an increase in gathering and processing revenues associated with increased throughput volumes across several of Anadarko’s fee-based systems.

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 discussed above. These increases were partially offset by lower margins associated with natural-gas sales from inventory.

 

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Gains (Losses) on Divestitures and Other, net

For the year ended December 31, 2012, gains (losses) on divestitures and other, net increased $19 million primarily due to increased mineral revenue of $36 million related to increased mining of soda ash on Anadarko’s Land Grant and higher per-ton average sales prices. Increased mineral revenue was partially offset by an increase in net losses on divestitures of $17 million. In January 2013, the Company divested its equity interest in the OCI soda ash business for $310 million and additional potential consideration while retaining its royalty interest in minerals mined from the Company’s Land Grant.

Gains (losses) on divestitures for 2012 included net losses of $71 million, primarily related to the sale of oil and gas exploration and production reporting segment properties in Indonesia.

Gains (losses) on divestitures for 2011 included net losses of $54 million, primarily related to write-downs of $422 million of assets held for sale. In 2011, the Company began marketing certain 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. Also included in 2011 was a $76 million loss, which occurred in connection with the Company’s purchase of the Wattenberg Plant. This loss was associated with the effective elimination, for purposes of consolidated financial reporting, of a pre-existing third-party relationship between the Company and the previous owner of the plant related to natural-gas processing contracts. 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 market transactions for the same or similar services at the date of the Company’s acquisition of the plant. These losses were partially offset by 2011 gains of $419 million for receipt and final settlement of contingent consideration related to the 2008 divestiture of its interest in the Peregrino field offshore Brazil and $21 million from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition 7% equity interest in the Wattenberg Plant.

For the year ended December 31, 2011, gains (losses) on divestitures and other, net decreased $57 million primarily due to 2011 net losses on divestitures discussed above.

Costs and Expenses

 

                                                                                                        
    2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Oil and gas operating (millions)

  $ 976       (2)   $ 993       20   $ 830  

Oil and gas operating—per BOE

    3.65       (9)         4.00       13       3.54  

Oil and gas transportation and other (millions)

    955              891       9       816  

Oil and gas transportation and other—per BOE

    3.57       (1)         3.59       3       3.48  

For the year ended December 31, 2012, oil and gas operating expenses decreased by $17 million primarily due to lower workover expenses of $67 million associated with fewer workovers, primarily in the Gulf of Mexico and the Rockies, partially offset by $52 million of higher operating expenses from increased activity in Ghana. Per-BOE oil and gas operating expenses decreased by $0.35 for the year ended December 31, 2012, primarily as a result of increased sales volumes, while efficiently maintaining production costs, and lower workover expenses discussed above. For the year ended December 31, 2011, oil and gas operating expenses increased by $163 million primarily due to (i) $47 million from increased workovers and related freight costs, 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) $34 million in operating costs resulting from the start of production in Ghana, and (iv) $10 million in higher surface maintenance costs primarily in the Rockies. Oil and gas operating expenses per BOE increased by $0.46 for the year ended December 31, 2011, primarily due to the higher costs discussed above, partially offset by increased sales volumes.

 

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For the year ended December 31, 2012, oil and gas transportation and other expenses increased $64 million primarily due to higher gas-gathering and transportation costs attributable to higher volumes and increased costs attributable to growth in the Company’s U.S. onshore asset base. 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 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. Oil and gas transportation and other expenses per BOE decreased by $0.02 for the year ended December 31, 2012, primarily due to increased sales volumes, partially offset by the higher costs discussed above. For the year ended December 31, 2011, oil and gas transportation and other expenses per BOE increased by $0.11, primarily due to the higher costs discussed above, partially offset by increased sales volumes.

 

                                                  
millions   2012     2011     2010  

Exploration Expense

     

Dry hole expense

  $ 440     $ 154     $ 202  

Impairments of unproved properties

    1,104       471       480  

Geological and geophysical expenses

    151       246       103  

Exploration overhead and other

    251       205       189  
 

 

 

   

 

 

   

 

 

 

Total exploration expense

  $ 1,946     $ 1,076     $ 974  
 

 

 

   

 

 

   

 

 

 

Exploration expense increased $870 million for the year ended December 31, 2012, primarily due to increases of $633 million in impairments of unproved properties and $286 million in dry hole expense, partially offset by a $95 million decrease in geological and geophysical expenses.

The increase in 2012 impairments of unproved properties was primarily due to $845 million of impairments for certain unproved properties in the Rockies and the Gulf of Mexico. Approximately $721 million of the impairments were due to lower natural-gas prices associated with Powder River coalbed methane properties in the Rockies and $124 million related to a Gulf of Mexico natural-gas property that the Company does not plan to pursue under the forecasted natural-gas price environment. These increases were partially offset by 2011 impairments of certain unproved properties in the Gulf of Mexico of $124 million and Indonesia of $63 million due to decreases in the estimated recoverable cash flows.

The $286 million increase in dry hole expense for the year ended December 31, 2012, was primarily due to wells in Brazil, Sierra Leone, Côte d’Ivoire, Mozambique, and the Gulf of Mexico. The $95 million decrease in geological and geophysical expense was primarily due to fewer seismic purchases in Kenya, Liberia, New Zealand, and Mozambique.

For the year ended December 31, 2012, exploration overhead and other increased $46 million primarily due to increased exploration activity onshore United States and in Mozambique.

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.

 

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Index to Financial Statements
                                                                                                        
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

General and administrative

  $ 1,246       18   $ 1,060       10   $ 967  

Depreciation, depletion, and amortization

    3,964       3       3,830       3       3,714  

Other taxes

    1,224       (18     1,492       40       1,068  

Impairments

    389       (78     1,774       NM        216  

 

NM—not meaningful

For the year ended December 31, 2012, general and administrative (G&A) expense increased by $186 million due to higher employee-related expenses of $150 million primarily related to expense associated with general partner Unit Appreciation Rights (UARs) awarded in prior years to certain officers of the general partner of WES, pursuant to the WGH Equity Incentive Plan. This increase was related to the change in fair value of the UARs upon the WGP IPO. In addition, G&A expense increased by $41 million due to higher legal-related and consulting expenses primarily related to the Tronox litigation. For the year ended December 31, 2011, 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, and increased insurance costs of $9 million related to higher industry-specific rates as a result of the Deepwater Horizon events.

For the year ended December 31, 2012, depreciation, depletion, and amortization (DD&A) expense increased by $134 million primarily due to higher sales volumes, accelerated expense in 2012 associated with the depletion of fields in the Gulf of Mexico, and the start of production at Caesar/Tonga in March 2012. These increases were partially offset by lower per-barrel DD&A rates resulting from asset impairments recorded in the fourth quarter of 2011 and reserves additions in 2012 related to the Southern and Appalachia Region. For the year ended December 31, 2011, 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 recognized in 2010 associated with depleted fields in the Gulf of Mexico.

For the year ended December 31, 2012, other taxes decreased by $268 primarily related to lower Algeria exceptional profits taxes of $184 million due to a lower Algeria effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute. Other taxes also decreased due to lower commodity prices, which resulted in lower U.S. production and severance taxes of $55 million, and lower ad valorem taxes of $27 million. 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.

Impairment expense was $389 million for the year ended December 31, 2012. The Company recognized impairments of $363 million related to oil and gas exploration and production reporting segment properties located in the United States, $13 million related to midstream properties, and $13 million related to the Company’s Venezuelan cost-method investment. Impairment expense for U.S. oil and gas exploration and production reporting segment properties included $259 million related to lower natural-gas prices. Impairment expense for U.S. properties also included $79 million related to downward reserves revisions for a Gulf of Mexico property that was near the end of its economic life and $25 million for a platform in the Gulf of Mexico with no salvage value. Also during 2012, the Company recognized impairment expense of $13 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable reserves and lower crude-oil prices. Further declines in commodity prices or negative reserves revisions could result in additional 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.

 

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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 Venezuelan cost-method investment. 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 for certain Gulf of Mexico properties related to declines in estimated recoverable reserves, and $100 million related to onshore properties due to changes in projected cash flows resulting from the Company’s intent to divest of the subject properties. All of these assets were impaired to fair value.

Impairment expense for the year ended December 31, 2010, included $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, and $61 million related to the Company’s Venezuelan cost-method investment.

 

                                                  
millions   2012     2011     2010  

Algeria exceptional profits tax settlement

  $ (1,797   $     $   

Deepwater Horizon settlement and related costs

    18       3,930       15  

In March 2012, Anadarko and Sonatrach resolved the exceptional profits tax dispute. The resolution provided for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the year ended December 31, 2012, to reflect the effect of this agreement for previously recorded expenses. During 2012, the Company collected $1.0 billion associated with the Algeria exceptional profits tax receivable. The Company expects to collect the balance of the Algeria exceptional profits tax receivable during the first half of 2013.

In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company agreed to pay $4.0 billion in cash and transfer its interest in the Macondo well and the Mississippi Canyon Block 252 lease (Lease) to BP, and BP agreed to accept 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 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-on 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 17—Contingencies—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.

 

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For the year ended December 31, 2012, Deepwater Horizon settlement and related costs included $18 million of legal expenses and related costs associated with the Deepwater Horizon events. 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 discussed above, 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 of 2011 for insurance recoveries associated with the Deepwater Horizon events. 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 2011 payment made to BP as part of the Settlement Agreement.

Other (Income) Expense

 

                                                                                                        
millions except percentages       2012         Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

Interest Expense

         

Current debt, long-term debt, and other

  $ 963       (2 )%    $ 986       13   $ 871  

(Gain) loss on early debt retirements and commitment termination

          NM              (100     112  

Capitalized interest

    (221     (50     (147     (15     (128
 

 

 

     

 

 

     

 

 

 

Interest expense

  $ 742       (12   $ 839       (2   $ 855  
 

 

 

     

 

 

     

 

 

 

Anadarko’s interest expense decreased $97 million for the year ended December 31, 2012, primarily due to an increase in capitalized interest of $74 million related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense for the year ended December 31, 2012, decreased $32 million as a result of interest incurred during 2011 related to the Company’s capital lease obligations for a floating production, storage, and offloading vessel (FPSO) for the Company’s Jubilee field operations in Ghana. In December 2011, the Company and its partners in the Jubilee project purchased the vessel, resulting in cancellation of the capital lease obligation.

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 commitment fees related to the $5.0 billion Facility. For additional information, see Liquidity and Capital Resources—Uses of Cash—Debt Retirements and Repayments, and Interest-Rate Risk under Item 7A of this Form 10-K.

 

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Index to Financial Statements
                                                  
millions   2012     2011     2010  

(Gains) Losses on Derivatives, net

     

Commodity derivatives

     

Realized (gains) losses

     

Natural gas

  $ (678   $ (288   $ (513

Oil and condensate

    (65     61       15  

Natural gas liquids

    (10     1        
 

 

 

   

 

 

   

 

 

 

Total realized (gains) losses

    (753     (226     (498
 

 

 

   

 

 

   

 

 

 

Unrealized (gains) losses

     

Natural gas

    444       (192     (353

Oil and condensate

    (64     (140     (42

Natural gas liquids

    (14     (4      
 

 

 

   

 

 

   

 

 

 

Total unrealized (gains) losses

    366       (336     (395
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on commodity derivatives, net

    (387     (562     (893
 

 

 

   

 

 

   

 

 

 

Interest-rate and other derivatives

     

Realized (gains) losses

    66       59        

Unrealized (gains) losses

    (5     964       285  
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on interest-rate and other derivatives, net

    61       1,023       285  
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on derivatives, net

  $ (326   $ 461     $ (608
 

 

 

   

 

 

   

 

 

 

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 during the year and price changes related to positions open at December 31 of each year. For additional information on (gains) losses on commodity derivatives, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to unfavorable interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease). In 2012, the Company extended the swap maturity dates from October 2012 to September 2016 for interest-rate swaps with an aggregate notional principal amount of $800 million. 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. Interest-rate swap agreements with an aggregate notional principal amount of $200 million were settled in October 2012, resulting in a realized loss of $64 million, and interest-rate swap agreements with an aggregate notional principal amount of $150 million were settled in October 2011, resulting in a realized loss of $57 million. For additional information, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Index to Financial Statements
                                                                                                        
millions except percentages       2012         Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

Other (Income) Expense, net

         

Interest income

  $ (16     (24 )%    $ (21     62   $ (13

Other

    (238     187       275       NM        (106
 

 

 

     

 

 

     

 

 

 

Total other (income) expense, net

  $ (254     NM      $ 254       NM      $ (119
 

 

 

     

 

 

     

 

 

 

Total other income increased $508 million for the year ended December 31, 2012, primarily due to the $250 million reversal of the Tronox-related contingent loss recognized in 2011. See Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

For 2011, total other income decreased $373 million, primarily due to the recognition of a $250 million Tronox-related contingent loss in 2011, and the 2010 reversal of the $95 million reimbursement obligation to Tronox as a result of the cancellation of the Master Separation Agreement (MSA) by Tronox that occurred as part of Tronox’s bankruptcy proceedings. Additionally, total other income in 2011 decreased $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 at 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 under consideration by the Brazilian courts, and the Company expects this litigation to be resolved within the next year. An unfavorable decision may require the Company to record a tax liability in the Consolidated Financial Statements. See Note 17—Contingencies—Other Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Income Tax Expense

 

                                                  
millions except percentages   2012     2011     2010  

Income tax expense (benefit)

  $ 1,120     $ (856   $ 820  

Effective tax rate

    31%        25%        50%   

The decrease from the 35% U.S. federal statutory rate for the year ended December 31, 2012, was primarily attributable to the resolution of the Algerian exceptional profits tax dispute. This amount was partially offset by the following:

 

   

Algerian exceptional profits taxes

 

   

tax impact from foreign operations

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:

 

   

Algerian exceptional profits taxes

 

   

tax impact from foreign operations

 

   

items resulting from business acquisitions and other items

These amounts were partially offset by state income tax benefits of the loss.

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

 

   

Algerian exceptional profits taxes

 

   

unfavorable resolution of uncertain tax positions

 

   

tax impact from foreign operations

For additional information on income tax rates, see Note 19—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Net Income Attributable to Noncontrolling Interests

In December 2012, WGP completed its IPO of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit. The Company’s net income attributable to noncontrolling interests of $54 million for the year ended December 31, 2012, $81 million for 2011, and $60 million for 2010, primarily related to public ownership interests in WES and WGP. Public ownership of WES was 51.8% at December 31, 2012, 54.7% at December 31, 2011, and 51.5% at December 31, 2010. Public ownership of WGP was 9.0% at December 31, 2012. See Note 10—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Index to Financial Statements

OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX  To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes, interest expense, exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, unrealized (gains) losses on derivatives, net, and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests. 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, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion of these events. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. Therefore, Anadarko’s consolidated Adjusted EBITDAX should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures prepared in accordance with GAAP, such as operating income or cash 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.

 

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Adjusted EBITDAX

 

                                                                                                        
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Income (loss) before income taxes

  $ 3,565       NM      $ (3,424     NM      $ 1,641  

Exploration expense

    1,946       81     1,076       10     974  

DD&A

    3,964       3        3,830       3        3,714  

Impairments

    389       (78     1,774       NM        216  

Deepwater Horizon settlement and related costs

    18       (100     3,930       NM        15  

Algeria exceptional profits tax settlement (1)

    (1,797     NM              NM         

Tronox-related contingent loss (1)

    (250     NM        250       NM        (95

Interest expense

    742       (12     839       (2     855  

Unrealized (gains) losses on derivatives, net

    377       (39     616       NM        (114

Realized (gains) losses on other derivatives, net (1)

    66       12        59       NM         

Less net income attributable to noncontrolling interests

    54       (33     81       35        60  
 

 

 

     

 

 

     

 

 

 

Consolidated Adjusted EBITDAX

  $ 8,966       1      $ 8,869       24      $ 7,146  
 

 

 

     

 

 

     

 

 

 

Adjusted EBITDAX by segment

         

Oil and gas exploration and production

  $ 8,500       (3   $ 8,787       29      $ 6,786  

Midstream

    474       13       419       36        308  

Marketing

    (104     (65     (63     NM        4  

Other and intersegment eliminations

    96       135        (274     NM        48  

 

(1) 

In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. The prior periods have been adjusted to reflect this change.

Oil and Gas Exploration and Production  The decrease in Adjusted EBITDAX for the year ended December 31, 2012, was primarily due to lower NGLs and natural-gas prices, partially offset by higher sales volumes. The increase in Adjusted EBITDAX for the year ended December 31, 2011, was primarily due to the higher crude-oil and NGLs prices and higher sales volumes. These increases were partially offset by lower natural-gas prices and increased operating expenses, primarily other taxes, which increased as a result of higher sales volumes and crude-oil prices.

Midstream  The increase in Adjusted EBITDAX for the year ended December 31, 2012, is primarily due to additional margin provided by assets acquired in February 2011 and May 2011, and an increase in gathering and processing revenues associated with increased throughput across several of Anadarko’s fee-based systems. This increase was partially offset by lower commodity prices, which led to reduced natural-gas processing margins. For the year ended December 31, 2011, the increase in Adjusted EBITDAX resulted from increased margins due to higher NGLs prices and volumes, lower prices for natural-gas purchases, and margins provided by 2011 asset acquisitions. Also contributing to the increase was 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. These increases were partially offset by losses related to midstream assets held for sale.

Marketing  Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. The decrease in Adjusted EBITDAX for the year ended December 31, 2012, resulted from lower margins on sales from inventory as a result of lower prices and increased transportation expenses primarily due to higher unutilized demand fees. The decrease in Adjusted EBITDAX for the year ended December 31, 2011, resulted primarily from lower margins associated with natural-gas sales from inventory and an increase in transportation expense related to new transportation agreements effective January 2011.

 

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Other and Intersegment Eliminations  Other and intersegment eliminations consist primarily of corporate costs, realized gains and losses on derivatives, and income from hard minerals investments and royalties. The increase in Adjusted EBITDAX for the year ended December 31, 2012, was primarily due to higher realized gains on commodity derivatives in 2012, partially offset by expense associated with general partner UARs awarded in prior years to certain officers of the general partner of WES, pursuant to the WGH Equity Incentive Plan. This increase was related to the change in fair value of the UARs in connection with the WGP IPO. The decrease in Adjusted EBITDAX for the year ended December 31, 2011, was primarily due to lower realized gains on commodity derivatives in 2011 and exchange-rate changes applicable to foreign currency.

Proved Reserves  Anadarko is focused on growth and profitability, and reserves replacement is a key to growth. Future profitability partially depends on commodity prices and the cost of finding and developing oil and gas reserves. Reserves growth can be achieved through successful exploration and development drilling, improved recovery, or acquisition of producing properties.

Additional reserves information is contained in the Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K.

 

                                                  
MMBOE   2012     2011     2010  

Proved Reserves

     

Beginning of year

    2,539       2,422       2,304  

Reserves additions and revisions

     

Discoveries and extensions

    82       174       83  

Infill-drilling additions (1)

    383       203       312  
 

 

 

   

 

 

   

 

 

 

Drilling-related reserves additions and revisions

    465       377       395  

Other non-price-related revisions (1)

    (31     7       (66
 

 

 

   

 

 

   

 

 

 

Net organic reserves additions

    434       384       329  

Acquisition of proved reserves in place

    4             1  

Price-related revisions (1)

    (68     8       29  
 

 

 

   

 

 

   

 

 

 

Total reserves additions and revisions

    370       392       359  

Sales in place

    (81     (29     (6

Production

    (268     (246     (235
 

 

 

   

 

 

   

 

 

 

End of year

    2,560       2,539       2,422  
 

 

 

   

 

 

   

 

 

 

Proved Developed Reserves

     

Beginning of year

    1,811       1,673       1,624  
 

 

 

   

 

 

   

 

 

 

End of year

    1,883       1,811       1,673  
 

 

 

   

 

 

   

 

 

 

 

(1) 

Combined and reported as revisions of prior estimates in the Company’s Supplemental Information under Item 8 of this Form 10-K.

Proved Reserves Additions and Revisions  During 2012, the Company added 370 MMBOE of proved reserves as a result of additions (purchases in place, discoveries, and extensions) and revisions. The Company expects the majority of future reserves growth to come from revisions associated with infill drilling (reserves bookings related to infill wells are treated as positive revisions due to increases in expected recovery), extensions of current fields, new discoveries onshore United States and in the Gulf of Mexico, successful exploration in international growth areas, and purchases of properties in strategic areas.

 

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Additions  During 2012, Anadarko added 82 MMBOE of proved reserves through extensions and discoveries primarily as a result of successful drilling in the Marcellus shale area and the Gulf of Mexico. Although shale plays represent only about 10% of the Company’s total proved reserves at December 31, 2012, growth in the shale plays contributed 66 MMBOE of the total extensions and discoveries. During 2011, Anadarko added 174 MMBOE of proved reserves primarily as a result of successful drilling in the Marcellus and Eagleford shale areas and the Gulf of Mexico. Shale plays contributed 119 MMBOE of additions in 2011. During 2010, Anadarko added 83 MMBOE of proved reserves primarily as a result of successful drilling in the United States. Shale plays contributed 45 MMBOE of the 2010 additions.

Revisions  Total revisions in 2012 resulted in an increase of 284 MMBOE or 11% of the beginning-of-year reserves base. Total revisions include: the effects of new infill drilling, changes in commodity prices and other updates reflecting changes in economic conditions, reservoir performance, and development plans. Total 2012 revisions included an increase of 383 MMBOE related to successful infill drilling, primarily in large onshore areas such as Greater Natural Buttes, Wattenberg, and Carthage, and 33 MMBOE resulting from the resolution of the Algeria exceptional profits tax dispute. Partially offsetting these positive revisions were decreases of 68 MMBOE due to lower commodity prices, 56 MMBOE at Wattenberg primarily due to removing reserves associated with the discontinued vertical drilling program, and 8 MMBOE resulting from updates to all other assets. Total revisions in 2011 were 218 MMBOE or 9% of the beginning-of-year reserves base. The revisions included an increase of 203 MMBOE related to continuation of successful infill drilling in large onshore areas, including Greater Natural Buttes, Wattenberg, and Pinedale fields, 182 MMBOE of positive revisions to prior estimates, and 8 MMBOE associated with higher oil prices. These positive revisions were partially offset by the transfer of 175 MMBOE of proved reserves to unproved categories as a result of changes to development plans and economic conditions experienced during 2011. Total revisions in 2010 were 275 MMBOE or 12% of the beginning-of-year reserves base. The revisions included an increase of 312 MMBOE related to successful infill drilling in large onshore areas, 77 MMBOE of favorable revisions to prior estimates, and 29 MMBOE associated with higher oil and natural-gas prices.

Sales in Place  In 2012, the Company sold U.S. properties or interests in U.S. properties containing 59 MMBOE of proved developed reserves and 22 MMBOE of proved undeveloped reserves. Sales included partial sales of working interests in the Rockies Salt Creek enhanced oil recovery project and the Gulf of Mexico Lucius development project, and asset divestitures in South Texas, West Texas, the Gulf of Mexico, Rockies, and North Louisiana. In 2011, the Company sold U.S. properties containing 7 MMBOE of proved developed reserves and 22 MMBOE of proved undeveloped reserves. This included a sale of a working interest in the Maverick basin and asset divestitures in South Texas and Alaska.

Discounted Future Net Cash Flows  At December 31, 2012, the discounted estimated future net cash flows (at 10%) from Anadarko’s proved reserves was $26.3 billion (measured in accordance with the regulations of the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB)). This amount was calculated based on the 12-month average beginning-of-month prices for the year, held flat for the life of the reserves, adjusted for any contractual provisions. See Supplemental Information under Item 8 of this Form 10-K.

The present value of future net cash flows is not an estimate of the fair value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and natural gas.

 

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LIQUIDITY AND CAPITAL RESOURCES

Overview  Anadarko generates cash needed to fund capital expenditures, debt-service obligations, and dividend payments primarily from operating activities, and enters into debt and equity transactions to maintain its desired capital structure and to finance acquisition opportunities. Liquidity may also be enhanced through asset divestitures and joint ventures that reduce future capital expenditures.

Consistent with this approach, the primary source for capital investment funding during 2012 was cash flows from operating activities. In addition, the Company collected $1.0 billion associated with the Algerian exceptional profits tax receivable that was used to reduce outstanding borrowings under the $5.0 billion Facility. The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions.

In March 2012, Moody’s Investors Service returned the Company’s senior unsecured rating to investment grade. As a result, the Company was able to terminate the LOC Facility (discussed below). All cash that secured financial trades previously posted due to credit-related provisions has been returned to the Company.

During 2012, the Company fully repaid $2.5 billion of borrowings under the Company’s $5.0 billion Facility with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute. At December 31, 2012, Anadarko had no scheduled debt maturities in 2013, exclusive of the Zero-Coupon Senior Notes due 2036 (Zero Coupons) that can be put to the Company in October 2013 (the next potential put date) for the then-accreted value of $718 million. Scheduled debt maturities in 2014 are $775 million, exclusive of the Zero Coupons. The Company has a variety of funding sources available to it, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements, and availability of the $5.0 billion Facility. Management believes that the Company’s liquidity position, asset portfolio, and continued strong operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Revolving Credit Facility and Letter of Credit Facility  Borrowings under the $5.0 billion Facility bear interest, at the Company’s election, at (i) the London Interbank Offered Rate (LIBOR) plus a margin ranging from 1.25% to 2.50%, based on the Company’s credit rating, or (ii) the greatest of (a) the JPMorgan Chase Bank, N.A. prime rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) one-month LIBOR plus 1%, plus, in each case, an applicable margin ranging from 0.25% to 1.50%.

Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments as discussed in Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, are guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and are secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries.

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (LOC Facility). In the third quarter of 2012, the Company terminated the LOC Facility.

Financial Covenants  The $5.0 billion Facility contains various customary covenants with which Anadarko must comply, including, but not limited to, limitations on incurrence of indebtedness, liens on assets, and asset sales. Anadarko is also required to maintain, at the end of each quarter, (i) a Consolidated Leverage Ratio of no more than 4.5 to 1.0 (relative to Consolidated EBITDAX for the most recent period of four calendar quarters), (ii) a ratio of Current Assets to Current Liabilities of no less than 1.0 to 1.0, and (iii) a Collateral Coverage Ratio of no less than 1.75 to 1.0, in each case, as defined in the $5.0 billion Facility. The Collateral Coverage Ratio is the ratio of an annually redetermined value of pledged assets to outstanding loans under the $5.0 billion Facility. Additionally, to borrow from the $5.0 billion Facility, the Collateral Coverage Ratio must be no less than 1.75 to 1.0 after giving pro forma effect to the requested borrowing. At December 31, 2012, the Company was in compliance with applicable covenants, and there were no restrictions on its ability to utilize the $5.0 billion Facility.

 

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The covenants contained in certain of the Company’s credit agreements provide for a maximum debt-to-capitalization ratio of 67%. The covenants do not specifically restrict the payment of dividends; however, the impact of dividends paid on the Company’s debt-to-capitalization ratio must be considered in order to ensure covenant compliance. At December 31, 2012, Anadarko was in compliance with all financial covenants.

Zero-Coupon Notes  In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the Zero Coupons. The Zero Coupons mature in October 2036 and have an aggregate principal amount due at maturity of $2.4 billion, reflecting a yield to maturity of 5.24%. The holder has the right to cause the Company to repay an amount up to the then-accreted value of the outstanding Zero Coupons in October of each year. The accreted value of the outstanding Zero Coupons was $690 million at December 31, 2012, and will be $718 million in October 2013 (the next potential put date).

The Company considers its cash-flow-generating capacity and access to additional liquidity sufficient to continue to satisfy the Company’s debt-service and other obligations, including the potential early repayment of the outstanding Zero Coupons.

WES Funding Sources  Anadarko’s consolidated subsidiary, WES, uses cash flows from operations to fund ongoing operations (including capital investments in the ordinary course of business), service its debt, and make distributions to its equity holders. As needed, WES supplements cash generated from its operating activities with proceeds from debt or equity issuances or borrowings under its five-year, $800 million senior unsecured revolving credit facility maturing in March 2016 (RCF).

Borrowings under the RCF bear interest at (i) LIBOR plus an applicable margin ranging from 1.30% to 1.90%, or (ii) the greatest of (a) the Wells Fargo Bank, National Association prime rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) one-month LIBOR plus 1%, plus, in each case, an applicable margin ranging from 0.30% to 0.90%. At December 31, 2012, WES was in compliance with all covenants contained in the RCF, had no outstanding borrowings under the RCF, and had all $800 million of RCF borrowing capacity available. See Financing Activities below.

Insurance Coverage and Other Indemnities  Anadarko maintains property and casualty insurance that includes coverage for physical damage to the Company’s properties, blowout/control of a well, restoration and redrill, sudden and accidental pollution, third-party liability, workers’ compensation and employers’ liability, and other risks. Anadarko’s insurance coverage includes deductibles that must be met prior to recovery. Additionally, the Company’s insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect the Company against liability or loss from all potential consequences and damages.

The Company’s current insurance coverage, which was obtained subsequent to the Deepwater Horizon events, includes physical damage to Anadarko’s properties on a replacement cost basis; $750 million for an offshore blowout/control of a well, restoration and redrill, and pollution from an offshore blowout ($75 million for onshore); $275 million for aircraft liability; and $675 million for third-party liabilities (including sudden and accidental pollution). The Company’s total limit for the negative environmental impacts of an offshore blowout is approximately $1.425 billion (which is reduced proportionally to the Company’s participating interest in a venture except for the $750 million portion dealing with an offshore blowout, which does not reduce below a 50% participating interest subject to certain reporting requirements). There is currently no coverage for loss of production income from any facilities or for physical damage to the Company’s properties, blowout/control of a well, or restoration and redrill to the extent these items result from the effects of a named windstorm.

Anadarko’s property and casualty insurance policies renew in June of each year. At the next renewals scheduled for June 2013, the Company may not be able to secure similar coverage for the same costs, if at all. Future insurance coverage costs for the oil and gas industry could increase and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that the Company considers economically acceptable.

 

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The Company’s service agreements, including drilling contracts, generally indemnify Anadarko for injuries and death to employees of the service provider and subcontractors hired by the service provider as well as for property damage suffered by the service provider and its contractors. Also, these service agreements generally indemnify Anadarko for pollution originating from the equipment of any contractors or subcontractors hired by the service provider.

Following is a discussion of significant sources and uses of cash flows for the three-year period ended December 31, 2012. Forward-looking information related to the Company’s liquidity and capital resources is discussed in Outlook that follows.

Sources of Cash

Operating Activities  Anadarko’s cash flows from operating activities in 2012 was $8.3 billion compared to $2.5 billion in 2011 and $5.2 billion in 2010. Cash flows from operating activities for 2012 increased year over year primarily due to the $4.0 billion payment to BP related to the Settlement Agreement in 2011, $1.0 billion collected in 2012 associated with the Algeria exceptional profits tax receivable, higher sales volumes, and the favorable impact of changes in working capital items, partially offset by lower average NGLs and natural-gas prices. Cash flows from operating activities for 2011 decreased year over year primarily due to the $4.0 billion payment to BP, lower natural-gas prices, increased operating expenses primarily due to other taxes (which increased as a result of higher sales volumes and crude-oil prices), and the unfavorable impact of changes in working capital items. These decreases were partially offset by higher crude-oil and NGLs prices and higher sales volumes.

One of the primary sources of variability in the Company’s cash flows from operating activities is fluctuation in commodity prices, which Anadarko partially mitigates by entering into commodity derivatives. Sales-volume changes also impact cash flow, but have not been as volatile as commodity prices. Anadarko’s long-term cash flows from operating activities is dependent on commodity prices, sales volumes, costs required for continued operations, and debt service.

Investing Activities  Anadarko received pretax sales proceeds related to property divestiture transactions of $657 million in 2012, $555 million in 2011, and $70 million in 2010.

Financing Activities  During 2012, Anadarko’s consolidated subsidiary, WES, borrowed $374 million under its RCF, primarily to fund the acquisition of certain midstream assets from Anadarko. Also during 2012, WES completed its public offering of $670 million aggregate principal amount of 4.000% Senior Notes due 2022 and issued five million common units to the public, raising net proceeds of $212 million. Proceeds from these public offerings were used to repay outstanding RCF borrowings and for other general partnership purposes, including the funding of capital expenditures.

In December 2012, WGP completed its IPO of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit, for net proceeds of $411 million. The proceeds will be used for general partnership purposes, including the funding of WES capital expenditures.

During 2011, Anadarko borrowed $2.5 billion under the $5.0 billion Facility to fund a portion of the $4.0 billion payment to BP associated with the Settlement Agreement (see Deepwater Horizon Settlement Costs below). In 2011, WES borrowed $320 million under its RCF primarily to fund a third-party asset acquisition and $250 million under its RCF to repay the senior unsecured term loan (Term Loan) as discussed in Uses of Cash. Also during 2011, WES issued approximately 10 million common units to the public, raising net proceeds of $328 million, which were used to repay outstanding RCF borrowings and for other general partnership purposes. In addition, during 2011, WES completed a public offering of $500 million aggregate principal amount of 5.375% Senior Notes due 2021, with net proceeds from the offering used to repay amounts then outstanding under its RCF.

 

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During 2010, the Company received net proceeds of $2.7 billion related to the issuance of $2.8 billion in aggregate principal amount of senior notes and used the net proceeds, combined with cash on hand, to redeem $3.0 billion aggregate principal amount of 2011 and 2012 debt maturities. See Uses of Cash for further information about debt repayments.

During 2010, WES borrowed a total of $670 million under its Term Loan and RCF primarily to fund the acquisition of certain midstream assets from Anadarko. WES also issued approximately 13 million common units in two 2010 public offerings, realizing net proceeds of $338 million, which were used to repay a portion of outstanding RCF borrowings.

Uses of Cash

Anadarko invests significant capital to develop, acquire, and explore for oil and natural-gas resources and to expand its midstream infrastructure, and also utilizes cash to fund ongoing operating costs, capital contributions to equity subsidiaries, debt repayments, and distributions to its shareholders.

Capital Expenditures  The following table presents the Company’s capital expenditures by category:

 

                                                  
millions   2012     2011     2010  

Property acquisitions

     

Exploration

  $ 239     $ 647     $ 519  

Development

                22  

Exploration

    2,064       1,469       1,278  

Development

    4,064       3,525       3,267  
 

 

 

   

 

 

   

 

 

 

Total oil and gas costs incurred (1)

    6,367       5,641       5,086  

Less corporate acquisitions and non-cash property exchanges

    (32     (17     (37

Less asset retirement costs

    (98     (148     (86

Less geological and geophysical, exploration overhead, delay rentals expenses, and other expenses

    (401     (450     (291
 

 

 

   

 

 

   

 

 

 

Total oil and gas capital expenditures

    5,836       5,026       4,672  

Gathering, processing, and marketing and other (2)

    1,475       1,527       497  
 

 

 

   

 

 

   

 

 

 

Total capital expenditures (1)

  $ 7,311     $ 6,553     $ 5,169  
 

 

 

   

 

 

   

 

 

 

 

(1) 

Oil and gas costs incurred represent costs related to finding and developing oil and gas reserves. Capital expenditures represent additions to property and equipment excluding corporate acquisitions, property exchanges, and asset retirement costs. Capital expenditures and costs incurred are presented on an accrual basis. Additions to properties and equipment and dry hole costs on the Consolidated Statements of Cash Flows include certain adjustments that give effect to the timing of actual cash payments in order to provide a cash-basis presentation.

 

(2) 

Includes WES capital expenditures of $529 million in 2012, $439 million in 2011, and $81 million in 2010.

The Company’s capital spending increased 12% for the year ended December 31, 2012, primarily due to increased exploration drilling onshore and offshore United States, and in East and West Africa; increased development drilling onshore United States; construction costs related to the development of the Lucius project located in the Gulf of Mexico; and higher expenditures for additional capital projects at domestic onshore plants and gathering systems. These increases were partially offset by lower exploration property acquisition costs, primarily onshore United States, and 2011 midstream asset acquisitions. In May 2011, Anadarko increased its ownership interest in the Wattenberg Plant to 100% by acquiring an additional 93% interest for $576 million. Also, in February 2011, WES acquired a third-party natural-gas processing plant and related gathering systems, located in the Rocky Mountains area, for $302 million.

In the third quarter of 2012, the Company entered into a carried-interest arrangement that requires a third-party partner to fund $556 million of Anadarko’s capital costs to earn a 7.2% working interest in the Lucius development, located in the Gulf of Mexico. The amount of the carry obligation represents 100% of the Company’s expected future capital costs through first production. The funding obligation is expected to be complete by year-end 2014. At December 31, 2012, $179 million of the $556 million obligation had been funded.

 

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The Company’s capital spending increased 27% for the year ended December 31, 2011, primarily due to the 2011 midstream asset acquisitions discussed above. The increase to capital expenditures was also due to increased development drilling costs of $258 million primarily related to onshore U.S. properties and higher exploration expenditures of $191 million primarily resulting from exploration drilling in Ghana.

In the first quarter of 2011, the Company entered into a carried-interest arrangement that requires a third-party partner to fund approximately $1.6 billion of Anadarko’s future capital costs in the Eagleford shale, located in South Texas, to earn a one-third interest in Anadarko’s Eagleford shale assets. The third-party funding is expected to cover 90% of Anadarko’s future capital costs in the basin until the carry is fully funded, which is expected to occur by year-end 2013. At December 31, 2012, $1.2 billion of the $1.6 billion obligation had been funded.

Deepwater Horizon Settlement Costs  In October 2011, the Company and BP entered into the Settlement Agreement related to the Deepwater Horizon events. The Company paid $4.0 billion and transferred its interest in the Macondo well and Lease to BP. Refer to Note 17—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.

Pension Contributions  During 2012, the Company made contributions of $101 million to its funded pension plans, $6 million to its unfunded pension plans, and $19 million to its unfunded other postretirement benefit plans. The decrease in contributions to the funded pension plans in 2012 resulted from revised discount rates used for funding purposes. The Company expects to contribute approximately $81 million to its funded pension plans, approximately $45 million to its unfunded pension plans, and approximately $16 million to its unfunded other postretirement benefit plans in 2013.

During 2011, the Company made contributions of $301 million to its funded pension plans, $10 million to its unfunded pension plans, and $17 million to its unfunded other postretirement benefit plans. The increase in contributions to the funded pension plans during 2011 resulted from lower discount rates compared to the prior measurement period, which increased the pension liability and the corresponding funding target.

Debt Retirements and Repayments  During 2012, the Company repaid the entire $2.5 billion of borrowings under its $5.0 billion Facility, and retired $131 million of 6.125% Senior Notes that matured in March 2012 and $39 million of 5.000% Senior Notes that matured in October 2012. In addition, WES repaid $374 million of borrowings under its RCF.

During 2011, WES repaid $619 million of borrowings under its RCF and a $250 million Term Loan primarily from proceeds from public debt and equity offerings, as discussed in Sources of Cash. In addition, the Company repaid $285 million principal amount of 6.875% Senior Notes that matured in September 2011.

In 2010, the Company used $1.6 billion to repay the Midstream Subsidiary Note and $1.5 billion, including $86 million for early-tender premiums, to redeem senior notes scheduled to mature in 2011 and 2012. The repayments were funded with proceeds from new borrowings, as well as cash on hand. Also in 2010, WES repaid $371 million outstanding under its RCF primarily from proceeds related to its public offerings discussed in Sources of Cash. In connection with entering into the $5.0 billion Facility in 2010, the Company paid upfront underwriting, structuring, arrangement, and other costs totaling $172 million.

For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity, and interest rates, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Common Stock Dividends and Distributions to Noncontrolling Interest Owners  Anadarko paid dividends to its common stockholders (nine cents per share per quarter) of $181 million in 2012, $181 million in 2011, and $180 million in 2010. Anadarko has paid a dividend to its common stockholders quarterly since becoming an independent public company in 1986. The amount of future dividends paid to Anadarko common stockholders will be determined by the Board of Directors on a quarterly basis and will depend on earnings, financial conditions, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors.

 

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WES distributed to its unitholders, other than Anadarko, an aggregate of $100 million in 2012, $72 million in 2011, and $42 million in 2010. WES has made quarterly distributions to its unitholders since its IPO in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.52 per common unit for the fourth quarter of 2012.

WGP has declared a prorated cash distribution of $0.03587 per unit for the fourth quarter of 2012. The distribution is the first declared by WGP and corresponds to a per-unit quarterly distribution of $0.165.

Other  During 2011, the Company and its partners in the Jubilee project in Ghana purchased the FPSO. The Company’s cash contribution was $108 million.

Outlook

The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company plans to allocate approximately 70% of its 2013 capital spending to development activities, 20% to exploration activities, and 10% to gas-gathering and processing activities and other business activities. The Company expects its 2013 capital spending by area to be approximately 60% for the U.S. onshore region and Alaska, 15% for the Gulf of Mexico, 15% for International, and 10% for Midstream and other.

Anadarko believes that its cash on hand and expected level of operating cash flows will be sufficient to fund the Company’s projected operational and capital programs for 2013, while continuing to meet its other obligations. The Company’s cash on hand is available for use and could be supplemented, as needed, with available borrowing capacity under the $5.0 billion Facility. The Company currently does not consider European sovereign debt events to pose significant risk to its ability to access available borrowing capacity under the $5.0 billion Facility. The Company may also enter into carried-interest arrangements with third parties to fund certain capital expenditures and asset divestitures to supplement cash flow.

The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions. In order to reduce commodity-price risk and increase the predictability of 2013 cash flows, Anadarko entered into strategic derivative positions, which cover a portion of its anticipated natural-gas and crude-oil sales volumes for 2013. For details of derivative positions at December 31, 2012, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Off-Balance-Sheet Arrangements

Anadarko may enter into off-balance-sheet arrangements and transactions that can give rise to material off-balance-sheet obligations. The Company’s material off-balance-sheet arrangements and transactions include operating lease arrangements and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Anadarko’s liquidity or availability of or requirements for capital resources. See Obligations and Commitments for more information regarding off-balance-sheet arrangements.

 

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Obligations and Commitments

The following is a summary of the Company’s obligations at December 31, 2012:

 

                                                                                                        
    Obligations by Period (1)  
millions   2013     2014-2015     2016-2017     2018 and
beyond
    Total  

Total debt

         

Principal—long-term borrowings (2)

  $     $ 775     $ 3,750     $ 10,427     $ 14,952  

Investee entities’ debt (3)

                      2,853       2,853  

Interest on borrowings

    844       1,603       1,451       7,604       11,502  

Investee entities’ interest (3)

    38       89       141       2,990       3,258  

Operating leases

         

Drilling rig commitments

    706       1,596       825       258       3,385   

Production platforms

    44       107       68       135       354  

Other

    67       89       55       49       260  

Asset retirement obligations

    298       466       202       919       1,885  

Midstream and marketing activities

    629       1,573       1,414       2,722       6,338  

Oil and gas activities

    1,021       950       239       212       2,422  

Derivative liabilities (4)

    7       823       377             1,207  

Uncertain tax positions, interest, and penalties (5)

    56       7       11             74  

Environmental liabilities

    17       14       4       46       81  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 3,727     $ 8,092     $ 8,537     $ 28,215     $ 48,571  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

This table does not include the Company’s pension or postretirement benefit obligations. See Note 22—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

(2) 

Includes the fully accreted principal amount of the Zero Coupons of $2.4 billion as coming due after 2016. While the Zero Coupons do not mature until 2036, the holder has the right to put the outstanding Zero Coupons to the Company each October at the then-accreted value. The Company could be required to repurchase the outstanding Zero Coupons at $718 million in October 2013 (the next potential put date).

 

(3) 

Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets in other long-term liabilities—other for all periods presented. These notes payable provide for a variable rate of interest, reset quarterly. Therefore, future interest payments presented in the table above are estimated using the forward LIBOR rate curve. Further, the above table does not reflect the preferred return that Anadarko receives on its investment in these entities, which is also LIBOR-based, with a lower margin than the margin on the associated notes payable. See Note 11—Equity-Method Investments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

(4) 

Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties. See Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

(5) 

See Note 19—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Operating Leases  Operating lease obligations include approximately $3.2 billion related to 12 offshore drilling vessels and $183 million related to certain contracts for onshore U.S. drilling rigs. Anadarko manages its access to rigs in order to execute its drilling strategy over the next several years. Lease payments associated with the drilling of exploratory wells and development wells, net of amounts billed to partners, will initially be capitalized as a component of oil and gas properties, and either depreciated or impaired in future periods or written off as exploration expense. See Note 17—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 drilling rigs.

 

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At December 31, 2012, the Company had $614 million in various commitments under non-cancelable operating lease agreements for production platforms and equipment, buildings, facilities, compressors, and aircraft.

For additional information, see Note 16—Commitments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Asset Retirement Obligations  Anadarko is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The majority of Anadarko’s asset retirement obligations (AROs) relate to the plugging of wells and the related abandonment of oil and gas properties. The Company’s AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

Midstream and Marketing Activities  Anadarko has entered into various processing, transportation, storage, and purchase agreements in order to access markets and provide flexibility for the sale of its natural gas, crude oil, and NGLs in certain areas.

Oil and Gas Activities  Anadarko has various long-term contractual commitments pertaining to exploration, development, and production activities that extend beyond 2012. The Company has work-related commitments for, among other things, drilling wells, obtaining and processing seismic, and fulfilling rig commitments. The preceding table includes long-term drilling and work-related commitments of $2.4 billion, comprised of approximately $1.5 billion related to the United States and $872 million related to international locations.

Environmental Liabilities  Anadarko is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. At December 31, 2012, the Company’s balance sheet included an $81 million liability for remediation and reclamation obligations. The Company continually monitors the liability recorded and ongoing remediation and reclamation processes, and believes the amount recorded is appropriate. For additional information on environmental issues, see Risk Factors under Item 1A of this Form 10-K.

For additional information on contracts, obligations, and arrangements the Company enters into from time to time, see Note 12—Derivative Instruments, Note 13—Debt and Interest Expense, Note 16—Commitments, and Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

CRITICAL ACCOUNTING ESTIMATES

In preparing financial statements in accordance with GAAP in the United States, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; goodwill; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment. The selection and development of these estimates is discussed with the Company’s Audit Committee.

 

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Oil and Gas Activities

Anadarko applies the successful efforts method of accounting to account for its oil and gas activities. Under this method, acquisition costs and the costs associated with drilling exploratory wells are capitalized pending the determination of proved oil and gas reserves. Exploration geological and geophysical costs and other costs of carrying properties such as delay rentals are expensed as incurred.

Acquisition Costs

Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities.

Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Significant undeveloped leasehold costs are assessed for impairment at a lease level or resource play (for example, the Greater Natural Buttes area in the Rockies), while leasehold acquisition costs associated with prospective areas that have limited or no previous exploratory drilling are generally assessed for impairment by major prospect area. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense.

Certain of the Company’s unproved property costs are associated with acquired properties to which proved developed producing reserves are also attributed. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by the Company’s continuing exploration and development programs.

Another portion of the Company’s unproved property costs are associated with the Land Grant acreage, where the Company owns mineral interests in perpetuity and plans to continue to explore and evaluate the acreage.

A change in the Company’s expected future plans for exploration and development could cause an impairment of the Company’s unproved property.

Exploratory Costs

Under the successful efforts method of accounting, exploratory costs associated with a well discovering hydrocarbons are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory drilling costs are expensed in that period. Therefore, at any point in time, the Company may have capitalized costs on its Consolidated Balance Sheets associated with exploratory wells that may be charged to exploration expense in future periods.

 

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Proved Reserves

Anadarko estimates its proved oil and gas reserves as defined by the SEC and the FASB. This definition includes crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, government regulations, etc. (i.e., at prices and costs as of the date the estimates are made). Prices include consideration of price changes provided only by contractual arrangements, and do not include adjustments based on expected future conditions.

The Company’s estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions, and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A and could result in property impairments.

Fair Value

The Company estimates fair value for derivatives, long-lived assets for impairment testing, reporting units for goodwill impairment testing when necessary, assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, guarantees, pension plan assets, initial measurements of AROs, and financial instruments that require fair-value disclosure, including cash and cash equivalents, accounts receivable, accounts payable, and debt. When the Company is required to measure fair value and there is not a market-observable price for the asset or liability or for a similar asset or liability, the Company utilizes the cost, income, or market valuation approaches depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk-adjusted discount rate. The market approach is based on management’s best assumptions regarding prices and other relevant information from market transactions involving comparable assets. Such evaluations involve significant judgment and the results are based on expected future events or conditions, such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, future net cash flows, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors, and are consistent with assumptions used in the Company’s business plans and investment decisions.

Business Combinations

Accounting for the acquisition of a business requires the assets and liabilities of the acquired business to be recorded at fair value. Deferred taxes are recorded for any differences between the fair value and the tax basis of acquired assets and liabilities. Any excess of the purchase price over the amounts assigned to the identifiable assets and liabilities is recorded as goodwill.

 

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Goodwill

At December 31, 2012, the Company had $5.5 billion of goodwill. The Company tests goodwill for impairment annually at October 1, or more frequently as circumstances dictate. The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If the Company concludes that fair value of the reporting unit more than likely exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary. If the qualitative assessment is not performed or indicates fair value of the reporting unit may be less than its carrying amount, the Company will compare the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill, and determine whether an impairment is necessary.

Because quoted market prices for the Company’s reporting units are not available, management must apply judgment in determining the estimated fair value of reporting units for purposes of performing goodwill impairment tests, when such tests are necessary. Management uses all available information to make these fair-value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets and observed for the oil and gas exploration and production reporting unit, and market multiples of earnings before interest, taxes, depreciation, and amortization (EBITDA) for the gathering and processing and transportation reporting units.

In estimating the fair value of its oil and gas exploration and production reporting unit, the Company assumes production profiles utilized in its estimation of reserves that are disclosed in the Company’s supplemental oil and gas disclosures, market prices based on the forward price curve for oil and gas at the test date (adjusted for location and quality differentials), capital and operating costs consistent with pricing and expected inflation rates, and discount rates that management believes a market participant would utilize based upon the risks inherent in Anadarko’s operations.

For the Company’s other gathering and processing, WES gathering and processing, and transportation reporting units, the Company estimates fair value by applying an estimated multiple to projected EBITDA. The Company considered observable transactions in the market and trading multiples for peers in determining an appropriate multiple to apply against the Company’s projected EBITDA for these reporting units.

A lower fair-value estimate in the future for any of these reporting units could result in impairment of goodwill. Factors that could trigger a lower fair-value estimate include sustained price declines, cost increases, regulatory or political environment changes, and other changes in market conditions such as decreased prices in market-based transactions for similar assets, as well as difficulty or potential delays in obtaining drilling permits or other unanticipated events.

Environmental Obligations and Other Contingencies

Management makes judgments and estimates when it establishes reserves for environmental remediation, litigation, and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability is incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company’s estimate of environmental-remediation costs, such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment, and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the Company’s estimates. The Company’s in-house legal counsel and environmental personnel regularly assess these contingent liabilities and, in certain circumstances, consult with third-party legal counsel or consultants to assist in forming the Company’s conclusion.

 

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Impairment of Long-Lived Assets

A long-lived asset other than unproved oil and gas property is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may be greater than its future net undiscounted cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value. The Company utilizes a variety of fair-value measurement techniques when market information for the same or similar assets does not exist.

Derivative Instruments

All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation techniques.

The Company’s derivative instruments are either exchange-traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data for similar instruments. Option fair values are measured using the Black-Scholes option-pricing model and verified by comparing a sample to market quotes for similar options. Unrealized gains or losses on derivatives are recorded to current earnings.

Income Taxes

The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the world. The Company has recognized deferred tax assets and liabilities for temporary differences, operating losses, and tax-credit carryforwards. The Company routinely assesses the realizability of its deferred tax assets and reduces such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment by management and are reviewed and adjusted routinely based on changes in facts and circumstances. Although management considers its tax accruals adequate, material changes in these accruals may occur in the future, based on the progress of ongoing tax audits, changes in legislation, and resolution of pending tax matters.

Benefit Plan Obligations

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Determination of the benefit obligations for the Company’s defined-benefit pension plans and postretirement benefit plans impacts the recorded amounts for such obligations on the balance sheet and the amount of benefit expense recorded to the income statement.

Accounting for pension and other postretirement benefit obligations involves many assumptions, the most significant of which are the discount rate used to measure the present value of plan benefit obligations, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future increases in compensation levels of participating employees, and the future level of health care costs (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.

The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan.

 

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Discount rate

Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. Discount-rate selection for measurements prior to December 31, 2011, was based on a similar cash-flow-matching analysis, although, instead of using a portfolio of select high-quality fixed-income securities to determine the effective settlement rate for a given plan obligation, the Company relied primarily on a published yield curve derived from market-observed yields for a universe of high-quality bonds. Both methods are acceptable and result in a discount-rate assumption that represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. However, the Company believes a discount rate reflecting yields for high-quality fixed-income securities better corresponds to the Company’s expectations as to the amount and timing of its benefit payments. The weighted-average discount-rate assumption (weighted by the plan-level benefit obligation) used to measure the Company’s December 31, 2012 pension benefit obligations was 3.50%, and the weighted-average discount-rate assumption for other postretirement benefit obligations, which are longer in duration, was 4.00%.

Expected long-term rate of return

The expected long-term rate of return on plan assets assumption was determined using the year-end 2012 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach, while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, and inflation. Returns on fixed-income securities are generally developed based on expected inflation, real bond yield, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset class returns are derived from their relationship to the equity and fixed income markets. Because the assumption reflects the Company’s expectation of average annualized return over a long time horizon, generally, it is not expected to be significantly revised from year to year, even though actual rates of investment return from year to year often experience significant volatility. To measure the net periodic pension cost for its funded pension plans, Anadarko assumed an average long-term rate of return of 7.0%.

Rate of compensation increases

The Company’s rate of compensation increases assumption is based on its long-term plans for compensation increases specific to covered employee groups and expected economic conditions. The assumed rate of salary increases includes the effects of merit increases, promotions, and general labor cost inflation within the oil and gas industry. The benefit obligations at December 31, 2012, reflect assumed rates of long-term compensation increases for active participants that vary by age group, with the resulting weighted-average rate (weighted by the plan-level benefit obligation) of 4.50%.

Health care cost trend rate

The health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. An 8.00% annual rate of increase in the per-capita cost of covered health care benefits was assumed for 2013, decreasing gradually to 5.00% in 2018 and beyond.

 

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency denominated payments and receipts. These risks can affect revenues and cash flows from operating, investing, and financing activities. The Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments utilized by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties in order to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

COMMODITY PRICE RISK  The Company’s most significant market risk relates to prices for natural gas, crude oil, and NGLs. Management expects energy prices to remain volatile and unpredictable. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant and sustained decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes  The Company had derivative instruments in place to reduce the price risk associated with future production of 433 Bcf of natural gas and 24 MMBbls of crude oil at December 31, 2012, with a net derivative asset position of $263 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $349 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $351 million. However, any realized derivative gain or loss would be substantially offset by the realized sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes  At December 31, 2012, the Company had a net derivative asset position of $18 million (gains of $34 million and losses of $16 million) on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

Algerian Settlement Volumes  Volumes received by Anadarko in connection with the resolution of the Algeria exceptional profits tax dispute will be valued at month-average dated Brent prices plus a Saharan Blend quality differential. See Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information. Generally, the market in this region is priced over a five-day period related to the bill-of-lading date. To the extent the Company’s realized sales price is greater than or less than the settlement value in the period of sale, the Company will record a gain or a loss, which is included in gains (losses) on divestitures and other, net on the Consolidated Statements of Income.

For additional information regarding the Company’s marketing and trading portfolio, see Marketing Activities under Items 1 and 2 of this Form 10-K.

 

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INTEREST-RATE RISK  Any borrowings under the $5.0 billion Facility and the WES RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt in the Company’s Consolidated Balance Sheets is subject to fixed interest rates. The Company’s $2.9 billion of LIBOR-based obligations, which are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities, give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. A 10% increase in LIBOR would not materially impact the Company’s interest cost on debt already outstanding, but would affect the fair value of outstanding debt.

At December 31, 2012, the Company had a net derivative liability position of $1.2 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would increase (decrease) the aggregate fair value of outstanding interest-rate swap agreements by approximately $115 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by actual borrowing costs associated with any future debt issuances or borrowings under its $5.0 billion Facility. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

FOREIGN-CURRENCY EXCHANGE-RATE RISK  Anadarko’s operating revenues are realized in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are U.S.-dollar-denominated. Exposure to foreign-currency risk generally arises in connection with project-specific contractual arrangements and other commitments. Near-term foreign-currency-denominated expenditures are primarily in euros, Brazilian reais, British pounds sterling, and Mozambican meticais. Management periodically enters into various risk-management transactions to mitigate a portion of its exposure to foreign-currency exchange-rate risk.

The Company has risk related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability for its 2008 divestiture of the Peregrino field offshore Brazil. At December 31, 2012, cash of $166 million was held in escrow. A 10% increase or decrease in the foreign-currency exchange rate would not materially impact the Company’s gain or loss related to foreign currency.

 

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Item 8.  Financial Statements and Supplementary Data

ANADARKO PETROLEUM CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page  

Report of Management

     89  

Management’s Assessment of Internal Control Over Financial Reporting

     89  

Reports of Independent Registered Public Accounting Firm

     90  

Consolidated Statements of Income, Three Years Ended December 31, 2012

     92  

Consolidated Statements of Comprehensive Income, Three Years Ended December 31, 2012

     93  

Consolidated Balance Sheets, December 31, 2012 and 2011

     94  

Consolidated Statements of Equity, Three Years Ended December 31, 2012

     95  

Consolidated Statements of Cash Flows, Three Years Ended December 31, 2012

     96  

Notes to Consolidated Financial Statements

     97  

Supplemental Quarterly Information

     148  

Supplemental Information on Oil and Gas Exploration and Production Activities

     149  

 

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ANADARKO PETROLEUM CORPORATION

REPORT OF MANAGEMENT

Management prepared, and is responsible for, the Consolidated Financial Statements and the other information appearing in this annual report. The Consolidated Financial Statements present fairly the Company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its Consolidated Financial Statements, the Company includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Company’s financial statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to KPMG LLP all of the Company’s financial records and related data, as well as the minutes of the stockholders’ and Directors’ meetings.

MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Anadarko’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. This assessment was based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2012, the Company’s internal control over financial reporting was effective based on those criteria.

KPMG LLP has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2012.

 

/s/ R. A. WALKER

R. A. Walker

President and Chief Executive Officer

 

/s/ ROBERT G. GWIN

Robert G. Gwin

Senior Vice President, Finance and Chief

Financial Officer

February 19, 2013

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Anadarko Petroleum Corporation:

We have audited Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Anadarko Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Anadarko Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated February 19, 2013 expressed an unqualified opinion on those consolidated financial statements.

 

/s/ KPMG LLP

Houston, Texas
February 19, 2013

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Anadarko Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ KPMG LLP

Houston, Texas
February 19, 2013

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

 

                                                  
    Years Ended December 31,  
millions except per-share amounts   2012     2011     2010  

Revenues and Other

     

Natural-gas sales

  $ 2,444     $ 3,300     $ 3,420  

Oil and condensate sales

    8,728       8,072       5,592  

Natural-gas liquids sales

    1,224       1,462       997  

Gathering, processing, and marketing sales

    911       1,048       833  

Gains (losses) on divestitures and other, net

    104       85       142  
 

 

 

   

 

 

   

 

 

 

Total

    13,411       13,967       10,984  
 

 

 

   

 

 

   

 

 

 

Costs and Expenses

     

Oil and gas operating

    976       993       830  

Oil and gas transportation and other

    955       891       816  

Exploration

    1,946       1,076       974  

Gathering, processing, and marketing

    763       791       615  

General and administrative

    1,246       1,060       967  

Depreciation, depletion, and amortization

    3,964       3,830       3,714  

Other taxes

    1,224       1,492       1,068  

Impairments

    389       1,774       216  

Algeria exceptional profits tax settlement

    (1,797            

Deepwater Horizon settlement and related costs

    18       3,930       15  
 

 

 

   

 

 

   

 

 

 

Total

    9,684       15,837       9,215  
 

 

 

   

 

 

   

 

 

 

Operating Income (Loss)

    3,727       (1,870     1,769  

Other (Income) Expense

     

Interest expense

    742       839       855  

(Gains) losses on derivatives, net

    (326     461       (608

Other (income) expense, net

    (254     254       (119
 

 

 

   

 

 

   

 

 

 

Total

    162       1,554       128  
 

 

 

   

 

 

   

 

 

 

Income (Loss) Before Income Taxes

    3,565       (3,424     1,641  

Income Tax Expense (Benefit)

    1,120       (856     820  
 

 

 

   

 

 

   

 

 

 

Net Income (Loss)

    2,445       (2,568     821  

Net Income Attributable to Noncontrolling Interests

    54       81       60  
 

 

 

   

 

 

   

 

 

 

Net Income (Loss) Attributable to Common Stockholders

  $ 2,391     $ (2,649   $ 761  
 

 

 

   

 

 

   

 

 

 

Per Common Share

     

Net income (loss) attributable to common stockholders—basic

  $ 4.76     $ (5.32   $ 1.53  

Net income (loss) attributable to common stockholders—diluted

  $ 4.74     $ (5.32   $ 1.52  

Average Number of Common Shares Outstanding—Basic

    500       498       495  
 

 

 

   

 

 

   

 

 

 

Average Number of Common Shares Outstanding—Diluted

    502       498       497  
 

 

 

   

 

 

   

 

 

 

Dividends (per Common Share)

  $ 0.36     $ 0.36     $ 0.36  

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

                                                  
    Years Ended December 31,  
millions   2012     2011     2010  

Net Income (Loss)

  $ 2,445     $ (2,568   $ 821  

Other Comprehensive Income (Loss), net of taxes

     

Reclassification of previously deferred derivative losses to net income (1)

    8       10       17  

Adjustments for pension and other postretirement plans

     

Net gain (loss) incurred during period (2)

    (99     (136     (91

Prior service credit (cost) incurred during period (3)

          7       (4

Amortization of net actuarial loss and prior service cost to net periodic benefit cost (4)

    63       56       41  
 

 

 

   

 

 

   

 

 

 

Total adjustments for pension and other postretirement plans

    (36     (73     (54
 

 

 

   

 

 

   

 

 

 

Total

    (28     (63     (37
 

 

 

   

 

 

   

 

 

 

Comprehensive Income (Loss)

    2,417       (2,631     784  

Comprehensive Income Attributable to Noncontrolling Interests

    54       81       60  
 

 

 

   

 

 

   

 

 

 

Comprehensive Income (Loss) Attributable to Common Stockholders

  $ 2,363     $ (2,712   $ 724  
 

 

 

   

 

 

   

 

 

 

 

(1)

Net of income tax benefit (expense) of $(4) million in 2012, $(5) million in 2011, and $(9) million in 2010.

 

(2)

Net of income tax benefit (expense) of $56 million in 2012, $77 million in 2011, and $52 million in 2010.

 

(3)

Net of income tax benefit (expense) of $(5) million in 2011 and $2 million in 2010.

 

(4)

Net of income tax benefit (expense) of $(32) million in 2012, $(31) million in 2011, and $(23) million in 2010.

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

 

                                 
    December 31,  
millions   2012     2011  

ASSETS

   

Current Assets

   

Cash and cash equivalents

  $ 2,471      $ 2,697  

Accounts receivable (net of allowance of $7 million and $6 million)

   

Customers

    1,473        1,269  

Others

    1,274        1,990  

Algeria exceptional profits tax settlement

    730         

Other current assets

    847        975  
 

 

 

   

 

 

 

Total

    6,795        6,931  
 

 

 

   

 

 

 

Properties and Equipment

   

Cost

    63,598        60,081  

Less accumulated depreciation, depletion, and amortization

    25,200        22,580  
 

 

 

   

 

 

 

Net properties and equipment

    38,398        37,501  

Other Assets

    1,716        1,516  

Goodwill and Other Intangible Assets

    5,680        5,831  
 

 

 

   

 

 

 

Total Assets

  $ 52,589      $ 51,779  
 

 

 

   

 

 

 

LIABILITIES AND EQUITY

   

Current Liabilities

   

Accounts payable

  $ 2,989      $ 3,299  

Accrued expenses

    1,005        1,430  

Current portion of long-term debt

           170  
 

 

 

   

 

 

 

Total

    3,994        4,899  
 

 

 

   

 

 

 

Long-term Debt

    13,269        15,060  

Other Long-term Liabilities

   

Deferred income taxes

    8,759        8,479  

Asset retirement obligations

    1,587        1,737  

Other

    3,098        2,621  
 

 

 

   

 

 

 

Total

    13,444        12,837  
 

 

 

   

 

 

 

Equity

   

Stockholders’ equity

   

Common stock, par value $0.10 per share

   

(1.0 billion shares authorized, 518.6 million and 516.0 million shares issued)

    51       51  

Paid-in capital

    8,230        7,851  

Retained earnings

    13,829        11,619  

Treasury stock (18.1 million and 17.6 million shares)

    (841     (804

Accumulated other comprehensive income (loss)

    (640     (612
 

 

 

   

 

 

 

Total Stockholders’ Equity

    20,629        18,105  

Noncontrolling interests

    1,253        878  
 

 

 

   

 

 

 

Total Equity

    21,882        18,983  
 

 

 

   

 

 

 

Total Liabilities and Equity

  $ 52,589      $ 51,779  
 

 

 

   

 

 

 

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

 

    Total Stockholders’ Equity              
    Common
Stock
    Paid-in
Capital
    Retained
Earnings
    Treasury
Stock
    Accumulated
Other
Comprehensive
Income (Loss)
    Non-
controlling
Interests
    Total
Equity
 

millions

         

Balance at December 31, 2009

  $ 50     $ 7,243     $ 13,868     $ (721   $ (512   $ 487     $ 20,415  

Net income (loss)

                761                   60       821  

Common stock issued

    1       253                               254  

Dividends—common

                (180                       (180

Repurchase of common stock

                      (42                 (42

Subsidiary equity transactions

                                  256       256  

Distributions to noncontrolling interest owners

                                  (48     (48

Reclassification of previously deferred derivative losses to net income

                            17             17  

Adjustments for pension and other postretirement plans

                            (54           (54
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2010

    51       7,496       14,449       (763     (549     755       21,439  

Net income (loss)

                (2,649                 81       (2,568

Common stock issued

          161                               161  

Dividends—common

                (181                       (181

Repurchase of common stock

                      (41                 (41

Subsidiary equity transactions (1)

          32                         269       301  

Conversion of subordinated limited partner units to common units (1) (2)

          162                         (162      

Distributions to noncontrolling interest owners

                                  (82     (82

Contributions from noncontrolling interest owners

                                  17       17  

Reclassification of previously deferred derivative losses to net income

                            10             10  

Adjustments for pension and other postretirement plans

                            (73           (73
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2011

    51       7,851       11,619       (804     (612     878       18,983  

Net income (loss)

                2,391                   54       2,445  

Common stock issued

          249                               249  

Dividends—common

                (181                       (181

Repurchase of common stock

                      (37                 (37

Subsidiary equity transactions (1)

          130                         417       547  

Distributions to noncontrolling interest owners

                                  (112     (112

Contributions from noncontrolling interest owners

                                  16       16  

Reclassification of previously deferred derivative losses to net income

                            8             8  

Adjustments for pension and other postretirement plans

                            (36           (36
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2012

  $ 51     $ 8,230     $ 13,829     $ (841   $ (640   $ 1,253     $ 21,882  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

The $130 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $2,521 million for the year ended December 31, 2012. The $194 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $(2,455) million for the year ended December 31, 2011.

(2) 

Includes $92 million of tax associated with subsidiary equity transactions that occurred prior to the conversion of subordinated limited partner units to common units.

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

                                                  
    Years Ended December 31,  
millions   2012     2011     2010  

Cash Flows from Operating Activities

     

Net income (loss)

  $ 2,445     $ (2,568   $ 821  

Adjustments to reconcile net income (loss) to net cash provided by

     

operating activities

     

Depreciation, depletion, and amortization

    3,964       3,830       3,714  

Deferred income taxes

    164       (1,461     (123

Dry hole expense and impairments of unproved properties

    1,544       625       682  

Impairments

    389       1,774       216  

(Gains) losses on divestitures, net

    71       (22     (29

Unrealized (gains) losses on derivatives, net

    377       616       (114

Other

    232       204       308  

Changes in assets and liabilities

     

Deepwater Horizon settlement and related costs

    24       (18      

Algeria exceptional profits tax settlement

    (791            

Tronox-related contingent loss

    (250     250       (95

(Increase) decrease in accounts receivable

    520       (993     (172

Increase (decrease) in accounts payable and accrued expenses

    (476     284       (157

Other items—net

    126       (16     196  
 

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) operating activities

    8,339       2,505       5,247  
 

 

 

   

 

 

   

 

 

 

Cash Flows from Investing Activities

     

Additions to properties and equipment and dry hole costs

    (7,242     (5,650     (5,008

Acquisition of midstream businesses

          (802      

Divestitures of properties and equipment and other assets

    657       555       70  

Other—net

    (284     (78     (26
 

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) investing activities

    (6,869     (5,975     (4,964
 

 

 

   

 

 

   

 

 

 

Cash Flows from Financing Activities

     

Borrowings, net of issuance costs

    1,042       3,551       3,198  

Repayments of debt

    (3,044     (1,154     (1,879

Repayment of midstream subsidiary note payable to a related party

                (1,599

Repayment of capital lease obligation

          (108      

Increase (decrease) in accounts payable, banks

    (69     149       7  

Dividends paid

    (181     (181     (180

Repurchase of common stock

    (37     (41     (42

Issuance of common stock, including tax benefit on stock option exercises

    103       30       107  

Sale of subsidiary units

    623       328       338  

Distributions to noncontrolling interest owners

    (112     (82     (48

Contributions from noncontrolling interest owners

    16       17        

Other financing activities

          1       (24
 

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

    (1,659     2,510       (122
 

 

 

   

 

 

   

 

 

 

Effect of Exchange Rate Changes on Cash

    (37     (23     (12
 

 

 

   

 

 

   

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

    (226     (983     149  

Cash and Cash Equivalents at Beginning of Period

    2,697       3,680       3,531  
 

 

 

   

 

 

   

 

 

 

Cash and Cash Equivalents at End of Period

  $ 2,471     $ 2,697     $ 3,680  
 

 

 

   

 

 

   

 

 

 

See accompanying Notes to Consolidated Financial Statements.

 

96


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

1.  Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and natural gas liquids (NGLs). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, crude oil, and NGLs. The Company also participates in the hard minerals business through its ownership of non-operated joint ventures and royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

Basis of Presentation  The Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States. The Consolidated Financial Statements include the accounts of Anadarko and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Anadarko has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Certain prior-period amounts have been reclassified to conform to the current-year presentation.

Use of Estimates  The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires that management make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; goodwill; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value  Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:

Level 1—Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3—Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).

 

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Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

1.  Summary of Significant Accounting Policies (Continued)

 

In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value.

In arriving at fair-value estimates, the Company utilizes the most observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. For Anadarko, recurring fair-value measurements are performed for interest-rate derivatives, commodity derivatives, and investments in trading securities.

The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 13—Debt and Interest Expense, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.

Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, asset retirement obligations, exit or disposal costs, and capital lease assets where the present value of lease payments is greater than the fair value of the leased asset.

Revenues  The Company’s natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. Oil and condensate are sold primarily to marketers, gatherers, and refiners. NGLs are sold primarily to direct end-users, refiners, and marketers.

The Company recognizes sales revenues for natural gas, oil and condensate, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Anadarko provides gathering, processing, treating, and transporting services pursuant to a variety of contracts. Under these arrangements, the Company receives fees, or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time the services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.

Marketing margins related to the Company’s production are included in natural-gas sales, oil and condensate sales, and NGLs sales. Marketing margins related to sales of commodities purchased from third parties, as well as realized and unrealized gains and losses on derivatives related to such marketing activities are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.

The Company enters into buy/sell arrangements related to the transportation of a portion of its crude-oil production. Under these arrangements, barrels are sold to a third-party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These transactions are reported on a net basis and included in oil and gas transportation in the Consolidated Statements of Income.

 

98


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

1.  Summary of Significant Accounting Policies (Continued)

 

Cash Equivalents  The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Accounts Receivable and Allowance for Uncollectible Accounts  The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based on these analyses, the Company may require a standby letter of credit or a financial guarantee. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued.

Inventories  Commodity inventories are stated at the lower of average cost or market.

Properties and Equipment  Properties and equipment are stated at cost less accumulated depreciation, depletion, and amortization expense (DD&A). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gain or loss is recognized in gains (losses) on divestitures and other, net.

Oil and Gas Properties  The Company applies the successful efforts method of accounting for oil and gas properties. Exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are charged against earnings as incurred. If an exploratory well provides evidence to justify potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally in deepwater and international locations) depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average lease terms, at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense in the Consolidated Statements of Income.

 

99


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

1.  Summary of Significant Accounting Policies (Continued)

 

Capitalized Interest  For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties, significant exploration and development projects that have not commenced production, and significant midstream development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 13—Debt and Interest Expense.

Asset Retirement Obligations  Asset retirement obligations (AROs) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. See Note 8—Asset Retirement Obligations.

Impairments  Properties and equipment are reviewed for impairment at the lowest level for which identifiable cash flows are independent of cash flows from other assets, and when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed on the impairment unit. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. See Note 6—Impairments.

Depreciation, Depletion, and Amortization  Costs of drilling and equipping successful wells, costs to construct or acquire facilities other than offshore platforms, associated asset retirement costs, and capital lease assets used in oil and gas activities are depreciated using the unit-of-production (UOP) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the UOP method. All other properties are stated at historical acquisition cost, net of impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 40 years for buildings, and up to 47 years for gathering facilities.

Goodwill and Other Intangible Assets  Goodwill is subject to annual impairment testing at October 1 (or more frequent testing as circumstances dictate). Anadarko has allocated goodwill to the following reporting units: oil and gas exploration and production, other gathering and processing, Western Gas Partners, LP (WES) gathering and processing, and transportation. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures. See Note 9—Goodwill and Other Intangible Assets.

Other intangible assets represent contractual rights obtained in connection with business combinations that had favorable contractual terms relative to market at the acquisition date. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment whenever impairment indicators are present. See Note 9—Goodwill and Other Intangible Assets.

 

100


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

1.  Summary of Significant Accounting Policies (Continued)

 

Derivative Instruments  Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risk. Derivatives are carried on the balance sheet at fair value and are included in other current assets, other assets, accrued expenses, or other long-term liabilities, depending on the derivative position and the expected timing of settlement unless they satisfy the normal purchases and sales exception criteria. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis.

Realized and unrealized gains and losses on derivative instruments are recognized on a current basis in the Consolidated Statements of Income. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 12—Derivative Instruments.

Accounts Payable  Accounts payable included liabilities of $339 million at December 31, 2012, and $408 million at December 31, 2011, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in applicable bank accounts. Changes in these liabilities are reflected in cash flows from financing activities.

Legal Contingencies  The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 17—Contingencies.

Environmental Contingencies  The Company is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 17—Contingencies.

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans  The Company measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and the health care cost trend rate (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.

The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. See Note 22—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

1.  Summary of Significant Accounting Policies (Continued)

 

Noncontrolling Interests  Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 10Noncontrolling Interests.

Income Taxes  The Company files various U.S. federal, state, and foreign income tax returns. Deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). See Note 19—Income Taxes.

Share-Based Compensation  The Company accounts for share-based compensation at fair value. The Company grants equity-classified awards including stock options and non-vested equity shares (restricted stock awards and units). The Company may also grant equity-classified and liability-classified awards based on a comparison of the Company’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies (performance units).

The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of Anadarko common stock. For other share-based compensation awards, fair value is determined using a Monte Carlo simulation or discounted cash flow methodology.

The Company records compensation cost, net of estimated forfeitures, for share-based compensation awards over the requisite service period using the straight-line method. An adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the awards. For equity-classified share-based compensation awards, expense is recognized over the requisite performance period based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized over the requisite performance period for those awards expected to ultimately be paid. The amount of expense reported is adjusted throughout the performance period for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid. See Note 15—Share-Based Compensation.

Earnings Per Share  The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and performance-based stock awards, if the inclusion of these items is dilutive. See Note 14—Stockholders’ Equity.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

2.  Acquisitions

In May 2011, Anadarko 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. Anadarko operates and owns a 100% interest in the Wattenberg Plant. In February 2011, 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.

These acquisitions, along with future expansion plans, align Anadarko’s natural-gas processing capacity with the Company’s anticipated production growth in the Rocky Mountains Region (Rockies). In addition, these acquisitions position the Company to improve field recoveries and realize operational cost efficiencies.

The Wattenberg Plant and Platte Valley acquisitions constitute business combinations and were accounted for using the acquisition method. Preliminary fair-value measurements of assets acquired and liabilities assumed were finalized in the first quarter of 2012, and were equal to the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2011. The following summarizes the fair value of assets acquired and liabilities assumed at the acquisition dates:

 

millions      

Properties and equipment

  $ 298  

Intangible assets

    165  

Deferred income taxes

    31  

Other assets

    4  

Other liabilities

    (21

Goodwill

    362  
 

 

 

 

Total assets acquired and liabilities assumed

    839  
 

 

 

 

Less fair value of Anadarko’s pre-acquisition 7% equity interest in the Wattenberg Plant

    37  
 

 

 

 

Acquisition of midstream businesses

    802  
 

 

 

 

Loss on Anadarko’s preexisting contracts with the previous Wattenberg Plant owner

    76  
 

 

 

 

Total consideration paid

  $             878  
 

 

 

 

Fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. Liabilities assumed include asset retirement obligations existing at the date of acquisition, and are valued consistent with the Company’s policy for estimating such obligations.

Assets acquired and liabilities assumed are included within the midstream reporting segment, except for $335 million of goodwill and a portion of the related deferred tax asset recognized in connection with the Wattenberg Plant acquisition, which are included in the oil and gas exploration and production reporting segment. Goodwill of $469 million related to the Wattenberg Plant acquisition is amortizable for tax purposes.

Goodwill from these acquisitions is included in the oil and gas exploration and production reporting segment and the midstream reporting segment based on the increase in fair value to each of the respective reporting segments. The increase in fair value to these reporting segments is derived from improved NGLs volume retention from equity production and the alignment of Company-controlled natural-gas processing capacity with future production growth plans in the Rockies. See Note 9—Goodwill and Other Intangible Assets.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

2.  Acquisitions (Continued)

 

Prior to the Wattenberg Plant acquisition, the Company was party to natural-gas processing contracts with the previous Wattenberg Plant owner. As a result of the acquisition, these preexisting contracts were effectively eliminated, for purposes of consolidated financial reporting, causing the Company to recognize a $76 million loss, which is included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statement of Income for the year ended December 31, 2011. This loss represents the aggregate amount by which the contracts were unfavorable as compared to market transactions for the same or similar services at the date the Company acquired the Wattenberg Plant.

The Company also recognized a gain of $21 million from the acquisition-date fair-value remeasurement of its pre-acquisition 7% equity interest in the Wattenberg Plant. The gain is included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statement of Income for the year ended December 31, 2011.

Results of operations attributable to the Wattenberg Plant and Platte Valley acquisitions are included in the Company’s Consolidated Statements of Income from the dates acquired. The amounts of revenue and earnings included in the Company’s Consolidated Statement of Income for the year ended December 31, 2011, and the amounts of revenue and earnings that would have been recognized had the acquisitions occurred on January 1, 2010, are not material to the Company’s Consolidated Statements of Income.

3.  Divestitures and Assets Held for Sale

Divestitures  In 2012, proceeds from divestitures of $433 million were primarily related to U.S. oil and gas properties and net losses on divestitures of $43 million were primarily related to oil and gas properties in Indonesia. In 2011, the Company received $419 million related to contingent consideration received for the 2008 divestiture of its interest in the Peregrino field offshore Brazil. In 2010, proceeds from divestitures of $70 million and net gains on divestitures of $29 million were primarily related to U.S. onshore oil and gas properties.

Assets Held for Sale  In 2011, the Company began marketing certain domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect operating activities and capital investment to other areas. These assets were remeasured to their fair value, estimated using Level 3 fair-value inputs, with resulting losses of $390 million related to oil and gas exploration and production reporting segment properties and $32 million related to midstream reporting segment properties. On the Company’s Consolidated Balance Sheet at December 31, 2011, amounts associated with assets held for sale included $320 million in net properties and equipment, $38 million in goodwill and other intangible assets, and $75 million in other long-term liabilities.

In 2012, the Company recognized losses on assets held for sale of $28 million primarily related to certain oil and gas exploration and production reporting segment properties. Gains and losses related to assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. At December 31, 2012, the remaining balances of assets and liabilities associated with assets held for sale were not material.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

4.  Inventories

The following summarizes the major classes of inventories, included in other current assets, at December 31:

 

                                     
millions   2012     2011  

Crude oil

  $ 91     $ 103  

Natural gas

    48       49  

NGLs

    37       59  
 

 

 

   

 

 

 

Total

  $ 176     $ 211  
 

 

 

   

 

 

 

5.  Properties and Equipment

The following summarizes the cost of properties and equipment by segment at December 31:

 

                                 
millions   2012     2011  

Oil and gas exploration and production (1)

  $ 55,095     $ 52,711  

Midstream

    6,032       4,837  

Marketing

    94       9  

Other

    2,377       2,524  
 

 

 

   

 

 

 

Total

  $ 63,598     $ 60,081  
 

 

 

   

 

 

 

 

(1)

Includes costs associated with unproved properties of $7.1 billion at December 31, 2012, and $8.3 billion at December 31, 2011.

6.  Impairments

The following summarizes impairments by segment for the years ended December 31:

 

                                            
millions   2012     2011     2010  

Oil and gas exploration and production

     

Long-lived assets held for use

     

U.S. onshore properties

  $ 259     $ 1,063     $ 31  

Gulf of Mexico properties

    104       162       114  

Cost-method investment

    13       91       61  

Midstream

     

Long-lived assets held for use

    13       458       2  

Marketing

     

Long-lived assets held for use

                8  
 

 

 

   

 

 

   

 

 

 

Impairments

  $ 389     $ 1,774     $ 216  
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

6.  Impairments (Continued)

 

In 2012, U.S. onshore and midstream properties were impaired primarily due to lower natural-gas prices. The Gulf of Mexico properties were impaired primarily as a result of downward reserves revisions for a property that was near the end of its economic life. In 2011, U.S. onshore and midstream properties were impaired primarily due to decreases in natural-gas prices, and Gulf of Mexico properties were impaired due to declines in estimated recoverable reserves. In 2010, the impairment of Gulf of Mexico properties related to a production platform that remains idle with no immediate plan for use, and for which a limited market exists. Impairments of the Company’s Venezuelan cost-method investment were due to declines in estimated recoverable reserves in 2012, 2011, and 2010, and lower crude-oil prices in 2012.

The following summarizes the aggregate fair values of the above-described assets, by major category and input level within the fair-value hierarchy, at the respective dates of impairment:

 

                                                                                   
millions                        
2012   Level 1     Level 2 (1)     Level 3 (1)     Total  

Long-lived assets held for use

  $      $      $ 103     $ 103  

Cost-method investment

                34       34  

2011

       

Long-lived assets held for use

  $      $ 187     $ 739     $ 926  

Cost-method investment

                39       39  

 

(1) 

The income approach was used to measure fair value.

Impairments of Unproved Properties  Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. In 2012, the Company recognized a $721 million impairment of unproved Powder River coalbed methane properties primarily resulting from lower natural-gas prices. Also in 2012, the Company recognized a $124 million impairment of an unproved Gulf of Mexico natural-gas property that the Company does not plan to pursue under the forecasted natural-gas price environment.

7.  Suspended Exploratory Well Costs

The following summarizes the changes in suspended exploratory well costs at December 31 for each of the last three years. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

 

                                                  
millions   2012     2011     2010  

Balance at January 1

  $ 1,353     $ 935     $ 579  

Additions pending the determination of proved reserves

    960       572       491  

Reclassifications to proved properties

    (129     (116     (106

Charges to exploration expense

    (122     (38     (29
 

 

 

   

 

 

   

 

 

 

Balance at December 31

  $ 2,062     $ 1,353     $ 935  
 

 

 

   

 

 

   

 

 

 

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

7.  Suspended Exploratory Well Costs (Continued)

 

The following summarizes an aging of suspended exploratory well costs by geographic area and the year the costs were suspended at December 31, 2012:

 

                                                                                    
          Year Costs Incurred  
millions   Total     2012(1)     2011     2010     2009 and
prior
 

United States—Onshore

  $ 136     $ 123     $ 3      $      $ 10  

United States—Offshore

    392       158        (5     61       178  

International

    1,534       636       396        314       188  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $ 2,062     $ 917     $ 394      $ 375     $ 376  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Excludes additions subsequently reclassified to proved properties within the same year.

Suspended exploratory well costs capitalized for a period greater than one year at December 31, 2012, after completion of drilling were associated with 22 projects, primarily located in Ghana, Brazil, the Gulf of Mexico, and Mozambique. Project costs suspended for longer than one year were primarily suspended pending the completion of economic evaluations including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well-test analysis, additional geological and geophysical data, development plan approval, and permitting. Management believes projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to these projects. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

8.  Asset Retirement Obligations

The majority of Anadarko’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties. The following provides a rollforward of the Company’s combined short- and long-term AROs. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement.

 

                                 
millions   2012     2011  

Carrying amount of asset retirement obligations at January 1

  $ 1,768     $ 1,571  

Liabilities incurred

    70       39  

Property dispositions

    (78     (4

Liabilities settled

    (89     (68

Accretion expense

    110       100  

Revisions in estimated liabilities

    104       130  
 

 

 

   

 

 

 

Carrying amount of asset retirement obligations at December 31 (1)

  $ 1,885     $ 1,768  
 

 

 

   

 

 

 

 

(1)

Short-term AROs of $298 million at December 31, 2012, and $31 million at December 31, 2011, were included in accrued expenses on the Company’s Consolidated Balance Sheets.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

9.  Goodwill and Other Intangible Assets

Goodwill  The Company completed its annual impairment assessment of goodwill during the fourth quarter of 2012, and the test indicated no impairment. At December 31, 2012, the Company had $5.5 billion of goodwill allocated to the following reporting units: $5.3 billion to oil and gas exploration and production, $87 million to other gathering and processing, $83 million to WES gathering and processing, and $5 million to transportation.

Significant declines in commodity prices, difficulty or potential delays in obtaining drilling permits, or other unanticipated events could result in further goodwill impairment tests in the near term, the results of which may have a material adverse impact on the Company’s results of operations.

Other Intangible Assets  Intangible assets and associated amortization expense were as follows:

 

                                                                                           
millions   Gross Carrying
      Amount      
    Accumulated
Amortization
    Net Carrying
Amount
    Amortization
Expense
 

December 31, 2012

       

Offshore platform leases

  $ 60     $ (36   $ 24     $ 3  

Customer contracts

    169       (5     164       3  
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 229     $ (41   $ 188     $ 6  
 

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

       

Offshore platform leases

  $ 60     $ (33   $ 27     $ 2  

Customer contracts

    165       (2     163       2  
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 225     $ (35   $ 190     $ 4  
 

 

 

   

 

 

   

 

 

   

 

 

 

Customer contract intangible assets are primarily related to the Wattenberg Plant acquisition. The contracts are included in the Company’s midstream reporting segment and are being amortized over 50 years. See Note 2—Acquisitions. The estimated aggregate amortization expense for intangible assets for the next five years is not expected to be material.

10.  Noncontrolling Interests

In December 2012, Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own Anadarko’s partnership interests in WES, completed its initial public offering (IPO) of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit, for net proceeds of $411 million. At December 31, 2012, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire general partner interest.

WES, a consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES issued approximately 5 million common units to the public raising net proceeds of $212 million in 2012, approximately 10 million common units were issued to the public raising net proceeds of $328 million in 2011, and approximately 13 million common units were issued to the public raising net proceeds of $338 million in 2010. At December 31, 2012, WGP’s ownership interest in WES consisted of a 46.2% limited partner interest, the entire 2.0% general partner interest, and all of the WES incentive distribution rights.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

11.  Equity-Method Investments

In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of $2.9 billion at the time of the contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable London Interbank Offered Rate (LIBOR) based preferred interests in those entities. The common equity of the investee entities is 95% owned by third parties that also maintain control over the assets. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion. The Company accounts for its investment in these entities using the equity method of accounting. The carrying amount of these investments was $2.8 billion and the carrying amount of notes payable to affiliates was $2.9 billion at December 31, 2012. Anadarko has legal right of setoff and intends to net settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets with the excess of the notes payable to affiliates over the aggregate investment carrying amounts reported in other long-term liabilities—other for all periods presented.

Interest on the notes issued by Anadarko is variable, based on LIBOR, plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.31% at December 31, 2012, and 1.55% at December 31, 2011. The note payable agreement contains a covenant that provides for a maximum debt-to-capital ratio of 67%. Anadarko was in compliance with this covenant at December 31, 2012. Other (income) expense, net includes interest expense on the notes payable of $42 million in 2012, $38 million in 2011, and $39 million in 2010, and equity earnings from Anadarko’s investments in the investee entities of $(43) million in 2012, $(41) million in 2011, and $(37) million in 2010.

12.  Derivative Instruments

Objective and Strategy  The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Henry Hub for natural gas and Cushing for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).

The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. Accumulated other comprehensive loss balances related to interest-rate derivatives that were previously subject to hedge accounting were $96 million ($61 million after tax) at December 31, 2012, and $109 million ($70 million after tax) at December 31, 2011.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

12.  Derivative Instruments (Continued)

 

Oil and Natural-Gas Production/Processing Derivative Activities  The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX West Texas Intermediate (WTI) and IntercontinentalExchange, Inc. (ICE) Brent prices. The following is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Activities at December 31, 2012:

 

    2013
  Settlement  
 

Natural Gas

 

Three-Way Collars (thousand MMBtu/d)

     (1) 

Fixed-Price Contracts (thousand MMBtu/d)

    1,185  

Average price per MMBtu

  $ 4.00  

Crude Oil

 

Three-Way Collars (MBbls/d)

    26  

Average price per barrel

 

Ceiling sold price (call)

  $ 125.15  

Floor purchased price (put)

  $ 105.00  

Floor sold price (put)

  $ 85.00  

Fixed-Price Contracts (MBbls/d)

    40  

Average price per barrel

  $ 107.04  

 

(1)

The Company entered into offsetting purchased and sold natural-gas three-way collars of 450,000 MMBtu/d for 2013 settlement.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

Marketing and Trading Derivative Activities  In addition to the positions in the above tables, the Company also engages in marketing and trading activities. These activities include physical product sales and related derivative transactions used to manage commodity-price risk. At December 31, 2012, the Company had fixed-price physical transactions related to natural gas totaling 10 billion cubic feet (Bcf), offset by derivative transactions totaling 10 Bcf. At December 31, 2011, the Company had fixed-price physical transactions related to natural gas totaling 22 Bcf, offset by derivative transactions totaling 21 Bcf.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

12.  Derivative Instruments (Continued)

 

Interest-Rate Derivatives  In December 2008 and January 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payer to mitigate the interest-rate risk associated with anticipated 2011 and 2012 debt issuances. The Company locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. The swap instruments include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period.

To align the swap portfolio with the anticipated timing of future debt refinancing, the Company extended the swap maturity dates for certain interest-rate swaps. In 2012, the Company extended the swap maturity dates from October 2012 to September 2016 for interest-rate swaps with an aggregate notional principal amount of $800 million. 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. Interest-rate swap agreements with an aggregate notional principal amount of $200 million were settled in October 2012, resulting in a realized loss of $64 million, and interest-rate swap agreements with an aggregate notional principal amount of $150 million were settled in October 2011, resulting in a realized loss of $57 million.

The Company had the following outstanding interest-rate swaps at December 31, 2012:

 

                                                                                                  
millions except percentages  

Reference Period

 

Weighted-Average

Notional Principal Amount

 

Start

 

End

  Interest Rate

$                    750

  June 2014   June 2024               6.00%

$                 1,100

  June 2014   June 2044               5.57%

$                      50

  September 2016   September 2026               5.91%

$                    750

  September 2016   September 2046               5.86%

Effect of Derivative InstrumentsBalance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31:

 

                                                                                                   
millions   Gross
      Derivative Assets      
    Gross
      Derivative Liabilities      
 

Balance Sheet Classification          

      2012             2011             2012             2011      

Commodity derivatives

       

Other current assets

  $ 475     $ 924     $ (197   $ (353

Other assets

    24       150       (7     (15

Accrued expenses

    6       5       (14     (33

Other liabilities

    1       1       (7     (17
 

 

 

   

 

 

   

 

 

   

 

 

 
    506       1,080       (225     (418
 

 

 

   

 

 

   

 

 

   

 

 

 

Interest-rate and other derivatives

       

Accrued expenses

                      (391

Other liabilities

                (1,194     (808
 

 

 

   

 

 

   

 

 

   

 

 

 
                (1,194     (1,199
 

 

 

   

 

 

   

 

 

   

 

 

 

Total derivatives

  $ 506     $ 1,080     $ (1,419   $ (1,617
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

12.  Derivative Instruments (Continued)

 

Effect of Derivative InstrumentsStatement of Income  The following summarizes realized and unrealized gains or losses related to derivative instruments:

 

                                                  
millions                  

Classification of (Gain) Loss Recognized                

      Realized           Unrealized             Total        

2012

     

Commodity derivatives

     

Gathering, processing, and marketing sales (1)

  $ 2     $ 16     $ 18  

(Gains) losses on derivatives, net

    (753     366       (387

Interest-rate and other derivatives

     

(Gains) losses on derivatives, net

    66       (5     61  
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on derivatives, net

  $ (685   $ 377     $ (308
 

 

 

   

 

 

   

 

 

 

2011

     

Commodity derivatives

     

Gathering, processing, and marketing sales (1)

  $ 20     $ (12   $ 8  

(Gains) losses on derivatives, net

    (226     (336     (562

Interest-rate and other derivatives

     

(Gains) losses on derivatives, net

    59       964       1,023  
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on derivatives, net

  $ (147   $ 616     $ 469  
 

 

 

   

 

 

   

 

 

 

2010

     

Commodity derivatives

     

Gathering, processing, and marketing sales (1)

  $ 3     $ (4   $ (1

(Gains) losses on derivatives, net

    (498     (395     (893

Interest-rate and other derivatives

     

(Gains) losses on derivatives, net

          285       285  
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on derivatives, net

  $ (495   $ (114   $ (609
 

 

 

   

 

 

   

 

 

 

 

(1)

Represents the effect of marketing and trading derivative activities.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

12.  Derivative Instruments (Continued)

 

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure. The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties.

In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and that provide for contract termination and net settlement across derivative types. At December 31, 2012, $339 million of the Company’s $1.4 billion gross derivative liability balance, and at December 31, 2011, $749 million of the Company’s $1.6 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

Some of the Company’s derivative instruments are subject to provisions that can require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered. However, most of the Company’s derivative counterparties maintain secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility ($5.0 billion Facility), the available capacity of which is sufficient to secure potential obligations to such counterparties.

Unsecured derivative obligations may require immediate settlement or full collateralization if certain credit-risk-related provisions are triggered, such as the Company’s credit rating declining to a level below investment grade by major credit rating agencies. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $94 million (net of collateral) at December 31, 2012, and $2 million (net of collateral) at December 31, 2011. These amounts were included in accrued expenses on the Company’s Consolidated Balance Sheets.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

12.  Derivative Instruments (Continued)

 

Fair Value  Fair value of futures contracts is based on quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity-option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, implied market volatility and discount factors. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments.

The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:

 

                                                                                                                             
millions     Level 1         Level 2         Level 3       Netting (1)      Collateral          Total      

December 31, 2012

           

Assets

           

Commodity derivatives

           

Financial institutions

  $ 6     $ 453     $      $ (206   $      $ 253  

Other counterparties

          47             (5           42  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total derivative assets

  $ 6     $ 500     $      $ (211   $      $ 295  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities

           

Commodity derivatives

           

Financial institutions

  $ (6   $ (202   $      $ 206     $ 1     $ (1

Other counterparties

          (17           5             (12

Interest-rate and other derivatives

          (1,194                       (1,194
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total derivative liabilities

  $ (6   $ (1,413   $      $ 211     $ 1     $ (1,207
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

           

Assets

           

Commodity derivatives

           

Financial institutions

  $ 3     $ 947     $      $ (361   $ (52   $ 537  

Other counterparties

          130             (13           117  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total derivative assets

  $ 3     $ 1,077     $      $ (374   $ (52   $ 654  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities

           

Commodity derivatives

           

Financial institutions

  $ (4   $ (375   $      $ 361     $ 7     $ (11

Other counterparties

          (39           13             (26

Interest-rate and other derivatives

          (1,199                 130       (1,069
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total derivative liabilities

  $ (4   $ (1,613   $      $ 374     $ 137     $ (1,106
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

13.  Debt and Interest Expense

Debt  The Company’s outstanding debt is senior unsecured, except for borrowings, if any, under the $5.0 billion Facility. See Note 11—Equity-Method Investments for disclosure regarding Anadarko’s notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. The following summarizes the Company’s outstanding debt:

 

                                         
    December 31,  
millions   2012     2011  

6.125% Senior Notes due 2012

  $      $ 131  

5.000% Senior Notes due 2012

          39  

5.750% Senior Notes due 2014

    275       275  

7.625% Senior Notes due 2014

    500       500  

5.950% Senior Notes due 2016

    1,750       1,750  

6.375% Senior Notes due 2017

    2,000       2,000  

7.050% Debentures due 2018

    114       114  

6.950% Senior Notes due 2019

    300       300  

8.700% Senior Notes due 2019

    600       600  

WES 5.375% Senior Notes due 2021

    500       500  

WES 4.000% Senior Notes due 2022

    670        

6.950% Senior Notes due 2024

    650       650  

7.500% Debentures due 2026

    112       112  

7.000% Debentures due 2027

    54       54  

7.125% Debentures due 2027

    150       150  

6.625% Debentures due 2028

    17       17  

7.150% Debentures due 2028

    235       235  

7.200% Debentures due 2029

    135       135  

7.950% Debentures due 2029

    117       117  

7.500% Senior Notes due 2031

    900       900  

7.875% Senior Notes due 2031

    500       500  

Zero-Coupon Senior Notes due 2036

    2,360       2,360  

6.450% Senior Notes due 2036

    1,750       1,750  

7.950% Senior Notes due 2039

    325       325  

6.200% Senior Notes due 2040

    750       750  

7.730% Debentures due 2096

    61       61  

7.500% Debentures due 2096

    78       78  

7.250% Debentures due 2096

    49       49  

$5.0 billion Facility

          2,500  
 

 

 

   

 

 

 

Total debt at face value

  $ 14,952     $ 16,952  

Net unamortized discounts and premiums (1)

    (1,683     (1,722
 

 

 

   

 

 

 

Total borrowings

  $ 13,269     $ 15,230  
 

 

 

   

 

 

 

Less current portion of long-term debt

          170  
 

 

 

   

 

 

 

Total long-term debt

  $ 13,269      $ 15,060   
 

 

 

   

 

 

 

 

(1) 

Unamortized discounts and premiums are amortized over the term of the related debt.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

13.  Debt and Interest Expense (Continued)

 

In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the Zero-Coupon Senior Notes due 2036 (Zero Coupons). The Zero Coupons mature in 2036 and have an aggregate principal amount due at maturity of $2.4 billion, reflecting a yield to maturity of 5.24%. The holder has the right to cause the Company to repay an amount up to the then-accreted value of the outstanding Zero Coupons in October of each year. The holder did not elect to put any of the accreted balance of the Zero Coupons to the Company in October 2012. The Zero Coupons are classified as long-term debt on the Consolidated Balance Sheets based on the Company’s ability and intent to refinance the obligations, if the holder requests repayment in 2013.

Fair Value  The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $16.2 billion at December 31, 2012, and $17.3 billion at December 31, 2011.

Debt Activity  The following summarizes the Company’s debt activity during 2012 and 2011:

 

millions   Carrying
Value
   

Description

Balance at December 31, 2010

  $     12,787    

Issuances

    494     WES 5.375% Senior Notes due 2021

Borrowings

    570     WES revolving credit facility
    2,500     $5.0 billion Facility

Repayments

    (869   WES revolving credit facility and WES term loan
    (285   6.875% Senior Notes due 2011

Other, net

    33     Changes in debt premium or discount
 

 

 

   

Balance at December 31, 2011

  $ 15,230    

Issuances

    674     WES 4.000% Senior Notes due 2022

Borrowings

    374     WES revolving credit facility

Repayments

    (131   6.125% Senior Notes due 2012
    (39   5.000% Senior Notes due 2012
    (374   WES revolving credit facility
    (2,500   $5.0 billion Facility

Other, net

    35     Changes in debt premium or discount
 

 

 

   

Balance at December 31, 2012

  $ 13,269    
 

 

 

   

Capital Lease Obligation  In the fourth quarter of 2010, a lease commenced for a floating production, storage, and offloading vessel (FPSO) for the Company’s Jubilee field operations in Ghana. In December 2011, the Company and its partners in the Jubilee project purchased the FPSO, resulting in the cancellation of the capital lease obligation.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

13.  Debt and Interest Expense (Continued)

 

Anadarko Revolving Credit Facility and Letter of Credit Facility  In September 2010, the Company entered into the $5.0 billion Facility maturing in September 2015. Borrowings under the $5.0 billion Facility bear interest at LIBOR plus an applicable margin ranging from 1.25% to 2.50%, depending on the Company’s credit rating, or rates at a margin above the one-month LIBOR, the federal funds rate, or prime rates offered by certain designated banks. During 2012, the Company repaid all outstanding borrowings under the $5.0 billion Facility with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute.

Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments that are supported by the $5.0 billion Facility (as discussed in Note 12—Derivative Instruments), are guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and are secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries. At December 31, 2012, the Company was in compliance with applicable covenants and there were no restrictions on its ability to utilize the $5.0 billion Facility.

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (LOC Facility). In the third quarter of 2012, the Company terminated the LOC Facility.

WES Borrowings  In March 2011, WES entered into a five-year, $800 million senior unsecured revolving credit facility (RCF). The $800 million RCF matures in March 2016 and bears interest at LIBOR plus an applicable margin ranging from 1.30% to 1.90%, or rates at a margin above the one-month LIBOR, the federal funds rate, or prime rates offered by certain designated banks. In 2012, WES repaid all outstanding borrowings under its RCF with net proceeds from its public offering of $670 million aggregate principal amount of 4.000% Senior Notes due 2022. At December 31, 2012, WES was in compliance with all of the covenants contained in the RCF.

Scheduled Maturities  Total principal amount of debt maturities for the five years ending December 31, 2017, excluding the potential repayment of the outstanding Zero Coupons that may be put by the holder to the Company annually, were as follows:

 

millions   Principal
Amount of
Debt Maturities
 

2013

  $  

2014

    775  

2015

     

2016

    1,750  

2017

    2,000  

Interest Expense  The following summarizes interest expense for the years ended December 31:

 

                                                  
millions   2012     2011     2010  

Current debt, long-term debt, and other

  $ 963      $ 986     $ 871  

(Gain) loss on early debt retirements and commitment termination (1)

                112  

Capitalized interest

    (221     (147     (128
 

 

 

   

 

 

   

 

 

 

Interest expense

  $     742     $     839     $     855  
 

 

 

   

 

 

   

 

 

 

 

(1) 

Loss on early debt retirements in 2010 is the result of repurchasing $1.4 billion aggregate principal amount of debt due 2011 and 2012.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

14.  Stockholders’ Equity

Common Stock  In August 2011, the Company terminated its $5.0 billion share-repurchase program under which shares could be repurchased either in the open market or through privately negotiated transactions. The following summarizes the changes in the Company’s outstanding shares of common stock:

 

                                                        
millions   2012     2011     2010  

Shares of common stock issued

     

Shares at January 1

    516       513       509  

Exercise of stock options

    1       1       2  

Issuance of restricted stock

    2       2       2  
 

 

 

   

 

 

   

 

 

 

Shares at December 31

    519       516       513  
 

 

 

   

 

 

   

 

 

 

Shares of common stock held in treasury

     

Shares at January 1

    18       17       16  

Shares received for restricted stock vested and options exercised

          1       1  
 

 

 

   

 

 

   

 

 

 

Shares at December 31

    18       18       17  
 

 

 

   

 

 

   

 

 

 

Shares of common stock outstanding at December 31

    501       498       496  
 

 

 

   

 

 

   

 

 

 

The reconciliation between basic and diluted EPS attributable to common stockholders is as follows:

 

                                                        
    Years Ended December 31,  
millions except per-share amounts   2012     2011     2010  

Net income (loss)

     

Net income (loss) attributable to common stockholders

  $ 2,391     $ (2,649   $ 761  

Less distributions on participating securities

    1             1  

Less undistributed income allocated to participating securities

    14             4  
 

 

 

   

 

 

   

 

 

 

Basic

  $ 2,376     $ (2,649   $ 756  
 

 

 

   

 

 

   

 

 

 

Diluted

  $ 2,376     $ (2,649   $ 756  
 

 

 

   

 

 

   

 

 

 

Shares

     

Average number of common shares outstanding—basic

    500       498       495  

Dilutive effect of stock options and performance-based stock awards

    2             2  
 

 

 

   

 

 

   

 

 

 

Average number of common shares outstanding—diluted

    502       498       497  
 

 

 

   

 

 

   

 

 

 

Excluded (1)

    6       12       6  

Net income (loss) per common share

     

Basic

  $ 4.76     $ (5.32   $ 1.53  

Diluted

  $ 4.74     $ (5.32   $ 1.52  

Dividends per common share

  $ 0.36     $ 0.36     $ 0.36  

 

(1) 

Inclusion of certain shares would have had an anti-dilutive effect.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

15.  Share-Based Compensation

At December 31, 2012, 30 million shares of the 31 million shares of Anadarko common stock authorized for awards under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. The following summarizes share-based compensation expense for the years ended December 31:

 

                                                        
millions   2012     2011     2010  

Equity-Classified Awards

     

Restricted stock

  $ 103     $ 80     $ 103  

Stock options

    43       51       45  

Performance-based share awards and other

    1       1       3  
 

 

 

   

 

 

   

 

 

 

Total equity-classified award compensation expense

    147       132       151  
 

 

 

   

 

 

   

 

 

 

Liability-Classified Awards

     

Value creation plan

    (2     26        

Performance-based unit awards

    8       28       36  

Other performance-based awards

    165       28       8  

Other

    2       1       2  
 

 

 

   

 

 

   

 

 

 

Total liability-classified award compensation expense

    173       83       46  
 

 

 

   

 

 

   

 

 

 

Pretax compensation expense

  $ 320     $ 215     $ 197  
 

 

 

   

 

 

   

 

 

 

Income tax benefit

  $ 117     $ 78     $ 72  

Cash flows from financing activities included excess tax benefits related to share-based compensation of $51 million in 2012, $(15) million in 2011, and $26 million in 2010. Cash received from stock option exercises was $52 million in 2012, $45 million in 2011, and $78 million in 2010.

Equity-Classified Awards

Restricted Stock  Certain employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. A restricted stock unit is equivalent to a restricted stock award except that unit holders do not have the right to vote. Restricted stock vests over service periods ranging from the date of grant up to three years and is not considered issued and outstanding until vested.

Non-employee directors are granted deferred shares that are held in a grantor trust by the Company until payable. Non-employee directors may receive these shares in a lump-sum payment or in annual installments.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

15.  Share-Based Compensation (Continued)

 

The following summarizes the Company’s restricted stock activity:

 

                                                 
     Shares
(millions)
    Weighted-
Average
Grant-Date
Fair Value

(per share)
 

Non-vested at January 1, 2012

    2.47     $ 69.55  

Granted

    1.75     $ 79.97  

Vested

    (1.33   $ 62.11  

Forfeited

    (0.07   $ 79.35  
 

 

 

   

Non-vested at December 31, 2012

    2.82     $ 79.27  
 

 

 

   

The weighted-average grant-date fair value per share of restricted stock granted was $81.19 during 2011 and $68.51 during 2010. The total fair value of restricted shares vested was $105 million during 2012, $124 million during 2011, and $122 million during 2010, based on the market price at the vesting date. At December 31, 2012, total unrecognized compensation cost related to restricted stock of $148 million is expected to be recognized over a weighted-average remaining service period of 1.9 years.

Stock Options  Certain employees may be granted nonqualified options to purchase shares of Anadarko common stock with an exercise price equal to, or greater than, the fair market value of Anadarko common stock on the date of grant. These stock options vest over three years from the date of grant and terminate at the earlier of the date of exercise or seven years from the date of grant.

Non-employee directors may be granted nonqualified stock options with an exercise price equal to, or greater than, the fair market value of Anadarko common stock on the date of grant. These stock options vest over a one-year service period from the date of grant and terminate at the earlier of the date of exercise or ten years from the date of grant.

The fair value of stock option awards is determined using the Black-Scholes option-pricing model. The expected life of an option is estimated based on historical exercise behavior. Volatility assumptions are estimated based on an average of historical volatility over the expected life of an option and the 12-month average implied volatility. Risk-free interest rates are based on the U.S. Treasury rate over the expected life of an option. The dividend yield is based on a 12-month average dividend yield, taking into account the Company’s expected dividend policy over the expected life of an option. Expected forfeiture rates are estimated based on historical forfeiture experience. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during 2012, 2011, and 2010:

 

                                                        
    2012     2011     2010  

Expected option life—years

    4.9       4.8       4.9  

Volatility

    44.2     42.0     43.9

Risk-free interest rate

    0.7     1.5     2.0

Dividend yield

    0.5     0.5     0.7

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

15.  Share-Based Compensation (Continued)

 

The following summarizes the Company’s stock option activity:

 

                                                                                                   
    Shares
(millions)
    Weighted-
Average
Exercise
Price

(per share)
    Weighted-
Average
Remaining
Contractual
Term
(years)
    Aggregate
Intrinsic
Value
(millions)
 

Outstanding at January 1, 2012

    9.87     $ 55.27      

Granted

    0.88     $ 70.33      

Exercised

    (1.31   $ 40.04      

Forfeited or expired

    (0.08   $ 72.23      
 

 

 

       

Outstanding at December 31, 2012

    9.36     $ 58.66       3.92     $ 158.6  
 

 

 

       

Vested or expected to vest at December 31, 2012

    9.26     $ 58.50       3.90     $ 158.3  
 

 

 

       

Exercisable at December 31, 2012

    6.78     $ 52.59       3.26     $ 151.4  
 

 

 

       

The per-option weighted-average grant-date fair value of stock options granted was $25.84 during 2012, $29.77 during 2011, and $26.44 during 2010. The total intrinsic value of stock options exercised was $49 million during 2012, $45 million during 2011, and $62 million during 2010, based on the difference between the market price at the exercise date and the exercise price. At December 31, 2012, total unrecognized compensation cost related to stock options of $46 million is expected to be recognized over a weighted-average remaining period of 2.0 years.

Performance-Based Share Awards  In 2007, certain officers of the Company were provided Performance Unit Award Agreements with performance periods ranging from one to three years. The number of shares of common stock earned under these agreements was based on a comparison of the Company’s TSR to the TSR of a predetermined group of peer companies over the specified performance periods. The maximum number of shares of Anadarko common stock available to be earned was 934,424 shares based on predefined payout percentages. At December 31, 2012, all performance periods have ended and a total of 521,258 shares were earned, with no additional shares available to be earned in the future. Of the total shares earned, 386,574 shares have been issued and 134,684 shares have been deferred pursuant to the agreements. There were no performance-based shares issued during 2012. The fair value of the performance-based share awards issued was $6 million during 2011 and $17 million during 2010, based on the market price on the date of issuance. At December 31, 2012, the Company had no unrecognized compensation cost related to these awards.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

15.  Share-Based Compensation (Continued)

 

Liability-Classified Awards

Value Creation Plan  As a part of its employee compensation program, the Company offers an incentive compensation program that provides non-officer employees the opportunity to earn cash bonus awards based on the Company’s TSR for the year, compared to the TSR of a predetermined group of peer companies. The Company paid $24 million during 2012 related to the plan, and zero during 2011 and 2010. At December 31, 2012, the Company had no outstanding liability attributable to the 2012 performance period.

Performance-Based Unit Awards  Certain officers of the Company were provided Performance Unit Award Agreements with two- and three-year performance periods. The vesting of these units is based solely on comparing the Company’s TSR to the TSR of a predetermined group of peer companies over the specified performance period. Each performance unit represents the value of one share of the Company’s common stock. At the end of each performance period, the value of the vested performance units, if any, is paid in cash. The Company paid $37 million related to vested performance units in 2012, $25 million in 2011, and zero in 2010. At December 31, 2012, the Company’s liability under Performance Unit Award Agreements was $26 million, with total estimated unrecognized compensation cost related to these awards of $19 million expected to be recognized over a weighted-average remaining performance period of 1.8 years.

Other Performance-Based Awards  Prior to 2011, certain officers of the general partner of WES were awarded general partner Unit Appreciation Rights (UARs) pursuant to the Western Gas Holdings, LLC Equity Incentive Plan. The fair value of the UARs was determined based on the fair value of WES’s general partner, as determined by the WGP IPO price. The Company paid $203 million related to the UARs upon the WGP IPO in 2012, and zero in 2011 and 2010. At December 31, 2012, the Company had no outstanding liability and no unrecognized compensation cost attributable to these awards.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

16.  Commitments

Operating Leases  The Company had $3.4 billion in long-term drilling rig commitments that satisfy operating lease criteria. The Company also has various commitments under non-cancelable operating lease agreements of $614 million for production platforms and equipment, buildings, facilities, compressors, and aircraft. These operating leases expire at various dates through 2026. Certain of these operating leases contain residual value guarantees at the end of the lease term, totaling $96 million at December 31, 2012; however, no liability has been accrued for residual value guarantees. Future minimum lease payments under operating leases at December 31, 2012, were as follows:

 

millions   Operating
Leases
 

2013

  $ 817   

2014

    1,001   

2015

    791  

2016

    548  

2017

    400  

Later years

    442  
 

 

 

 

Total future minimum lease payments

  $ 3,999   
 

 

 

 

Total rent expense, net of sublease income, amounted to $136 million in 2012, $143 million in 2011, and $154 million in 2010. Total rent expense includes contingent rent expense related to processing fees of $18 million in 2012, $21 million in 2011, and $20 million in 2010.

Drilling Rig Commitments  Anadarko has entered into various agreements to secure drilling rigs necessary to execute its drilling plans over the next several years. The table of future minimum lease payments above includes approximately $3.2 billion related to 12 offshore drilling vessels and $183 million related to certain contracts for U.S. onshore drilling rigs. Lease payments associated with the drilling of exploratory wells and development wells, net of amounts billed to partners, will initially be capitalized as a component of oil and gas properties, and either depreciated in future periods or written off as exploration expense.

Spar Platform and Production Vessel Leases  Anadarko has operating leases related to certain spar platforms in the Gulf of Mexico. The table of future minimum lease payments above includes approximately $354 million for these agreements. These agreements also contain unrecorded residual value guarantees totaling $37 million at the end of the lease periods.

Other Commitments  In the normal course of business, the Company enters into other contractual agreements for processing, treating, transportation, and storage of natural gas, crude oil, and NGLs, as well as for other services. These agreements expire at various dates through 2028. At December 31, 2012, aggregate future payments under these contracts totaled $8.8 billion, of which $1.7 billion is expected to be paid in 2013, $1.4 billion in 2014, $1.1 billion in 2015, $881 million in 2016, $772 million in 2017, and $2.9 billion thereafter.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies

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, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. The Company had accrued $49 million at December 31, 2012, and $342 million at December 31, 2011, related to litigation contingencies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. The Company’s Consolidated Balance Sheets include liabilities of $81 million at December 31, 2012, and $92 million at December 31, 2011, for remediation and reclamation obligations. 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.

Deepwater Horizon Events  In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% non-operated interest. 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), under which the Company paid $4.0 billion in cash and transferred its interest in the Macondo well and the Mississippi Canyon Block 252 (Lease) to BP. Pursuant to the Settlement Agreement, the Company is fully indemnified by BP 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 assessment costs, and any claims arising under the Operating Agreement with BP (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-on 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 securities laws claims, or certain other claims.

Liability Accrual  Below is a discussion of the Company’s current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the OA (OA Liabilities), (ii) OPA-related environmental costs, and (iii) other contingent liabilities. Accounting rules require loss recognition where a potential loss is considered probable and can be reasonably estimated.

The Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and other potential liabilities. The Company may be required to recognize a liability for these 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. The Company has not recorded a liability for any costs that are subject to indemnification by BP.

OA Liabilities  Pursuant to the Settlement Agreement, all amounts deemed by BP to have been due under the OA, as well as all future amounts that otherwise would be invoiced to Anadarko under the OA, have been satisfied.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

OPA-Related Environmental Costs  BP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the U.S. Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under OPA. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup. The USCG’s identification of Anadarko as an RP arises as a result of Anadarko’s status as a co-lessee in the Lease.

Applicable accounting guidance requires the Company to accrue an environmental liability if it is both probable that a liability is incurred and the amount of the liability can be reasonably estimated. Under accounting guidance applicable to environmental liabilities, a liability is presumed probable if the entity is both identified as an RP and associated with the environmental event. The Company’s co-lessee status in the Lease at the time of the event and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company’s potential environmental liabilities related to the Deepwater Horizon events are probable.

As BP funds OPA-related environmental costs, any potential joint and several liability for these costs is satisfied for all RPs, including Anadarko. This bears significance in that once these costs are funded by BP, such costs are no longer analyzed as OPA-related environmental costs, but instead are analyzed as OA Liabilities. As discussed above, Anadarko has settled its OA Liabilities with BP. Thus, potential liability to the Company for OPA-related environmental costs can arise only where BP does not, or otherwise is unable to, fund all of the OPA-related environmental costs. Under this scenario, the joint and several nature of the liability for these costs could cause the Company to recognize a liability for OPA-related environmental costs. However, the Company is fully indemnified by BP against these costs (including guarantees by BPCNA or BP p.l.c.).

Gross OPA-Related Environmental Cost Estimate  In prior periods, the Company provided an estimated range of gross OPA-related environmental costs for all identified RPs. This estimate was comprised of spill-response costs and OPA damage claims and was derived from cost information received by the Company from BP. The Company no longer receives Deepwater Horizon-related cost and claims data from BP. Accordingly, the OPA-related environmental cost estimate included in BP’s public releases is the best data available to the Company.

Based on information included in BP p.l.c.’s public release on February 5, 2013, gross OPA-related environmental costs are estimated to be $10.7 billion, excluding (i) amounts BP has already funded, which constitute settled OA Liabilities; (ii) amounts that in BP’s view cannot reasonably be estimated, which include NRD claims and other litigation damages; (iii) non-OPA-related fines and penalties that may be assessed against Anadarko, including assessments under the Clean Water Act (CWA); and (iv) estimated state and local governmental claims, which BP no longer publicly discloses and, as a result, Anadarko cannot estimate. Actual gross OPA-related environmental costs may vary from those estimated by BP p.l.c. in its public releases, perhaps materially from the above estimate.

 

125


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

Allocable Share of Gross OPA-Related Environmental Costs  Under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs. To date, BP has paid all Deepwater Horizon event-related costs, which satisfies the Company’s potential liability for these costs. Additionally, BP has repeatedly stated publicly and in prior congressional testimony that it will continue to pay these costs. BP’s funding and public commentary has continued subsequent to the release of BP’s own investigation report, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling’s final report, and the Deepwater Horizon Joint Investigation Team final report, which the Company considers to be significant positive indications in assessing the likelihood of BP continuing to fund all of these costs. Based on BP’s stated intent to continue funding these costs, the Company’s assessment of BP’s financial ability to continue funding these costs, and the impact of BP’s settlements with both of its OA partners, the Company believes the likelihood of BP not continuing to satisfy these claims to be remote. Accordingly, the Company considers zero to be its allocable share of gross OPA-related environmental costs and, consistent with applicable accounting guidance, has not recorded a liability for these amounts.

Penalties and Fines  These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the CWA, the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company. To date, no penalties or fines have been assessed against the Company. However, in December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko Petroleum Corporation and Anadarko E&P Company LP (AE&P), a subsidiary of Anadarko, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA and denied both the Company’s and the United States’ motions for summary judgment with respect to the liability of AE&P. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. Also, in February 2012, the Louisiana District Court entered a stipulated order (Stipulated Order), agreed to by the Company and the United States, that the United States will not assert any claim for a CWA penalty against AE&P, and that the United States will not assert any other theories of liability under the CWA (e.g., operator or person-in-charge liability) against either Anadarko or AE&P. Further, the Stipulated Order reserved the issue of an assessment of a civil penalty against Anadarko until a later proceeding, to be scheduled by the Louisiana District Court. The Company believes that the Stipulated Order does not have a material impact on Anadarko’s potential liability. In August 2012, Anadarko filed a notice of appeal in the U.S. Court of Appeals for the Fifth Circuit concerning that portion of the February 2012 declaratory judgment finding Anadarko liable for civil penalties under the CWA.

As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments have appealed, or have provided indication of a likely appeal of, the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. If such an appeal is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.

 

126


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability is incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012 satisfies the requirement that a loss, arising from the future assessment of a civil penalty against Anadarko, is probable. Notwithstanding the declaratory judgment, the Company currently cannot estimate the amount of any potential civil penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which significantly influence the magnitude of CWA penalty assessments. As a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty nor determine a range of potential loss. Furthermore, neither the February 2012 settlement of Deepwater Horizon-related civil penalties (including those under the CWA) by the other non-operating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) nor the January 2013 proposed settlement of CWA civil and criminal penalties by the drilling contractor with the United States affects the Company’s current conclusion regarding its ability to estimate potential fines and penalties. The Company lacks insight into those settlements, retains legal counsel separate from the other parties, and was not involved in any manner with respect to those settlements. Events or factors that could assist the Company in estimating the amount of any potential civil penalty or a range of potential loss related to such penalties include (i) an assessment by the DOJ, (ii) a ruling by a court of competent jurisdiction, or (iii) the initiation of substantive settlement negotiations between the Company and the DOJ.

Given the Company’s lack of direct operational involvement in the event, as confirmed by the Louisiana District Court, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Natural Resource Damages  This category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.

The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior (DOI), and the Department of Defense. These governmental departments, along with the five affected states – Alabama, Florida, Louisiana, Mississippi, and Texas – are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning.

The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related state law claims against the Company in the Louisiana District Court. In November 2011, the Court dismissed all the NRD-related state law claims asserted against the Company by the states of Alabama and Louisiana.

NRD claims are generally sought after the damage assessment and restoration planning is completed, which may take several years. Thus, the Company remains unable to reasonably estimate the magnitude of any NRD claim. The Company anticipates that BP will satisfy any NRD claim, which eliminates any potential liability to Anadarko for such costs. In the event any NRD damage claim is made directly against Anadarko, the Company is fully indemnified by BP against such claims (including guarantees by BPCNA or BP p.l.c.).

 

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Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

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

This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. In March 2012, BP and the Plaintiffs’ Steering Committee (PSC) entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events, which the Louisiana District Court approved in orders issued in December 2012 and January 2013. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have provided indication of a likely appeal of, the MDL court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.

The Louisiana District Court plans to hold a trial in Transocean’s Limitation of Liability case in the MDL commencing in 2013. In May 2012, the Louisiana District Court issued its revised case management order (CMO) ruling that the first phase of the trial will commence in February 2013 (Phase I). Phase I is expected to last for six to twelve weeks. BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean will participate in Phase I of the trial. The CMO provides that the Stipulated Order excusing Anadarko from participation in Phase I of the trial remains in effect. The issues to be tried in Phase I include the cause of the blow-out and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. The allocation of fault remains in the Phase I trial because Halliburton and Transocean have not settled with any of the parties and wish to prove to the court that their respective company was not at fault. The second phase of trial is estimated to start in July 2013 (Phase II) and may take six to eight weeks to complete. The issues to be tried in Phase II will include spill-source control and quantification of the spill for the period from April 22, 2010, until the well was capped. The Company, BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean will participate in Phase II of the trial.

 

128


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

Two separate class action complaints were filed in June and August 2010, in the U.S. District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company’s stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 (Exchange Act) for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. In March 2012, the New York District Court granted the Lead Plaintiff’s motion to transfer venue to the U.S. District Court for the Southern District of Texas – Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellis. In July 2012, the plaintiffs filed their First Amended Consolidated Class Action Complaint. The defendants filed a renewed motion to dismiss in the Southern District Court of Texas in September 2012. The motion is fully briefed and is pending before the court.

In November 2011, the Company’s Board of Directors (Board) received a letter from a purported shareholder demanding that the Board investigate, address, remedy, and commence derivative proceedings against certain officers and directors for their alleged breach of fiduciary duty related to the Deepwater Horizon events. The Board has considered this demand and in February 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter. In March 2012, the Company’s Board received a similar demand letter from a purported shareholder supplementing an original demand that had been made by the shareholder in September 2010 related to the Deepwater Horizon events. The Board has considered this demand and in April 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

Given the various stages of these matters, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses, related to ongoing proceedings. The Company intends to vigorously defend itself, its officers, and its directors in each of these matters, and will avail itself of any and all indemnities provided by BP against civil damages.

Remaining Liability Outlook  It is reasonably possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties, shareholder claims, and certain other claims not covered by the indemnification provisions of the Settlement Agreement; however, the Company does not believe that any potential liability attributable to the foregoing items, individually or in the aggregate, will have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. This assessment takes into account certain qualitative factors, including the subjective and fault-based nature of CWA penalties, the Company’s indemnification by BP against certain damage claims as discussed above, BP’s creditworthiness, the merits of the shareholder claims, and directors and officers insurance coverage related to outstanding shareholder claims.

The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings.

Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these 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.

 

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Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

Tronox Litigation  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 (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 $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In February 2011, in accordance with Chapter 11 of the Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization (Plan). The terms of the Plan, which were confirmed by the Bankruptcy Court in the third quarter of 2010, contemplate that the claims of the U.S. government (together with other federal, state, local, or tribal governmental entities having regulatory authority or responsibilities for environmental laws, the Governmental Entities) related to Tronox’s environmental liabilities will be settled through certain environmental response trusts and a litigation trust (Anadarko Litigation Trust). The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. In accordance with the Plan, the Adversary Proceeding was prosecuted by the Anadarko Litigation Trust. Pursuant to the Plan, the Anadarko Litigation Trust was “deemed substituted” for Tronox in the Adversary Proceeding as the party in such litigation. For purposes of this Form 10-K, references to “Tronox” after February 2011 refer to the Anadarko Litigation Trust. In May 2011, the Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting. In January 2012, the Court granted partial summary judgment in favor of Tronox on the issue of whether damages in the Adversary Proceeding are limited to the amount of allowed creditor claims filed in the Bankruptcy. The Court held that Section of 550(a) of the Bankruptcy Code does not impose a cap on Tronox’s potential damages, but stated that the appropriate measure of damages should only be determined after trial.

The U.S. government was granted authority to intervene in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). Anadarko and Kerr-McGee moved to dismiss the claims of the U.S. government, but that motion has been stayed by the Bankruptcy Court. In April 2012, Anadarko and Kerr-McGee filed an answer to the FDCPA Complaint.

In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May 2012 and in September 2012, the evidence closed and both sides rested. In November 2012, the parties filed post-trial briefs and closing arguments were presented in December 2012. The parties filed final post-trial briefs in January 2013. The matter is pending before the court.

In the first quarter of 2012, the Company believed it probable that the parties would reach a settlement on reasonable terms and thus the Company considered a loss, via settlement, related to the Adversary Proceeding probable. Based on this assumption, a $275 million loss contingency was accrued in the first quarter of 2012, which increased the Company’s total estimated contingent loss accrual related to the Adversary Proceeding to $525 million at March 31, 2012. The Company’s attempts during the second quarter of 2012 to resolve the Adversary Proceeding through mediation and settlement discussions reached an impasse, resulting in the Company’s assessment that the likelihood of settlement is remote and that litigation would be the probable form of final resolution of the Adversary Proceeding. Due to the change in the Company’s opinion as to the probable form of resolution of this matter, the Company reversed the settlement-based $525 million contingent loss accrual related to this matter in the second quarter of 2012.

 

130


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

The Company remains confident in the merits of its position, and will continue to vigorously defend the claims asserted in the Adversary Proceeding. The Company does not believe a loss resulting from litigating the Adversary Proceeding is probable. Accounting guidance requires that contingent losses be probable in nature for loss recognition to be appropriate. Accordingly, the Company’s Consolidated Balance Sheet at December 31, 2012, does not include a loss-contingency liability related to the litigation of the Adversary Proceeding.

Although the Company does not consider a loss related to the litigation of the Adversary Proceeding to be probable, it is reasonably possible that the Company could incur a loss as a result of litigating this matter. Despite the plaintiffs’ damage claims in excess of $18.9 billion, the Company currently believes a reasonable range of potential loss is zero to $1.4 billion. The low end of the Company’s estimated range of potential loss is based on the Company’s current belief that it will more likely than not prevail in defending against the claims asserted in the Adversary Proceeding. The high end of the Company’s estimated range of potential loss represents the amount of consideration received by Kerr-McGee at the time of the Tronox spin-off, approximately $985 million, plus interest thereon.

The Company’s estimated range of potential loss is based on the Company’s opinion regarding the current status of and likelihood of final resolution through litigation and could change as a result of developments in the Adversary Proceeding, or if the likelihood of settlement ceases to be remote. The Company’s ultimate financial obligation resulting from resolution of the Adversary Proceeding could vary, perhaps materially, from the Company’s above-stated estimated range of potential loss.

Separately, in July 2009, a consolidated class action complaint was filed in the New York District Court on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009, against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (Securities Case). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Exchange Act for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort-claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In April 2012, certain parties, including Anadarko, Kerr-McGee, and the former Kerr-McGee officers and directors, reached a settlement, which was approved by the court in November 2012. The settlement was directly funded by the insurers for Tronox, Anadarko, and Kerr-McGee.

Other Litigation  In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. Currently, $166 million, the amount of tax in dispute, resides in a judicially controlled Brazilian bank account, pending final resolution of the matter and is included in other assets on the Company’s Consolidated Balance Sheet at December 31, 2012.

In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court’s ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior Court and the Brazilian Supreme Court. The Brazilian Superior Court and the Brazilian Supreme Court have agreed to hear the case and the Company currently is awaiting the setting of initial hearing dates.

The Company believes that it will more likely than not prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at December 31, 2012. The Company continues to vigorously defend itself in Brazilian courts.

 

131


Table of Contents
Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

17.  Contingencies (Continued)

 

Deepwater Drilling Moratorium and Other Related Matters  In June 2010, as a result of the moratorium on drilling in the Gulf of Mexico between mid-May 2010 and mid-October 2010 (Moratorium), the Company gave written notice of termination to a drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the Texas District Court against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserting that Anadarko had breached the drilling contract. In the second quarter of 2012, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. The resolution of this dispute did not have a material impact on Anadarko’s consolidated financial position, results of operations, or cash flows.

Algeria Exceptional Profits Tax Settlement  In 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. The Company disagreed with Sonatrach’s collection of the exceptional profits tax and initiated arbitration against Sonatrach in 2009. In March 2012, the Company and Sonatrach resolved this dispute. The resolution provided for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. At December 31, 2012, a receivable of $730 million was included on the Company’s Consolidated Balance Sheet and is in the oil and gas exploration and production reporting segment. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the year ended December 31, 2012, to reflect the effect of this agreement for previously recorded expenses. Additionally, the parties amended the existing Production Sharing Agreement (PSA) to increase the Company’s sales volumes and to lower the effective exceptional profits tax rate. The amendment confirmed the length of each exploitation license to be 25 years from the date the license was granted under the PSA with expiration dates ranging from December 2022 to December 2036.

Guarantees and Indemnifications  Under the terms of the MSA entered into between Kerr-McGee and Tronox, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement of $100 million. During 2010, the Company reversed to non-operating income a $95 million liability recorded for this reimbursement obligation as a result of a court-authorized rejection of the MSA. See Tronox Litigation section of this note.

The Company also provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation, or tax matters existing at the date of disposition. No material liabilities were recorded for any such indemnifications at December 31, 2012.

18.  Other Taxes

Taxes incurred, other than income taxes, were as follows:

 

                                                        
     Years Ended December 31,  
millions    2012      2011      2010  

Production and severance

   $ 855      $ 1,094      $ 770  

Ad valorem

     238        265        219  

Other

     131        133        79  
  

 

 

    

 

 

    

 

 

 

Total

   $ 1,224      $ 1,492      $ 1,068  
  

 

 

    

 

 

    

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

19.  Income Taxes

Components of income tax expense (benefit) were as follows:

 

                                                                    
     Years Ended December 31,  
millions    2012     2011     2010  

Current

      

Federal

   $ 45     $ (381   $ 305  

State

     25       1       18  

Foreign

     891       977       628  
  

 

 

   

 

 

   

 

 

 
     961       597       951  
  

 

 

   

 

 

   

 

 

 

Deferred

      

Federal

     (30     (1,470     (72

State

     115       (68     (11

Foreign

     74       85       (48
  

 

 

   

 

 

   

 

 

 
     159       (1,453     (131
  

 

 

   

 

 

   

 

 

 

Income tax expense (benefit)

   $ 1,120     $ (856   $ 820  
  

 

 

   

 

 

   

 

 

 

Total income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate to income (loss) before income taxes. The sources of these differences were as follows:

 

                                                                    
     Years Ended December 31,  
millions except percentages    2012     2011     2010  

Income (loss) before income taxes

      

Domestic

   $ 132     $ (5,416   $ 855  

Foreign

     3,433       1,992       786  
  

 

 

   

 

 

   

 

 

 

Total

   $ 3,565     $ (3,424   $ 1,641  
  

 

 

   

 

 

   

 

 

 

U.S. federal statutory tax rate

     35%        35%        35%   

Tax computed at the U.S. federal statutory rate

   $ 1,248     $ (1,198   $ 574  

Adjustments resulting from

      

State income taxes (net of federal income tax benefit)

     93       (44     5  

Tax impact from foreign operations

     178       54       89  

Algerian exceptional profits taxes

     188       258       193  

Non-taxable Algeria exceptional profits tax settlement

     (679            

Net changes in uncertain tax positions

     27       8       28  

Items resulting from business acquisitions

           19        

Other—net

     65       47       (69
  

 

 

   

 

 

   

 

 

 

Income tax expense (benefit)

   $ 1,120     $ (856   $ 820  
  

 

 

   

 

 

   

 

 

 

Effective tax rate

     31%        25%        50%   
  

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

19.  Income Taxes (Continued)

 

Components of total deferred taxes were as follows:

 

                                         
    December 31,  
millions   2012     2011  

Federal

  $ (7,890   $ (7,916

State, net of federal

    (325     (252

Foreign

    (216     (173
 

 

 

   

 

 

 

Total deferred taxes

  $ (8,431   $ (8,341
 

 

 

   

 

 

 

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) were as follows:

 

                                         
    December 31,  
millions   2012     2011  

Net current deferred tax assets

  $ 328     $ 138  
 

 

 

   

 

 

 

Oil and gas exploration and development operations

    (8,683     (8,187

Mineral operations

    (408     (407

Midstream and other depreciable properties

    (1,295     (1,264

Other

    (152     (1
 

 

 

   

 

 

 

Gross long-term deferred tax liabilities

    (10,538     (9,859
 

 

 

   

 

 

 

Oil and gas exploration and development costs

    762       127  

Net operating loss carryforward

    477       1,071  

Foreign tax credit carryforward and alternative minimum tax credit carryforward

    450       119  

Other

    1,012       618  
 

 

 

   

 

 

 

Gross long-term deferred tax assets

    2,701       1,935  

Less valuation allowances on deferred tax assets not expected to be realized

    (922     (555
 

 

 

   

 

 

 

Net long-term deferred tax assets

    1,779       1,380  
 

 

 

   

 

 

 

Net long-term deferred tax liabilities

    (8,759     (8,479
 

 

 

   

 

 

 

Total deferred taxes

  $ (8,431   $ (8,341
 

 

 

   

 

 

 

Changes to valuation allowances, due to changes in judgment regarding the future realizability of deferred tax assets, were an increase of $23 million for 2012 and a decrease of $17 million for 2011. The following summarizes changes in the balance of valuation allowances on deferred tax assets:

 

                                                              
millions   2012     2011     2010  

Balance at January 1

  $ (555   $ (454   $ (418

Additions

    (426     (138     (49

Reductions

    59       37       13  
 

 

 

   

 

 

   

 

 

 

Balance at December 31

  $ (922   $ (555   $ (454
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

19.  Income Taxes (Continued)

 

Taxes receivable (payable) related to income tax expense (benefit) were as follows:

 

                                                 
millions   December 31,  

Balance Sheet Classification                    

  2012     2011  

Income taxes receivable

   

Accounts receivable—other

  $ 179     $ 597  

Other assets

    2       2  
 

 

 

   

 

 

 
    181       599  
 

 

 

   

 

 

 

Income taxes (payable)

   

Accrued expense

    (38     (248
 

 

 

   

 

 

 

Income taxes receivable (payable)

  $ 143     $ 351  
 

 

 

   

 

 

 

Tax carryforwards available for use on future income tax returns at December 31, 2012, were as follows:

 

                                                                          
millions   Domestic     Foreign     Expiration  

Net operating loss—federal

  $ 809     $        2031  

Net operating loss—foreign

  $     $ 884       2016 - Indefinite   

Net operating loss—state

  $ 4,560     $        2012-2031   

Alternative minimum tax credit—federal

  $ 17     $        Indefinite   

Foreign tax credits

  $ 433     $        2017-2021   

Texas margins tax credit

  $ 36     $        2026  

Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:

 

                                                                          
    Assets (Liabilities)  
millions   2012     2011     2010  

Balance at January 1

  $ (31   $ (32   $ (29

Increases related to prior-year tax positions

    (17           (13

Decreases related to prior-year tax positions

    3       3       8  

Increases related to current-year tax positions

    (1     (10      

Settlements

          8       2  
 

 

 

   

 

 

   

 

 

 

Balance at December 31

  $ (46   $ (31   $ (32
 

 

 

   

 

 

   

 

 

 

Included in the 2012 ending balance of unrecognized tax benefits presented above are potential benefits of $(40) million that would affect the effective tax rate on income if recognized. Also included in the 2012 ending balance are benefits of $(6) million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain. The Company estimates that $(5) million to $(29) million of unrecognized tax benefits related to adjustments to taxable income and credits previously recorded pursuant to the accounting standard for accounting for tax uncertainties will reverse within the next 12 months due to expiration of statutes of limitation and audit settlements.

The Company had approximately $28 million of accrued interest related to uncertain tax positions at December 31, 2012, and $18 million at December 31, 2011. The Company recognized interest and penalties in income tax expense (benefit) of $9 million during 2012 and $(8) million during 2011.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

19.  Income Taxes (Continued)

 

Anadarko is subject to audit by tax authorities in the U.S. federal, state, and local tax jurisdictions as well as in various foreign jurisdictions. The Company is currently under routine examination by the U.S. Internal Revenue Service for the tax years 2007, 2008, 2010, 2011, and 2012.

Income tax audits and the Company’s acquisition and divestiture activity have given rise to tax disputes in U.S. and foreign jurisdictions. See Note 17—Contingencies—Other Litigation. Management does not believe that the final resolution of outstanding tax audits and litigation will have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

The following lists the tax years subject to examination by major tax jurisdiction:

 

    Tax Year

United States

  2007, 2008, 2010-2012

China

  2008-2012

Algeria

  2009-2012

Ghana

  2006-2011

20.  Supplemental Cash Flow Information

The following summarizes cash paid (received) for interest (net of amounts capitalized) and income taxes, as well as non-cash investing and financing transactions:

 

                                                              
    Years Ended December 31,  
millions   2012     2011     2010  

Cash paid (received)

     

Interest

  $ 684     $ 806     $ 672  

Income taxes

    (300     262       308  

Non-cash investing activities

     

Fair value of properties and equipment received in
non-cash exchange transactions

  $ 65     $ 19     $ 37  

Gain related to the fair-value remeasurement of Anadarko’s
pre-acquisition 7% equity interest in the Wattenberg Plant

          21        

Non-cash financing activities

     

Capital lease obligation

  $      $ (118   $ 226  

21.  Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces natural gas, crude oil, condensate, and NGLs. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream activities, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells much of Anadarko’s production, as well as third-party purchased volumes.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

21.  Segment Information (Continued)

 

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; Deepwater Horizon settlement and related costs; Algeria exceptional profits tax settlement; Tronox-related contingent loss; unrealized (gains) losses on derivatives, net; and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests. The Company’s definition of Adjusted EBITDAX 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, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 17—Contingencies. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

 

    Years Ended December 31,  
millions   2012     2011     2010  

Income (loss) before income taxes

  $ 3,565     $ (3,424   $ 1,641  

Exploration expense

    1,946       1,076       974  

DD&A

    3,964       3,830       3,714  

Impairments

    389       1,774       216  

Deepwater Horizon settlement and related costs

    18       3,930       15  

Algeria exceptional profits tax settlement (1)

    (1,797              

Tronox-related contingent loss (1)

    (250     250       (95

Interest expense

    742       839       855  

Unrealized (gains) losses on derivatives, net

    377       616       (114

Realized (gains) losses on other derivatives, net (1)

    66       59         

Less net income attributable to noncontrolling interests

    54       81       60  
 

 

 

   

 

 

   

 

 

 

Consolidated Adjusted EBITDAX

  $ 8,966     $ 8,869     $ 7,146  
 

 

 

   

 

 

   

 

 

 

 

(1) 

In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

21.  Segment Information (Continued)

 

The Company’s accounting policies for individual segments are the same as those described in the summary of significant accounting policies, with the following exception: certain intersegment commodity contracts may meet the U.S. Generally Accepted Accounting Principles (GAAP) definition of a derivative instrument, which would be accounted for at fair value under GAAP. However, Anadarko does not recognize any mark-to-market adjustments on such intersegment arrangements. Additionally, intersegment asset transfers are accounted for at historical cost basis, and do not give rise to gain or loss recognition.

Information presented below as “Other and Intersegment Eliminations” includes results from hard-minerals non-operated joint ventures and royalty arrangements; and corporate, financing, and certain hedging activities. The following summarizes selected financial information for Anadarko’s reporting segments:

 

                                                                                                                                      
millions   Oil and Gas
Exploration
& Production
    Midstream     Marketing     Other and
Intersegment
Eliminations
    Total  

2012

         

Sales revenues

  $ 6,752     $ 325     $ 6,230     $     $ 13,307  

Intersegment revenues

    5,318       959       (5,734     (543      

Gains (losses) on divestitures and other, net

    (65     (8           177       104  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other

    12,005       1,276       496       (366     13,411  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses (1)

    3,505       748       616       295       5,164  

Realized (gains) losses on commodity derivatives, net

                      (753     (753

Other (income) expense, net (2)

                      (4     (4

Net income attributable to noncontrolling interests

          54                   54  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses and other

    3,505       802       616       (462     4,461  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Unrealized (gains) losses on derivatives, net included in marketing revenue

                16             16  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

  $ 8,500     $ 474     $ (104   $ 96     $ 8,966  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net properties and equipment

  $ 31,939     $ 4,459     $ 94     $ 1,906     $ 38,398  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures

  $ 5,836     $ 1,250     $ 70     $ 155     $ 7,311  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Goodwill

  $ 5,317     $ 175     $     $     $ 5,492  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

21.  Segment Information (Continued)

 

                                                                                                                                      
millions   Oil and Gas
Exploration
& Production
    Midstream     Marketing     Other and
Intersegment
Eliminations
    Total  

2011

         

Sales revenues

  $ 7,519     $ 342     $ 6,023     $ (2   $ 13,882  

Intersegment revenues

    5,005       957       (5,515     (447      

Gains (losses) on divestitures and other, net

    (41     (13           139       85  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other

    12,483       1,286       508       (310     13,967  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses (1)

    3,696       786       559       186       5,227  

Realized (gains) losses on commodity derivatives, net

                      (226     (226

Other (income) expense, net (2)

                      4       4  

Net income attributable to noncontrolling interests

          81                   81  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses and other

    3,696       867       559       (36     5,086  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Unrealized (gains) losses on derivatives, net included in marketing revenue

                (12           (12
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

  $ 8,787     $ 419     $ (63   $ (274   $ 8,869  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net properties and equipment

  $ 32,235     $ 3,432     $ 9     $ 1,825     $ 37,501  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures

  $ 5,026     $ 1,420     $     $ 107     $ 6,553  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Goodwill

  $ 5,475     $ 166     $     $     $ 5,641  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2010

         

Sales revenues

  $ 5,613     $ 192     $ 5,037     $     $ 10,842  

Intersegment revenues

    4,136       831       (4,572     (395      

Gains (losses) on divestitures and other, net

                      142       142  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other

    9,749       1,023       465       (253     10,984  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses (1)

    2,963       655       457       221       4,296  

Realized (gains) losses on commodity derivatives, net

                      (498     (498

Other (income) expense, net (2)

                      (24     (24

Net income attributable to noncontrolling interests

          60                   60  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses and other

    2,963       715       457       (301     3,834  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Unrealized (gains) losses on derivatives, net included in marketing revenue

                (4           (4
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

  $ 6,786     $ 308     $ 4     $ 48     $ 7,146  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net properties and equipment

  $ 32,850     $ 3,303     $ 9     $ 1,795     $ 37,957  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures

  $ 4,672     $ 384     $     $ 113     $ 5,169  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Goodwill

  $ 5,143     $ 139     $     $     $ 5,282  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Operating costs and expenses exclude exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

(2)

Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

In 2012, sales to Total SA were $1.9 billion, including $532 million that was reported as a reduction to the Algeria exceptional profits tax settlement included on the Company’s Consolidated Balance Sheet. These amounts are included in the oil and gas exploration and production reporting segment. In 2011 and 2010, there were no sales to individual customers that exceeded 10% of the Company’s total sales revenues.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

21.  Segment Information (Continued)

 

The following represents Anadarko’s sales revenues (based on the origin of the sales) and net properties and equipment by geographic area:

 

                                                              
    Years Ended December 31,  
millions   2012     2011     2010  

Sales Revenues

     

United States

  $ 9,911     $ 10,477     $ 8,806  

Algeria

    2,182       2,258       1,582  

Other International

    1,214       1,147       454  
 

 

 

   

 

 

   

 

 

 

Total

  $ 13,307     $ 13,882     $ 10,842  
 

 

 

   

 

 

   

 

 

 

 

                                         
    December 31,  
millions   2012     2011  

Net Properties and Equipment

   

United States

  $ 33,337     $ 33,050  

Algeria

    1,575       1,416  

Other International

    3,486       3,035  
 

 

 

   

 

 

 

Total

  $ 38,398     $ 37,501  
 

 

 

   

 

 

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is non-contributory.

In 2012, the Company made contributions of $101 million to its funded pension plans, $6 million to its unfunded pension plans, and $19 million to its unfunded other postretirement benefit plans. While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2012, the Company monitors the funded status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. The Company expects to contribute approximately $81 million to its funded pension plans, approximately $45 million to its unfunded pension plans, and approximately $16 million to its unfunded other postretirement benefit plans in 2013.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)

 

The following sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2012 and 2011, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2012 and 2011:

 

                                                                           
    Pension Benefits     Other Benefits  
millions   2012     2011     2012     2011  

Change in benefit obligation

       

Benefit obligation at beginning of year

  $ 2,024     $ 1,882     $ 354     $ 316  

Service cost

    76       78       9       9  

Interest cost

    85       85       16       16  

Plan amendments

          (12            

Actuarial (gain) loss

    224       94       (1     30  

Participant contributions

    1       1       3       4  

Benefit payments

    (117     (103     (22     (21

Foreign-currency exchange-rate changes

    4       (1            
 

 

 

   

 

 

   

 

 

   

 

 

 

Benefit obligation at end of year (1)

  $ 2,297     $ 2,024     $ 359     $ 354  
 

 

 

   

 

 

   

 

 

   

 

 

 

Change in plan assets

       

Fair value of plan assets at beginning of year

  $ 1,308     $ 1,104     $     $  

Actual return on plan assets

    159       (4            

Employer contributions

    107       311       19       17  

Participant contributions

    1       1       3       4  

Benefit payments

    (117     (103     (22     (21

Foreign-currency exchange-rate changes

    4       (1            
 

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets at end of year

  $ 1,462     $ 1,308     $     $  
 

 

 

   

 

 

   

 

 

   

 

 

 

Funded status of the plans at end of year

  $ (835   $ (716   $ (359   $ (354
 

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized amounts in the balance sheet consist of

       

Other assets

  $ 30     $ 11     $     $  

Accrued expenses

    (44     (33     (16     (18

Other long-term liabilities—other

    (821     (694     (343     (336
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ (835   $ (716   $ (359   $ (354
 

 

 

   

 

 

   

 

 

   

 

 

 

Total recognized amounts in accumulated other comprehensive income consist of

       

Prior service cost (credit)

  $ (2   $ (2   $ 3     $ 5  

Net actuarial (gain) loss

    916       853       (4     (4
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 914     $ 851     $ (1   $ 1  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

The accumulated benefit obligation for all defined-benefit pension plans was $2.1 billion at December 31, 2012, and $1.9 billion at December 31, 2011.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)

 

The following summarizes the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets for the years ended December 31:

 

                                             
    Pension Benefits  
millions   2012     2011  

Projected benefit obligation

  $ 2,198     $ 1,925  

Accumulated benefit obligation

    2,054       1,818  

Fair value of plan assets

    1,333       1,198  

The following summarizes the Company’s pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31:

 

                                                                                                     
    Pension Benefits     Other Benefits  
millions   2012     2011     2010     2012     2011     2010  

Components of net periodic benefit cost

           

Service cost

  $ 76     $ 78     $ 69     $ 9     $ 9     $ 9  

Interest cost

    85       85       84       16       16       16  

Expected return on plan assets

    (91     (85     (80                  

Amortization of net actuarial loss (gain)

    93       85       65                   (3

Amortization of net prior service cost (credit)

          2       3       2             (1
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit cost

  $ 163     $ 165     $ 141     $ 27     $ 25     $ 21  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in other comprehensive income (expense)

           

Net actuarial gain (loss)

  $ (156   $ (183   $ (151   $ 1     $ (30   $ 8  

Amortization of net actuarial (gain) loss

    93       85       65                   (3

Net prior service (cost) credit

          12       (6                  

Amortization of net prior service cost (credit)

          2       3       2             (1
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total amounts recognized in other comprehensive income (expense)

  $ (63   $ (84   $ (89   $ 3     $ (30   $ 4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

In 2013, an estimated $116 million of net actuarial loss and $1 million of net prior service cost for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)

 

The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations at December 31:

 

                                                                                   
    Pension Benefits     Other Benefits  
    2012     2011     2012     2011  

Discount rate

    3.50     4.50     4.00     4.75

Rates of increase in compensation levels

    4.50     4.50     4.50     4.50

Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. Discount-rate selection for measurements prior to December 31, 2011, was based on a similar cash-flow-matching analysis, although, instead of using a portfolio of select high-quality fixed-income securities to determine the effective settlement rate for a given plan obligation, the Company relied primarily on a published yield curve derived from market-observed yields for a universe of high-quality bonds. Both methods are acceptable and result in a discount-rate assumption that represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. However, the Company believes a discount rate reflecting yields for high-quality fixed-income securities better corresponds to the Company’s expectations as to the amount and timing of its benefit payments. Assumed rates of compensation increases for active participants vary by age group, with the resulting weighted-average assumed rate (weighted by the plan-level benefit obligation) provided in the preceding table.

The following summarizes the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost:

 

                                                                                                     
    Pension Benefits     Other Benefits  
    2012     2011     2010     2012     2011     2010  

Discount rate

      4.50       4.75       5.25       4.75       5.25       5.50

Long-term rate of return on plan assets

    7.00     7.00     7.50     N/A        N/A        N/A   

Rates of increase in compensation levels

    4.50     5.00     5.00     4.50     5.00     5.00

At December 31, 2012, an 8.00% annual rate of increase in the per-capita cost of covered health care benefits for 2013 was assumed for purposes of measuring other postretirement benefit obligations. At December 31, 2011, a 9.00% annual rate of increase in the per-capita cost of covered health care benefits for 2012 was assumed for purposes of measuring other postretirement benefit obligations. This rate is expected to gradually decrease to 5.00% in 2018 and beyond. The assumed health care cost trend rate can have a significant effect on the cost and obligation amounts reported for the health care plan. A 1% change in the assumed health care cost trend rate over the projected period would have the following effects:

 

                                                 
millions   1% Increase     1% Decrease  

Effect on total of service and interest cost components

  $ 3     $ (2

Effect on other postretirement benefit obligation

  $ 28     $ (24

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)

 

Plan Assets

Investment Policies and Strategies  The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (domestic large- and small-capitalization equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 45%-55% equity securities, 20%-30% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines.

Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ collective fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2012 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach, while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, and inflation. Returns on fixed-income securities are generally developed based on expected inflation, real bond yield, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are derived from their relationship to the equity and fixed-income markets.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)

 

The fair value of the Company’s pension plan assets by asset category and input level within the fair-value hierarchy were as follows:

 

                                                                                   
millions                        
December 31, 2012   Level 1     Level 2     Level 3     Total  

Investments

       

Cash and cash equivalents

  $ 23      $ 36      $      $ 59   

Fixed income

       

Mortgage-backed securities

           63               63   

U.S. government securities

           54               54   

Other fixed-income securities (1)

    40        196               236   

Equity securities

       

Domestic

    313        109               422   

International

    112        238               350   

Other

       

Real estate

           46        78        124   

Private equity

                  64        64   

Hedge funds and other alternative strategies

    20               77        97   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total investments (2)

  $ 508      $ 742      $ 219      $ 1,469   
 

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities

       

Hedge funds and other alternative strategies

  $ (11   $      $      $ (11
 

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

  $ (11   $      $      $ (11
 

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

       

Investments

       

Cash and cash equivalents

  $ 37     $ 54     $     $ 91  

Fixed income

       

Mortgage-backed securities

          66             66  

U.S. government securities

    1       49             50  

Other fixed-income securities (1)

    36       171             207  

Equity securities

       

Domestic

    265       94             359  

International

    91       203             294  

Other

       

Real estate

          37       72       109  

Private equity

                55       55  

Hedge funds and other alternative strategies

    26             64       90  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total investments (3)

  $ 456     $ 674     $ 191     $ 1,321  
 

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities

       

Hedge funds and other alternative strategies

  $ (12   $     $     $ (12
 

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

  $ (12   $     $     $ (12
 

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities.

(2) 

Amount excludes net receivables of $4 million, primarily related to Level 1 investments.

(3) 

Amount excludes net payables of $1 million, primarily related to Level 1 investments.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)

 

Investments in securities traded in active markets are measured based on quoted prices, which represent Level 1 inputs. Investments based on Level 2 inputs include direct investments in corporate debt and other fixed-income securities, as well as shares of open-end mutual funds or similar investment vehicles that do not have a readily determinable fair value, but are valued at the net asset value per share (NAV). For such funds, the NAV is the value at which investors transact with the fund, and is determined by the fund based on the estimated fair values of the underlying fund assets. Fair value of investments included as Level 3 inputs generally also reflect investments valued at fund NAVs, but, unlike investments characteristic of Level 2 fair-value measurements, such plan assets have significant liquidity restrictions or other features that are not reflected in NAV.

The following summarizes changes in the fair value of investments based on Level 3 inputs:

 

                                                                                                           
millions   Hedge Funds
and Other
Alternative
Strategies
    Private
Equity
    Real Estate     Total  

Balance at January 1, 2012

  $ 64     $ 55     $ 72     $ 191  

Acquisitions (dispositions), net

    9       4       2       15  

Actual return on plan assets

       

Relating to assets sold during the reporting period

    (2     2              

Relating to assets still held at the reporting date

    6       3       4       13  
 

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2012

  $ 77     $ 64     $ 78     $ 219  
 

 

 

   

 

 

   

 

 

   

 

 

 

Balance at January 1, 2011

  $ 49     $ 41     $ 9     $ 99  

Acquisitions (dispositions), net

    17       6       60       83  

Actual return on plan assets

       

Relating to assets sold during the reporting period

    (1     1              

Relating to assets still held at the reporting date

    (1     7       3       9  
 

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2011

  $ 64     $ 55     $ 72     $ 191  
 

 

 

   

 

 

   

 

 

   

 

 

 

Risks and Uncertainties  The plan assets include various investment securities that are exposed to various risks, such as interest-rate, credit, and market risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of investment securities could significantly impact the plan assets.

The plan assets may include securities with contractual cash flows, such as asset-backed securities, collateralized mortgage obligations, and commercial mortgage-backed securities, including securities backed by subprime mortgage loans. The value, liquidity, and related income of those securities are sensitive to changes in economic conditions, including real estate value, delinquencies, or defaults, or both, and may be adversely affected by shifts in the market’s perception of the issuers and changes in interest rates.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

 

22.  Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)

 

Expected Benefit Payments

The following summarizes estimated benefit payments for the next ten years, including benefit increases due to continuing employee service:

 

                                         
millions   Pension
Benefit
Payments
    Other
Benefit
Payments
 

2013

  $ 269     $ 16  

2014

    257       18  

2015

    248       19  

2016

    240       20  

2017

    230       22  

2018-2022

    901       117  

Defined-Contribution Plans  The Company maintains several defined-contribution benefit plans, including the Anadarko Employee Savings Plan (ESP). All regular employees of the Company on its U.S. payroll are eligible to participate in the ESP by making elective contributions that are matched by the Company, subject to certain limitations. The Company recognized expense of $55 million for 2012, $41 million for 2011, and $40 million for 2010, related to these plans.

 

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ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL QUARTERLY INFORMATION

(Unaudited)

Quarterly Financial Data

The following summarizes quarterly financial data for 2012 and 2011:

 

                                                                   
millions except per-share amounts   First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
 

2012

       

Sales revenues

  $ 3,412     $ 3,200     $ 3,283     $ 3,412  

Gains (losses) on divestitures and other, net

    35       22       49       (2

Algeria exceptional profits tax settlement

    (1,804           7        

Deepwater Horizon settlement and related costs

    8       3       4       3  

Operating income (loss)

    2,702       (279     816       488  

Net income (loss)

    2,183       (70     142       190  

Net income (loss) attributable to noncontrolling interests

    27       19       21       (13

Net income (loss) attributable to common stockholders

    2,156       (89     121       203  

Earnings per share:

       

Net income (loss) attributable to common stockholders—basic

  $ 4.30     $ (0.18   $ 0.24     $ 0.40  

Net income (loss) attributable to common stockholders—diluted

  $ 4.28     $ (0.18   $ 0.24     $ 0.40  

Average number common shares outstanding—basic

    499       500       500       500  

Average number common shares outstanding—diluted

    501       500       502       502  

2011

       

Sales revenues

  $ 3,224     $ 3,734     $ 3,384     $ 3,540  

Gains (losses) on divestitures and other, net

    29       (58     (185     299  

Deepwater Horizon settlement and related costs

    26       9       4,042       (147

Operating income (loss)

    896       1,001       (3,626     (141

Net income (loss)

    237       562       (3,028     (339

Net income attributable to noncontrolling interests

    21       18       23       19  

Net income (loss) attributable to common stockholders

    216       544       (3,051     (358

Earnings per share:

       

Net income (loss) attributable to common stockholders—basic

  $ 0.43     $ 1.09     $ (6.12   $ (0.72

Net income (loss) attributable to common stockholders—diluted

  $ 0.43     $ 1.08     $ (6.12   $ (0.72

Average number common shares outstanding—basic

    497       498       498       498  

Average number common shares outstanding—diluted

    499       500       498       498  

 

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ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

The unaudited supplemental information on oil and gas exploration and production activities for 2012, 2011, and 2010 has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas and the Securities and Exchange Commission’s final rule, Modernization of Oil and Gas Reporting. Disclosures by geographic area include the United States and International. The International geographic area consists of proved reserves located in Algeria, Ghana, and China.

Oil and Gas Reserves

The following reserves disclosures reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests, of natural gas, oil, condensate, and NGLs owned at each year end and changes in proved reserves during each of the last three years. Natural-gas volumes are presented in billion cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate, and NGLs are presented in millions of barrels (MMBbls). 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 reserves volumes.

Reserves for international locations are calculated in accordance with the terms of governing agreements. The international reserves include estimated quantities allocated to Anadarko for recovery of costs and income taxes and Anadarko’s net equity share after recovery of such costs.

The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, prices, economic conditions, and governmental restrictions.

In 2012, Anadarko added 82 MMBOE of proved reserves through extensions and discoveries as the result of successful drilling in the United States. Reserves revisions for 2012 include an increase of 352 MMBOE primarily related to successful infill drilling in the large onshore areas, such as the Greater Natural Buttes, Wattenberg, and Carthage, and a decrease of 68 MMBOE associated with lower commodity prices. Sales of proved reserves in place were 81 MMBOE, related to domestic assets.

In 2011, Anadarko added 174 MMBOE of proved reserves primarily as the result of successful drilling in the United States. Reserves revisions for 2011 include an increase of 210 MMBOE primarily related to successful infill drilling in the large onshore areas, such as the Greater Natural Buttes, Wattenberg, and Pinedale fields, and an increase of 8 MMBOE driven by higher oil prices. Sales of proved reserves in place were 29 MMBOE, related to onshore domestic assets.

In 2010, Anadarko added 83 MMBOE of proved reserves primarily as the result of successful drilling in the United States. Reserves revisions for 2010 include an increase of 246 MMBOE primarily related to successful infill drilling in the large onshore natural-gas plays, such as the Greater Natural Buttes, Wattenberg, and Pinedale fields, and an increase of 29 MMBOE driven by higher oil and gas prices. Sales of proved reserves in place were 6 MMBOE, related to onshore domestic and international assets.

Prices used to compute the information presented in the tables below are adjusted only for fixed and determinable amounts under provisions in existing contracts. These prices, before adjustments, were $2.76, $4.12, and $4.38 per MMBtu of natural gas and $94.71, $96.19, and $79.43 per barrel of oil for 2012, 2011, and 2010.

 

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ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Oil and Gas Reserves (Continued)

 

                                                                                                                                                                 
    Natural Gas
(Bcf)
    Oil and Condensate
(MMBbls)
 
    United States     International     Total     United States     International     Total  

Proved Reserves

           

December 31, 2009

    7,764             7,764       500       233       733  

Revisions of prior estimates

    851             851       32       44       76  

Extensions, discoveries, and other additions

    363             363       13             13  

Purchases in place

    7             7                    

Sales in place

    (39           (39                  

Production

    (829           (829     (47     (26     (73
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2010

    8,117             8,117       498       251       749  

Revisions of prior estimates

    550             550       44       14       58  

Extensions, discoveries, and other additions

    614             614       52             52  

Purchases in place

                                   

Sales in place

    (64           (64     (10           (10

Production

    (852           (852     (48     (30     (78
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

    8,365             8,365       536       235       771  

Revisions of prior estimates

    635             635       62       52       114  

Extensions, discoveries, and other additions

    418             418       9             9  

Purchases in place

    26             26                    

Sales in place

    (199           (199     (42           (42

Production

    (916           (916     (54     (31     (85
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2012

    8,329             8,329       511       256       767  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed Reserves

           

December 31, 2009

    5,884             5,884       300       144       444  

December 31, 2010

    5,982             5,982       303       150       453  

December 31, 2011

    6,113             6,113       352       173       525  

December 31, 2012

    6,445             6,445       318       208       526  

Proved Undeveloped Reserves

           

December 31, 2009

    1,880             1,880       200       89       289  

December 31, 2010

    2,135             2,135       195       101       296  

December 31, 2011

    2,252             2,252       184       62       246  

December 31, 2012

    1,884             1,884       193       48       241  

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Oil and Gas Reserves (Continued)

 

                                                                                                                                                                 
    NGLs
(MMBbls)
    Total
(MMBOE)
 
    United States     International     Total     United States     International     Total  

Proved Reserves

           

December 31, 2009

    260       17       277       2,054       250       2,304  

Revisions of prior estimates (1)

    60       (4     56       235       40       275  

Extensions, discoveries, and other additions

    10             10       83             83  

Purchases in place

                      1             1  

Sales in place

                      (6           (6

Production

    (23           (23     (209     (26     (235
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2010

    307       13       320       2,158       264       2,422  

Revisions of prior estimates (1)

    68             68       204       14       218  

Extensions, discoveries, and other additions

    20             20       174             174  

Purchases in place

                                   

Sales in place

    (8           (8     (29           (29

Production

    (26           (26     (216     (30     (246
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

    361       13       374       2,291       248       2,539  

Revisions of prior estimates (1)

    65       (1     64       233       51       284  

Extensions, discoveries, and other additions

    3             3       82             82  

Purchases in place

                      4             4  

Sales in place

    (6           (6     (81           (81

Production

    (30           (30     (237     (31     (268
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2012

    393       12       405       2,292       268       2,560  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed Reserves

           

December 31, 2009

    199             199       1,480       144       1,624  

December 31, 2010

    222             222       1,523       150       1,673  

December 31, 2011

    267             267       1,638       173       1,811  

December 31, 2012

    283             283       1,675       208       1,883  

Proved Undeveloped Reserves

           

December 31, 2009

    61       17       78       574       106       680  

December 31, 2010

    85       13       98       635       114       749  

December 31, 2011

    94       13       107       653       75       728  

December 31, 2012

    110       12       122       617       60       677  

 

(1)

Revisions of prior estimates include additions generated by Anadarko’s infill drilling programs of 383 MMBOE for 2012, 203 MMBOE for 2011, and 312 MMBOE for 2010.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Capitalized Costs

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. Capitalized costs associated with activities of the Company’s midstream and marketing reporting segments, and other corporate activities are not included.

 

                                                                                      
millions   United States     International     Total  

December 31, 2012

     

Capitalized

     

Unproved properties

  $ 5,188     $ 1,922     $ 7,110  

Proved properties

    43,016       4,969       47,985  
 

 

 

   

 

 

   

 

 

 
    48,204       6,891       55,095  

Less accumulated DD&A

    21,206       1,950       23,156  
 

 

 

   

 

 

   

 

 

 

Net capitalized costs

  $ 26,998     $ 4,941     $ 31,939  
 

 

 

   

 

 

   

 

 

 

December 31, 2011

     

Capitalized

     

Unproved properties

  $ 7,020     $ 1,328     $ 8,348  

Proved properties

    39,711       4,652       44,363  
 

 

 

   

 

 

   

 

 

 
    46,731       5,980       52,711  

Less accumulated DD&A

    18,908       1,568       20,476  
 

 

 

   

 

 

   

 

 

 

Net capitalized costs

  $ 27,823     $ 4,412     $ 32,235  
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities. Costs associated with activities of the Company’s midstream and marketing reporting segments, and other corporate activities are not included.

 

                                                                                      
millions   United States     International     Total  

Year Ended December 31, 2012

     

Property acquisitions

     

Unproved

  $ 224     $ 15     $ 239  

Proved

                 

Exploration

    1,064       1,000       2,064  

Development

    3,592       472       4,064  
 

 

 

   

 

 

   

 

 

 

Total costs incurred

  $ 4,880     $ 1,487     $ 6,367  
 

 

 

   

 

 

   

 

 

 

Year Ended December 31, 2011

     

Property acquisitions

     

Unproved

  $ 610     $ 37     $ 647  

Proved

                 

Exploration

    666       803       1,469  

Development

    2,970       555       3,525  
 

 

 

   

 

 

   

 

 

 

Total costs incurred

  $ 4,246     $ 1,395     $ 5,641  
 

 

 

   

 

 

   

 

 

 

Year Ended December 31, 2010

     

Property acquisitions

     

Unproved

  $ 428     $ 91     $ 519  

Proved

    22             22  

Exploration

    693       585       1,278  

Development

    2,368       899       3,267  
 

 

 

   

 

 

   

 

 

 

Total costs incurred

  $ 3,511     $ 1,575     $ 5,086  
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Results of Operations

Results of operations for producing activities consist of all activities within the oil and gas exploration and production reporting segment. Net revenues from production include only the revenues from the production and sale of natural gas, oil, condensate, and NGLs. Gains (losses) on property dispositions represent net gains or losses on sales of oil and gas properties. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining unproved leaseholds. Algeria exceptional profits tax settlement represents the Company’s resolution of the Algeria exceptional profits tax dispute with Sonatrach, which provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. Deepwater Horizon settlement and related costs represents the Company’s $4.0 billion settlement with BP, and associated legal and other costs, net of related insurance recoveries. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion, and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

 

                                                                          
millions   United States     International     Total  

Year Ended December 31, 2012

     

Net revenues from production

     

Third-party sales

  $ 6,233     $ 846     $ 7,079  

Sales to consolidated affiliates

    2,767       2,550       5,317  

Gains (losses) on property dispositions

    (16     (48     (64
 

 

 

   

 

 

   

 

 

 
    8,984       3,348       12,332  

Production costs

     

Oil and gas operating

    786       190       976  

Oil and gas transportation and other

    931       22       953  

Production-related general and administrative expenses

    318       18       336  

Other taxes

    581       599       1,180  
 

 

 

   

 

 

   

 

 

 
    2,616       829       3,445  

Exploration expenses

    1,484       462       1,946  

Depreciation, depletion, and amortization

    3,320       390       3,710  

Impairments related to oil and gas properties

    364             364  

Algeria exceptional profits tax settlement

          (1,797     (1,797

Deepwater Horizon settlement and related costs

    18             18  
 

 

 

   

 

 

   

 

 

 
    1,182       3,464       4,646  

Income tax expense

    433       943       1,376  
 

 

 

   

 

 

   

 

 

 

Results of operations

  $ 749     $ 2,521     $ 3,270  
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Results of Operations (Continued)

 

                                                                                      
millions   United States     International     Total  

Year Ended December 31, 2011

     

Net revenues from production

     

Third-party sales

  $ 5,778     $ 2,051     $ 7,829  

Sales to consolidated affiliates

    3,652       1,353       5,005  

Gains (losses) on property dispositions

    (495     454       (41
 

 

 

   

 

 

   

 

 

 
    8,935       3,858       12,793  

Production costs

     

Oil and gas operating

    862       131       993  

Oil and gas transportation and other

    867       23       890  

Production-related general and administrative expenses

    322       20       342  

Other taxes

    646       811       1,457  
 

 

 

   

 

 

   

 

 

 
    2,697       985       3,682  

Exploration expenses

    688       388       1,076  

Depreciation, depletion, and amortization

    3,193       391       3,584  

Impairments related to oil and gas properties

    1,225             1,225  

Deepwater Horizon settlement and related costs

    3,930             3,930  
 

 

 

   

 

 

   

 

 

 
    (2,798     2,094       (704

Income tax expense

    (1,015     1,027       12  
 

 

 

   

 

 

   

 

 

 

Results of operations

  $ (1,783   $ 1,067     $ (716
 

 

 

   

 

 

   

 

 

 

Year Ended December 31, 2010

     

Net revenues from production

     

Third-party sales

  $ 4,369     $ 1,504     $ 5,873  

Sales to consolidated affiliates

    3,604       532       4,136  

Gains (losses) on property dispositions

    33       (7     26  
 

 

 

   

 

 

   

 

 

 
    8,006       2,029       10,035  

Production costs

     

Oil and gas operating

    744       86       830  

Oil and gas transportation and other

    792       22       814  

Production-related general and administrative expenses

    274       16       290  

Other taxes

    456       581       1,037  
 

 

 

   

 

 

   

 

 

 
    2,266       705       2,971  

Exploration expenses

    677       297       974  

Depreciation, depletion and amortization

    3,281       204       3,485  

Impairments related to oil and gas properties

    145             145  

Deepwater Horizon settlement and related costs

    15             15  
 

 

 

   

 

 

   

 

 

 
    1,622       823       2,445  

Income tax expense

    565       563       1,128  
 

 

 

   

 

 

   

 

 

 

Results of operations

  $ 1,057     $ 260     $ 1,317  
 

 

 

   

 

 

   

 

 

 

 

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ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Standardized Measure of Discounted Future Net Cash Flows

Estimates of future net cash flows from proved reserves of natural gas, oil, condensate, and NGLs for 2012, 2011, and 2010 are computed using the average first-day-of-the-month price during the 12-month period for the respective year. Prices used to compute the information presented in the tables below are adjusted only for fixed and determinable amounts under provisions in existing contracts. These prices, before adjustments, were $2.76, $4.12, and $4.38 per MMBtu of natural gas and $94.71, $96.19, and $79.43 per barrel of oil, for 2012, 2011, and 2010. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, and abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows, giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense. The 10% discount factor is prescribed by U.S. Generally Accepted Accounting Principles.

The present value of future net cash flows is not an estimate of the fair value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves, and a discount factor more representative of the time value of money and the risks inherent in producing oil and natural gas. Significant changes in estimated reserves volumes or commodity prices could have a material effect on the Company’s Consolidated Financial Statements.

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

 

                                                                                      
millions   United States     International     Total  

December 31, 2012

     

Future cash inflows

  $ 86,129     $ 29,268     $ 115,397  

Future production costs

    29,356       6,239       35,595  

Future development costs

    9,195       606       9,801  

Future income tax expenses

    16,804       9,035       25,839  
 

 

 

   

 

 

   

 

 

 

Future net cash flows

    30,774       13,388       44,162  

10% annual discount for estimated timing of cash flows

    13,236       4,612       17,848  
 

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

  $ 17,538     $ 8,776     $ 26,314  
 

 

 

   

 

 

   

 

 

 

December 31, 2011

     

Future cash inflows

  $ 98,615     $ 27,351     $ 125,966  

Future production costs

    30,385       8,342       38,727  

Future development costs

    10,534       995       11,529  

Future income tax expenses

    20,391       8,101       28,492  
 

 

 

   

 

 

   

 

 

 

Future net cash flows

    37,305       9,913       47,218  

10% annual discount for estimated timing of cash flows

    17,132       3,630       20,762  
 

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

  $ 20,173     $ 6,283     $ 26,456  
 

 

 

   

 

 

   

 

 

 

December 31, 2010

     

Future cash inflows

  $ 82,793     $ 20,633     $ 103,426  

Future production costs

    26,245       6,989       33,234  

Future development costs

    8,041       1,040       9,081  

Future income tax expenses

    16,512       5,543       22,055  
 

 

 

   

 

 

   

 

 

 

Future net cash flows

    31,995       7,061       39,056  

10% annual discount for estimated timing of cash flows

    15,008       2,550       17,558  
 

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

  $ 16,987     $ 4,511     $ 21,498  
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

 

                                                                                      
millions   United States     International     Total  

2012

     

Balance at January 1

  $ 20,173     $ 6,283     $ 26,456  

Sales and transfers of oil and gas produced, net of production costs

    (6,384     (2,571     (8,955

Net changes in prices and production costs

    (7,948     (391     (8,339

Changes in estimated future development costs

    (744     (70     (814

Extensions, discoveries, additions, and improved recovery, less related costs

    963             963  

Development costs incurred during the period

    1,103       357       1,460  

Revisions of previous quantity estimates

    5,026       4,390       9,416  

Purchases of minerals in place

    (9           (9

Sales of minerals in place

    (763           (763

Accretion of discount

    3,063       1,139       4,202  

Net change in income taxes

    1,285       (759     526  

Other

    1,773       398       2,171  
 

 

 

   

 

 

   

 

 

 

Balance at December 31

  $ 17,538     $ 8,776     $ 26,314  
 

 

 

   

 

 

   

 

 

 

2011

     

Balance at January 1

  $ 16,987     $ 4,511     $ 21,498  

Sales and transfers of oil and gas produced, net of production costs

    (6,733     (2,420     (9,153

Net changes in prices and production costs

    2,424       4,777       7,201  

Changes in estimated future development costs

    32       (709     (677

Extensions, discoveries, additions, and improved recovery, less related costs

    3,040             3,040  

Development costs incurred during the period

    561       442       1,003  

Revisions of previous quantity estimates

    5,438       313       5,751  

Purchases of minerals in place

    1             1  

Sales of minerals in place

    (560           (560

Accretion of discount

    2,519       800       3,319  

Net change in income taxes

    (2,254     (1,611     (3,865

Other

    (1,282     180       (1,102
 

 

 

   

 

 

   

 

 

 

Balance at December 31

  $ 20,173     $ 6,283     $ 26,456  
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves (Continued)

 

                                                                                      
millions   United States     International     Total  

2010

     

Balance at January 1

  $ 11,525     $ 2,028     $ 13,553  

Sales and transfers of oil and gas produced, net of production costs

    (5,707     (1,331     (7,038

Net changes in prices and production costs

    6,645       2,704       9,349  

Changes in estimated future development costs

    (516     (185     (701

Extensions, discoveries, additions, and improved recovery, less related costs

    1,150             1,150  

Development costs incurred during the period

    424       811       1,235  

Revisions of previous quantity estimates

    4,181       1,235       5,416  

Purchases of minerals in place

    8             8  

Sales of minerals in place

    (61     (5     (66

Accretion of discount

    1,673       421       2,094  

Net change in income taxes

    (3,001     (1,305     (4,306

Other

    666       138       804  
 

 

 

   

 

 

   

 

 

 

Balance at December 31

  $ 16,987     $ 4,511     $ 21,498  
 

 

 

   

 

 

   

 

 

 

 

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Index to Financial Statements

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.  Controls and Procedures

EVALUATION AND DISCLOSURE CONTROLS AND PROCEDURES

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2012.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Form 10-K.

ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM

See Report of Independent Registered Public Accounting Firm under Item 8 of this Form 10-K.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in Anadarko’s internal control over financial reporting during the fourth quarter of 2012 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B.  Other Information

None.

 

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PART III

Item 10.  Directors, Executive Officers, and Corporate Governance

See Anadarko Board of Directors, Corporate Governance—Board of Directors, Corporate Governance—Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance in the Anadarko Petroleum Corporation Proxy Statement (Proxy Statement), for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 14, 2013 (to be filed with the Securities and Exchange Commission prior to April 4, 2013), each of which is incorporated herein by reference.

See list of Executive Officers of the Registrant under Items 1 and 2 of this Form 10-K, which is incorporated herein by reference.

The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company’s website located at www.anadarko.com/About/Pages/Governance.aspx. Any stockholder may request a printed copy of the Code of Ethics by submitting a written request to the Company’s Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.

Item 11.  Executive Compensation

See Corporate Governance—Board of Directors—Compensation and Benefits Committee Interlocks and Insider Participation, Corporate Governance—Board of Directors—Director Compensation, Corporate Governance—Director Compensation Table for 2012, Compensation and Benefits Committee Report on 2012 Executive Compensation, Compensation Discussion and Analysis and Executive Compensation in the Proxy Statement, each of which is incorporated herein by reference. The Compensation and Benefits Committee Report and related information incorporated by reference herein shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such 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.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

See Security Ownership of Certain Beneficial Owners and Management in the Proxy Statement, which is incorporated herein by reference.

See Securities Authorized for Issuance under Equity Compensation Plans under Item 5 of this Form 10-K, which is incorporated herein by reference.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

See Corporate Governance—Board of Directors and Transactions with Related Persons in the Proxy Statement, each of which is incorporated herein by reference.

Item 14.  Principal Accountant Fees and Services

See Independent Auditor in the Proxy Statement, which is incorporated herein by reference.

 

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PART IV

Item 15.  Exhibits, Financial Statement Schedules

 

a)

EXHIBITS

The following documents are filed as part of this report or incorporated by reference:

 

  (1)

The Consolidated Financial Statements of Anadarko Petroleum Corporation are listed on the Index to this report, page 88.

 

  (2)

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

 

Exhibit
Number

 

Description

 

Original Filed

Exhibit

 

File
Number

            2(i)   Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Acquisition Sub, Inc. and Kerr-McGee Corporation   2.2 to Form 8-K filed on June 26, 2006   1-8968
            3(i)   Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009   3.3 to Form 8-K filed on May 22, 2009   1-8968
              (ii)   By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 15, 2012   3.1 to Form 8-K filed on May 15, 2012   1-8968
            4(i)   Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A.   4.1 to Form 8-K filed on September 19, 2006   1-8968
              (ii)   Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.   4.1 to Form 8-K filed on October 6, 2006   1-8968
              (iii)   Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.   4.2 to Form 8-K filed on October 6, 2006   1-8968
              (iv)   Officers’ Certificate of Anadarko Petroleum Corporation, dated March 2, 2009, establishing the 7.625% Senior Notes due 2014 and the 8.700% Senior Notes due 2019   4.1 to Form 8-K filed on March 6, 2009   1-8968
              (v)   Form of 7.625% Senior Notes due 2014   4.2 to Form 8-K filed on March 6, 2009   1-8968
              (vi)   Form of 8.700% Senior Notes due 2019   4.3 to Form 8-K filed on March 6, 2009   1-8968
              (vii)   Officers’ Certificate of Anadarko Petroleum Corporation, dated June 9, 2009, establishing the 5.75% Senior Notes due 2014, the 6.95% Senior Notes due 2019 and the 7.95% Senior Notes due 2039   4.1 to Form 8-K filed on June 12, 2009   1-8968

 

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Exhibit
Number

 

Description

 

Original Filed

Exhibit

 

File
Number

            4(viii)   Form of 5.75% Senior Notes due 2014   4.2 to Form 8-K filed on June 12, 2009   1-8968
              (ix)   Form of 6.95% Senior Notes due 2019   4.3 to Form 8-K filed on June 12, 2009   1-8968
              (x)   Form of 7.95% Senior Notes due 2039   4.4 to Form 8-K filed on June 12, 2009   1-8968
              (xi)   Officers’ Certificate of Anadarko Petroleum Corporation dated March 9, 2010, establishing the 6.200% Senior Notes due 2040   4.1 to Form 8-K filed on March 16, 2010   1-8968
              (xii)   Form of 6.200% Senior Notes due 2040   4.2 to Form 8-K filed on March 16, 2010   1-8968
              (xiii)   Officers’ Certificate of Anadarko Petroleum Corporation dated August 9, 2010, establishing the 6.375% Senior Notes due 2017   4.1 to Form 8-K filed on August 12, 2010   1-8968
              (xiv)   Form of 6.375% Senior Notes due 2017   4.2 to Form 8-K filed on August 12, 2010   1-8968
†        10(i)   1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998   Appendix A to DEF 14A filed on March 16, 1998   1-8968
†            (ii)   Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement   10.1 to Form 8-K filed on November 17, 2005   1-8968
†            (iii)   Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan   Appendix A to DEF 14A filed on March 18, 2005   1-8968
†            (iv)   Form of Anadarko Petroleum Corporation Executive 1999 Stock Incentive Plan Stock Option Agreement   10.2 to Form 8-K filed on November 17, 2005   1-8968
†            (v)   Form of Anadarko Petroleum Corporation Non-Executive 1999 Stock Incentive Plan Stock Option Agreement   10.3 to Form 8-K filed on November 17, 2005   1-8968
†            (vi)   Form of Stock Option Agreement—1999 Stock Incentive Plan (UK Nationals)   10.4 to Form 8-K filed on November 17, 2005   1-8968
†            (vii)   Amendment to Stock Option Agreement Under the Anadarko Petroleum Corporation 1999 Stock Incentive Plan   10.1 to Form 8-K filed on January 23, 2007   1-8968
†            (viii)   Anadarko Petroleum Corporation 1999 Stock Incentive Plan (Amendment to Performance Unit Agreement)   10.3 to Form 8-K filed on November 13, 2007   1-8968

 

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Exhibit
Number

 

Description

 

Original Filed

Exhibit

 

File
Number

†          10(ix)   Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement   10(b)(xxiv) to Form 10-K for year ended December 31, 1999, filed on March 16, 2000   1-8968
†              (x)   Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Unit Award Letter   10.1 to Form 8-K filed on November 13, 2007   1-8968
†              (xi)   The Approved UK Sub-Plan of the Anadarko Petroleum Corporation 1999 Stock Incentive Plan   10(b)(xxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004   1-8968
†              (xii)   Key Employee Change of Control Contract   10(b)(xxii) to Form 10-K for year ended December 31, 1997, filed on March 18, 1998   1-8968
†              (xiii)   First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract   10(b) to Form 10-Q for quarter ended September 30, 2000, filed on November 13, 2000   1-8968
†              (xiv)   Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract   10(b)(ii) to Form 10-Q for quarter ended June 30, 2003, filed on August 11, 2003   1-8968
†              (xv)   Form of Key Employee Change of Control Contract (2011)   10(i) to Form 10-Q for quarter ended June 30, 2011, filed on July 27, 2011   1-8968
†              (xvi)   Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004—Robert J. Allison, Jr.   10(b)(xxxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004   1-8968
†              (xvii)   Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007)   10(xxii) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010   1-8968
†              (xviii)   Anadarko Retirement Restoration Plan (As Amended and Restated Effective as of November 7, 2007)   10.2 to Form 8-K filed on November 13, 2007   1-8968

 

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Exhibit
Number

 

Description

 

Original Filed

Exhibit

 

File
Number

†          10(xix)   Anadarko Petroleum Corporation Estate Enhancement Program   10(b)(xxxiv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999   1-8968
†              (xx)   Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives   10(b)(xxxv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999   1-8968
†              (xxi)   Estate Enhancement Program Agreements effective November 29, 2000   10(b)(xxxxii) to Form 10-K for year ended December 31, 2000, filed on March 15, 2001   1-8968
†              (xxii)   Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002   10(b)(xxxii) to Form 10-K for year ended December 31, 2002, filed on
March 14, 2003
  1-8968
†              (xxiii)   First Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective June 30, 2003   10(b)(xliii) to Form 10-K for year ended December 31, 2003, filed on
March 4, 2004
  1-8968
†              (xxiv)   Second Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective January 1, 2008   10(xxix) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010   1-8968
†              (xxv)   Anadarko Petroleum Corporation Officer Severance Plan   10(b)(iv) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003   1-8968
†              (xxvi)   Form of Termination Agreement and Release of All Claims Under Officer Severance Plan   10(b)(v) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003   1-8968
†              (xxvii)   Form of Director and Officer Indemnification Agreement   10 to Form 8-K filed on September 3, 2004   1-8968

 

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Exhibit
Number

 

Description

 

Original Filed

Exhibit

 

File
Number

            10(xxviii)   $5,000,000,000 Revolving Credit Agreement, dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., DnB NorBank ASA, The Royal Bank of Scotland plc, Société Général, and Wells Fargo Bank, N.A., as Syndication Agents, and the several lenders named therein.   10.1 to Form 8-K filed on September 8, 2010   1-8968
                (xxix)   First Amendment to Revolving Credit Agreement, dated as of August 3, 2011, to the Revolving Credit Agreement dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent, Bank of America, N.A., DnB Nor Bank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as co-syndication agents, and each of the Lenders from time to time party thereto.   10(i) to Form 10-Q for quarter ended September 30, 2011, filed on October 31, 2011   1-8968
†              (xxx)   Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, effective as of May 20, 2008   10.1 to Form 8-K filed on May 27, 2008   1-8968
†              (xxxi)   Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Stock Option Award Agreement   10.3 to Form 8-K filed on November 13, 2009   1-8968
†              (xxxii)   Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement   10.1 to Form 8-K filed on November 13, 2009   1-8968
†              (xxxiii)   Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Performance Unit Award Agreement   10.2 to Form 8-K filed on November 13, 2009   1-8968
†              (xxxiv)   Anadarko Petroleum Corporation 2008 Director Compensation Plan, effective as of May 20, 2008   10.2 to Form 8-K filed on May 27, 2008   1-8968
†              (xxxv)   Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan   10.3 to Form 8-K filed on May 27, 2008   1-8968
†              (xxxvi)   Anadarko Petroleum Corporation Benefits Trust Agreement, amended and restated effective as of November 5, 2008   10(lvi) to Form 10-K for year ended December 31, 2008, filed on February 25, 2009   1-8968
†              (xxxvii)   Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2010)   10(xlvi) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010   1-8968

 

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Exhibit
Number

 

Description

 

Original Filed

Exhibit

 

File
Number

†        10(xxxviii)   Amended and Restated Employment Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated November 11, 2009   10.4 to Form 8-K filed on November 13, 2009   1-8968
†            (xxxix)   Letter Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated February 16, 2012   10.1 to Form 8-K filed on February 21, 2012   1-8968
              (xl)   Operating Agreement, dated October 1, 2009, between BP Exploration & Production Inc., as Operator, and MOEX Offshore 2007 LLC, as Non-Operator, as ratified by that certain Ratification and Joinder of Operating Agreement, dated December 17, 2009, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation (as Non-Operator), Anadarko E&P Company LP (as predecessor in interest to Anadarko Petroleum Corporation), and MOEX Offshore 2007 LLC, together with material exhibits.   10 to Form 10-Q for quarter ended June 30, 2010, filed on August 3, 2010   1-8968
†            (xli)   Retention Agreement, dated August 2, 2010   10.1 to Form 8-K filed on August 6, 2010   1-8968
‡            (xlii)   Confidential Settlement Agreement, Mutual Releases and Agreement to Indemnify, dated October 16, 2011, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation, Anadarko E&P Company LP, BP Corporation North America Inc. and BP p.l.c.   10(xlii) to Form 10-K for year ended December 31, 2011, filed on February 21, 2012   1-8968
†            (xliii)   Severance Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated February 16, 2012   10.2 to Form 8-K filed on February 21, 2012   1-8968
†            (xliv)   Time Sharing Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated May 15, 2012   10(i) to Form 10-Q filed on August 8, 2012   1-8968
†            (xlv)   Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated May 15, 2012   10(ii) to Form 10-Q filed on August 8, 2012   1-8968
†            (xlvi)   Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, effective as of May 15, 2012   10.1 to Form 8-K filed on May 15, 2012   1-8968
†            (xlvii)   Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Stock Option Award Agreement   10.2 to Form 8-K filed on May 15, 2012   1-8968
†            (xlviii)   Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement   10.3 to Form 8-K filed on May 15, 2012   1-8968

 

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Index to Financial Statements

Exhibit
Number

 

Description

 

Original Filed

Exhibit

 

File
Number

†        10(xlix)   Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement   10.4 to Form 8-K filed on May 15, 2012   1-8968
†            (l)   Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement   10.1 to Form 8-K filed on November 9, 2012   1-8968
†            (li)   Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement   10.2 to Form 8-K filed on November 9, 2012   1-8968
†            (lii)   Form of U.K. Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan   10.5 to Form 8-K filed on May 15, 2012   1-8968
†            (liii)   Amended and Restated Performance Unit Award Agreement, effective November 5, 2012, for
Mr. R. A. Walker
  10.3 to Form 8-K filed on November 9, 2012   1-8968
*        12   Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends    
*        21   List of Subsidiaries    
*        23(i)   Consent of KPMG LLP    
*        23(ii)   Consent of Miller and Lents, Ltd.    
*        24   Power of Attorney    
*        31(i)   Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer    
*        31(ii)   Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer    
*        32   Section 1350 Certifications    
*        99   Report of Miller and Lents, Ltd.    
*      101.INS   XBRL Instance Document    
*      101.SCH   XBRL Schema Document    
*      101.CAL   XBRL Calculation Linkbase Document    
*      101.DEF   XBRL Definition Linkbase Document    
*      101.LAB   XBRL Label Linkbase Document    
*      101.PRE   XBRL Presentation Linkbase Document    

 

Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.

Application has been made to the Securities and Exchange Commission (SEC) for confidential treatment of certain provisions of the exhibit. Omitted material for which confidential treatment has been requested has been filed separately with the SEC.

 

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The total amount of securities of the registrant authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrants and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the SEC, to furnish copies of any or all of such instruments to the SEC.

b) FINANCIAL STATEMENT SCHEDULES

Financial statement schedules have been omitted because they are not required, not applicable, or the information is included in the Company’s Consolidated Financial Statements.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

       

ANADARKO PETROLEUM CORPORATION

February 19, 2013

  By:  

/s/ ROBERT G. GWIN

   

Robert G. Gwin

Senior Vice President, Finance and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 19, 2013.

 

Name and Signature    Title

(i) Principal executive officer:*

  

R. A. WALKER

  

President and Chief Executive Officer

R. A. Walker

  

(ii) Principal financial officer:

  

Senior Vice President, Finance and Chief

Financial Officer

/s/ ROBERT G. GWIN

  

Robert G. Gwin

  

(iii) Principal accounting officer:

  

/s/ M. CATHY DOUGLAS

  

Vice President and Chief Accounting Officer

M. Cathy Douglas

  

(iv) Directors:*

  

KEVIN P. CHILTON

LUKE R. CORBETT

H. PAULETT EBERHART

PETER J. FLUOR

RICHARD L. GEORGE

PRESTON M. GEREN III

CHARLES W. GOODYEAR

JOHN R. GORDON

JAMES T. HACKETT

ERIC D. MULLINS

PAULA ROSPUT REYNOLDS

R. A. WALKER

  

 

* Signed on behalf of each of these persons and on his own behalf:

By:

 

/s/ ROBERT G. GWIN

Robert G. Gwin, Attorney-in-Fact

  

 

170