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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 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.
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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.

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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.

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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 carbondioxide 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 fracturedreservoir 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.

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 gatheringsystem 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.

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.

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-togross 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 gascondensate 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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Index to Financial Statements

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 yearend 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 carriedinterest 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 moratoriumrelated 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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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

Average

Production

Costs

(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

Excludes the impact of commodity derivatives.

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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Index to Financial Statements

Drilling Statistics

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

Net Exploratory Net Development

Productive Dry Holes Total Productive Dry Holes Total Total

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 

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 9 5 218 659

Net 5.7 57.4 77.7 432.0

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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Productive Wells

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

Oil Wells Gas Wells 

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

 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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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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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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•

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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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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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 hydraulicfracturing 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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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 spillresponse 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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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 mid2013.

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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 5 9 Executive Chairman

R. A. Walker 5 5 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 5 5 Senior Vice President, General Counsel and Chief Administrative Officer

M. Cathy Douglas 5 6 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 KerrMcGee 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 hydraulicfracturing 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 naturalgas 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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Index to Financial Statements

•

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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Index to Financial Statements

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 

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 — $ — 

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

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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Item 6. Selected Financial Data

Summary Financial Information 

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) 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

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

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

Table of Measures

Bcf—Billion cubic feet MBbls/d—Thousand barrels per day

MMBbls—Million barrels MBOE/d—Thousand barrels of oil equivalent per day

MMBOE—Million barrels of oil equivalent Tcf—Trillion cubic feet

MMcf/d—Million cubic feet per day

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

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements,

which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A. Unless the context otherwise requires, the terms

“Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

OVERVIEW

Anadarko 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 naturalgas 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 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 $ 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

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.

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.

5 6

 (1)

 (2)

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Index to Financial Statements

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.

5 9
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Index to Financial Statements

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 liquidsrich 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 7 891 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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Index to Financial Statements

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 debtissuance 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.

6 5
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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 5 9 —

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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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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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 (1,797) NM — NM —

Tronox-related contingent loss (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 66 12 5 9 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

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 feebased 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 acquisitiondate 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 383 203 312

Drilling-related reserves additions and revisions 465 377 395

Other non-price-related revisions (31) 7 (66) 

Net organic reserves additions 434 384 329

Acquisition of proved reserves in place 4 — 1

Price-related revisions (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

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 ZeroCoupon 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 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 1,475 1,527 497

Total capital expenditures $ 7,311 $ 6,553 $ 5,169

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.

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 thirdparty 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 debtrepayment 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 

millions 2013 2014-2015 2016-2017

2018 and

beyond Total

Total debt

Principal—long-term borrowings $ — $ 775 $ 3,750 $ 10,427 $ 14,952

Investee entities’ debt — — — 2,853 2,853

Interest on borrowings 844 1,603 1,451 7,604 11,502

Investee entities’ interest 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 5 5 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 7 823 377 — 1,207

Uncertain tax positions, interest, and penalties 5 6 7 11 — 74

Environmental liabilities 17 14 4 46 81

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

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.

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).

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 longterm 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.

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.

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 industrystandard 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 weightedaverage 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 buildingblock 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 projectspecific 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 9 5

Consolidated Statements of Cash Flows, Three Years Ended December 31, 2012 9 6

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 Control—Integrated 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 8 10 17

Adjustments for pension and other postretirement plans

Net gain (loss) incurred during period (99) (136) (91) 

Prior service credit (cost) incurred during period — 7 (4) 

Amortization of net actuarial loss and prior service cost to net periodic benefit cost 63 5 6 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

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

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

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

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)

Noncontrolling

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 — 32 — — — 269 301

Conversion of subordinated limited partner units

to common units — 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 — 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

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.

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.

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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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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 endusers, 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.

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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.

9 9
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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)

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.

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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. Definedbenefit 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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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 10—Noncontrolling 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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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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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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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 5 9

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 $ 55,095 $ 52,711

Midstream 6,032 4,837

Marketing 94 9

Other 2,377 2,524

Total $ 63,598 $ 60,081

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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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 Level 3 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

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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Index to Financial Statements

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 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

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, welltest 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 $ 1,885 $ 1,768

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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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 debtto-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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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) —

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

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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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 interestrate 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 Instruments—Balance 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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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

12. Derivative Instruments (Continued)

Effect of Derivative Instruments—Statement 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 $ 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 $ 20 $ (12) $ 8

(Gains) losses on derivatives, net (226) (336) (562) 

Interest-rate and other derivatives

(Gains) losses on derivatives, net 5 9 964 1,023

Total (gains) losses on derivatives, net $ (147) $ 616 $ 469

2010

Commodity derivatives

Gathering, processing, and marketing sales $ 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) 

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 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) 

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 (1,683) (1,722) 

Total borrowings $ 13,269 $ 15,230

Less current portion of long-term debt — 170

Total long-term debt $ 13,269 $ 15,060 

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

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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 (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 fairvalue 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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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 — — 112

Capitalized interest (221) (147) (128) 

Interest expense $ 742 $ 839 $ 855

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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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 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

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

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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)

WeightedAverage

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 weightedaverage 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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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)

WeightedAverage

Exercise

Price

(per share)

WeightedAverage

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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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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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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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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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.

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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.

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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 CoTrustees 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 CoTrustees 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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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.

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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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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.

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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 abovestated 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 KerrMcGee 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 divestiturerelated litigation at December 31, 2012. The Company continues to vigorously defend itself in Brazilian courts.

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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 midMay 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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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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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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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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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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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 (1,797) — — 

Tronox-related contingent loss (250) 250 (95) 

Interest expense 742 839 855

Unrealized (gains) losses on derivatives, net 377 616 (114) 

Realized (gains) losses on other derivatives, net 66 5 9 — 

Less net income attributable to noncontrolling interests 54 81 60

Consolidated Adjusted EBITDAX $ 8,966 $ 8,869 $ 7,146

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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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 3,505 748 616 295 5,164

Realized (gains) losses on commodity derivatives,

net — — — (753) (753) 

Other (income) expense, net — — — (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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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 3,696 786 559 186 5,227

Realized (gains) losses on commodity derivatives,

net — — — (226) (226) 

Other (income) expense, net — — — 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 2,963 655 457 221 4,296

Realized (gains) losses on commodity derivatives,

net — — — (498) (498) 

Other (income) expense, net — — — (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

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.

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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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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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 $ 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

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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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 $ 6 9 $ 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 6 5 — — (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 6 5 — — (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 smallcapitalization 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 assetallocation 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 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 $ 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 — 6 6 — 6 6

U.S. government securities 1 49 — 50

Other fixed-income securities 36 171 — 207

Equity securities

Domestic 265 94 — 359

International 91 203 — 294

Other

Real estate — 37 72 109

Private equity — — 5 5 5 5

Hedge funds and other alternative strategies 26 — 64 90

Total investments $ 456 $ 674 $ 191 $ 1,321

Liabilities

Hedge funds and other alternative strategies $ (12) $ — $ — $ (12) 

Total liabilities $ (12) $ — $ — $ (12) 

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.

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

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 $ 9 9

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 $ 5 5 $ 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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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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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 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 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 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

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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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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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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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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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.

156
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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

157
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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

158
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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

159
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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.

160
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Index to Financial Statements

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.

161
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Index to Financial Statements

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

162
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Index to Financial Statements

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

163
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Index to Financial Statements

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

164
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Index to Financial Statements

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

165
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Index to Financial Statements

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

166
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Index to Financial Statements

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

167
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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.

168
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Index to Financial Statements

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.

169
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Index to Financial Statements

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

/s/ ROBERT G. GWIN Financial Officer

 

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
EXHIBIT 12

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF COMPUTATION OF RATIOS OF

EARNINGS TO FIXED CHARGES AND EARNINGS TO

COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

Years Ended December 31,

(Unaudited)

millions except ratio amounts 2012 2011 2010 2009 2008

Income (loss) from continuing operations before income taxes $ 3,565 $ (3,424) $1,641 $ (108) $5,368

Equity (income) adjustment (110) (102) (74) (76) (134) 

Fixed charges 1,209 1,232 1,289 1,077 1,355

Amortization of capitalized interest 17 29 41 46 28

Distributed income of equity investees 33 34 11 49 136

Capitalized interest (221) (147) (128) (69) (123) 

Non-controlling interest in pre-tax income of subsidiaries that have not incurred fixed

charges (10) (7) (6) (8) —

Total Earnings $ 4,483 $ (2,385) $ 2,774 $ 911 $6,630

Interest expense including capitalized interest 954 984 999 758 876

Interest expense included in other (income) expense 42 38 39 57 123

Estimated interest portion of rental expenditures 213 210 251 262 356

Total Fixed Charges $ 1,209 $ 1,232 $1,289 $1,077 $1,355

Preferred Stock Dividends — — — — 2

Combined Fixed Charges and Preferred Stock Dividends $ 1,209 $ 1,232 $1,289 $1,077 $1,357

Ratio of Earnings to Fixed Charges 3.71 (1.94) 2.15 0.85 4.89

Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 3.71 (1.94) 2.15 0.85 4.89

Estimated interest component of rental expenditures reflects a portion of rental expenditures representative of an interest factor, whether such rentals are

expensed, or capitalized when incurred. For the years ended December 31, 2012, 2011 and 2010, the estimated interest component in rentals includes

$157 million, $138 million, and $178 million, respectively, associated with the Company’s drilling rig leases.

As a result of the Company’s net loss in 2011 and 2009, Anadarko’s earnings did not cover total fixed charges, nor combined fixed charges by

$3,617 million for 2011 and $166 million for 2009.

These ratios were computed by dividing earnings by either fixed charges or combined fixed charges and preferred stock dividends. For this purpose,

earnings include income from continuing operations before income taxes, adjusted for: income or loss from equity investees, fixed charges to the extent they

affect current year earnings, amortization of capitalized interest, distributed income of equity investees, and interest capitalized during the year. Fixed charges

include interest expensed and capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and estimates of interest within

rental expenses. Preferred stock dividends are adjusted to reflect the amount of pretax earnings required for payment.

(a)

(b)

(b)

(a)

(b)
EXHIBIT 21

LIST OF SUBSIDIARIES 

At December 31, 2012

Anadarko (S.L.) Company

a Cayman Islands corporation,

Anadarko 20-11 Company

a Cayman Islands corporation,

Anadarko 20-13 Company

a Cayman Islands corporation,

Anadarko 20-18 Company

a Cayman Islands corporation,

Anadarko 20-22 Company

a Cayman Islands corporation,

Anadarko 20-4 Company

a Cayman Islands corporation,

Anadarko Algeria Company LLC 

a Delaware limited liability company,

Anadarko Brazil Investment I LLC

a Delaware limited liability company,

Anadarko Development Holding Ltd.

a Gibraltar limited liability company,

Anadarko E&P Company LP 

a Delaware limited partnership,

Anadarko Energy Holding Ltd.

a Gibraltar limited liability company,

Anadarko Energy Marketing, Inc.

a Delaware corporation,

Anadarko Energy Services Company 

a Delaware corporation,

Anadarko Exploracao e Producao de Petroleo e Gas Natural LTDA.

a Brazil limited liability company,

Anadarko Ghana Mahogany-1 Company

a Cayman Islands corporation,

Anadarko Global Energy SARL 

a Luxembourg limited liability company,

(1)

(2)

(2) (3)

(2)

(2)
Anadarko Global Funding 1 Company

a Cayman Islands corporation,

Anadarko Holding Company 

a Utah corporation,

Anadarko International Development SARL

a Luxembourg limited liability company,

Anadarko Land Corp

a Nebraska corporation,

Anadarko Limited Resources LLC

a Delaware limited liability company,

Anadarko Marcellus Midstream, L.L.C.

a Delaware limited liability company,

Anadarko Mauritius Holdings Limited

a Mauritius corporation,

Anadarko Midkiff/Chaney Dell LLC

a Delaware limited liability company,

Anadarko Mozambique Area 1, Limitada Home

a Mozamique limited liability company,

Anadarko Offshore Holding Company, LLC

a Delaware limited liability company,

Anadarko Petroleum Corporation 

a Delaware corporation,

Anadarko Realty Company

a Texas limited liability company,

Anadarko Uintah Midstream, LLC

a Delaware limited liability company,

Anadarko US Offshore Corporation 

a Delaware corporation,

Anadarko Venezuela Company

a Cayman Islands corporation,

Anadarko Venezuela LLC

a Delaware limited liability company,

Anadarko WCTP Company

a Cayman Islands corporation,

Anadarko West Texas LLC

a Delaware limited liability company,

(2)

(2)

(2)
Anadarko Worldwide Holdings CV 

a Netherlands limited partnership,

APC International Holdings LLC

a Delaware limited liability company,

Big Island Trona Company

a Delaware corporation,

Bitter Creek Coal Company

a Utah corporation,

Headwater LLC

a Delaware limited liability company,

Howell Corporation

a Delaware corporation,

Howell Petroleum Corporation

a Delaware corporation,

Kerr-McGee China Petroleum LTD.

a Bahama Islands limited liability company,

Kerr-McGee Corporation 

a Delaware corporation,

Kerr-McGee Energy Services Corporation

a Delaware corporation,

Kerr-McGee Gathering LLC

a Colorado limited liability company,

Kerr-McGee Oil and Gas Onshore LP 

a Delaware limited partnership,

Kerr-McGee Onshore Holding LLC 

a Delaware limited liability company,

Kerr-McGee Shared Services Company LLC 

a Delaware limited liability company,

Kerr-McGee Worldwide Corporation 

a Delaware corporation,

KM BM-C Seven Ltd. 

a Bahamas limited liability company,

KM Denmark Overseas ApS

a Denmark corporation,

KM Global LTD.

a Delaware corporation,

(2)

(2)

(2)

(2)

(2)

(2)

(2)
KM Investment Corporation 

a Nevada corporation,

Lance Oil & Gas Company, Inc.

a Delaware corporation,

Mountain Gas Resources LLC

a Delaware limited liability company,

Resources Holding Inc. 

a Delaware corporation,

Rock Springs Royalty Company LLC

a Utah limited liability company,

Springfield Pipeline LLC

a Texas limited liability company,

Upland Industries Corporation

a Nebraska corporation,

Venezuela US SRL

a Barbados limited liability company,

Western Gas Equity Partners, LP

a Deleware limited partnership,

Western Gas Partners, LP

a Deleware limited partnership,

Western Gas Resources, Inc. 

a Delaware corporation,

WGR Asset Holding Company LLC

a Delaware limited liability company,

WGR Operating, LP

a Delaware limited partnership,

WHL, Inc. 

a Delaware corporation

The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant

subsidiary, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w).

Subsidiary meets the conditions of a significant subsidiary under the Securities and Exchange Commission Regulation S-X 210.1-02(w).

Effective January 1, 2013, this subsidiary converted to a Delaware limited liability company and changed its name to Anadarko E&P Onshore LLC.

Effective January 1, 2013, this subsidiary merged into Anadarko Holding Company.

(2)

(4)

(2)

(2)

(1)

(2)

(3)

(4)
EXHIBIT 23(i)

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Anadarko Petroleum Corporation:

We consent to the incorporation by reference in the registration statements on Forms S-3 and S-8 (No. 33-8643), Form S-3 (No. 333-161370) and Form S-8

(Nos. 333-152049, 333-161367, and 333-181429) of Anadarko Petroleum Corporation of our reports dated February 19, 2013, with respect to the

consolidated balance sheets of Anadarko Petroleum Corporation 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 the effectiveness of internal control

over financial reporting as of December 31, 2012, which reports appear in the December 31, 2012 annual report on Form 10-K of Anadarko Petroleum

Corporation.

/s/ KPMG LLP

Houston, Texas

February 19, 2013
EXHIBIT 23(ii)

February 19, 2013

Anadarko Petroleum Corporation

1201 Lake Robbins Drive

The Woodlands, TX 77380

Re: Securities and Exchange Commission

Form 10-K of Anadarko Petroleum Corporation

Gentlemen:

We hereby consent to the incorporation by reference in the registration statements on Forms S-3 and S-8 (No. 33-8643), Form S-3 (No. 333-161370) and

Form S-8 (Nos. 333-152049, 333-161367, and 333-181429) of Anadarko Petroleum Corporation of our Procedures and Methods Review Letter dated

February 19, 2013, regarding the Anadarko Petroleum Corporation Proved Reserves and Future Net Cash Flows as of December 31, 2012, and of references to

our firm which are to be included in Form 10-K for the year ended December 31, 2012, to be filed by Anadarko Petroleum Corporation with the Securities and

Exchange Commission.

Miller and Lents, Ltd. has no financial interest in Anadarko Petroleum Corporation or in any of its affiliated companies or subsidiaries and is not to

receive any such interest as payment for such letter. Miller and Lents, Ltd. also has no director, officer, or employee employed or otherwise connected with

Anadarko Petroleum Corporation. We are not employed by Anadarko Petroleum Corporation on a contingent basis.

MILLER AND LENTS, LTD.

Texas Registered Engineering Firm No. F-1442

By: /s/ ROBERT J. OBERST

Robert J. Oberst, P.E.

Senior Vice President
EXHIBIT 24

POWER OF ATTORNEY

KNOW ALL BY THESE PRESENTS that each undersigned Director of ANADARKO PETROLEUM CORPORATION (the “Company”), a

Delaware corporation, does hereby constitute and appoint ROBERT G. GWIN, M. CATHY DOUGLAS, and ROBERT K. REEVES, and each of them, with

full power to act without the other, his or her true and lawful attorney and agent to do any and all acts and things and execute any and all instruments which,

with the advice of counsel, said attorney and agent may deem necessary or advisable to enable the Company to comply with the Securities Exchange Act of

1934, as amended, and any rules, regulations and requirements of the Securities and Exchange Commission in connection with the filing under said Act of the

Form 10-K Annual Report for the Year Ended December 31, 2012, including specifically, but without limitation thereof, to sign his or her name as a Director

of the Company to the Form 10-K Annual Report for the Year Ended December 31, 2012 filed with the Securities and Exchange Commission, and to any

instrument or document filed as a part of, or in connection with, said Form 10-K Annual Report for the Year Ended December 31, 2012 or amendment thereto;

and the undersigned does hereby ratify and confirm all that said attorney and agent shall do or cause to be done by virtue thereof.

IN WITNESS WHEREOF, the undersigned have subscribed these presents this 19 day of February, 2013.

/s/ JAMES T. HACKETT

James T. Hackett

 

/s/ KEVIN P. CHILTON

Kevin P. Chilton

/s/ LUKE R. CORBETT

Luke R. Corbett

 

/s/ H. PAULETT EBERHART

H. Paulett Eberhart

/s/ PETER J. FLUOR

Peter J. Fluor

 

/s/ RICHARD L. GEORGE

Richard L. George

/s/ PRESTON M. GEREN III

Preston M. Geren III

 

/s/ CHARLES W. GOODYEAR

Charles W. Goodyear

/s/ JOHN R. GORDON

John R. Gordon 

/s/ ERIC D. MULLINS

Eric D. Mullins

/s/ PAULA ROSPUT REYNOLDS

Paula Rosput Reynolds 

/s/ R. A. WALKER

R. A. Walker

th
EXHIBIT 31(i)

CERTIFICATIONS

I, R. A. Walker, certify that:

1. I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make

the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered

by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects

the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and

15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known

to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed

under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of

financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions

about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such

evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially

affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to

the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which

are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information;

and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s

internal control over financial reporting.

February 19, 2013

/s/ R. A. WALKER

R. A. Walker

President and Chief Executive Officer
EXHIBIT 31(ii)

CERTIFICATIONS

I, Robert G. Gwin, certify that:

1. I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make

the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered

by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects

the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and

15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known

to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed

under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of

financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions

about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such

evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially

affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to

the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which

are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information;

and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s

internal control over financial reporting.

February 19, 2013

/s/ ROBERT G. GWIN

Robert G. Gwin

Senior Vice President, Finance and Chief Financial Officer
EXHIBIT 32

SECTION 1350 CERTIFICATION OF PERIODIC REPORT

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, R. A. Walker, President and Chief Executive Officer of Anadarko

Petroleum Corporation (Company), and Robert G. Gwin, Senior Vice President, Finance and Chief Financial Officer of the Company, certify that:

(1) the Annual Report on Form 10-K of the Company for the period ending December 31, 2012, as filed with the Securities and Exchange

Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934;

and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

February 19, 2013

/s/ R. A. WALKER

R. A. Walker

President and Chief Executive Officer

February 19, 2013

/s/ ROBERT G. GWIN

Robert G. Gwin

Senior Vice President, Finance and Chief Financial Officer

This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose. A signed original of this written statement required

by Section 906 will be retained by Anadarko and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 99

February 19, 2013

Mr. Robert G. Gwin

Senior Vice President, Finance and Chief Financial Officer

Anadarko Petroleum Corporation

1201 Lake Robbins Drive

The Woodlands, TX 77380

Re: Procedures and Methods Review of Anadarko Petroleum Corporation

 Proved Reserves and Future Net Cash Flows as of December 31, 2012

Dear Mr. Gwin:

At your request, Miller and Lents, Ltd. reviewed the procedures and methods employed by Anadarko Petroleum Corporation (Anadarko) in preparing its

internal estimates of proved reserves and future net cash flows as of 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 the Securities and Exchange

Commission (SEC) Regulation S-X, Rule 4-10(a).

From July through December 2012, we participated in the review of 17 fields which included major assets in the United States and Africa. Reserves

estimates for these properties were approximately 2,237 million barrels of oil equivalent, or approximately 87 percent of Anadarko’s total proved reserves as of

December 31, 2012. In each review, Anadarko’s technical staff presented us with an overview of the data, methods, and assumptions used in its reserve

estimates. 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.

Anadarko’s proved reserves were estimated generally by extrapolation of well-established historical production performance trends and/or were supported

by other geologic and engineering studies. Where sufficient performance data did not exist, Anadarko’s reserves were estimated by volumetric calculations or

by analogy to similar producing properties.

The ownership, reversions, test and production data, operating costs, estimated capital expenditures, and other information presented by Anadarko

during the reviews were accepted as represented. We did not conduct any field inspections or other tests in conjunction with this procedures and methods

review.
Our work 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 proved reserves and future net cash flows. Anadarko’s estimates of proved reserves and future net cash

flows as of December 31, 2012 were determined solely by its staff and are the responsibility of its management.

Based upon our reviews and subsequent due diligence, it is our judgment that the procedures and methods employed by Anadarko in estimating its

December 31, 2012 proved reserves and future net cash flows are effective and in accordance with the SEC reserves definitions.

The opinions presented in this letter reflect our informed judgments and are subject to the inherent uncertainties associated with interpretation of geological,

geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the

application of professional judgments.

Miller and Lents, Ltd. is an international oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any direct

financial ownership in Anadarko or any affiliate company. Our compensation for the required investigations is not contingent on the results obtained and

reported, and we have not performed other work that would affect our objectivity. The procedures and methods reviews were supervised by Robert J. Oberst,

an officer of the firm who is a licensed Professional Engineer in the State of Texas and professionally qualified with more than 20 years of relevant experience

in the estimation, assessment, and evaluation of oil and gas reserves.

Any distribution or publication of this letter or any part thereof must include this letter in its entirety.

Very truly yours,

MILLER AND LENTS, LTD.

Texas Registered Engineering Firm No. F-1442

By: /s/ ROBERT J. OBERST

Robert J. Oberst, P.E.

Senior Vice President