APC 2014 10K - 10K
Table of Contents
Index to Financial Statements

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
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  ý    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  ý
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  ý    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  ý    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.  ¨
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  ý    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  ý
The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 30, 2014, was $55.3 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 30, 2015, is shown below:
Title of Class
  
Number of Shares Outstanding
Common Stock, par value $0.10 per share
  
506,650,285
Documents Incorporated By Reference
Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 12, 2015 (to be filed with the Securities and Exchange Commission prior to April 2, 2015), are incorporated by reference into Part III of this Form 10-K.


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS
 
 
Page
PART I
 
 
Items 1 and 2.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 3.
Item 4.
PART II
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
 
 
Item 15.


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Index to Financial Statements

PART I

Items 1 and 2.  Business and Properties

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with approximately 2.9 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2014. 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, the Appalachian basin, and Alaska. The Company is also among the largest independent producers in the deepwater Gulf of Mexico, and has exploration and production activities worldwide, including activities in Mozambique, Algeria, Ghana, Brazil, Colombia, Côte d’Ivoire, Kenya, Liberia, 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, oil, condensate, and natural gas liquids (NGLs), and plans for the development and operation of the Company’s liquefied natural gas (LNG) project.

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, oil, and NGLs.

Marketing—This segment sells much of Anadarko’s oil, natural-gas, and NGLs production, as well as third-party purchased volumes. The Company actively markets oil, natural gas, and NGLs in the United States; oil and NGLs internationally; and the anticipated LNG production from Mozambique.

Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. 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.

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Available Information  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. 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, or any amendments thereto, and other reports and filings 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, by selecting SEC Filings on its website located at www.anadarko.com. The Company will also make available to any stockholder, without charge, printed 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 (855) 820-6605, send an email to investor@anadarko.com, or complete an information request on the Company’s website at www.anadarko.com, by selecting Investors/Shareholder Resources/Shareholder Services.
The public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reading Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reading Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, like Anadarko, that file electronically with the SEC.

OIL AND GAS PROPERTIES AND ACTIVITIES

The map below illustrates the locations of Anadarko’s oil and natural-gas exploration and production operations.

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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 2014 and 92% of total proved reserves at year-end 2014.

Rocky Mountains Region  Anadarko’s Rocky Mountains Region (Rockies) properties include oil and natural-gas plays located in Colorado, Utah, and Wyoming where the Company operates approximately 14,500 wells and owns an interest in approximately 8,000 nonoperated wells. 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 eight 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 enhances the Company’s economic returns from production on Land Grant acreage, offers drilling opportunities for the Company without expiration, and allows the Company to capture royalty revenue from third-party activity on Land Grant acreage. The Company also believes its liquids-rich reservoirs, strong well performance, low development and operating costs, and large expandable midstream infrastructure each provide tangible benefits to the Company.
Activities in the Rockies primarily focus on expanding existing fields to increase production and adding proved reserves through horizontal drilling, infill drilling, and down-spacing operations. The Company focused its 2014 capital investments in areas that offer high liquids yields (liquids-rich areas), which resulted in significant oil production growth. In 2014, total-year Rockies sales volumes increased 10% over 2013, with a 45% or 49 thousand barrels of oil equivalent per day (MBOE/d) increase in liquids volumes. The Company drilled 569 wells and completed 487 wells in the Rockies during 2014. The Company plans to continue its drilling program in 2015, focusing on the Wattenberg field.

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Wattenberg  Anadarko operates approximately 5,800 vertical wells and 750 horizontal wells in the Wattenberg field. The field contains the Niobrara and Codell formations, which are naturally fractured formations that hold liquids and natural gas. During 2014, the Company’s drilling program focused entirely on horizontal development, drilling 369 horizontal wells. Sales volumes in the Wattenberg field increased 55% compared to 2013, with year-over-year increases of 69% in oil volumes and 79% in total liquids volumes. Horizontal drilling results in the Wattenberg field continue to be strong, with economics that are enhanced by the Land Grant mineral interest, a consolidated core acreage position, and recent enhancements in infrastructure and takeaway capacity.
Major facility and takeaway expansions occurred in 2014. The Lancaster cryogenic plant and Front Range Pipeline (FRP) were commissioned in 2014. The Lancaster cryogenic plant resulted in a field-wide increase in NGLs recoveries and the FRP resulted in access to the premium Mt. Belvieu NGLs market. Gas processing capacity is expected to increase in mid-2015 with the addition of Lancaster II, which is a second 300 million cubic feet per day (MMcf/d) cryogenic processing facility currently under construction. The White Cliffs pipeline expansion was completed in the third quarter of 2014, providing additional oil transportation capacity for the region. Management believes that Anadarko is well-positioned with its oil and NGLs export capacity, which includes transport by pipeline, rail, and truck.

Greater Natural Buttes  The Greater Natural Buttes area in eastern Utah is one of the Company’s major tight-gas assets. The Company utilizes both refrigeration and cryogenic processing facilities in this area to extract NGLs from the natural-gas stream.
The Company operates approximately 2,800 wells in the Greater Natural Buttes area and drilled 133 wells in 2014. The Company operated the field at a reduced activity level for the majority of 2014 due to capital allocation to higher-margin projects.

Powder River Deep  The Company drilled 10 horizontal wells in the Powder River basin during 2014 as part of a multi-objective horizontal exploration program targeting oil opportunities. The Company has seen encouraging results in the Niobrara and Turner formations. Anadarko controls over 350,000 acres of deep mineral rights within the Powder River basin.

Coalbed Methane Properties  Anadarko operates approximately 2,300 CBM wells and owns an interest in approximately 2,500 nonoperated 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 640,000 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. The Company operated the field at a reduced activity level in 2014 due to capital allocation to higher-margin projects.

Salt Creek and Monell  During 2014, the Company continued the development of its Rockies EOR assets in the Salt Creek and Monell fields in Wyoming. The Company’s EOR operations use carbon dioxide (CO2) to stimulate oil production from mature reservoirs after primary and water-flood recovery methods have been completed. Significant gains in production were achieved in this area due to the Company’s ongoing development programs, with oil production rising 10% in 2014. In 2015, the Company plans to continue the management of these fields to enhance CO2 flooding operations.
In 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 in the Salt Creek field in Wyoming. The funding commitment was completed in 2014.

Laramie County, Wyoming  Anadarko holds ownership in more than 100,000 mineral-interest acres in this emerging liquids-rich play, targeting the Niobrara and Codell formations in the northern DJ Basin. In 2014, the Company participated in more than 70 nonoperated wells testing the Niobrara and Codell formations. Early results from wells drilled in 2014 are encouraging, as results from the 19 nonoperated wells that are currently producing remain strong with initial 30-day net production averaging approximately 1,000 barrels of oil equivalent per day (BOE/d).

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Greater Green River Basin  Anadarko operates over 1,400 wells in the Wamsutter and Moxa fields, which are primarily dry-gas assets. The Company also carries a nonoperated position in 2,600 wells between the two fields. Much of this producing area is in the Land Grant, which improves the economics of projects in the area.
In late 2013, Anadarko acquired additional working interests and became the operator in the Moxa field, increasing the Company’s net production by approximately 6,500 BOE/d. In 2014, additional value was realized through reduction in the decline rates and decreasing operating costs.
In January 2014, Anadarko sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million.

Southern and Appalachia Region  Anadarko’s Southern and Appalachia Region properties are primarily located in Texas, Pennsylvania, Louisiana, and Kansas. The region includes the Eagleford shale in South Texas, the Delaware basin in West Texas, the Marcellus shale in north-central Pennsylvania, and the Haynesville shale in East Texas and Louisiana. Operations in these areas are focused on finding and developing both natural gas and liquids from shales, tight sands, and fractured-reservoir plays.
During 2014, the Company continued to focus on liquids-rich opportunities across the region by expanding drilling activity in the emerging Wolfcamp shale play in the Delaware basin and other shale plays, while continuing its existing liquids-rich projects in the Eagleford shale, Delaware basin, and East Texas/North Louisiana plays. The Company has reduced costs and benefited from improved cycle-time efficiencies in both drilling and completion operations across all operating areas in the region.
In 2014, total-year sales volumes in the Southern and Appalachia Region increased 16% over 2013, with a 33% increase in liquids volumes. The Company drilled 589 operated horizontal wells and brought 730 wells online in 2014. In 2015, the Company expects to continue its horizontal drilling program, focusing on the Texas assets.

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Eagleford  The Eagleford shale development in South Texas consists of approximately 357,000 gross acres and over 1,100 producing wells. The Company drilled 393 wells, completed 388 wells, and brought 385 wells online generating 47% sales volume growth year over year. Anadarko entered 2014 with 10 drilling rigs and reduced the rig count to eight by the end of 2014 due to outstanding drilling performance. To facilitate additional completion activities, water infrastructure was expanded in 2014, increasing capacity by 75 thousand barrels per day (MBbls/d). The Company continues to test concepts for additional recovery across its acreage position and completed successful tests on two upper-Eagleford shale wells.

Delaware Basin  Anadarko holds an interest in over 600,000 gross acres in the Delaware basin. Anadarko’s 2014 drilling activity primarily targeted the liquids-rich Bone Spring formation, the Avalon shale, and the developing Wolfcamp shale play. In 2014, Anadarko drilled 97 operated wells and participated in 43 nonoperated wells. Significant infrastructure was added, which increased NGLs sales volumes by 82% over 2013. In addition, in November 2014, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired Nuevo Midstream, LLC (Nuevo), which has gathering and processing assets located in the Delaware basin. The Company had one operated rig drilling in the Bone Spring formation, one operated rig drilling in the Avalon shale, and eight operated rigs drilling in the Wolfcamp shale at year-end 2014.
The successful Wolfcamp shale delineation program continues to deliver encouraging results across the majority of Anadarko’s acreage position. Anadarko is testing multiple zones within the Wolfcamp shale and several development concepts including multi-well pads, extended laterals, and horizontal well spacing for increased efficiency. The Company has identified thousands of potential drilling locations in the Wolfcamp formations that are expected to provide substantial opportunity for Anadarko’s continued activity in the basin.

Eaglebine  Anadarko holds 156,000 gross acres in the Eaglebine shale in Southeast Texas, most of which is held by existing Austin Chalk production. In 2014, Anadarko continued to delineate and develop this acreage with a one-rig drilling program. In September 2014, the Company entered into a carried-interest arrangement requiring a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development. Anadarko will remain the operator with an average post-transaction working interest of approximately 51%. This transaction allows the Company to develop this oil opportunity while further enhancing Anadarko’s capital efficiency and flexibility. At December 31, 2014, $22 million of the total $442 million obligation had been funded.

East Texas/North Louisiana  Anadarko holds 293,000 gross acres in East Texas/North Louisiana. Anadarko increased its capital program in the East Texas Carthage area in 2014, targeting a liquids-rich area in the Haynesville shale. In 2014, Anadarko operated six rigs and drilled 52 wells in the Haynesville and Cotton Valley formations. The Company increased sales volumes from the area by 10% year over year.

Marcellus  The Company holds 654,000 gross acres in the Marcellus shale of the Appalachian basin. During the year, 24 operated horizontal wells were drilled using one rig. Anadarko also participated in drilling an additional 78 nonoperated horizontal wells in 2014. The Company’s production in Marcellus continued to improve with sales volumes increasing 12% over 2013.

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Gulf of Mexico  In the Gulf of Mexico, Anadarko owns an average 61% working interest in 394 blocks. The Company operates seven active floating platforms and holds interests in 23 producing fields. During 2014, the Company advanced development of the Lucius and Heidelberg projects and continued an active deepwater development and appraisal program in the Gulf of Mexico as it continues to take advantage of its existing infrastructure to accelerate development activities at reduced costs.
The following includes the significant development, exploration, and appraisal activity in the Gulf of Mexico during 2014.

Development
Lucius  The Company realized first production at the Anadarko-operated Lucius Spar in January 2015, bringing on three wells initially and ramping up production with an additional three wells expected to come online during the first quarter of 2015. The successful Lucius project was developed with production startup only three years from sanction and five years from discovery. The 80-MBbls/d spar resides in Keathley Canyon Block 875 with a water depth of 7,100 feet.
A carried-interest arrangement with a third party, entered into in 2012, provided funding for the substantial majority of Anadarko’s development capital commitment through first production. Following the carried-interest arrangement and 2014 equity re-determination, the Company holds a 23.8% working interest in Lucius.

Heidelberg  The Company continues to advance the Anadarko-operated Heidelberg development project, which was sanctioned during the second quarter of 2013. The construction of the 80-MBbls/d spar is progressing on schedule with anticipated start-up in 2016. At December 31, 2014, fabrication of the main topsides module was more than 70% complete and ahead of schedule.
In 2013, the Company entered into a carried-interest arrangement requiring a third party to fund $860 million of capital costs in exchange for a 12.75% working interest in the project. The carry obligation is expected to cover the substantial majority of the Company’s expected future capital costs through first production. At December 31, 2014, $386 million of the $860 million obligation had been funded. Anadarko holds a 31.5% working interest in Heidelberg. Development drilling commenced in late 2014 on two development wells.

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Caesar/Tonga  At Caesar/Tonga (33.75% working interest), the Company successfully completed a fourth development well (GC 727#2) in the first quarter of 2014, and the well is producing 10 MBbls/d of oil. Anadarko is currently completing a fifth development well (GC 683#2), which is expected to come online during the first quarter of 2015.

K2  At K2 (41.8% working interest), the GC 562 #5 infill well found 210 feet of oil pay in the Miocene, and the well is being sidetracked for a subsequent completion. The well is expected to come online in the second half of 2015.

Constitution  At Constitution (100% working interest), the Company executed a successful platform drilling program in 2014, where the A1 well was sidetracked, completed, and brought online producing 3 MBbls/d of oil.

Vito  In 2014, Anadarko sold its 18.67% working interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks, for $500 million.

Exploration
Three exploration wells were drilled in the Gulf of Mexico during 2014. The Deep Nansen exploration well (35% working interest) targeted Lower Tertiary-aged sediments in a large, four-way structure beneath Anadarko’s Nansen field and found non-commercial quantities of hydrocarbons and the well was plugged and abandoned. The evidence of a working petroleum system is being incorporated into potential future activity on the surrounding leasehold. The Bimini exploration well (50% working interest) was drilled in Garden Banks close to existing infrastructure at the Anadarko-operated Power Play field and near the Conger field and Baldpate Platform. The well tested a subsalt Miocene prospect and was plugged and abandoned. The K2 development well was drilled deeper to test the Wilcox potential beneath the existing field in Green Canyon and did not find commercial quantities of hydrocarbons in the Wilcox objective. The K2 well will be sidetracked and completed in a field pay interval. Also, the Yeti exploration well (37.5% nonoperated working interest) was spud prior to year end. The well will test a Miocene sub-salt three-way closure in Walker Ridge.

Appraisal
Shenandoah Basin  The Company spud the Shenandoah-3 well, its second appraisal well at the Shenandoah discovery, in the second quarter of 2014. The well finished drilling at the end of 2014 and found approximately 50% (1,470 feet) more of the same reservoir sands 1,500 feet down-dip and 2.3 miles east of the Shenandoah-2 well, which encountered over 1,000 feet of net oil pay in excellent quality Lower Tertiary-aged sands. The Shenandoah-3 well confirmed the sand depositional environment, lateral sand continuity, excellent reservoir qualities, and down-dip thickening. The well also enabled the projection of oil-water contacts based on pressure data and reduced the uncertainty of the resource range. Planning is underway for the next appraisal well, which the Company expects to spud in the second quarter of 2015.
An appraisal well at the Coronado discovery (35% working interest) reached total depth during the second quarter of 2014 and did not find the Lower Miocene objective and was plugged and abandoned.
During the third quarter of 2014, the first appraisal well of the Yucatan discovery (25% working interest) was drilled down-dip of the original discovery, and found approximately 57 gross feet of pay in Lower Tertiary oil-bearing sands. The Yucatan discovery is located approximately three miles south of the Shenandoah discovery.
 
Alaska  Anadarko’s nonoperated oil production and development activity in Alaska is concentrated on the North Slope. Infrastructure construction began in 2013 on the Alpine West satellite development, a 15-to-20-well extension of the Alpine field. Drilling at Alpine West is scheduled to commence in mid-2015 with production anticipated to come online in late 2015 or early 2016.

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International

Overview  Anadarko’s international operations include oil, natural-gas, and NGLs production and development in Mozambique, Algeria, and Ghana. The Company also has exploration acreage in Brazil, Colombia, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, New Zealand, and other countries. International locations accounted for 11% of Anadarko’s total sales volumes and 21% of sales revenues during 2014, and 8% of total proved reserves at year-end 2014. In 2015, the Company expects to focus its exploration and appraisal activity in East Africa, Côte d’Ivoire, and Colombia.
Mozambique  Anadarko operates two blocks (one onshore and one offshore) totaling approximately 5.3 million gross acres at December 31, 2014. From a construction, finance, and marketing perspective, the Company is positioned to commence project execution and deliver first cargoes in the expected 2019 timeframe; however, the pace of this project is dependent upon securing necessary approvals from the government of Mozambique.

Development In February 2014, the Company sold a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion. Anadarko remains the operator of Offshore Area 1 with a working interest of 26.5%.
During 2014, the Company obtained reserves certification from a third party indicating sufficient volumes to support an initial LNG development. The Environmental Impact Assessment was approved by the government of Mozambique. The Company completed front-end engineering and design (FEED) for the onshore liquefaction facilities and the offshore gathering infrastructure and is in the process of selecting the contractor groups for construction. Anadarko and its partners reached non-binding Heads of Agreements for long-term LNG sales to buyers in Asian markets covering in excess of eight million metric tonnes per annum. In December 2014, the Mozambique government published a Decree Law that is sufficient to continue progressing project finance, marketing, and construction and operation of an LNG project. This legislation marks a critical step toward establishing a project-wide legal and contractual framework that delivers a level of fiscal stability enabling continued equity investments by the Company and potential access to significant limited-recourse project finance capital.

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Exploration  In the Offshore Area 1, the Tubarão Tigre-1 exploration well was drilled approximately 37 miles south of the Orca-1 discovery well and encountered more than 92 feet of net gas pay in Paleocene sands. The Ouriço do Mar exploration well was drilled 22.5 miles south of the Orca-1 discovery well and tested the potential down-dip extent of the Paleocene reservoirs found in the Orca and Tubarão Tigre discoveries. The well was plugged and abandoned during the third quarter of 2014. Appraisal of the Orca discovery continued with the drilling of three appraisal wells. During the first quarter of 2014, the Orca-2 well encountered 151 feet of Paleocene reservoir sand with the top 26 feet being charged, establishing the gas/water contact for the discovery. The rig moved to the Orca-3 location and encountered 102 net feet of natural-gas pay in the Paleocene. The Orca-4 well reached total depth during the fourth quarter of 2014 encountering natural-gas pay in two reservoirs. At the end of 2014, the rig was located at Tubarão Tigre-2 drilling the first appraisal well associated with the Tubarão Tigre discovery. Data from these wells will be used to further delineate the size of the resource and determine future appraisal activity for the Orca and Tubarão Tigre discoveries.
In the Onshore Rovuma (35.7% working interest), the Anadarko-operated Tembo-1 well completed drilling at the end of the fourth quarter in 2014. The well encountered gas and condensate in one of the Cretaceous reservoirs and post-drill evaluations are underway to determine if additional exploration is warranted within the prospect area. A rig has been mobilized to the second well in the program, Kifaru, which will test Miocene, Oligocene, and Paleocene gas targets near the future LNG facility site.
 
Algeria  Anadarko is engaged in production and development operations in Algeria’s Sahara Desert in Blocks 404 and 208, which are governed by a Production Sharing Agreement 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 for these blocks. The Company produces oil through the Hassi Berkine South and Ourhoud central processing facilities (CPF) in Block 404 and oil, condensate, and NGLs through the El Merk CPF in Block 208. Gross production through these facilities averaged more than 383 MBbls/d in 2014, and a quarterly net production record of approximately 75 MBOE/d was achieved as all of the fields at the El Merk CPF were increased to full oil production rates. The Company drilled nine development wells in 2014.

Ghana  Anadarko’s production and development activities in Ghana are located offshore in the West Cape Three Points Block and the Deepwater Tano Block.
The Jubilee field (27% nonoperated unit interest), which spans both the West Cape Three Points Block and the Deepwater Tano Block, averaged gross production of 102 MBbls/d of oil in 2014. In the fourth quarter of 2014, a pipeline tie-in was completed and natural-gas exports commenced from the Jubilee field to an onshore gas processing plant. The natural-gas exports are being delivered to satisfy a commitment established in conjunction with the Jubilee development plan and are expected to allow increases in future oil production rates. The Company and its partners are evaluating options to further expand the oil throughput capacity of the floating production, storage, and offloading vessel (FPSO) and expect to submit a full-field development plan for the Jubilee field to the government of Ghana in 2015.
The Jubilee J-24 development well was drilled deeper to evaluate the Mahogany sands below the Jubilee reservoirs. Additional appraisal work was completed in 2014 in the Mahogany and Akasa fields and the data is under evaluation.
In 2013, development commenced on the Tweneboa/Enyenra/Ntomme (TEN) project (19% nonoperated working interest). The project will use an 80-MBbls/d-capacity FPSO for production from subsea wells. Significant progress was made during 2014, including engineering design completion, the successful dry-docking of the FPSO, and drilling of the first nine wells. The project was approximately 50% complete at year-end 2014 and remains on budget and on schedule for first production in 2016.

China  In August 2014, the Company sold its Chinese subsidiary for $1.075 billion.

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Brazil  Anadarko holds exploration interests in approximately 300,000 gross acres in two offshore blocks located in the Campos basin. At the Wahoo discovery, the Company is evaluating commercialization options by performing pre-FEED and FEED studies.

Colombia  During 2014, Anadarko was the high bidder on the COL1, COL 6, and COL 7 blocks. At December 31, 2014, Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on nine blocks, totaling 16 million acres. The COL 1, COL 2, COL 6, and COL 7 blocks are operated at 100% working interest and the remaining blocks are operated at a 50% working interest.
Two initial prospects have been selected for the 2015 exploration drilling program. The Calasu prospect is a large four-way structure on the north end of the Fuerte Norte block. It has multiple targets and success would reduce the risk of several adjacent structures on the block. The Kronos prospect is located in the Fuerte Sur block and will test a large structure associated with the frontal area of a large thrust complex. As with Calasu, success would reduce the risk of multiple prospects. The two-well program commenced in early 2015.

Côte d’Ivoire  Anadarko owns an operated working interest in five offshore blocks totaling approximately 1.3 million acres, including CI-515 and CI-516 each with a 45% working interest, CI-103 with a 65% working interest, and CI-528 and CI-529 each with a 90% working interest.
The Company continued appraisal of the Cretaceous Paon discovery in Block CI-103, where the discovery well encountered 100 feet of net pay. The Paon-3AR was drilled 3.7 miles down-dip to the discovery well and encountered more than 94 feet of pay. The well established an oil/water contact and appears to be in communication with the Paon-1X discovery. As a result of the success, the drilling of the Paon-4A was accelerated. The well, located six miles east of the Paon-3AR, penetrated over 37 feet of pay in the target section and defined the eastern extent of the reservoir. During 2014, Anadarko became operator of the block and farmed down a portion of the working interest for a carry on the appraisal activities. Based on the successful drilling program to date, the partnership and the government are currently discussing additional appraisal drilling activity for 2015, which would include a drillstem test.
The Morue prospect in Block CI-516 was drilled and encountered a small accumulation of oil in the well-developed sands in the targeted interval, and was plugged and abandoned as non-commercial.
The Saumon prospect was drilled in Block CI-515 during 2014. The well reached total depth and did not find hydrocarbons. The well was plugged and abandoned.

Kenya  Anadarko owns and operates a 45% working interest in five offshore deepwater blocks, encompassing approximately 5.6 million gross acres. An exploration well is currently planned to test a large four-way structure at the Mlima prospect in Block L-11B during 2015.

Liberia  Two exploration wells were drilled in Block LB-10 (50% working interest) during 2014. The Anadarko-operated Iroko and Timbo wells both encountered non-commercial quantities of oil in their primary targets and were plugged and abandoned. Post-well evaluation is underway to determine the remaining prospectivity of the block. Anadarko completed a farm down prior to drilling, which covered a majority of the drilling costs for these two wells.

New Zealand  Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on four blocks totaling 42 million acres, of which 6.1 million acres are owned under exploration licenses. Anadarko operates a 45% working interest in the Canterbury basin block and a 100% working interest in two Pegasus basin blocks. In the 36 million acre New Caledonia basin block, Anadarko controls a 25% nonoperated working interest. The Caravel prospect reached its total-depth objective in the Canterbury basin block and was plugged and abandoned, having encountered natural gas shows and high-quality reservoir in the primary objective. A seismic acquisition is planned during 2015 on the block.

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

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Proved Reserves

Estimates of proved reserves volumes owned at year end, net of third-party royalty interests, are presented in billions of cubic feet (Bcf), at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (MMBbls) for oil, condensate, and NGLs. Total volumes are presented in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is the equivalent of 6,000 cubic feet of natural gas. Shrinkage associated with NGLs has been deducted from the natural-gas reserves volumes. Proved reserves are estimated based on the average beginning-of-month prices during the 12-month period for the respective year.
Disclosures by geographic area include the United States and International. The International geographic area consists of proved reserves located in Algeria and Ghana, which by country and in total represents less than 15% of the Company’s total proved reserves. The Company sold its Chinese subsidiary during 2014.

Summary of Proved Reserves
 
Natural Gas
(Bcf)
 
Oil and
Condensate
(MMBbls)
 
NGLs
(MMBbls)
 
Total
(MMBOE)
December 31, 2014
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
6,635

 
352

 
304

 
1,762

International
27

 
190

 
13

 
207

Undeveloped
 
 
 
 
 
 
 
United States
2,033

 
352

 
162

 
853

International
4

 
35

 

 
36

Total proved
8,699

 
929

 
479

 
2,858

 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
7,120

 
347

 
268

 
1,801

International

 
202

 

 
202

Undeveloped
 
 
 
 
 
 
 
United States
2,085

 
245

 
127

 
720

International

 
57

 
12

 
69

Total proved
9,205

 
851

 
407

 
2,792

 
 
 
 
 
 
 
 
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


The Company’s year-end 2014 proved reserves product mix was comparable to the last two years with 51% natural gas, 33% oil and condensate, and 16% NGLs.

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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.

MMBOE
2014
 
2013
 
2012
Proved Reserves
 
 
 
 
 
January 1
2,792

 
2,560

 
2,539

Reserves additions and revisions
 
 
 
 
 
Discoveries and extensions
63

 
145

 
82

Infill-drilling additions (1)
577

 
410

 
383

Drilling-related reserves additions and revisions
640

 
555

 
465

Other non-price-related revisions (1)
(137
)
 
(40
)
 
(31
)
Net organic reserves additions
503

 
515

 
434

Acquisition of proved reserves in place

 
36

 
4

Price-related revisions (1)
(1
)
 
(23
)
 
(68
)
Total reserves additions and revisions
502

 
528

 
370

Sales in place
(124
)
 
(12
)
 
(81
)
Production
(312
)
 
(284
)
 
(268
)
December 31
2,858

 
2,792

 
2,560

Proved Developed Reserves
 
 
 
 
 
January 1
2,003

 
1,883

 
1,811

December 31
1,969

 
2,003

 
1,883

_______________________________________________________________________________
(1) 
Combined and reported as revisions of prior estimates in the Company’s Supplemental Information under Item 8 of this Form 10-K. Reserves bookings related to infill drilling additions are treated as positive revisions. Other non-price-related revisions in 2014 are driven by a reduction of 116 MMBOE in the Wattenberg area primarily associated with the optimization of horizontal drilling locations and the discontinuation of vertical well workover plans.

The Company’s estimates of proved developed reserves, proved undeveloped reserves (PUDs), and total proved reserves at December 31, 2014, 2013, and 2012, 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. 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 Critical Accounting Estimates under Item 7 of this Form 10-K for additional information on the Company’s proved reserves.
The Company has not yet filed information with a federal authority or agency with respect to its estimated total proved reserves at December 31, 2014. 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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Changes in PUDs  Changes to PUDs occurring during 2014 are summarized in the table below. Revisions of prior estimates reflect Anadarko’s ongoing evaluation of its asset portfolio and 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 changes in commodity prices. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUDs development within five years unless specific circumstances warrant a longer development time horizon.
MMBOE
 
PUDs at January 1, 2014
789

Revisions of prior estimates
333

Extensions, discoveries, and other additions
32

Conversion to developed
(210
)
Sales
(55
)
PUDs at December 31, 2014
889


Revisions In 2014, PUD revisions of 333 MMBOE were primarily related to successful infill drilling in large onshore areas such as Wattenberg in the Rockies and the Eagleford shale in the Southern and Appalachia Region, partially offset by decreases primarily due to development plan updates.

Extensions, Discoveries, and Other Additions During 2014, Anadarko added 32 MMBOE of PUDs through extensions, discoveries, and other additions, primarily as a result of successful drilling in the Marcellus and Wolfcamp shale plays in the Southern and Appalachia Region.

Conversions  In 2014, the Company converted 210 MMBOE, or 27% of total year-end 2013 PUDs, to developed status. Approximately 73% of PUD conversions occurred in U.S. onshore assets, 16% in international assets, and the remaining 11% in Gulf of Mexico assets.
Development activity in the U.S. onshore assets resulted in the conversion of 80 MMBOE in the Southern and Appalachia Region and 72 MMBOE in the Rockies. Ongoing development activity in the Company’s Algerian assets resulted in the conversion of 34 MMBOE in 2014. The remaining PUD conversions were associated with development projects in various Gulf of Mexico fields.
Anadarko spent $1.6 billion to develop PUDs in 2014, of which approximately 74% related to U.S. onshore assets, 13% related to Gulf of Mexico assets, and 13% related to international assets.
In 2013, the Company converted 183 MMBOE, or 27% of the total year-end 2012 PUDs, to developed status. Approximately 85% of PUD conversions occurred in U.S. onshore assets, 11% in international assets, and the remaining 4% in Gulf of Mexico assets. Anadarko spent $1.0 billion on PUD development in 2013, of which approximately 70% related to domestic development programs in the Rockies and the Southern and Appalachia Regions, 25% related to development of international projects, and the remaining 5% related to Alaska and Gulf of Mexico development projects.

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Development Plans  The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Typically, U.S. onshore 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 U.S. onshore PUDs at December 31, 2014, 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.
At December 31, 2014, the Company had 39 MMBOE of pre-2010 PUDs that remained undeveloped. Approximately 51% of these PUDs are associated with Gulf of Mexico opportunities where longer development times are a result of delays associated with operating in a deepwater environment, including delays associated with the development and adoption of enhanced safety procedures and other regulatory changes following the Deepwater Horizon event.
Another 33% of the Company’s pre-2010 PUDs are associated with the Salt Creek EOR single-development project located in the Rockies. Since 2003, Anadarko has invested an average of $90 million per year to develop the Salt Creek EOR project and will continue similar spending levels in the future.
The remaining pre-2010 PUDs are associated with the El Merk development project and are being developed according to an Algerian government-approved plan. Anadarko and its partners achieved initial oil production in 2013 and the El Merk facility reached maximum allowable oil production rates in 2014 when all the fields were brought online and the facility became fully operational.

Technologies Used in Proved Reserves Estimation  The Company’s 2014 proved reserves additions were based on estimates generated through the integration of relevant geological, engineering, and production data, using 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 used 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).
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 VP-Corporate Planning. The VP-Corporate Planning reports to the Company’s Executive Vice President, Finance and Chief Financial Officer, who in turn reports to the Chairman, President, and Chief Executive Officer. The Governance and Risk 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.

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The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserves estimates, has over 28 years of experience in the oil and gas industry, including over 14 years as either a reserves estimator or manager. His 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 28 years. In addition, he 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 the Company’s estimates of proved reserves and future net cash flows at December 31, 2014. The purpose of the review was to determine if 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 reviews by M&L were limited reviews of Anadarko’s procedures and methods and do 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 reviews covered 16 fields that included major assets in the United States and Africa, and encompassed approximately 88% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2014. 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 308 MMBOE for 2014, 285 MMBOE for 2013, and 268 MMBOE for 2012. Production costs are costs to operate and maintain the Company’s wells, related equipment, and supporting facilities, including the cost of labor, well service and repair, location maintenance, power and fuel, gathering, processing, 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 20—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. The following provides the Company’s annual sales volumes, average sales prices, and average production costs per BOE for each of the last three years:
 
Sales Volumes
 
Average Sales Prices (1)
 
Average
Production
Costs (2)
(Per BOE)
 
Natural
Gas
(Bcf)
 
Oil and
Condensate
(MMBbls)
 
NGLs
(MMBbls)
 
Barrels of
Oil
Equivalent
(MMBOE)
 
Natural
Gas
(Per Mcf)
 
Oil and
Condensate
(Per Bbl)
 
NGLs
(Per Bbl)
 
2014

 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
154

 
1

 
4

 
31

 
$
3.93

 
$
81.74

 
$
39.16

 
$
10.30

Wattenberg
125

 
27

 
13

 
62

 
4.19

 
87.76

 
36.46

 
8.00

Other United States
666

 
46

 
26

 
182

 
4.08

 
88.29

 
34.29

 
9.28

Total United States
945

 
74

 
43

 
275

 
4.07

 
87.99

 
35.48

 
9.11

International

 
32

 
1

 
33

 

 
99.79

 
56.16

 
8.22

Total
945

 
106

 
44

 
308

 
4.07

 
91.58

 
36.01

 
9.01

2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
168

 
1

 
4

 
33

 
$
3.12

 
$
87.46

 
$
41.79

 
$
9.59

Wattenberg
102

 
16

 
6

 
40

 
3.75

 
94.27

 
41.75

 
8.55

Other United States
698

 
41

 
23

 
179

 
3.56

 
98.38

 
36.14

 
8.72

Total United States
968

 
58

 
33

 
252

 
3.50

 
97.02

 
37.97

 
8.81

International

 
33

 

 
33

 

 
109.15

 

 
9.96

Total
968

 
91

 
33

 
285

 
3.50

 
101.41

 
37.97

 
8.94

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

 _______________________________________________________________________________
Mcf—thousand cubic feet
Bbl—barrel
(1) 
Excludes the impact of commodity derivatives.
(2) 
Excludes ad valorem and severance taxes.

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Delivery Commitments

The Company sells oil and natural gas under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. At December 31, 2014, Anadarko was contractually committed to deliver approximately 874 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 2015, and 70% by 2019. At December 31, 2014, Anadarko also was contractually committed to deliver approximately 9 MMBbls of oil to ports in Algeria and Ghana through 2015. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves.

Properties and Leases

The following shows the developed lease, undeveloped lease, and fee mineral acres in which Anadarko held interests at December 31, 2014:
 
Developed
Lease
 
Undeveloped
Lease
 
Fee Mineral
 
Total
thousands of acres
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Onshore
5,069

 
3,314

 
5,203

 
2,140

 
10,313

 
8,472

 
20,585

 
13,926

Offshore
293

 
139

 
2,079

 
1,401

 

 

 
2,372

 
1,540

Total United States
5,362

 
3,453

 
7,282

 
3,541

 
10,313

 
8,472

 
22,957

 
15,466

International
499

 
113

 
56,725

 
39,328

 

 

 
57,224

 
39,441

Total
5,861

 
3,566

 
64,007

 
42,869

 
10,313

 
8,472

 
80,181

 
54,907


At December 31, 2014, the Company had approximately 26 million net undeveloped lease acres scheduled to expire by December 31, 2015, 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 2014 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 2014 consisted of 88 gross completed wells, which included 71 U.S. onshore wells, five Gulf of Mexico wells, and 12 international wells. Development activity in 2014 consisted of 1,268 gross completed wells, which included 1,264 U.S. onshore wells and four Gulf of Mexico wells.

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Drilling Statistics
The following shows the number of oil and gas wells that completed drilling in each of the last three years:
 
Net Exploratory
 
Net Development
 
Total

Productive
 
Dry Holes
 
Total
 
Productive
 
Dry Holes
 
Total
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
35.6

 
1.6

 
37.2

 
811.4

 
6.0

 
817.4

 
854.6

International
0.9

 
4.5

 
5.4

 

 

 

 
5.4

Total
36.5

 
6.1

 
42.6

 
811.4

 
6.0

 
817.4

 
860.0

2013
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
62.9

 
1.4

 
64.3

 
879.3

 
3.3

 
882.6

 
946.9

International
0.2

 
3.5

 
3.7

 
5.4

 

 
5.4

 
9.1

Total
63.1

 
4.9

 
68.0

 
884.7

 
3.3

 
888.0

 
956.0

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


The following 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, 2014:
 
Wells in the process
of drilling or
in active completion
 
Wells suspended or
waiting on completion (1)
 
Exploration
 
Development
 
Exploration
 
Development
United States
 
 
 
 
 
 
 
Gross
7

 
186

 
60

 
861

Net
3.8

 
118.6

 
28.2

 
557.9

International
 
 
 
 
 
 
 
Gross
2

 

 
57

 
19

Net
0.9

 

 
17.8

 
4.2

Total
 
 
 
 
 
 
 
Gross
9

 
186

 
117

 
880

Net
4.7

 
118.6

 
46.0

 
562.1

 _______________________________________________________________________________
(1) 
Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

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Productive Wells

At December 31, 2014, the Company’s ownership interest in productive wells was as follows:
 
Oil Wells (1)
 
Gas Wells (1)
United States
 
 
 
Gross
4,611

 
28,200

Net
3,157.9

 
19,271.8

International
 
 
 
Gross
201

 
4

Net
36.1

 
1.0

Total
 
 
 
Gross
4,812

 
28,204

Net
3,194.0

 
19,272.8

________________________________________________________________
(1) 
Includes wells containing multiple completions as follows:
Gross
245

 
2,862

Net
216.8

 
2,401.4


MIDSTREAM PROPERTIES AND ACTIVITIES

Anadarko invests in and operates 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 contract structures, including fixed-fee, percent-of-proceeds, and keep-whole agreements. Anadarko’s midstream activities include WES, which is a publicly traded limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES’s general partner interest is owned by Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary formed to own substantially all of the partnership interests in WES previously owned by Anadarko. At December 31, 2014, Anadarko’s ownership interest in WGP consisted of an 88.3% limited partner interest and the entire non-economic general partner interest. At December 31, 2014, WGP’s ownership interest in WES consisted of a 34.9% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At December 31, 2014, Anadarko also owned an 8.3% limited partner interest in WES through other subsidiaries.
At the end of 2014, Anadarko had 41 gathering systems and 38 processing and treating plants located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania, and Texas. In 2014, the Company’s midstream activity was concentrated in liquids-rich growth areas such as Wattenberg, Greater Natural Buttes, the Delaware basin, the Eagleford shale, and East Texas/North Louisiana plays, as well as in the Marcellus shale dry-gas play. In 2015, the Company plans to continue midstream investments in these core areas.

Wattenberg  The Company is constructing a second 300-MMcf/d train at its Lancaster cryogenic processing plant, with completion expected in the second quarter of 2015. The plant will support the increasing production from horizontal drilling in the Niobrara development, helping to relieve processing constraints and improve recoveries of NGLs in the basin. Three new compressor stations are scheduled to come online in the first quarter of 2015 with a total capacity of 120 MMcf/d. In addition, the Company is constructing a Central Oil Stabilization Facility (COSF) with an expected completion date of mid-year 2015. The COSF will stabilize oil in a centralized location and will reduce equipment and installation cost at each well pad. Initial planned throughput for the facility is 125 MBbls/d.

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The Company participates in two long-haul NGL pipeline joint ventures, FRP and Texas Express Pipeline (TEP), which provide access to the Gulf Coast NGLs market. The FRP, which is connected to the Company’s Lancaster processing facility, was placed in service in the first quarter of 2014. The FRP extends 435 miles, providing 150 MBbls/d (expandable to 230 MBbls/d) of NGLs takeaway capacity from Weld County, Colorado to Skellytown, Texas. In Skellytown, the FRP connects to other pipelines including the TEP. The TEP extends 593 miles providing 280 MBbls/d (expandable to 400 MBbls/d) of NGLs takeaway capacity to NGLs fractionation and storage facilities in Mont Belvieu, Texas. The Company has ownership interests of 33% in the FRP, 20% in the TEP, and 25% in two NGLs fractionators at Mont Belvieu.
In July 2014, construction of the second pipeline for the White Cliffs Pipeline system was completed and placed in service. This 526-mile dual pipeline system now provides 150 MBbls/d of oil takeaway capacity from Platteville, Colorado to Cushing, Oklahoma. The Company and its joint-venture partners are currently expanding the existing pipeline system to over 200 MBbls/d. The expansion project is scheduled to be completed in mid-2015.

Greater Natural Buttes  Chipeta’s total processing capacity (cryogenic and refrigeration) is approximately one billion cubic feet per day with cryogenic processing capacity exceeding 600 MMcf/d. Chipeta’s third-party pipeline interconnect has added over 100 MMcf/d of natural-gas supply to the plant. Optimization projects, including several pipeline-freeze mitigation projects in the gathering system, have continued to improve the Company’s reliability and efficiency.

Wyoming  During the second half of 2014, the Company connected five third-party well locations to the Patrick Draw plant. Initial deliveries are expected in the first quarter of 2015. The Company also constructed a 10-mile pipeline in the Barricade unit to gather and deliver the incremental third-party gas to the Company’s Patrick Draw plant for processing. Also, gathering connections and expansions in 2014 increased throughput of the Hilight plant by about 40%.

Delaware Basin  In 2014, the Company expanded its midstream infrastructure for Bone Spring, Wolfcamp, and Avalon production in the Delaware basin of West Texas, installing a total of 127 miles of oil and gas gathering lines. Also, significant progress was made towards expanding three central production facilities that will add 30 MBbls/d of capacity upon completion in early 2015. Substantial progress was made on a new CGF with a capacity of 24 MMcf/d, which will be completed in early 2015. The Company entered into a joint-venture agreement with a third party to construct a new 200-MMcf/d cryogenic plant located in Loving County, Texas. The new plant will be operated by the third party.
In November 2014, WES acquired Nuevo, which owns and operates gathering and processing assets located in the Delaware basin. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). The assets include a 300-MMcf/d cryogenic gas processing plant. WES is preparing to construct an additional 200-MMcf/d cryogenic unit (Train IV) and progress payments have been made towards the construction of another cryogenic unit (Train V), with both expected to come online in 2016.

Eagleford  In the Eagleford shale, Anadarko continued the expansion of its infield gathering system with (i) the installation of two new field gas compression facilities, (ii) the addition of incremental compression at Stumberg and Catarina Ranch compressor stations, and the Maverick main central delivery point compression facilities, as well as three other existing field compression facilities, (iii) the completion of approximately 90 miles of gathering pipelines and lateral that connected more than 20 central production facilities, and (iv) enhancements at the main oil-handling facility that increased its reliability and capabilities. The 200-MMcf/d Brasada natural-gas cryogenic processing plant completed its first full year of operations and remains at or near capacity.

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East Texas/North Louisiana  In East Texas, the Company continued to expand its midstream infrastructure for Cotton Valley Taylor and Haynesville production in 2014. The high-pressure Haynesville gathering system, and related water and condensate infrastructure, was expanded in the Carthage area to handle the continued growth associated with the liquids-rich Haynesville natural-gas production. Additionally, Anadarko has secured access to 430 MMcf/d of firm-processing capacity for the Company’s current and future development in East Texas.

Marcellus  In the Marcellus shale, Anadarko continued to expand its gathering system in Lycoming County, Pennsylvania. In 2014, the Company connected 44 Anadarko-operated wells and constructed 52 miles of new pipeline. The Seely West trunk line, completed in December 2014, connects the COP 356/357 gathering system and Larry’s Creek gathering system to the Seely gathering system and alleviates the need to use third parties to gather natural gas.

Springfield  In September 2014, the Company sold the Springfield gathering system located in East Texas to a third party.

San Juan  In April 2014, the Company sold the San Juan gathering system located in New Mexico, Colorado, and Utah along with the San Juan River gas processing plant located in New Mexico to a third party.

The following provides information regarding the Company’s midstream assets by geographic regions:
Area
 
Asset Type
 
Miles of
Gathering
Pipelines
 
Total
Horsepower
 
2014
Average Net
Throughput
(MMcf/d)
Rocky Mountains
 
Gathering, processing, and treating
 
11,900

 
1,244,100

 
3,800

Texas
 
Gathering, processing, and treating
 
3,600

 
248,400

 
1,100

Mid-Continent and other
 
Gathering
 
3,300

 
392,200

 
1,100

Total
 
 
 
18,800

 
1,884,700

 
6,000


MARKETING ACTIVITIES

The Company’s marketing segment actively manages Anadarko’s natural-gas, oil, condensate, and NGLs sales, as well as the Company’s anticipated LNG 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, oil, condensate, and NGLs are generally made at market prices for those products at the time of sale. The Company also purchases natural gas, oil, condensate, and NGLs from third parties, primarily near Anadarko’s production areas, to aggregate volumes so that the Company is positioned to fully use transportation, storage and fractionation capacity, facilitate efforts to maximize prices received, and minimize balancing issues with customers and pipelines during operational disruptions.
The Company sells its products under a variety of contract structures 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, oil, condensate, and NGLs. The Company does not engage in market-making practices and limits its marketing activities to natural-gas, oil, NGLs, and LNG commodity contracts. The Company’s marketing-risk position is typically a net short position (reflecting agreements to sell natural gas, 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 oil reserves). See Commodity-Price Risk under Item 7A of this Form 10-K.


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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.

Oil, Condensate, and NGLs  Anadarko’s oil, condensate, and NGLs revenues are derived from production in the United States, Algeria, and Ghana. Most of the Company’s U.S. oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality, and transportation. Product from Algeria is sold by tanker as Saharan Blend, condensate, refrigerated propane, and refrigerated butane 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 Ghana is sold by tanker as Jubilee Oil to customers around the world. Jubilee Oil is high-quality crude that provides refiners large quantities of premium products such as gasoline, diesel, and jet fuel. Prior to the Company divesting its subsidiary in August 2014, oil from China was sold by tanker as Cao Fei Dian Blend to customers primarily in the Far East markets.

COMPETITION

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

SEGMENT INFORMATION

For additional information on operations by segment, see Note 20—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and 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 6,100 employees at December 31, 2014.

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REGULATORY AND ENVIRONMENTAL MATTERS

Environmental and Occupational Health and Safety Regulations

Anadarko’s business operations are subject to numerous international, provincial, federal, regional, state, tribal, and local environmental and occupational health and safety laws and regulations. The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. laws and regulations, as amended from time to time:
 
the U.S. Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring, and reporting requirements
the U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act (CWA), which regulates discharges of pollutants from facilities to state and federal waters
the U.S. Oil Pollution Act of 1990 (OPA), which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States
U.S. Department of the Interior regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes 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 generation, treatment, storage, transport, 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 implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories
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 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

These laws and 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. See Risk Factors under Item 1A of this Form 10-K for further discussion on hydraulic fracturing, ozone standards, climate change, including methane or other greenhouse gas emissions, and other regulations relating to environmental protection. 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.

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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. In addition, environmental laws and regulations, including those that may arise to address potential air and water impacts, 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.
The Company has reviewed its potential responsibilities under both OPA and CWA as they relate to the Deepwater Horizon events.
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, 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. 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.
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 condition, 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 subject to compliance with the federal Bureau of Safety and Environmental Enforcement (BSEE) regulations, which, among other standards, 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 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 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 contractually engaged by the Company for such matters), and representatives of relevant governmental agencies. The Plans must be approved by the BSEE.

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As part of the Company’s oil spill-response preparedness, and as set forth in the Plans, Anadarko maintains membership in CGA, and has an employee representative on the executive committee of CGA. CGA was created to provide a means of effectively staging response equipment and to provide effective spill-response capability for its member companies operating in the Gulf of Mexico. CGA equipment and capabilities include skimming vessels, barges, boom and dispersants, among others. 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.
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 dedicated Responder Class Oil Spill-Response Vessels (OSRVs), designed and built specifically to recover spilled oil.
MSRC has equipment housed for the Atlantic Region, the Gulf of Mexico Region, the California Region, and the Pacific Northwest Region. Their equipment includes skimmers, 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 a 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.
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 satellites, which 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. for assistance with Subsea Dispersant applications. 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 has an aircraft available for dispersant application or equipment transport. OSRL also has a number of active recovery boom systems, and a range of booms that can be used for offshore, nearshore, or shoreline responses. In addition, OSRL 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. 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, 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, thorough title examinations of the drill site tract are conducted by third-party attorneys 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
January 31,
2015
 
Position
R. A. Walker
 
57
 
Chairman, President and Chief Executive Officer
Robert P. Daniels
 
56
 
Executive Vice President, International and Deepwater Exploration
Robert G. Gwin
 
51
 
Executive Vice President, Finance and Chief Financial Officer
James J. Kleckner
 
57
 
Executive Vice President, International and Deepwater Operations
Charles A. Meloy
 
54
 
Executive Vice President, U.S. Onshore Exploration and Production
Robert K. Reeves
 
57
 
Executive Vice President, General Counsel and Chief Administrative Officer
M. Cathy Douglas
 
58
 
Senior Vice President, Chief Accounting Officer and Controller

Mr. Walker was named Chairman of the Board of the Company in May 2013, in addition to the role of Chief Executive Officer and director, both of which he assumed in May 2012, and the role of President, which he assumed in February 2010. He previously served as Chief Operating Officer from March 2009 until his appointment as Chief Executive Officer. He served as Senior Vice President, Finance and Chief Financial Officer from September 2005 until March 2009. From August 2007 until March 2013, he 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 served as a director of Western Gas Equity Holdings, LLC (WGEH), the general partner of WGP, from September 2012 until March 2013. 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 and as a director of BOK Financial Corporation since April 2013.
Mr. Daniels was named Executive Vice President, International and Deepwater Exploration in May 2013 and previously served as Senior Vice President, International and Deepwater Exploration since July 2012. Prior to these positions, 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 Executive Vice President, Finance and Chief Financial Officer in May 2013 and previously served as Senior Vice President, Finance and Chief Financial Officer since March 2009 and 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 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 Chairman of the Board of LyondellBasell Industries N.V. since August 2013 and as a director since May 2011.

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Mr. Kleckner was named Executive Vice President, International and Deepwater Operations in May 2013. Prior to this position, he served as Vice President, Operations for the Rockies region since May 2007. Mr. Kleckner joined Anadarko upon the acquisition of Kerr-McGee Corporation in August 2006. He has held positions of increasing responsibility with Anadarko and Kerr-McGee Corporation, including management roles in the North Sea, South America, China, the Gulf of Mexico and U.S. onshore. Prior to joining Kerr-McGee Corporation, Mr. Kleckner was in the oil and natural-gas industry with Oryx Energy Company and its predecessor, Sun Oil Company.
Mr. Meloy was named Executive Vice President, U.S. Onshore Exploration and Production in May 2013 and previously served as Senior Vice President, U.S. Onshore Exploration and Production since 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 in August 2006. Prior to joining Anadarko, he served Kerr-McGee Corporation 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. Prior to joining Kerr-McGee Corporation, Mr. Meloy was in the oil and natural-gas industry with Oryx Energy Company and its predecessor, Sun Oil Company. Mr. Meloy has served as a director of WGH since February 2009 and as a director of WGEH since September 2012.
Mr. Reeves was named Executive Vice President, General Counsel and Chief Administrative Officer in May 2013 and previously served as Senior Vice President, General Counsel and Chief Administrative Officer since February 2007. He also served as Chief Compliance Officer from July 2012 to May 2013. He 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 Senior Vice President, Chief Accounting Officer and Controller in May 2013. Prior to this position, she served as Vice President and Chief Accounting Officer since November 2008 and served as Corporate Controller from September 2007 to March 2009 and from March 2013 to May 2013. 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 12, 2015, 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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include, among other things, 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 be realized. 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 energy markets
production and sales volume levels
reserves levels
operating results
competitive conditions
technology
availability of capital resources, levels of capital expenditures, and other contractual obligations
supply and demand for, the price of, and the commercialization and transporting of natural gas, 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
processing volumes and pipeline throughput
general economic conditions, either nationally, internationally, or in the jurisdictions in which the Company or its subsidiaries are doing business
the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects
legislative or regulatory changes, including changes relating to hydraulic fracturing; retroactive royalty or production tax regimes; 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

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the ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for Deepwater Horizon events, including, 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
the 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
civil or political unrest or acts of terrorism in a region or country
the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties
volatility in the securities, capital, or credit markets 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 oil, NGLs, and condensate cargo shipping activities
physical, digital, internal, and external security breaches
supply and demand, technological, political, governmental, 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

RISK FACTORS

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. In addition, in September 2014, the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) issued its Findings of Fact and Conclusions of Law in the first phase of the Deepwater Horizon trial. The Louisiana District Court found that BP is liable under general maritime law for the blowout, explosion, and oil spill and apportioned 67% of the fault to BP. BP is challenging certain of the Louisiana District Court’s findings.

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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 penalties and fines, 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.

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. For example, daily settlement prices for New York Mercantile Exchange (NYMEX) West Texas Intermediate oil ranged from a high of $107.26 per barrel to a low of $53.27 per barrel during 2014. Daily settlement prices for NYMEX Henry Hub natural gas ranged from a high of $6.15 per million British thermal units (MMBtu) to a low of $2.89 per MMBtu during 2014. Our revenues, operating results, cash flows from operations, capital budget, 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. 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 oil and natural-gas inventories
weather conditions
potential U.S. exports of liquefied natural gas, oil, condensate, or NGLs
ability of the members of the Organization of the 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 laws, regulations, and taxes
proximity to, and capacity of, natural-gas pipelines and other transportation facilities
general economic conditions worldwide

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

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reducing our revenues, operating income, or cash flows
reducing the amounts of our estimated proved oil, natural-gas, and NGLs 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, natural-gas, and NGLs 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, provincial, 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. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, provincial, regional, state, tribal, and local governmental authorities. We may incur substantial costs to maintain compliance with these existing laws and regulations. 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:
 
Ozone Standards. In December 2014, the U.S. Environmental Protection Agency (EPA) published proposed regulations to revise the National Ambient Air Quality Standard for ozone, recommending a standard between 65 to 70 parts per billion (ppb) for both the 8-hour primary and secondary standards protective of public health and public welfare. The current primary and secondary ozone standards are set at 75 ppb. The EPA is also taking comments on whether a 60 ppb standard should be established for the primary standard or whether the existing 75 ppb standard should be retained. If adopted, compliance with such regulations may require the Company to install new equipment to further control emissions and may also cause permitting delays. The EPA currently expects to issue a final rule by October 1, 2015.
Reduction of Methane Emissions. In January 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will regulate methane emissions from the oil and gas sector. The Obama Administration seeks to reduce methane emissions from new and modified infrastructure and equipment in the oil and gas sector, including the drilling of new wells, by up to 45% from 2012 levels by 2025.
Climate Change. A number of state and regional efforts exist that are aimed at tracking or reducing greenhouse gas (GHG) emissions. In addition, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. 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 together with other criteria pollutants.
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 accelerated depreciation for tangible property.

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Changes in laws or regulations regarding hydraulic fracturing or other oil and gas operations could increase our costs of doing business, impose 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 oil from dense subsurface rock formations such as shales. 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 to fracture the surrounding rock and stimulate production.
Hydraulic fracturing is regulated by state oil and natural-gas commissions. However, several federal agencies have also asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards for the oil and gas industry; announced its intent to propose in early 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the Bureau of Land Management issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is expected to promulgate a final rule in early 2015. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the 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 operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
Certain states in which we operate, including Colorado, Pennsylvania, Louisiana, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, or well-construction requirements on hydraulic-fracturing operations or prohibit these operations completely. 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. For example, in exchange for the withdrawal of several initiatives relating to hydraulic fracturing and other oil and gas operations proposed for inclusion on the Colorado state ballot in November 2014, the governor of Colorado created the Task Force on State and Local Regulation of Oil and Gas Operations (Task Force) in September 2014 to make recommendations to the state legislature regarding the responsible development of Colorado’s oil and gas resources. Although it is early in the process, it is possible that, as a result of the Task Force’s recommendations, Colorado could adopt new policies or legislation relating to oil and natural-gas operations, including measures that would give local governments in Colorado greater authority to limit hydraulic fracturing and other oil and natural-gas operations or require greater distances between well sites and occupied structures. In the event state or local restrictions or prohibitions are adopted in areas where we conduct operations, such as the Wattenberg field in Colorado, we may incur significant costs to comply with such requirements or we may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Such costs, delays, restrictions, or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
In addition to asserting regulatory authority, a number of federal entities are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In April 2012, President Obama issued an executive order that established a working group for the purpose of coordinating policy, information sharing, and planning among federal agencies and offices regarding “unconventional natural-gas production,” including hydraulic fracturing. In December 2012, the EPA issued an initial progress report on a study begun in 2011 of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft final report expected to be issued for peer review and comment in early 2015. These studies and initiatives, or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing.

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

Our total debt was $15.1 billion at December 31, 2014. 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 fully realize the value of our assets and opportunities 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 agreements governing our $3.0 billion five-year senior unsecured revolving credit facility and our $2.0 billion 364-day senior unsecured revolving credit facility contain a number of customary covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65%, and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes. Our ability to meet such covenants may be affected by events beyond our control.

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

As of December 31, 2014, our long-term debt was rated “BBB” with a stable outlook by Standard and Poor’s (S&P), “BBB-” with a positive outlook by Fitch Ratings (Fitch), and “Baa3” with a positive outlook by Moody’s Investors Service (Moody’s). In February 2015, Moody’s raised our long-term debt rating to “Baa2” and changed the outlook to stable. 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 ratings were downgraded, it could affect our ability 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 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Our proved reserves are estimates. Any material inaccuracies in our 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

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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 the average beginning-of-month prices during the 12-month period for the respective year. Actual future prices and costs may differ materially from the SEC regulation-compliant prices used for purposes of estimating future discounted net cash flows from proved reserves.

Failure to replace reserves may negatively affect our business.

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

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

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

Future 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, potential default on U.S. debt, energy costs, geopolitical issues, the availability and cost of credit, and uncertainties with regard to European sovereign debt, have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. Continued concerns could cause demand for petroleum products to diminish or stagnate, which could impact the price at which we can sell our oil, natural gas, and NGLs; affect the ability of our vendors, suppliers, and customers 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 $5.6 billion of goodwill on our Consolidated Balance Sheet at December 31, 2014. 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, difficulty or potential delays in obtaining drilling permits, or other adverse events, such as lower 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.

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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, provincial, 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, including the assessment of 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 our activities in a particular area. 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, such as the sage grouse, may negatively impact our operations. 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 Legal Proceedings under Item 3 and Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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

We conduct offshore operations in the Gulf of Mexico, Mozambique, Ghana, Brazil, Colombia, Côte d’Ivoire, Kenya, Liberia, 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 and decommissioning activities 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.

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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.

Additional domestic and international deepwater drilling laws, regulations, and other restrictions; delays in the processing and approval of drilling permits and exploration and oil spill-response plans; and other related developments 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 and the Bureau of Safety and Environmental Enforcement, each agencies of the U.S. Department of the Interior, imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these new and more stringent rules and regulations, in addition to 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, and possible additional regulatory initiatives could adversely affect or delay new drilling and ongoing development efforts. 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 supplemental bonding and costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities. If similar material spill events were to occur in the future, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover the risks associated with such operations.
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.

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, Colombia, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, and New Zealand. As a result, we face political and economic risks and other uncertainties with respect to our international operations. These risks may include the following, among other things:
 
loss of revenue, property, and equipment or delays in operations as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection, civil unrest, and other political risks, including tension and confrontations among political parties
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
changes in laws and policies governing operations of foreign-based companies

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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 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 developing the TEN complex. In the event Côte d’Ivoire is successful in its maritime border claims, this development could be materially impacted. Also, Venezuela and Guyana are in a dispute regarding their maritime and land borders in which the two countries have initiated a dialogue. We are unable to ascertain the full impact of this border dispute on future operations in Guyana.
Outbreaks of civil and political unrest and acts of terrorism have occurred in countries in Europe, Africa, and the Middle East, including countries where we conduct operations. 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, directly or indirectly, by laws, policies, and regulations of the United States affecting foreign trade and taxation, including U.S. trade sanctions.
Realization of any of the factors listed above could materially and adversely affect the Company’s financial condition, 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 notional volumes
a widening of price basis differentials occurs between delivery points for our production and the delivery point assumed in the derivative 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, natural-gas, or NGLs prices

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, 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, requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. While many rules and regulations have been promulgated and are already in effect, other rules and regulations, including the proposed margin rules, position limits, and commodity clearing requirements, remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time.

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New or modified rules, regulations, or legal requirements may increase the cost and impact the availability to our counterparties of their hedging and swap positions that they can make available to us, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities, which may not be as creditworthy as the current counterparties. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation or post margin collateral. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.
The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives we use to hedge against commodity-price fluctuations (including through requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter, and (iv) increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and applicable rules and regulations, our cash flow may become more volatile and less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent the Company transacts with counterparties in foreign jurisdictions, it may become subject to such regulations. At this time, the impact of such regulations is not clear.

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; environmental hazards, such as gas leaks, oil spills, pipeline and vessel ruptures, and releases of chemicals or other hazardous substances, any of which could result in damage to, or destruction of, oil and natural-gas wells or formations, production facilities, and other property; pollution or other environmental damage; and 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/loss of 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 financial condition, results of operations, or cash flows.

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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 and the completion of those projects may be delayed beyond our anticipated completion dates. 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 or legislative and other governmental approvals
weather conditions
availability of qualified personnel
civil and political environment of, and existing infrastructure in, 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.

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.

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Our drilling activities may not be productive.

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

We have limited influence 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 the operation or future development of these nonoperated 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 the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital, lead to unexpected future costs, or adversely affect the timing of activities.

Our ability to sell our oil, natural gas, and NGLs 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 oil, natural gas, and NGLs, which could increase our costs and/or reduce the revenues we might obtain from the sale of the oil and gas.

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Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats such as attempts to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities, and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data, which could have an adverse effect on our reputation, financial condition, results of operations, or cash flows.
While we have experienced cybersecurity attacks, we have not suffered any material losses relating to such attacks; however, there is no assurance that we will not suffer such losses in the future. In addition, as cybersecurity threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cybersecurity vulnerabilities.

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.

Item 1B.  Unresolved Staff Comments

None.

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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; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. 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 financial condition, results of operations, or cash flows.
In September 2013, Anadarko received a Notice of Proposed Penalty Assessment from the Bureau of Safety and Environmental Enforcement (BSEE) as the result of an incident that occurred in February 2012 relating to a drilling rig in the Gulf of Mexico. In the notice, BSEE alleged several violations of certain offshore operational requirements. Anadarko disputed many of the allegations and in October 2014 received a Revised Final Reviewing Officer’s Decision from BSEE for a penalty of $70,000.
In June 2014, the EPA alleged that Anadarko was not in compliance with a consent decree entered into by the U.S. District Court for the District of Colorado on March 27, 2008 to resolve certain Clean Air Act violations in Colorado and Utah. Specifically, the EPA alleged violations of the consent decree at three of Anadarko’s compressor station facilities located in Utah. In November 2014, Anadarko entered into a joint stipulation with the EPA and agreed to pay a penalty of $599,000.
WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA concerning enforcement for alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.
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 30, 2015, there were approximately 11,400 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 2014 and 2013:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2014
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
86.86

 
$
112.06

 
$
113.51

 
$
102.68

Low
$
77.80

 
$
84.54

 
$
100.40

 
$
71.00

Dividends
$
0.18

 
$
0.27

 
$
0.27

 
$
0.27

2013
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
89.20

 
$
92.18

 
$
96.75

 
$
98.47

Low
$
74.73

 
$
78.30

 
$
86.08

 
$
73.60

Dividends
$
0.09

 
$
0.09

 
$
0.18

 
$
0.18


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 sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the Company at December 31, 2014:
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
 
6,791,018

 
$
69.96

 
21,169,470

Equity compensation plans not
   approved by security holders
 

 

 

Total
 
6,791,018

 
$
69.96

 
21,169,470


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 2014:
Period
 
Total
number of
shares
purchased (1)
 
Average
price paid
per share
 
Total number of
shares purchased
as part of publicly
announced plans
or programs
 
Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs
October
 
14,821

 
$
92.69

 

 
 
November
 
79,151

 
$
92.83

 

 
 
December
 
2,084

 
$
77.60

 

 
 
Fourth Quarter 2014
 
96,056

 
$
92.48

 

 
$

 _______________________________________________________________________________
(1) 
During the fourth quarter of 2014, 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; Murphy Oil Corporation; Noble Energy, Inc.; Occidental Petroleum Corporation; and Pioneer Natural Resources Company.

Comparison of 5-Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index, and a Peer Group
Copyright© 2015 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, 2009, and its relative performance is tracked through December 31, 2014. 
Fiscal Year Ended December 31
2009
 
2010
 
2011
 
2012
 
2013
 
2014
Anadarko Petroleum Corporation
$
100.00

 
$
122.78

 
$
123.64

 
$
120.97

 
$
129.92

 
$
136.59

S&P 500
100.00

 
115.06

 
117.49

 
136.30

 
180.44

 
205.14

Peer Group
100.00

 
123.66

 
130.54

 
133.12

 
167.31

 
154.38


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Item 6.  Selected Financial Data
 
Summary Financial Information (1)
millions except per-share amounts
2014
 
2013
 
2012
 
2011
 
2010
Sales Revenues
$
16,375

 
$
14,867

 
$
13,307

 
$
13,882

 
$
10,842

Gains (Losses) on Divestitures and Other, net
2,095

 
(286
)
 
104

 
85

 
142

Total Revenues and Other
18,470

 
14,581

 
13,411

 
13,967

 
10,984

Algeria Exceptional Profits Tax Settlement

 
33

 
(1,797
)
 

 

Deepwater Horizon Settlement and Related Costs
97

 
15

 
18

 
3,930

 
15

Operating Income (Loss)
5,403

 
3,333

 
3,727

 
(1,870
)
 
1,769

Tronox-related Contingent Loss
4,360

 
850

 
(250
)
 
250

 

Income (Loss)
(1,563
)
 
941

 
2,445

 
(2,568
)
 
821

Net Income (Loss) Attributable to Common Stockholders
(1,750
)
 
801

 
2,391

 
(2,649
)
 
761

Per Common Share (amounts attributable to common stockholders)
 
 
 
 
 
 
 
 
 
Net Income (Loss)—Basic
$
(3.47
)
 
$
1.58

 
$
4.76

 
$
(5.32
)
 
$
1.53

Net Income (Loss)—Diluted
$
(3.47
)
 
$
1.58

 
$
4.74

 
$
(5.32
)
 
$
1.52

Dividends
$
0.99

 
$
0.54

 
$
0.36

 
$
0.36

 
$
0.36

Average Number of Common Shares Outstanding—Basic
506

 
502

 
500

 
498

 
495

Average Number of Common Shares Outstanding—Diluted
506

 
505

 
502

 
498

 
497

Cash Provided by Operating Activities
8,466

 
8,888

 
8,339

 
2,505

 
5,247

Capital Expenditures
$
9,256

 
$
8,523

 
$
7,311

 
$
6,553

 
$
5,169

Current Portion of Long-term Debt
$

 
$
500

 
$

 
$
170

 
$
291

Long-term Debt
15,092

 
13,065

 
13,269

 
15,060

 
12,722

Total Debt
$
15,092

 
$
13,565

 
$
13,269

 
$
15,230

 
$
13,013

Total Stockholders’ Equity
19,725

 
21,857

 
20,629

 
18,105

 
20,684

Total Assets
$
61,689

 
$
55,781

 
$
52,589

 
$
51,779

 
$
51,559

Annual Sales Volumes
 
 
 
 
 
 
 
 
 
Natural Gas (Bcf)
945

 
968

 
913

 
852

 
829

Oil and Condensate (MMBbls)
106

 
91

 
86

 
79

 
74

Natural Gas Liquids (MMBbls)
44

 
33

 
30

 
27

 
23

Total (MMBOE)(2)
308

 
285

 
268

 
248

 
235

Average Daily Sales Volumes
 
 
 
 
 
 
 
 
 
Natural Gas (MMcf/d)
2,589

 
2,652

 
2,495

 
2,334

 
2,272

Oil and Condensate (MBbls/d)
292

 
248

 
233

 
217

 
201

Natural Gas Liquids (MBbls/d)
119

 
91

 
83

 
74

 
63

Total (MBOE/d)
843

 
781

 
732

 
680

 
643

Proved Reserves
 
 
 
 
 
 
 
 
 
Natural-gas Reserves (Tcf)
8.7

 
9.2

 
8.3

 
8.4

 
8.1

Oil and Condensate Reserves (MMBbls)
929

 
851

 
767

 
771

 
749

Natural-gas Liquids Reserves (MMBbls)
479

 
407

 
405

 
374

 
320

Total Proved Reserves (MMBOE)
2,858

 
2,792

 
2,560

 
2,539

 
2,422

Number of Employees
6,100

 
5,700

 
5,200

 
4,800

 
4,400

(1) 
Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
(2) 
Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.
Table of Measures
 
 
Bcf—Billion cubic feet
 
MBbls/d—Thousand barrels per day
MMBbls—Million barrels
 
MBOE/d—Thousand barrels of oil equivalent per day
MMBOE—Million barrels of oil equivalent
 
Tcf—Trillion cubic feet
MMcf/d—Million cubic feet per day
 
 

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

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

OVERVIEW

Anadarko met or exceeded its key operational objectives in 2014. The Company increased sales volumes per day by approximately 8% over 2013 and added 502 million barrels of oil equivalent (MMBOE) of proved reserves. The Company ended 2014 with $7.4 billion of cash on hand, full availability of its $5.0 billion senior secured revolving credit facility maturing in September 2015 ($5.0 billion Facility), and access to credit and capital markets as needed.
In January 2015, the Company paid $5.2 billion after the settlement agreement resolving all claims asserted in the Tronox Adversary Proceeding became effective and replaced the $5.0 billion Facility with two new unsecured credit facilities. The Company paid the settlement using cash on hand and borrowings. Management believes that the Company is positioned to continue to satisfy its operational objectives and capital commitments with cash on hand, available borrowing capacity, and cash flows from operations.

Mission and Strategy

Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:
 
explore in high-potential, proven basins
identify and commercialize resources
employ a global business development approach
ensure financial discipline and flexibility

Exploring in high-potential, proven, and emerging basins worldwide provides the Company with growth opportunities. Anadarko’s exploration success has created value by increasing 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 and predictable development opportunities that, 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 investment in its businesses to efficiently manage commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the opportunities afforded by its global portfolio, while allowing the Company to pursue new strategic growth opportunities.

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Significant 2014 operating and financial activities include the following:

Overall
Anadarko’s full-year sales volumes averaged 843 thousand barrels of oil equivalent per day (MBOE/d), representing an 8% increase over 2013.
Anadarko’s liquids sales volumes were 411 thousand barrels per day (MBbls/d), representing a 21% increase over 2013, primarily due to increased sales volumes in the Wattenberg field, the Eagleford shale, and the Delaware basin.
The Company’s overall sales product mix increased to 49% liquids in 2014 compared to 43% in 2013.
Anadarko and Kerr-McGee Corporation and certain of its subsidiaries entered into a settlement agreement resolving all claims asserted in the Tronox Adversary Proceeding resulting in a payment of $5.2 billion, including interest, in January 2015. See Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

U.S. Onshore
The Rocky Mountains Region (Rockies) full-year sales volumes averaged 361 MBOE/d, representing a 10% increase over 2013, primarily from the Wattenberg field.
The Southern and Appalachia Region full-year sales volumes averaged 298 MBOE/d, representing a 16% increase over 2013, primarily from the Marcellus and Eagleford shales, the Delaware basin, and the East Texas/North Louisiana horizontal development.
Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired Nuevo Midstream, LLC (Nuevo), which owns and operates gathering and processing assets located in the Delaware basin in West Texas, for $1.554 billion. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM).
The Company entered into a carried-interest arrangement that requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, located in Southeast Texas.
The Company sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million.

Gulf of Mexico
Gulf of Mexico full-year sales volumes averaged 83 MBOE/d, representing a 14% decrease from 2013, primarily due to natural production declines.
Anadarko’s Lucius development project in the deepwater Gulf of Mexico was completed with first oil achieved in January 2015.
The Company sold its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for $500 million, recognizing a gain of $237 million.

International
International full-year sales volumes averaged 92 MBOE/d, representing a 2% increase from 2013, primarily due to increased sales volumes at El Merk in Algeria.
Anadarko sold a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion, recognizing a gain of $1.5 billion.
Anadarko sold its Chinese subsidiary for $1.075 billion, recognizing a gain of $510 million.
The Tweneboa/Enyenra/Ntomme (TEN) project in Ghana was approximately 50% complete and nine development wells had been drilled at year end 2014. First oil is expected in 2016.

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Financial
Anadarko’s net loss attributable to common stockholders for 2014 totaled $1.8 billion, which included a $4.360 billion contingent loss related to the Tronox Adversary Proceeding and $836 million of impairment expense primarily related to certain U.S. onshore and Gulf of Mexico properties.
The Company generated $8.5 billion of cash flow from operations in 2014 and ended 2014 with $7.4 billion of cash on hand.
Anadarko increased the quarterly dividend paid to its common stockholders from $0.18 per share to $0.27 per share.
The Company repaid $775 million of Senior Notes that matured in 2014.
Anadarko entered into a $3.0 billion five-year senior unsecured revolving credit facility, which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility. These facilities (collectively, the New Credit Facilities) replaced the $5.0 billion Facility upon satisfaction of certain conditions, including the January 2015 settlement payment related to the Tronox Adversary Proceeding.
Anadarko issued $625 million aggregate principal amount of 3.450% Senior Notes due 2024 and $625 million aggregate principal amount of 4.500% Senior Notes due 2044.
The Company sold approximately 6 million Western Gas Equity Partners, LP (WGP) common units to the public, raising net proceeds of $335 million.
WES entered into a five-year $1.2 billion, expandable to $1.5 billion, senior unsecured revolving credit facility maturing in February 2019 (RCF), which amended and restated its then-existing $800 million senior unsecured revolving credit facility.
WES completed public offerings of $100 million aggregate principal amount of 2.600% Senior Notes due 2018 and $400 million aggregate principal amount of 5.450% Senior Notes due 2044.
WES issued approximately 10 million common units to the public, raising total net proceeds of $691 million.

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, 2014,” refer to the comparison of the year ended December 31, 2014, to the year ended December 31, 2013. Similarly, any increases or decreases “for the year ended December 31, 2013,” refer to the comparison of the year ended December 31, 2013, to the year ended December 31, 2012. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, 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.

51

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Index to Financial Statements

RESULTS OF OPERATIONS
millions except per-share amounts and percentages
2014
 
2013
 
2012
Financial Results
 
 
 
 
 
Natural-gas, oil and condensate, and NGLs sales
$
15,169

 
$
13,828

 
$
12,396

Gathering, processing, and marketing sales
1,206

 
1,039

 
911

Gains (losses) on divestitures and other, net
2,095

 
(286
)
 
104

Total revenues and other
18,470

 
14,581

 
13,411

Costs and expenses (1)
13,067

 
11,248

 
9,684

Other (income) expense (2)
5,349

 
1,227

 
162

Income tax expense (benefit)
1,617

 
1,165

 
1,120

Net income (loss) attributable to common stockholders
$
(1,750
)
 
$
801

 
$
2,391

Net income (loss) per common share attributable to common
stockholders—diluted
$
(3.47
)
 
$
1.58

 
$
4.74

Average number of common shares outstanding—diluted
506

 
505

 
502

 
 
 
 
 
 
Operating Results
 
 
 
 
 
Adjusted EBITDAX (3)
$
12,721

 
$
9,403

 
$
8,966

Total proved reserves (MMBOE)
2,858

 
2,792

 
2,560

Annual sales volumes (MMBOE)
308

 
285

 
268

 
 
 
 
 
 
Capital Resources and Liquidity
 
 
 
 
 
Cash provided by operating activities
$
8,466

 
$
8,888

 
$
8,339

Capital expenditures
9,256

 
8,523

 
7,311

Total debt
15,092

 
13,565

 
13,269

Total equity
$
22,318

 
$
23,650

 
$
21,882

Debt to total capitalization ratio
40.3
%
 
36.5
%
 
37.7
%
 _______________________________________________________________________________
(1) 
Includes a credit of $1.8 billion in 2012 for previously recognized expenses related to the favorable resolution of the Algeria exceptional profits tax dispute.
(2) 
Includes Tronox-related contingent loss of $4.360 billion in 2014, $850 million in 2013, and reversal of the 2011 Tronox-related contingent loss $(250) million in 2012.
(3) 
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 the most directly comparable financial measure presented in accordance with GAAP.


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FINANCIAL RESULTS
millions
Natural
Gas
 
Oil and
Condensate
 
NGLs
 
Total
2013 sales revenues
$
3,388

 
$
9,178

 
$
1,262

 
$
13,828

Changes associated with prices
540

 
(1,046
)
 
(86
)
 
(592
)
Changes associated with sales volumes
(79
)
 
1,616

 
396

 
1,933

2014 sales revenues
$
3,849

 
$
9,748

 
$
1,572

 
$
15,169

Increase/(Decrease) vs. 2013
14
%
 
6
%
 
25
%
 
10
%
 
 
 
 
 
 
 
 
2012 sales revenues
$
2,444

 
$
8,728

 
$
1,224

 
$
12,396

Changes associated with prices
798

 
(85
)
 
(82
)
 
631

Changes associated with sales volumes
146

 
535

 
120

 
801

2013 sales revenues
$
3,388

 
$
9,178

 
$
1,262

 
$
13,828

Increase/(Decrease) vs. 2012
39
%
 
5
%
 
3
%
 
12
%

Anadarko’s sales revenues increased for the year ended December 31, 2014, primarily due to higher oil and NGLs sales volumes and higher average natural-gas prices, partially offset by lower average oil and NGLs prices and slightly lower natural-gas sales volumes. Total sales revenues increased for the year ended December 31, 2013, primarily due to higher sales volumes for all products and higher average natural-gas prices, partially offset by lower average oil and NGLs prices.

The following provides Anadarko’s sales volumes for the years ended December 31, 2014, 2013, and 2012:
 
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
Barrels of Oil Equivalent
 
 
 
 
 
 
 
 
 
(MMBOE except percentages)
 
 
 
 
 
 
 
 
 
United States
275

 
9
%
 
252

 
6
%
 
237

International
33

 
2

 
33

 
7

 
31

Total barrels of oil equivalent
308

 
8

 
285

 
6

 
268

Barrels of Oil Equivalent per Day
 
 
 
 
 
 
 
 
 
(MBOE/d except percentages)
 
 
 
 
 
 
 
 
 
United States
751

 
9
%
 
691

 
7
%
 
648

International
92

 
2

 
90

 
7

 
84

Total barrels of oil equivalent per day
843

 
8

 
781

 
7

 
732


Sales volumes represent actual production volumes adjusted for changes in commodity inventories and natural-gas production volumes provided to a certain government entity to satisfy a commitment established in conjunction with the development plan. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Other (Income) Expense—(Gains) Losses on Derivatives, net. Production of natural gas, oil, and NGLs is usually not affected by seasonal swings in demand.

53

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Index to Financial Statements

Natural-Gas Sales Volumes, Average Prices, and Revenues
 
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
United States
 
 
 
 
 
 
 
 
 
Sales volumes—Bcf
945

 
(2
)%
 
968

 
6
%
 
913

MMcf/d
2,589

 
(2
)
 
2,652

 
6

 
2,495

Price per Mcf
$
4.07

 
16

 
$
3.50

 
31

 
$
2.68

Natural-gas sales revenues (millions)
$
3,849

 
14

 
$
3,388

 
39

 
$
2,444

 _______________________________________________________________________________
Bcf—billion cubic feet
MMcf/d—million cubic feet per day
Mcf—thousand cubic feet

Natural-Gas Sales Volumes
2014 vs. 2013  The Company’s natural-gas sales volumes decreased by 63 MMcf/d.
Sales volumes decreased by 90 MMcf/d in the Rockies primarily due to the sale of the Company’s Pinedale/Jonah assets in January 2014 and natural production declines in the Powder River basin and Greater Natural Buttes. These decreases were partially offset by higher sales volumes in the Wattenberg field due to increased horizontal drilling.
Sales volumes decreased by 67 MMcf/d in the Gulf of Mexico primarily due to natural production declines.
Sales volumes for the Southern and Appalachia Region increased by 94 MMcf/d primarily due to infrastructure expansions that allowed the Company to bring wells online in the Marcellus and Eagleford shales, as well as continued horizontal drilling in the liquids-rich East Texas/North Louisiana horizontal development.

2013 vs. 2012  The Company’s natural-gas sales volumes increased by 157 MMcf/d.
Sales volumes increased by 246 MMcf/d in the Southern and Appalachia Region primarily due to horizontal drilling and infrastructure expansions in the Eagleford and Marcellus shales, as well as new wells drilled in the liquids-rich East Texas/North Louisiana horizontal development.
Sales volumes decreased by 47 MMcf/d in the Gulf of Mexico primarily due to natural production declines.
Sales volumes for the Rockies decreased by 42 MMcf/d primarily due to a natural production decline in the Powder River basin, partially offset by higher sales volumes in the Wattenberg field due to increased horizontal drilling.

Natural-Gas Prices
2014 vs. 2013  The average natural-gas price Anadarko received increased primarily due to low industry natural-gas storage levels as a result of colder than average winter temperatures and the associated high residential heating demand in early 2014. In addition, natural-gas prices increased as a result of higher industrial natural-gas demand, reduced natural-gas imports from Canada, and continued strength in exports to Mexico.

2013 vs. 2012  Anadarko’s average natural-gas price received increased as higher-than-normal residential and commercial demand early in 2013 reduced overall industry natural-gas storage below the previous year’s record levels. Natural-gas prices were further supported by higher demand in the fourth quarter of 2013, a reduction in natural-gas imports from Canada, and continued strength in exports to Mexico. 

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Oil and Condensate Sales Volumes, Average Prices, and Revenues
 
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
United States
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
74

 
28
 %
 
58

 
6
 %
 
55

MBbls/d
203

 
28

 
158

 
6

 
149

Price per barrel
$
87.99

 
(9
)
 
$
97.02

 

 
$
97.46

International
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
32

 
(1
)%
 
33

 
7
 %
 
31

MBbls/d
89

 
(1
)
 
90

 
7

 
84

Price per barrel
$
99.79

 
(9
)
 
$
109.15

 
(2
)
 
$
111.11

Total
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
106

 
18
 %
 
91

 
6
 %
 
86

MBbls/d
292

 
18

 
248

 
6

 
233

Price per barrel
$
91.58

 
(10
)
 
$
101.41

 
(1
)
 
$
102.35

Oil and condensate sales revenues (millions)
$
9,748

 
6

 
$
9,178

 
5

 
$
8,728

 _______________________________________________________________________________
MMBbls—million barrels

Oil and Condensate Sales Volumes
2014 vs. 2013  Anadarko’s oil and condensate sales volumes increased by 44 MBbls/d.
Sales volumes for the Rockies increased by 33 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling.
Sales volumes for the Southern and Appalachia Region increased by 15 MBbls/d, primarily as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale and increased horizontal drilling in the Delaware basin.
International sales volumes decreased by 1 MBbls/d primarily due to lower sales volumes in China as a result of maintenance downtime and the sale of the Company’s Chinese subsidiary and the timing of liftings in Ghana, partially offset by higher sales volumes in Algeria from additional facilities and wells brought online at El Merk.
Sales volumes in the Gulf of Mexico decreased by 1 MBbls/d primarily due to natural production declines.
2013 vs. 2012  Anadarko’s oil and condensate sales volumes increased by 15 MBbls/d.
Sales volumes for the Rockies increased by 15 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling.
Sales volumes for the Southern and Appalachia Region increased by 6 MBbls/d, as a result of horizontal drilling and infrastructure expansions in the Eagleford shale.
International sales volumes increased by 6 MBbls/d primarily in Ghana as a result of enhanced production due to successful acid stimulations and additional Phase 1A Jubilee wells brought online, as well as timing of cargo liftings.
Sales volumes in the Gulf of Mexico decreased by 10 MBbls/d primarily due to natural production declines.

Oil and Condensate Prices
2014 vs. 2013  Anadarko’s average oil price received decreased as a result of a global oversupply and reduced oil demand resulting from continued economic weakness particularly in late 2014.
2013 vs. 2012  Anadarko’s average oil price received decreased due to slightly lower international oil prices in 2013.

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Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues
 
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
United States
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
43

 
28
 %
 
33

 
10
 %
 
30

MBbls/d
116

 
28

 
91

 
10

 
83

Price per barrel
$
35.48

 
(7
)
 
$
37.97

 
(6
)
 
$
40.44

International
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
1

 
NM

 

 
NM

 

MBbls/d
3

 
NM

 

 
NM

 

Price per barrel
$
56.16

 
NM

 
$

 
NM

 
$

Total
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
44

 
31
 %
 
33

 
10
 %
 
30

MBbls/d
119

 
31

 
91

 
10

 
83

Price per barrel
$
36.01

 
(5
)
 
$
37.97

 
(6
)
 
$
40.44

Natural-gas liquids sales revenues (millions)
$
1,572

 
25

 
$
1,262

 
3

 
$
1,224

_________________________________________________________________________
NM—not meaningful

NGLs Sales Volumes
NGLs sales represent revenues from the sale of products derived from the processing of Anadarko’s natural-gas production.
2014 vs. 2013  The Company’s NGLs sales volumes increased by 28 MBbls/d.
Sales volumes in the Rockies increased by 16 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling and the Lancaster plant coming online in April 2014.
Sales volumes for the Southern and Appalachia Region increased by 10 MBbls/d primarily as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale.
International sales volumes increased by 3 MBbls/d due to the commencement of NGLs sales in 2014 from the Company’s El Merk facility in Algeria.

2013 vs. 2012  Anadarko’s NGLs sales volumes increased 8 MBbls/d.
Sales volumes for the Southern and Appalachia Region increased by 12 MBbls/d as a result of increased horizontal drilling and infrastructure expansion in the Eagleford shale and horizontal drilling in the liquids-rich East Texas/North Louisiana horizontal development.
Sales volumes in the Rockies decreased by 2 MBbls/d primarily due to ethane rejection in 2013.
Sales volumes in the Gulf of Mexico decreased by 2 MBbls/d due to natural production declines.

NGLs Sales Prices
2014 vs. 2013  Anadarko’s average NGLs price received decreased primarily due to lower prices for butanes and natural gasoline resulting from higher industry production levels and related declines in oil prices.

2013 vs. 2012  Anadarko’s average NGLs price received decreased primarily due to lower prices for ethane and butanes as a result of higher U.S. inventory and production levels.

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Gathering, Processing, and Marketing Margin
millions except percentages
2014

Inc/(Dec) 
 vs. 2013

2013

Inc/(Dec) 
 vs. 2012

2012
Gathering, processing, and marketing sales
$
1,206


16
%

$
1,039


14
%

$
911

Gathering, processing, and marketing expense
1,030


19


869


14


763

Total gathering, processing, and marketing, net
$
176


4


$
170


15


$
148


Gathering and processing sales includes revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko, as well as fee revenue earned by providing gathering, processing, compression, and treating services to third parties. Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Gathering, processing, and marketing expense includes the cost of third-party natural gas purchased and processed by Anadarko, as well as other operating and transportation expenses related to the Company’s costs to perform gathering, processing, and marketing activities.
2014 vs. 2013  Gathering, processing, and marketing, net increased by $6 million primarily due to higher gathering and processing revenue associated with higher volumes, increased natural-gas prices, and increased infrastructure, partially offset by higher processing and transportation expenses due to the increased volumes.
 
2013 vs. 2012  Gathering, processing, and marketing, net increased by $22 million primarily due to higher gathering revenue as a result of increased volumes and higher marketing margins, partially offset by increased transportation expenses due to increased third-party volumes and increased demand fees.

57

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Gains (Losses) on Divestitures and Other, net
millions except percentages
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
Gains (losses) on divestitures
$
1,891

 
NM

 
$
(470
)
 
NM

 
$
(71
)
Other
204

 
11
%
 
184

 
5
%
 
175

Total gains (losses) on divestitures and other, net
$
2,095

 
NM

 
$
(286
)
 
NM

 
$
104


Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues including minerals sales, earnings from equity investments, and other revenues.
2014 
The Company recognized a gain of $1.5 billion related to its divestiture of a 10% working interest in Offshore Area 1 in Mozambique for sales proceeds of $2.64 billion.
The Company recognized a gain of $510 million associated with the divestiture of its Chinese subsidiary for sales proceeds of $1.075 billion.
The Company recognized a gain of $237 million associated with the divestiture of its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for sales proceeds of $500 million.
The Company recognized gains on divestitures of $127 million for certain oil and gas properties in the United States.
During the fourth quarter of 2014, Anadarko considered certain U.S. onshore oil and gas assets to be held for sale and recognized a $456 million loss. At December 31, 2014, these assets were no longer considered held for sale as the volatility in the current commodity-price environment reduced the probability that these assets would be sold within the next year.

2013 
The Company recognized losses on assets held for sale of $704 million, primarily associated with the loss of value of the Pinedale/Jonah assets in Wyoming, which were sold in January 2014 for sale proceeds of $581 million.
The Company divested its interest in a soda ash joint venture for sales proceeds of $310 million, recognizing a gain of $140 million, while retaining its royalty interest in soda ash mined by the joint venture from the Company’s Land Grant. Additional consideration may also be received based on future revenue of the joint venture.
The Company recognized gains on divestitures of $94 million for certain oil and gas properties in the United States.

2012
The Company recognized losses of $71 million on certain oil and gas properties, primarily related to the sale of oil and gas properties in Indonesia.
See Note 2—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on assets held for sale.

58

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Costs and Expenses
 
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
Oil and gas operating (millions)
$
1,171

 
7
 %
 
$
1,092

 
12
%
 
$
976

Oil and gas operating—per BOE
3.81

 
(1
)
 
3.83

 
5

 
3.65

Oil and gas transportation and other (millions)
1,184

 
16

 
1,022

 
7

 
955

Oil and gas transportation and other—per BOE
3.85

 
7

 
3.59

 
1

 
3.57

 _______________________________________________________________________________
BOE—barrels of oil equivalent

Oil and Gas Operating Expenses
2014 vs. 2013  Oil and gas operating expense increased by $79 million primarily due to higher costs associated with increased sales volumes in the Rockies and the Southern and Appalachia Region and increased activity in the Gulf of Mexico. These increases were partially offset by lower expenses due to the sales of the Company’s Pinedale/Jonah assets and its China subsidiary. The related costs per BOE decreased by $0.02 due to increased sales volumes, partially offset by the higher costs.

2013 vs. 2012  Oil and gas operating expenses increased by $116 million primarily due to increased workovers in the Gulf of Mexico, Rockies, and Southern and Appalachia Region; higher expenses in Algeria associated with the start of El Merk production in 2013; and increased costs associated with increased activity in the Rockies and Southern and Appalachia Region. Oil and gas operating expenses per BOE increased by $0.18 primarily due to these higher costs, partially offset by increased sales volumes.

Oil and Gas Transportation and Other Expenses
2014 vs. 2013  Oil and gas transportation and other expenses increased by $162 million primarily due to higher gas-gathering and transportation costs primarily attributable to higher volumes related to the growth in the Company’s U.S. onshore asset base. Oil and gas transportation and other expenses per BOE increased by $0.26 with the higher costs partially offset by increased sales volumes.

2013 vs. 2012  Oil and gas transportation and other expenses increased by $67 million primarily due to higher gas-gathering and transportation costs primarily attributable to higher volumes related to the growth in the Company’s U.S. onshore asset base. Oil and gas transportation and other expenses per BOE increased by $0.02, with the higher costs partially offset by increased sales volumes.

59

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millions
2014
 
2013
 
2012
Exploration Expense
 
 
 
 
 
Dry hole expense
$
762

 
$
556

 
$
440

Impairments of unproved properties
483

 
308

 
1,104

Geological and geophysical expense
168

 
208

 
151

Exploration overhead and other
226

 
257

 
251

Total exploration expense
$
1,639

 
$
1,329

 
$
1,946


2014 vs. 2013  Exploration expense increased by $310 million.
Dry hole expense increased by $206 million primarily due to unsuccessful drilling activities expensed in 2014 associated with wells in the Gulf of Mexico, the Rockies, and Mozambique, compared to unsuccessful drilling activities expensed in 2013 associated with wells in Kenya, Sierra Leone, and Côte d’Ivoire.
Impairments of unproved properties increased by $175 million primarily due to 2014 impairments in the Gulf of Mexico due to lower oil prices, reduction of reserves, and the expiration of certain leases; and impairments in Sierra Leone and certain U.S. onshore oil and gas properties as a result of changes in the Company’s drilling plans. Impairments for 2013 included China, Brazil, and a U.S. onshore property as a result of changes in the Company’s drilling plans.
Geological and geophysical expense decreased by $40 million due to lower seismic purchases in the Gulf of Mexico during 2014.

2013 vs. 2012  Exploration expense decreased by $617 million.
Impairments of unproved properties decreased by $796 million primarily due to 2012 impairments of $721 million related to Powder River coalbed methane properties primarily as a result of lower natural-gas prices and $124 million related to a Gulf of Mexico natural-gas property that the Company did not expect to develop under the forecasted natural-gas price environment.
Dry hole expense increased by $116 million primarily due to unsuccessful drilling activities expensed in 2013 associated with wells in the Gulf of Mexico, Sierra Leone, Kenya, Côte d’Ivoire, and New Zealand, compared to unsuccessful drilling activities expensed in 2012 associated with wells in Brazil, Sierra Leone, the Gulf of Mexico, Ghana, and Côte d’Ivoire.
Geological and geophysical expense increased by $57 million primarily due to 2013 seismic purchases in Colombia and the Gulf of Mexico.

60

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millions except percentages
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
General and administrative
$
1,316

 
21
%
 
$
1,090

 
(13
)%
 
$
1,246

Depreciation, depletion, and amortization
4,550

 
16

 
3,927

 
(1
)
 
3,964

Other taxes
1,244

 
16

 
1,077

 
(12
)
 
1,224

Impairments
836

 
5

 
794

 
104

 
389


General and Administrative Expenses (G&A)
2014 vs. 2013  G&A expense increased by $226 million primarily due to higher employee-related expenses of $152 million primarily associated with increased headcount and higher bonus plan expense. In addition, G&A expense increased due to higher legal expenses of $38 million primarily related to the third-party reimbursement of legal expenses associated with the Algeria exceptional profits tax settlement received in 2013 and legal fees related to Tronox, as well as higher consulting fees of $15 million.

2013 vs. 2012  G&A expense decreased by $156 million due to reduced legal-related expenses of $101 million and lower employee-related expenses of $60 million. The reduced legal-related expenses primarily related to lower 2013 Tronox legal expenses and the 2013 third-party reimbursement of the Company’s legal expenses associated with the Algeria exceptional profits tax settlement. The lower employee-related expenses primarily related to the 2012 expense associated with Unit Appreciation Rights (UARs), partially offset by higher 2013 employee-related expenses associated with operational expansions. The UARs were awarded in prior years to certain officers of the general partner of WES, a consolidated subsidiary of Anadarko, pursuant to the Western Gas Holdings, LLC (WGH) Equity Incentive Plan. This expense related to the change in fair value of the UARs upon the initial public offering (IPO) of WGP.

Depreciation, Depletion, and Amortization (DD&A)
2014 vs. 2013  DD&A expense increased by $623 million primarily due to higher sales volumes in 2014, increased asset retirement costs for wells in the Gulf of Mexico, and increased costs associated with additional gathering and processing facilities.

2013 vs. 2012  DD&A expense decreased by $37 million primarily due to accelerated expense in 2012 associated with the depletion of fields in the Gulf of Mexico, partially offset by higher sales volumes in 2013.

Other Taxes
2014 vs. 2013  Other taxes increased by $167 million.
Algerian exceptional profits taxes increased by $128 million attributable to higher oil sales volumes and the commencement of NGLs sales in 2014.
U.S. onshore ad valorem taxes increased by $85 million attributable to increased activity related to U.S. onshore properties.
Chinese windfall profits tax decreased by $47 million resulting from maintenance downtime in the first half of 2014 and the sale of the Company’s Chinese subsidiary in August 2014.

2013 vs. 2012  Other taxes decreased by $147 million.
Algerian exceptional profits taxes decreased by $116 million due to a lower Algeria effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute and lower oil prices.
Lower sales volumes and oil prices resulted in a $33 million decrease in U.S. production and severance taxes primarily in Alaska.

61

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Impairments
2014  
The Company recognized impairments of $545 million related to certain U.S. onshore oil and gas properties and $276 million related to certain oil and gas properties in the Gulf of Mexico that were impaired primarily due to lower forecasted natural-gas and oil prices.
Declines in commodity prices or negative reserves revisions could result in additional impairments in future periods. See Note 5—Impairments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on impairments and Risk Factors under Item 1A of this Form 10-K for further discussion on the risks associated with oil, natural-gas, and NGLs prices.

2013  
The Company recognized $562 million due to a reduction in estimated future net cash flows and downward revisions of reserves for certain Gulf of Mexico properties resulting from changes to the Company’s development plans.
The Company recognized $142 million for certain U.S. onshore oil and gas properties and $49 million for related midstream assets due to downward revisions of reserves resulting from changes to the Company’s development plans.
The Company recognized $30 million for certain midstream properties due to a reduction in estimated future cash flows and $11 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable value.

2012  
The Company recognized $363 million related to oil and gas exploration and production reporting segment properties located in the United States. These impairments included $259 million related to lower natural-gas prices, $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.
The Company recognized impairments of $13 million related to midstream properties and $13 million related to the Company’s Venezuelan cost-method investment.
millions
2014
 
2013
 
2012
Algeria exceptional profits tax settlement
$

 
$
33

 
$
(1,797
)
Deepwater Horizon settlement and related costs
97

 
15

 
18


Algeria Exceptional Profits Tax Settlement
In March 2012, Anadarko and Sonatrach resolved the exceptional profits tax dispute. The resolution provided for delivery to the Company of oil valued at $1.7 billion and the elimination of $62 million of previously recorded and unpaid transportation charges. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for 2012 to reflect the effect of this agreement for previously recorded expenses. During 2013, the Company revised its estimate of income tax expense related to the elimination of previously recorded and unpaid transportation charges and recognized a $33 million unfavorable adjustment to the settlement, which was offset by an equivalent income tax benefit also recognized in 2013. At December 31, 2013, the Company had collected all of the $1.7 billion associated with the Algeria exceptional profits tax receivable.

Deepwater Horizon Settlement and Related Costs
During 2014, the Company recorded a $90 million expense and contingent liability associated with a civil penalty under the Clean Water Act (CWA) related to the Deepwater Horizon event-related claims. In addition, Deepwater Horizon settlement and related costs included legal expenses and related costs associated with the Deepwater Horizon events for 2014, 2013, and 2012. 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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Other (Income) Expense
millions except percentages
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
Interest Expense
 
 
 
 
 
 
 
 
 
Current debt, long-term debt, and other
$
973

 
3
%
 
$
949

 
(1
)%
 
$
963

Capitalized interest
(201
)
 
24

 
(263
)
 
(19
)
 
(221
)
Total interest expense
$
772

 
13

 
$
686

 
(8
)
 
$
742


2014 vs. 2013  Anadarko’s interest expense increased by $86 million primarily due to a decrease in capitalized interest of $62 million related to lower construction-in-progress balances for the Mozambique liquefied natural gas project and the completion of certain U.S. pipeline projects in late 2013 and early 2014. In addition, interest expense increased $13 million due to increased long-term debt outstanding during 2014. For additional information, see Liquidity and Capital Resources and Interest-Rate Risk under Item 7A of this Form 10-K.

2013 vs. 2012  Anadarko’s interest expense decreased by $56 million primarily due to an increase in capitalized interest of $42 million related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense decreased by $31 million as a result of the repayment of outstanding borrowings during 2012 associated with the $5.0 billion Facility. These decreases were partially offset by $18 million of interest expense for outstanding borrowings primarily related to WES’s 4.000% Senior Notes due 2022, which were issued during 2012.
millions
2014
 
2013
 
2012
(Gains) Losses on Derivatives, net
 
 
 
 
 
(Gains) losses on commodity derivatives, net
$
(589
)
 
$
141

 
$
(387
)
(Gains) losses on interest-rate and other derivatives, net
786

 
(539
)
 
61

Total (gains) losses on derivatives, net
$
197

 
$
(398
)
 
$
(326
)

(Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments as a result of changes in commodity prices and interest rates. Anadarko enters into commodity derivatives to manage the risk of changes in the market prices for its anticipated sales of production. In addition, Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. For additional information, see Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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millions except percentages
2014

Inc/(Dec) 
 vs. 2013

2013

Inc/(Dec) 
 vs. 2012

2012
Other (Income) Expense, net









Interest income
$
(26
)

37
%

$
(19
)

19
%

$
(16
)
Other
46


57


108


NM


12

Total other (income) expense, net
$
20


78


$
89


NM


$
(4
)

2014 vs. 2013  In 2013, as a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, which were previously sold to the third party. During 2013, the Company accrued costs of $117 million to decommission the facility and related wells. During 2014, the Company recognized a $22 million increase in the estimated decommissioning costs. Anadarko completed decommissioning of the production facility in 2014 and expects to complete decommissioning of the wells in 2015. Also, as a result of a prior acquisition, the Company recognized a restoration liability of $50 million in 2013 with respect to a landfill located in California for which the Company was notified that it is a potentially responsible party. In the second quarter of 2013, the Company reversed the $56 million tax indemnification liability associated with the 2006 sale of the Company’s Canadian subsidiary. The indemnity was reversed as a result of certain changes to Canadian tax laws.

2013 vs. 2012  During 2013, the Company recognized a decommissioning charge of $117 million and a restoration liability of $50 million, partially offset by the 2013 reversal of the $56 million tax indemnification liability associated with the 2006 sale of the Company’s Canadian subsidiary.
millions
2014
 
2013
 
2012
Tronox-related contingent loss
$
4,360

 
$
850

 
$
(250
)

In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement for $5.15 billion resolving all claims asserted in the Tronox Adversary Proceeding. Anadarko recognized Tronox-related contingent losses of $4.3 billion in 2014, $850 million in 2013, and reversed $250 million in 2012 associated with the Tronox-related contingent loss recognized in 2011. In addition, Anadarko recognized settlement-related interest expense of $60 million during 2014. An aggregate Tronox-related contingent liability of $5.2 billion was included on the Company’s Consolidated Balance Sheet at December 31, 2014. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective. 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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Income Tax Expense
millions except percentages
2014
 
2013
 
2012
Income tax expense (benefit)
$
1,617

 
$
1,165

 
$
1,120

Effective tax rate
2,994
%
 
55
%
 
31
%

2014  The increase from the 35% U.S. federal statutory rate was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, changes in other uncertain tax positions, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual. For additional information on income tax rates, see Note 18—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
In 2013, the Company recognized a deferred tax benefit of $274 million related to the $850 million loss with respect to the Tronox-related contingent liability. In 2014, the Company recognized an additional deferred tax benefit of $316 million related to the additional $4.360 billion loss with respect to the Tronox-related contingent liability. See Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

2013  The increase from the 35% U.S. federal statutory rate was primarily attributable to the tax impact from foreign operations, non-deductible Algerian exceptional profits tax, and deferred tax adjustments.

2012  The decrease from the 35% U.S. federal statutory rate was primarily attributable to the non-taxable resolution of the Algeria exceptional profits tax dispute. This amount was partially offset by the tax impact from foreign operations and non-deductible Algerian exceptional profits tax.

Net Income Attributable to Noncontrolling Interests

The Company’s net income attributable to noncontrolling interests of $187 million for the year ended December 31, 2014, $140 million for 2013, and $54 million for 2012, was related to public ownership interests in WES and WGP. Public ownership of WES was 55% at December 31, 2014, 56.4% at December 31, 2013, and 51.8% at December 31, 2012. 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. During 2014, Anadarko sold approximately 6 million WGP common units to the public, raising net proceeds of $335 million. Public ownership of WGP was 11.7% at December 31, 2014, and was 9% at December 31, 2013 and 2012. See Note 9—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; exploration expense; DD&A; impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX, which is not a GAAP measure, 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. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
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 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
2014
 
Inc/(Dec) 
 vs. 2013
 
2013
 
Inc/(Dec) 
 vs. 2012
 
2012
Income (loss) before income taxes
$
54

 
(97
)%
 
$
2,106

 
(41
)%
 
$
3,565

Exploration expense
1,639

 
23

 
1,329

 
(32
)
 
1,946

DD&A
4,550

 
16

 
3,927

 
(1
)
 
3,964

Impairments
836

 
5

 
794

 
104

 
389

Interest expense
772

 
13

 
686

 
(8
)
 
742

Total (gains) losses on derivatives, net, less net cash
   received in settlement of commodity derivatives
578

 
NM

 
(307
)
 
(169
)
 
443

Deepwater Horizon settlement and related costs
97

 
NM

 
15

 
(17
)
 
18

Algeria exceptional profits tax settlement

 
(100
)
 
33

 
102

 
(1,797
)
Tronox-related contingent loss
4,360

 
NM

 
850

 
NM

 
(250
)
Certain other nonoperating items
22

 
(80
)
 
110

 
NM

 

Less net income attributable to noncontrolling
   interests
187

 
34

 
140

 
159

 
54

Consolidated Adjusted EBITDAX
$
12,721

 
35

 
$
9,403

 
5

 
$
8,966

 
 
 
 
 
 
 
 
 
 
Adjusted EBITDAX by segment
 
 
 
 
 
 
 
 
 
Oil and gas exploration and production
$
12,505

 
35

 
$
9,238

 
9

 
$
8,500

Midstream
660

 
30

 
508

 
7

 
474

Marketing
(219
)
 
(75
)
 
(125
)
 
(20
)
 
(104
)
Other and intersegment eliminations
(225
)
 
(3
)
 
(218
)
 
NM

 
96


Oil and Gas Exploration and Production  
2014 vs. 2013  The increase in Adjusted EBITDAX was primarily due to net gains on divestitures, higher sales volumes for oil and NGLs, and higher natural-gas prices. These increases were partially offset by lower oil prices, and higher oil and gas transportation expenses and other taxes, which increased as a result of higher sales volumes.

2013 vs. 2012  The increase in Adjusted EBITDAX was primarily due to higher sales volumes for all products and higher natural-gas prices, partially offset by lower oil and NGLs prices and losses on divestitures primarily related to the Pinedale/Jonah assets in Wyoming.

Midstream  
2014 vs. 2013  The increase in Adjusted EBITDAX was primarily due to higher gathering and processing revenue associated with higher volumes and increased natural-gas prices, partially offset by higher processing expenses primarily due to increased volumes.

2013 vs. 2012  The increase in Adjusted EBITDAX was primarily due to higher gathering revenue as a result of increased volumes.

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Marketing  
2014 vs. 2013  The decrease in Adjusted EBITDAX resulted from lower marketing margins and higher transportation expenses.

2013 vs. 2012  The decrease in Adjusted EBITDAX resulted from higher transportation expenses due to increased third-party volumes and increased demand fees, partially offset by higher margins primarily associated with natural-gas and NGLs sales.

Other and Intersegment Eliminations  
Other and intersegment eliminations consists primarily of corporate costs, income from hard minerals investments and royalties, and net cash received in settlement of commodity derivatives.
2014 vs. 2013  The Adjusted EBITDAX in 2014 was relatively flat compared to the prior year.

2013 vs. 2012  The increase in Adjusted EBITDAX was primarily due to a decrease in net cash received in settlement of commodity derivatives in 2013, partially offset by 2012 expense associated with the change in the fair value of the general partner UARs in connection with the WGP IPO. The UARs were awarded in prior years to certain officers of the general partner of WES, pursuant to the WGH Equity Incentive Plan.

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. For reserves information, see Oil and Gas Properties and Activities—Proved Reserves under Items 1 and 2 of this Form 10-K and the Supplemental Information on Oil and Gas Exploration and Production Activities under Item 8 of this Form 10-K.

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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. The Company has a variety of funding sources available, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements that reduce future capital expenditures, commercial paper, and the Company’s New Credit Facilities. In addition, as of January 2014, an effective registration statement is available to Anadarko covering the sale of up to 40 million WGP common units. These common units were issued to Anadarko in connection with WGP’s IPO in December 2012. During 2014, the Company sold 6 million WGP common units and at December 31, 2014, the Company had 34 million units available for sale.
During 2014, the primary source for funding of capital investments was cash flows from operating activities. 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.
At December 31, 2014, Anadarko had no scheduled debt maturities during the next year. Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $796 million at the next put date in October 2015. The Zero Coupons are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt. See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on the Zero Coupons. Anadarko’s scheduled 2016 debt maturities are $1.8 billion, exclusive of the Zero Coupons.
Management believes that the Company’s liquidity position, asset portfolio, and operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Tronox Adversary Proceeding Settlement Payment  In April 2014, Anadarko and Kerr-McGee entered into a settlement agreement to resolve all claims asserted in the Tronox Adversary Proceeding for $5.15 billion. In addition, the Company agreed to pay interest on the above amount from April 3, 2014, through the payment of the settlement, with an annual interest rate of 1.5% for the first 180 days and 1.5% plus the one-month LIBOR thereafter. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective. 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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Revolving Credit Facilities and Commercial Paper Program  During 2014, the Company maintained the $5.0 billion Facility maturing in September 2015. 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 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, were guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and were 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. During 2014, the Company had no outstanding borrowings under the $5.0 billion Facility.
In June 2014, Anadarko entered into a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). The New Credit Facilities replaced the $5.0 billion Facility upon satisfaction of certain conditions, including the January 2015 settlement payment related to the Tronox Adversary Proceeding. Under the New Credit Facilities, the Company’s derivative counterparties no longer maintain security interests in any of the Company’s assets. As a result, the Company may be required from time to time to post collateral of cash or letters of credit based on the negotiated terms of the individual derivative agreements.
In January 2015, the Company borrowed $1.5 billion under the 364-Day Facility. Borrowings under the New Credit Facilities generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the Five-Year Facility denominated in Euro) or an alternate base rate, in each case plus an applicable margin ranging from 0.00% to 1.65% for the Five-Year Facility and 0.00% to 1.675% for the 364-Day Facility. The applicable margin will vary depending on Anadarko’s credit ratings.
In January 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes.

Financial Covenants  The $5.0 billion Facility contained various customary covenants with which Anadarko had to comply, including, but not limited to, limitations on incurrence of indebtedness, liens on assets, and asset sales. Anadarko was 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 was 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 had to be no less than 1.75 to 1.0 after giving pro forma effect to the requested borrowing.
The covenants contained in certain of the Company’s credit agreements provide for a maximum Anadarko 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 to ensure covenant compliance. At December 31, 2014, Anadarko was in compliance with all financial covenants.
The New Credit Facilities contain certain customary affirmative and negative covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65%, and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes.

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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 $1.2 billion senior unsecured revolving credit facility (RCF).
In February 2014, WES entered into the RCF, which amended and restated its then-existing $800 million senior unsecured revolving credit facility. The RCF matures in February 2019 and is expandable to a maximum of $1.5 billion. Borrowings under the RCF bear interest at (i) LIBOR plus an applicable margin ranging from 0.975% to 1.45%, depending on WES’s credit rating, 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 0.00% to 0.45%. At December 31, 2014, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $510 million at an interest rate of 1.47%, and had available borrowing capacity of approximately $677 million ($1.2 billion capacity, less $510 million of outstanding borrowings and $13 million of outstanding letters of credit).
In August 2014, WES filed a registration statement with the Securities and Exchange Commission authorizing the issuance of up to an aggregate of $500 million of common units, in amounts, at prices, and on terms to be determined by market conditions and other factors at the time of the offerings.

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 includes (a) $400 million per occurrence from Oil Insurance Limited (OIL) for physical damage to Anadarko’s properties on a replacement cost basis, blowout/control of well, redrill, and sudden and accidental pollution; (b) $700 million per occurrence from the commercial markets for the items described in item (a) above, which is in excess of the OIL coverage and which follows the form of OIL coverage with certain exceptions; (c) $400 million from the commercial markets, which scales to Anadarko’s working interest, for third-party liabilities including sudden and accidental pollution and aviation liability; and (d) $275 million for aircraft liability (in addition to the third-party liability limits described in item (c) above). Anadarko does not carry significant coverage for loss of production income from any of the Company’s facilities or for any losses that result from the effects of a named windstorm.
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.

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Following is a discussion of significant sources and uses of cash flows for the three-year period ended December 31, 2014. 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 2014 was $8.5 billion compared to $8.9 billion in 2013 and $8.3 billion in 2012. Cash flows from operating activities for 2014 decreased year over year due to $730 million of cash received in 2013 associated with the Algeria exceptional profits tax settlement, a $520 million income tax payment in 2014 associated with the Company’s divestiture of a 10% working interest in Offshore Area 1 in Mozambique, lower average oil and NGLs prices, lower natural-gas volumes, higher operating expenses, and the unfavorable impact of changes in working capital items. These decreases were substantially offset by higher average natural-gas prices, higher sales volumes for oil and NGLs, and net cash received in settlement of commodity derivative instruments. Cash flows from operating activities for 2013 increased year over year primarily due to higher sales volumes, higher average natural-gas prices, and the favorable impact of changes in working capital items. These increases were partially offset by lower average oil and NGLs prices and a decrease in cash collected in 2013 associated with the Algeria exceptional profits tax receivable.
One of the primary sources of variability in the Company’s cash flows from operating activities is fluctuation in commodity prices, the impact of which Anadarko partially mitigates by entering into commodity derivatives. Sales-volume changes also impact cash flow, but historically have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are also impacted by the costs related to continued operations and debt service.

Investing Activities  Anadarko received pretax sales proceeds related to property divestiture transactions of $5.0 billion in 2014, $567 million in 2013, and $657 million in 2012. The increase in 2014 was primarily related to the Company’s divestitures of a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion, its Chinese subsidiary for $1.075 billion, its interest in the Pinedale/Jonah assets in Wyoming for $581 million, and its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for $500 million.

Financing Activities  During 2014, Anadarko’s consolidated subsidiary, WES, borrowed $1.2 billion under its RCF primarily to partially fund its acquisitions of DBM and Anadarko’s interests in Texas Express Pipeline LLC, Texas Express Gathering LLC, and Front Range Pipeline LLC and for other general partnership purposes, including the funding of capital expenditures. During 2014, WES completed public offerings of $100 million aggregate principal amount of 2.600% Senior Notes due 2018 and $400 million aggregate principal amount of 5.450% Senior Notes due 2044. These proceeds were used to repay borrowings under WES’s RCF and for general partnership purposes. During 2014, WES issued approximately 10 million common units to the public, raising total net proceeds of $691 million. The proceeds were used to partially fund a portion of its DBM acquisition. WES used all the capacity to issue units under the $125 million continuous offering program as of the end of the third quarter of 2014.
During 2014, Anadarko sold approximately 6 million WGP common units to the public, raising net proceeds of $335 million. Also, during 2014, Anadarko completed public offerings of $625 million aggregate principal amount of 3.450% Senior Notes due 2024 and $625 million aggregate principal amount of 4.500% Senior Notes due 2044. These proceeds were used for general corporate purposes.
During 2013, WES borrowed $710 million under its RCF, primarily to fund the 2013 acquisitions of an interest in certain gas-gathering systems located in the Marcellus shale in north-central Pennsylvania and an intrastate pipeline in southwestern Wyoming, and for other general partnership purposes, including the funding of capital expenditures. During 2013, WES also issued approximately 12 million common units to the public, including the $125 million continuous offering program. These offerings raised net proceeds of $725 million, which were primarily used to repay outstanding RCF borrowings and for other general partnership purposes, including funding of WES’s capital expenditures. Also in 2013, WES completed a public offering of $250 million aggregate principal amount of 2.600% Senior Notes due 2018, with net proceeds from the offering used to repay outstanding borrowings under its RCF.

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During 2012, WES borrowed $374 million under its RCF, primarily to fund the acquisition of certain midstream assets from Anadarko. Also during 2012, WES completed a 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 were used by WGP to purchase common and general partner units in WES, and were in turn used by WES for general partnership purposes, including the funding of WES capital expenditures.

Uses of Cash

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

Capital Expenditures  The following presents the Company’s capital expenditures by category:
millions
2014
 
2013
 
2012
Property acquisitions
 
 
 
 
 
Exploration
$
283

 
$
327

 
$
239

Development
3

 
324

 

Exploration
1,711

 
1,970

 
2,064

Development
6,715

 
4,865

 
4,064

Total oil and gas costs incurred (1)
8,712

 
7,486

 
6,367

Less corporate acquisitions and non-cash property transactions
(1
)
 
6

 
32

Less asset retirement costs
347

 
180

 
98

Less geological and geophysical, exploration overhead, delay rentals expenses, and other expenses
543

 
430

 
401

Total oil and gas capital expenditures
7,823

 
6,870

 
5,836

Gathering, processing, and marketing and other (2)
1,433

 
1,653

 
1,475

Total capital expenditures (1)
$
9,256

 
$
8,523

 
$
7,311

 _______________________________________________________________________________
(1) 
Oil and gas costs incurred represent costs related to finding and developing oil and gas reserves. Costs associated with activities of the Company’s midstream and marketing reporting segments, LNG facilities costs, and other corporate activities are not included in oil and gas costs incurred. Capital expenditures represent additions to property and equipment excluding corporate acquisitions and non-cash property transactions 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 to provide a cash-basis presentation.
(2) 
Includes WES capital expenditures of $696 million in 2014, $792 million in 2013, and $529 million in 2012.

The Company’s capital expenditures increased by 9% for the year ended December 31, 2014, due to increased development drilling primarily in the Wattenberg field of $663 million and in the Eagleford shale of $546 million and to a spar lease buyout of $110 million in the Gulf of Mexico. The increase in the Eagleford shale was primarily due to the 2013 development drilling being funded by a third party as a result of a carried-interest agreement that was fully funded in June 2013. These 2014 increases were partially offset by 2013 acquisitions of certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million, primarily representing the fair value of the oil and gas properties acquired, and the acquisition of a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania from a third party by WES for $135 million.

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In the third quarter of 2014, the Company entered into a carried-interest arrangement that requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, located in Southeast Texas. The third-party funding is expected to cover Anadarko’s future capital costs in the development through 2016. At December 31, 2014, $22 million of the total $442 million obligation had been funded.
The Company’s capital spending increased by 17% for the year ended December 31, 2013, due to development drilling onshore and offshore in the United States and acquisitions of oil and gas development properties and domestic onshore plants and gathering systems. In 2013, Anadarko exchanged certain oil and gas properties in the Wattenberg field with a third party to enhance the Company’s core acreage position, in which $106 million of capital was incurred. Also in 2013, Anadarko acquired certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million, primarily representing the fair value of the oil and gas properties acquired. In 2013, WES acquired a 33.75% interest in gas-gathering systems for $135 million and an intrastate pipeline in southwestern Wyoming for $28 million. These increases were offset by lower capital spending associated with decreased exploration drilling in West Africa and U.S. onshore and lower capital requirements to Anadarko related to development projects as a result of the carried-interest arrangements discussed below.
In 2013, the Company entered into a carried-interest arrangement that requires a third party to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. The third-party funding is expected to cover the substantial majority of Anadarko’s expected future capital costs through first production, which is expected to occur by mid-2016. At December 31, 2014, $386 million of the total $860 million obligation had been funded.
In the third quarter of 2012, the Company entered into a carried-interest arrangement that required a third party to fund $556 million of Anadarko’s capital costs in exchange for a 7.2% working interest in the Lucius development, located in the Gulf of Mexico. During the second quarter of 2014, as dictated by the Unitization and Participation Agreement, the working interests of all partners in the Lucius development were recalculated. As a result, Anadarko’s working interest in the Lucius development was reduced from 27.8% to 23.8% and its capital expenditures were reduced by $44 million due to the re-determination. In addition, the working interest of the third party that participated in the carried-interest arrangement was reduced from 7.2% to 6.2%, which resulted in a reduction in the funding commitment from $556 million to $476 million. The funding commitment, which was fully funded during the second quarter of 2014, covered the substantial majority of the Company’s capital costs through first production, which occurred in the fourth quarter of 2014.

Pension Contributions  During 2014, the Company made contributions of $106 million to its funded pension plans, $15 million to its unfunded pension plans, and $15 million to its unfunded other postretirement benefit plans, which are included in Operating Activities in the Consolidated Statement of Cash Flows. Contributions to the funded pension plans decreased in 2014 as a result of favorable asset returns in 2013. Contributions made to the unfunded pension plans in 2014 were lower as a result of higher funding in 2013 related to the retirement of the Company’s former Chief Executive Officer. The Company expects to contribute $5 million to its funded pension plans, $24 million to its unfunded pension plans, and $16 million to its unfunded other postretirement benefit plans in 2015.
During 2013, the Company made contributions of $123 million to its funded pension plans, $37 million to its unfunded pension plans, and $14 million to its unfunded other postretirement benefit plans. The increase in contributions to the funded pension plans in 2013 resulted from a decrease in the discount rates used for funding purposes.
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 an increase in the discount rates used for funding purposes.

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Investments  During 2014, the Company made capital contributions of $167 million related to equity investments, which are included in Other—net under Investing Activities in the Consolidated Statement of Cash Flows. These contributions were primarily associated with joint ventures for a gas processing plant, marine well containment, and pipelines. The Company made capital contributions related to equity investments of $396 million in 2013, which were primarily associated with joint ventures to build the Front Range Pipeline, the Texas Express Pipeline, and two fractionation trains in Mont Belvieu. The Company made capital contributions related to equity investments of $205 million in 2012.

Debt Retirements and Repayments  During 2014, Anadarko repaid $775 million of Senior Notes that matured during 2014. Also, WES repaid $650 million of borrowings under its RCF with proceeds from debt and equity offerings, as discussed in Sources of Cash. During 2013, WES repaid $710 million of borrowings under its RCF with proceeds from debt and equity offerings. 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.
For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity, and interest rates, see Note 12—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 of $505 million in 2014, $274 million in 2013, and $181 million in 2012. The Company increased the quarterly dividend paid to common stockholders from $0.09 per share to $0.18 per share during the third quarter of 2013. During the second quarter of 2014, Anadarko increased the quarterly dividend paid to common stockholders from $0.18 per share to $0.27 per share. Anadarko has paid a dividend to its common stockholders quarterly since becoming a 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.
WES distributed to its unitholders, other than Anadarko, an aggregate of $175 million in 2014, $130 million in 2013, and $100 million in 2012. 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 $0.70 per common unit for the fourth quarter of 2014 (paid in February 2015).
WGP distributed to its unitholders, other than Anadarko, an aggregate of $24 million during 2014 and $12 million in 2013. WGP declared a cash distribution of $0.31250 per unit for the fourth quarter of 2014 (to be paid in February 2015).

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Outlook

Oil, natural-gas, and NGLs prices can have significant price fluctuations. The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on the prices the Company receives for oil, natural gas, and NGLs. During 2014, New York Mercantile Exchange West Texas Intermediate oil prices ranged from a high of $107.26 per barrel to a low of $53.27 per barrel at the end of 2014. The duration and magnitude of the decline in oil prices cannot be predicted.
The Company has a deep portfolio of investment opportunities and the financial strength and operational flexibility to move capital spending from areas focused on near-term production growth to areas focused on longer-term growth where anticipated returns are less sensitive to spot oil and natural-gas prices. The recent decline in oil prices may result in the Company significantly reducing its capital expenditures in 2015 versus 2014. The Company will continue to evaluate the oil and natural-gas price environments and may adjust its capital spending plans as prices fluctuate while maintaining the appropriate liquidity and financial flexibility.
The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company currently plans to allocate approximately 65% of its 2015 capital spending to development activities, 15% to exploration activities, and 20% to gas-gathering and processing activities and other business activities. The Company currently expects its 2015 capital spending by area to be approximately 55% for the U.S. onshore region and Alaska, 10% for the Gulf of Mexico, 20% for Midstream and other, and 15% for International.
Anadarko believes that its cash on hand, available borrowing capacity, and expected level of operating cash flows will be sufficient to fund the Company’s projected operational and capital programs for 2015 and continue to meet its other current obligations. The Company’s cash on hand is available for use and could be supplemented, as needed, with available borrowing capacity under the New Credit Facilities and the commercial paper program. The Company may also enter into carried-interest arrangements with third parties to fund certain capital expenditures, execute asset divestitures, and sell a portion of the WGP common units that it owns in order to supplement cash flow.
The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions. To reduce commodity-price risk and increase the predictability of 2015 cash flows, Anadarko entered into strategic derivative positions, which cover a portion of its anticipated natural-gas sales volumes for 2015. For details of derivative positions at December 31, 2014, see Note 11—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. In addition, the Company enters into other contractual agreements in the normal course of business for processing, treating, transportation, and storage of natural gas, oil, and NGLs, as well as for other oil and gas activities as discussed below in Obligations and Commitments. Other than the items discussed above, 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.

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Obligations and Commitments

The following is a summary of the Company’s obligations at December 31, 2014:
 
Obligations by Period (1)
millions
2015
 
2016-2017
 
2018-2019
 
2020 and beyond
 
Total
Total debt
 
 
 
 
 
 
 
 
 
Principal—long-term borrowings (2)
$

 
$
3,750

 
$
1,874

 
$
11,063

 
$
16,687

Principal—capital lease obligation

 

 
1

 
20

 
21

Investee entities’ debt (3)

 

 

 
2,853

 
2,853

Interest on borrowings
876

 
1,647

 
1,219

 
7,907

 
11,649

Interest on capital lease obligations
2

 
3

 
3

 
15

 
23

Investee entities’ interest (3)
41

 
152

 
199

 
2,574

 
2,966

Operating leases
 
 
 
 
 
 
 
 
 
Drilling rig commitments
939

 
1,310

 
460

 
28

 
2,737

Production platforms
33

 
43

 
43

 
51

 
170

Other
50

 
72

 
24

 
8

 
154

Asset retirement obligations
258

 
413

 
180

 
1,202

 
2,053

Midstream and marketing activities
930

 
1,904

 
1,775

 
2,656

 
7,265

Oil and gas activities
1,295

 
1,059

 
426

 
400

 
3,180

Derivative liabilities (4)
43

 
1,200

 

 

 
1,243

Uncertain tax positions, interest, and penalties (5)
123

 
193

 
5

 
11

 
332

Environmental liabilities
20

 
19

 
9

 
78

 
126

Other
40

 
222

 

 

 
262

Total
$
4,650

 
$
11,987

 
$
6,218

 
$
28,866

 
$
51,721

 _______________________________________________________________________________
(1) 
This table does not include the Tronox-related contingent liability, other litigation-related contingent liabilities, or the Company’s pension and postretirement benefit obligations. See Note 17—Contingencies—Tronox Litigation and Note 21—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(2) 
Includes the fully accreted principal amount of the Zero Coupons of approximately $2.4 billion as coming due after 2019. While the Zero Coupons do not mature until 2036, the outstanding Zero Coupons can be put to the Company each October, in whole or in part, for the then-accreted value. The Company could be required to repurchase the outstanding Zero Coupons at $796 million in October 2015 (the next potential put date).
(3) 
Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets in other long-term liabilities—other for all periods presented. These notes payable provide for a variable rate of interest, reset quarterly. Therefore, future interest payments presented in the table above are estimated using the forward LIBOR rate curve. Further, the above table does not reflect the preferred return that Anadarko receives on its investment in these entities, which is also LIBOR-based, but with a lower margin than the margin on the associated notes payable. See Note 10—Equity-Method Investments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(4) 
Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties. See Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(5) 
See Note 18—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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Operating Leases  Operating lease obligations include approximately $2.5 billion related to seven offshore drilling vessels and $208 million related to certain contracts for U.S. onshore drilling rigs. Anadarko manages its access to rigs to support the execution of 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. At December 31, 2014, the Company had $324 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 to access markets and provide flexibility to sell its natural gas, oil, and NGLs in certain areas.

Oil and Gas Activities  At December 31, 2014, Anadarko had various long-term contractual commitments pertaining to exploration, development, and production activities that extend beyond 2014. The Company has work-related commitments for, among other things, drilling wells, obtaining and processing seismic data, and fulfilling rig commitments. The preceding table includes long-term drilling and work-related commitments of $3.2 billion, comprised of approximately $2.0 billion related to the United States and $1.2 billion 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, 2014, the Company’s Consolidated Balance Sheet included a $126 million liability for remediation and reclamation obligations. The Company continually monitors the liability recorded and ongoing remediation and reclamation activities, and believes the amount recorded is appropriate. For additional information on environmental issues, see Risk Factors under Item 1A of this Form 10-K.

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CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP in the United States requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion of the Company’s significant accounting policies. 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, development, and disclosure of these estimates is discussed with the Company’s Audit Committee.

Proved Reserves

Anadarko estimates its proved oil and gas reserves according to the definition of proved reserves provided by the Securities and Exchange Commission and the Financial Accounting Standards Board (FASB). This definition includes 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. (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.
The quantities of estimated proved oil and gas reserves are a significant component of DD&A. 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. If the estimates of proved reserves used in the unit-of-production calculations had been lower by five percent across all calculations, DD&A in 2014 would have increased by approximately $210 million.

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 well costs are expensed. 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. See Note 6—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.

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Fair Value

The Company estimates fair value for 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, pension plan assets, and initial measurements of AROs. 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 uses 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.

Property Impairments

When circumstances indicate that proved oil and gas properties may be impaired, the expected undiscounted future net cash flows of the asset group are compared to the carrying amount of the asset. If the expected undiscounted future net cash flows, based on our estimate of future oil and natural-gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the carrying amount, the carrying amount is reduced to fair value. Fair value estimates require significant judgment and oil and natural-gas prices are a significant component of the fair-value estimate. Prices have exhibited significant volatility in the past, and the Company expects that volatility to continue in the future.
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 undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value. The Company uses a variety of fair-value measurement techniques as discussed below when market information for the same or similar assets does not exist.

Goodwill Impairments

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 compares 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 determines whether impairment is necessary.
Because quoted market prices for the Company’s reporting units are not available, management applies 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 observable for the oil and gas exploration and production reporting unit, control premiums and market multiples of earnings before interest, taxes, depreciation, and amortization (EBITDA) for the gathering and processing and transportation reporting units.

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In estimating the fair value of its oil and gas exploration and production reporting unit, the Company assumes production profiles used 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 use based upon the risks inherent in Anadarko’s operations. Management also includes control premium assumptions based on observable market information regarding how a market participant would value the oil and gas exploration and reporting unit as a whole rather than as individual properties that are part of an oil and gas portfolio.
For the Company’s other gathering and processing, WES gathering and processing, and WES 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 commodity-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 liabilities for environmental remediation, litigation, and other contingent matters. Estimates of litigation-related liabilities are based on the facts and circumstances of the individual case and on information currently available to the Company. The extent of information available varies based on the status of the litigation and the Company’s evaluation of the claim and legal arguments. In future periods, a number of factors could significantly change the Company’s estimate of litigation-related liabilities including discovery activities, briefings filed with the relevant court, rulings from the court in the process or at the conclusion of any trial, and similar cases involving other plaintiffs and defendants that may set or change legal precedent. As events unfold throughout the litigation process, the Company evaluates the available information and may consult with third-party legal counsel to determine whether liability accruals should be established or adjusted.
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 that could arise 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 contingent liabilities and, in certain circumstances, consult with third-party legal counsel or consultants to assist in the evaluation of the Company’s liability for these contingencies.

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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 by analyzing the reversal periods of available net operating loss carryforwards and credit carryforwards, temporary differences in tax assets and liabilities, the availability of tax planning strategies, and estimates of future taxable income and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves and selling prices that are consistent with the Company’s internal business forecasts. 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 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.

RECENT ACCOUNTING DEVELOPMENTS

See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion of recent accounting developments affecting the Company.

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 used 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 to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 11—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, 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 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 356 Bcf of natural gas at December 31, 2014, with a net derivative asset position of $228 million. Based on actual derivative contractual volumes, a 10% increase in natural-gas prices would reduce the fair value of these derivatives by $60 million, while a 10% decrease in natural-gas prices would increase the fair value of these derivatives by $52 million. However, any cash received or paid to settle these derivatives would be substantially offset by the realized sales value of equivalent production. In 2014, the Company terminated or offset then-existing 2015 oil three-way collars with a notional volume of 25 MBbls/d due to lower oil prices, resulting in a cash receipt of $126 million.


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Derivative Instruments Held for Trading Purposes  At December 31, 2014, the Company had a net derivative asset position of $28 million (gains of $28 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.

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

INTEREST-RATE RISK  Any borrowings under the New Credit Facilities, the WES RCF, and the commercial paper program are subject to variable interest rates. The balance of Anadarko’s long-term debt on 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 impact the Company’s interest cost on fixed-rate debt already outstanding, but would affect the fair value of outstanding fixed-rate debt.
At December 31, 2014, 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 $104 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 the New Credit Facilities and the commercial paper program. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

FOREIGN-CURRENCY EXCHANGE-RATE RISK  Anadarko’s operating revenues are realized in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are U.S.-dollar-denominated. Exposure to foreign-currency risk generally arises in connection with project-specific contractual arrangements and other commitments. Near-term foreign-currency-denominated expenditures are primarily in euros, Brazilian reais, British pounds sterling, Mozambican meticais, and Colombian pesos. 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, which is currently under consideration by the Brazilian courts. See Note 17—Contingencies—Other Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. At December 31, 2014, cash of $128 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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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 condition, 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, 2014. This assessment was based on criteria established in the Internal ControlIntegrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2014, the Company’s internal control over financial reporting was effective based on those criteria. The Company acquired Nuevo Midstream, LLC in November 2014 and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, Nuevo Midstream, LLC’s internal control over financial reporting associated with total assets of $1.6 billion and total revenues of $12.5 million included in the consolidated financial statements of Anadarko Petroleum Corporation and subsidiaries as of and for the year ended December 31, 2014.
KPMG LLP has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2014.
 
/s/ R. A. WALKER
R. A. Walker
Chairman, President and Chief Executive Officer
 
/s/ ROBERT G. GWIN
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer
 
February 20, 2015


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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, 2014, based on criteria established in Internal Control Integrated Framework (2013) 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, 2014, based on criteria established in Internal Control Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Anadarko Petroleum Corporation acquired Nuevo Midstream, LLC in November 2014 and management excluded from its assessment of the effectiveness of Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2014, Nuevo Midstream, LLC’s internal control over financial reporting associated with total assets of $1.6 billion and total revenues of $12.5 million included in the consolidated financial statements of Anadarko Petroleum Corporation and subsidiaries as of and for the year ended December 31, 2014. Our audit of internal control over financial reporting of Anadarko Petroleum Corporation also excluded an evaluation of the internal control over financial reporting of Nuevo Midstream, LLC.

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, 2014 and 2013, 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, 2014, and our report dated February 20, 2015 expressed an unqualified opinion on those consolidated financial statements.
 
/s/ KPMG LLP
 
Houston, Texas
February 20, 2015

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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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three–year period ended December 31, 2014, 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, 2014, based on criteria established in Internal Control Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 20, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
 
/s/ KPMG LLP
 
Houston, Texas
February 20, 2015


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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME 
 
Years Ended December 31,
millions except per-share amounts
2014
 
2013
 
2012
Revenues and Other
 
 
 
 
 
Natural-gas sales
$
3,849

 
$
3,388

 
$
2,444

Oil and condensate sales
9,748

 
9,178

 
8,728

Natural-gas liquids sales
1,572

 
1,262

 
1,224

Gathering, processing, and marketing sales
1,206

 
1,039

 
911

Gains (losses) on divestitures and other, net
2,095

 
(286
)
 
104

Total
18,470

 
14,581

 
13,411

Costs and Expenses
 
 
 
 
 
Oil and gas operating
1,171

 
1,092

 
976

Oil and gas transportation and other
1,184

 
1,022

 
955

Exploration
1,639

 
1,329

 
1,946

Gathering, processing, and marketing
1,030

 
869

 
763

General and administrative
1,316

 
1,090

 
1,246

Depreciation, depletion, and amortization
4,550

 
3,927

 
3,964

Other taxes
1,244

 
1,077

 
1,224

Impairments
836

 
794

 
389

Algeria exceptional profits tax settlement

 
33

 
(1,797
)
Deepwater Horizon settlement and related costs
97

 
15

 
18

Total
13,067

 
11,248

 
9,684

Operating Income (Loss)
5,403

 
3,333

 
3,727

Other (Income) Expense
 
 
 
 
 
Interest expense
772

 
686

 
742

(Gains) losses on derivatives, net
197

 
(398
)
 
(326
)
Other (income) expense, net
20

 
89

 
(4
)
Tronox-related contingent loss
4,360

 
850

 
(250
)
Total
5,349

 
1,227

 
162

Income (Loss) Before Income Taxes
54

 
2,106

 
3,565

Income tax expense (benefit)
1,617

 
1,165

 
1,120

Net Income (Loss)
(1,563
)
 
941

 
2,445

Net income attributable to noncontrolling interests
187

 
140

 
54

Net Income (Loss) Attributable to Common Stockholders
$
(1,750
)
 
$
801

 
$
2,391

 
 
 
 
 
 
Per Common Share
 
 
 
 
 
Net income (loss) attributable to common stockholders—basic
$
(3.47
)
 
$
1.58

 
$
4.76

Net income (loss) attributable to common stockholders—diluted
$
(3.47
)
 
$
1.58

 
$
4.74

Average Number of Common Shares Outstanding—Basic
506

 
502

 
500

Average Number of Common Shares Outstanding—Diluted
506

 
505

 
502

Dividends (per Common Share)
$
0.99

 
$
0.54

 
$
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
2014
 
2013
 
2012
Net Income (Loss)
$
(1,563
)
 
$
941

 
$
2,445

Other Comprehensive Income (Loss)
 
 
 
 
 
Adjustments for derivative instruments
 
 
 
 
 
Reclassification of previously deferred derivative losses to (gains) losses
   on derivatives, net
9

 
11

 
12

Income taxes on reclassification of previously deferred derivative losses
   to (gains) losses on derivatives, net
(3
)
 
(4
)
 
(4
)
Total adjustments for derivative instruments, net of taxes
6

 
7

 
8

Adjustments for pension and other postretirement plans
 
 
 
 
 
Net gain (loss) incurred during period
(405
)
 
416

 
(155
)
Income taxes on net gain (loss) incurred during period
149

 
(152
)
 
56

Amortization of net actuarial (gain) loss to general and
   administrative expense
27

 
132

 
93

Income taxes on amortization of net actuarial (gain) loss
   to general and administrative expense
(9
)
 
(49
)
 
(32
)
Amortization of net prior service (credit) cost to general and
   administrative expense

 
1

 
2

Total adjustments for pension and other postretirement plans, net of taxes
(238
)
 
348

 
(36
)
Total
(232
)
 
355

 
(28
)
Comprehensive Income (Loss)
(1,795
)
 
1,296

 
2,417

Comprehensive income attributable to noncontrolling interests
187

 
140

 
54

Comprehensive Income (Loss) Attributable to Common Stockholders
$
(1,982
)
 
$
1,156

 
$
2,363



See accompanying Notes to Consolidated Financial Statements.
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS 
 
December 31,
millions
2014
 
2013
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
7,369

 
$
3,698

Accounts receivable (net of allowance of $7 million and $5 million)
 
 
 
Customers
1,118

 
1,481

Others
1,409

 
1,241

Other current assets
1,325

 
688

Total
11,221

 
7,108

Properties and Equipment
 
 
 
Cost
75,107

 
71,244

Less accumulated depreciation, depletion, and amortization
33,518

 
30,315

Net properties and equipment
41,589

 
40,929

Other Assets
2,310

 
2,082

Goodwill and Other Intangible Assets
6,569

 
5,662

Total Assets
$
61,689

 
$
55,781

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
3,683

 
$
3,530

Current asset retirement obligations
257

 
409

Accrued expenses
994

 
1,264

Current portion of long-term debt

 
500

Deepwater Horizon settlement and related costs
90

 

Tronox-related contingent liability
5,210

 

Total
10,234

 
5,703

Long-term Debt
15,092

 
13,065

Other Long-term Liabilities
 
 
 
Deferred income taxes
9,249

 
9,245

Asset retirement obligations
1,796

 
1,613

Tronox-related contingent liability

 
850

Other
3,000

 
1,655

Total
14,045

 
13,363

 
 
 
 
Equity
 
 
 
Stockholders’ equity
 
 
 
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 525.9 million and 522.5 million shares issued)
52

 
52

Paid-in capital
9,005

 
8,629

Retained earnings
12,125

 
14,356

Treasury stock (19.3 million and 18.8 million shares)
(940
)
 
(895
)
Accumulated other comprehensive income (loss)
(517
)
 
(285
)
Total Stockholders’ Equity
19,725

 
21,857

Noncontrolling interests
2,593

 
1,793

Total Equity
22,318

 
23,650

Total Liabilities and Equity
$
61,689

 
$
55,781


See accompanying Notes to Consolidated Financial Statements.
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY 
 
Total Stockholders’ Equity
 
 
 
 
millions
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interests
 
Total
Equity
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 stock

 

 
(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 (gains) losses on derivatives, net

 

 

 

 
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

Net income (loss)

 

 
801

 

 

 
140

 
941

Common stock issued
1

 
292

 

 

 

 

 
293

Dividends—common stock

 

 
(274
)
 

 

 

 
(274
)
Repurchase of common stock

 

 

 
(54
)
 

 

 
(54
)
Subsidiary equity transactions

 
107

 

 

 

 
554

 
661

Distributions to noncontrolling interest owners

 

 

 

 

 
(156
)
 
(156
)
Contributions from noncontrolling interest owners

 

 

 

 

 
2

 
2

Reclassification of previously deferred derivative
   losses to (gains) losses on derivatives, net

 

 

 

 
7

 

 
7

Adjustments for pension and other
   postretirement plans

 

 

 

 
348

 

 
348

Balance at December 31, 2013
52

 
8,629

 
14,356

 
(895
)
 
(285
)
 
1,793

 
23,650

Net income (loss)

 

 
(1,750
)
 

 

 
187

 
(1,563
)
Common stock issued

 
286

 

 

 

 

 
286

Dividends—common stock

 

 
(505
)
 

 

 

 
(505
)
Repurchase of common stock

 

 

 
(45
)
 

 

 
(45
)
Subsidiary equity transactions

 
90

 
24

 

 

 
829

 
943

Distributions to noncontrolling interest owners

 

 

 

 

 
(216
)
 
(216
)
Reclassification of previously deferred derivative
   losses to (gains) losses on derivatives, net

 

 

 

 
6

 

 
6

Adjustments for pension and other
   postretirement plans

 

 

 

 
(238
)
 

 
(238
)
Balance at December 31, 2014
$
52

 
$
9,005

 
$
12,125

 
$
(940
)
 
$
(517
)
 
$
2,593

 
$
22,318




See accompanying Notes to Consolidated Financial Statements.
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS 
 
Years Ended December 31,
millions
2014
 
2013
 
2012
Cash Flows from Operating Activities
 
 
 
 
 
Net income (loss)
$
(1,563
)
 
$
941

 
$
2,445

Adjustments to reconcile net income (loss) to net cash provided by
  operating activities
 
 
 
 
 
Depreciation, depletion, and amortization
4,550

 
3,927

 
3,964

Deferred income taxes
(105
)
 
90

 
164

Dry hole expense and impairments of unproved properties
1,245

 
864

 
1,544

Impairments
836

 
794

 
389

(Gains) losses on divestitures, net
(1,891
)
 
470

 
71

Total (gains) losses on derivatives, net
207

 
(392
)
 
(308
)
Operating portion of net cash received (paid) in settlement of
  derivative instruments
371

 
85

 
685

Other
327

 
246

 
232

Changes in assets and liabilities
 
 
 
 
 
Deepwater Horizon settlement and related costs
90

 
(2
)
 
24

Algeria exceptional profits tax settlement

 
730

 
(791
)
Tronox-related contingent loss
4,360

 
850

 
(250
)
(Increase) decrease in accounts receivable
103

 
(11
)
 
520

Increase (decrease) in accounts payable and accrued expenses
7

 
150

 
(476
)
Other items—net
(71
)
 
146

 
126

Net cash provided by (used in) operating activities
8,466

 
8,888

 
8,339

Cash Flows from Investing Activities
 
 
 
 
 
Additions to properties and equipment and dry hole costs
(9,508
)
 
(7,721
)
 
(7,242
)
Acquisition of businesses
(1,527
)
 
(473
)
 

Divestitures of properties and equipment and other assets
4,968

 
567

 
657

Other—net
(405
)
 
(589
)
 
(284
)
Net cash provided by (used in) investing activities
(6,472
)
 
(8,216
)
 
(6,869
)
Cash Flows from Financing Activities
 
 
 
 
 
Borrowings, net of issuance costs
2,879

 
958

 
1,042

Repayments of debt
(1,425
)
 
(710
)
 
(3,044
)
Financing portion of net cash paid in settlement of derivative instruments
(222
)
 

 

Increase (decrease) in outstanding checks
62

 
(13
)
 
(69
)
Dividends paid
(505
)
 
(274
)
 
(181
)
Repurchase of common stock
(45
)
 
(54
)
 
(37
)
Issuance of common stock, including tax benefit on share-based
  compensation awards
121

 
146

 
103

Sale of subsidiary units
1,026

 
724

 
623

Distributions to noncontrolling interest owners
(216
)
 
(156
)
 
(112
)
Contributions from noncontrolling interest owners

 
2

 
16

Net cash provided by (used in) financing activities
1,675

 
623

 
(1,659
)
Effect of Exchange Rate Changes on Cash
2

 
(68
)
 
(37
)
Net Increase (Decrease) in Cash and Cash Equivalents
3,671

 
1,227

 
(226
)
Cash and Cash Equivalents at Beginning of Period
3,698

 
2,471

 
2,697

Cash and Cash Equivalents at End of Period
$
7,369

 
$
3,698

 
$
2,471


See accompanying Notes to Consolidated Financial Statements.
92

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, oil, condensate, natural gas liquids (NGLs), and anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, oil, and NGLs. The Company also participates in the hard-minerals business through 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 generally accepted accounting principles in the United States (GAAP) requires management to 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 proved reserves; the value of properties and equipment; goodwill; intangible assets; asset retirement obligations; litigation liabilities; 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).

In determining fair value, the Company uses 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.

93

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

1. Summary of Significant Accounting Policies (Continued)

In arriving at fair-value estimates, the Company uses relevant 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 12—Debt and Interest Expense, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.
Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, asset retirement obligations, exit or disposal costs, and capital lease assets where the present value of lease payments is greater than the fair value of the leased asset.

Revenues  The Company’s natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. Oil and condensate are sold primarily to marketers, gatherers, and refiners. NGLs are sold primarily to direct end-users, refiners, and marketers.
The Company recognizes sales revenues for natural gas, oil and condensate, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.
Anadarko provides gathering, processing, treating, and transporting services pursuant to a variety of contracts. Under these arrangements, the Company receives fees, or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time the services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.
Marketing margins related to the Company’s production are included in natural-gas sales, oil and condensate sales, and NGLs sales. Marketing margins related to sales of commodities purchased from third parties and 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 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.

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


94

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

1. Summary of Significant Accounting Policies (Continued)

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.


95

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

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, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principle operations 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 12—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 7—Asset Retirement Obligations.

Impairments  Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. 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 5—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 WES transportation. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures. See Note 8—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 as well as customer-related intangible assets, including customer relationships established by acquired contracts. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment whenever impairment indicators are present. See Note 8—Goodwill and Other Intangible Assets.

96

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

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.
Gains and losses on derivative instruments are recognized currently in earnings. Net 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 11—Derivative Instruments.

Accounts Payable  Accounts payable included liabilities of $388 million at December 31, 2014, and $326 million at December 31, 2013, 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 at the time of acquisition, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. If the Company determines that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. 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 at the time of acquisition, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 17—Contingencies.

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans  The Company measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and the health care cost trend rate (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.
The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. See Note 21—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans.


97

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

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 9—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 basis. 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). The Company uses the flow-through method to account for its investment tax credits. See Note 18—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 based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted 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 13—Stockholders’ Equity.

Recently Issued Accounting Standards  The Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. This ASU is effective for annual and interim periods beginning in 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.


98

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

1. Summary of Significant Accounting Policies (Continued)

ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. This ASU is effective beginning in 2015, with early adoption permitted for disposals or for assets classified as held for sale not reported in previously issued financial statements. Anadarko early adopted this ASU on a prospective basis in the first quarter of 2014 with no material impact on the Company’s consolidated financial statements.
ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented in the financial statements as a reduction to a deferred tax asset, except in certain circumstances. This ASU is effective for annual and interim periods beginning in 2014. See Note 18—Income Taxes.

2. Acquisitions, Divestitures, and Assets Held for Sale

Acquisitions  In November 2014, WES acquired Nuevo Midstream, LLC (Nuevo), which owns and operates gathering and processing assets in the Delaware basin in West Texas, for $1.554 billion. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). This acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. This acquisition aligns the Company’s gas gathering and processing capacity with future industry production growth plans in the Delaware basin. The following summarizes the preliminary fair value of assets acquired and liabilities assumed at the acquisition date, pending the acquired entity’s final financial statements:
millions
 
 
Current assets
 
$
46

Properties and equipment
 
441

Other intangible assets
 
836

Accounts payable
 
(13
)
Accrued expenses
 
(25
)
Deferred income taxes
 
(1
)
Asset retirement obligations
 
(9
)
Goodwill
 
279

Total assets acquired and liabilities assumed
 
$
1,554


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 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 (liabilities) represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. All of the goodwill related to this acquisition is amortizable for tax purposes. The assets acquired and liabilities assumed are included within the midstream reporting segment.
Results of operations attributable to this acquisition are included in the Company’s Consolidated Statements of Income from the date acquired. The amounts of revenue and earnings included in the Company’s Consolidated Statement of Income for the year ended December 31, 2014, and the amounts of revenue and earnings that would have been recognized had the acquisition occurred on January 1, 2014, are not material to the Company’s Consolidated Statements of Income.

99

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

2. Acquisitions, Divestitures, and Assets Held for Sale (Continued)

There were no other material acquisitions made during 2014. The following summarizes acquisitions made during 2013:
millions, except percentages
Percentage
Acquired
 
Cash Paid
 
Certain oil and gas properties and related assets in the Moxa area of Wyoming
100
%
 
$
310

(1) 
Gas-gathering systems in the Marcellus shale in north-central Pennsylvania
33.75
%
 
135

 
Joint venture formed to design, construct, and own two fractionators located in
  Mont Belvieu, Texas
25
%
 
78

 
Intrastate pipeline in southwestern Wyoming
100
%
 
28

 
__________________________________________________________________
(1) 
Includes $306 million that represents the fair value of the oil and gas properties acquired.

Divestitures and Assets Held for Sale  The following summarizes the proceeds received and gains (losses) recognized on divestitures for the years ended December 31:
millions
2014
 
2013
 
2012
Proceeds received
$
4,968

 
$
567

 
$
657

Gains (losses) on divestitures, net
1,891

 
(470
)
 
(71
)

Divestitures The 2014 proceeds and net gains were primarily related to assets included in the oil and gas exploration and production reporting segment. The Company sold a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion, recognizing a gain of $1.5 billion. In addition, the Company sold its Chinese subsidiary for $1.075 billion, recognizing a gain of $510 million; sold its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for $500 million, recognizing a gain of $237 million; and sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million. These gains were partially offset by losses of $456 million discussed under Assets Held for Sale below.
The 2013 sales proceeds were primarily related to the Company’s divestiture of its interests in a soda ash joint venture and certain U.S. onshore and Indonesian oil and gas properties. Net losses were primarily related to the Company’s sale of the Pinedale/Jonah assets discussed under Assets Held for Sale below, partially offset by the Company’s divestiture of its interests in the soda ash joint venture and certain U.S. oil and gas properties. The 2012 sales proceeds were primarily related to U.S. oil and gas properties and net losses were primarily related to Indonesian oil and gas properties.

100

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

2. Acquisitions, Divestitures, and Assets Held for Sale (Continued)

Assets Held for Sale  During the fourth quarter of 2014, Anadarko considered certain U.S. onshore assets from the oil and gas exploration and production reporting segment to be held for sale. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement, and the Company recognized a loss of $456 million. Gains and losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. Volatility in the current commodity-price environment has reduced the probability that the assets will be sold within one year and the assets are therefore no longer considered held for sale at December 31, 2014. At December 31, 2014, the balances of assets and liabilities associated with assets held for sale were not material.
During the fourth quarter of 2013, the Company began marketing certain other domestic properties from the oil and gas exploration and production reporting segment to redirect its operating activities and capital investments to other areas. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement. In 2013, the Company recognized losses of $704 million primarily related to the sale of the Pinedale/Jonah assets in Wyoming, which closed in 2014. At December 31, 2013, the Company’s Consolidated Balance Sheets included long-term assets of $616 million and long-term liabilities of $27 million associated with assets held for sale.

Property Exchange  In 2013, the Company exchanged certain oil and gas properties in the Wattenberg field with a third party. The properties exchanged were measured at the Company’s historical net cost with no gain or loss recognized. Anadarko paid $106 million in cash as part of the exchange, which is included as an addition to properties and equipment on the Company’s Consolidated Statement of Cash Flows.

3. Inventories

The following summarizes the major classes of inventories included in other current assets at December 31:
millions
2014
 
2013
Oil
$
133

 
$
88

Natural gas
27

 
43

NGLs
83

 
79

Total inventories
$
243

 
$
210


4. Properties and Equipment
The following summarizes the cost of properties and equipment by segment at December 31:
millions
2014
 
2013
Oil and gas exploration and production (1)
$
63,674

 
$
61,302

Midstream
8,647

 
7,285

Marketing

 
9

Other
2,786

 
2,648

Total properties and equipment
$
75,107

 
$
71,244

__________________________________________________________________
(1) 
Includes costs associated with unproved properties of $5.1 billion at December 31, 2014, and $6.9 billion at December 31, 2013.

101

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

5. Impairments

The following summarizes impairments by segment for the years ended December 31:
millions
2014
 
2013
 
2012
Oil and gas exploration and production
 
 
 
 
 
Long-lived assets held for use
 
 
 
 
 
U.S. onshore properties
$
545

 
$
142

 
$
259

Gulf of Mexico properties
276

 
562

 
104

Cost-method investment
3

 
11

 
13

Midstream
 
 
 
 
 
Long-lived assets held for use
12

 
79

 
13

Total impairments
$
836

 
$
794

 
$
389


In 2014, certain U.S. onshore and Gulf of Mexico oil and gas properties were impaired primarily due to lower forecasted natural-gas and oil prices. While the Company’s other U.S. onshore oil and gas properties indicated no impairment at December 31, 2014, it is reasonably possible the estimate of undiscounted cash flows related to certain of these properties may change in the near term due to declines in commodity prices and could result in additional property impairments.
In 2013, certain Gulf of Mexico properties were impaired due to a reduction in estimated future net cash flows and downward revisions of reserves resulting from changes to the Company’s development plans. Also in 2013, certain U.S. onshore properties and related midstream assets were impaired due to downward revisions of reserves resulting from changes to the Company’s development plans. In addition, a midstream property was impaired during 2013 due to a reduction in estimated future cash flows. In 2012, certain U.S. onshore and midstream properties were impaired primarily due to lower natural-gas prices and 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. Impairments of the Company’s Venezuelan cost-method investment were due to declines in estimated recoverable value.
The following summarizes the post-impairment fair value of the above-described assets, which was measured using the income approach and Level 3 inputs:
millions
 
2014
 
2013
Long-lived assets held for use
 
$
731

 
$
548

Cost-method investment (1)
 
32

 
32

__________________________________________________________________
(1) 
This represents the Company’s after-tax net investment.

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 due to 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 did not expect to develop under the forecasted natural-gas price environment.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

6. 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
2014
 
2013
 
2012
Balance at January 1
$
2,232

 
$
2,062

 
$
1,353

Additions pending the determination of proved reserves
421

 
848

 
960

Divestitures (1)
(913
)
 
(48
)
 

Reclassifications to proved properties
(100
)
 
(507
)
 
(129
)
Charges to exploration expense
(118
)
 
(123
)
 
(122
)
Balance at December 31
$
1,522

 
$
2,232

 
$
2,062

__________________________________________________________________
(1) 
Includes $(744) million related to the Company’s sale of a 10% working interest in Offshore Area 1 in Mozambique during 2014.

The following summarizes an aging of suspended exploratory well costs by geographic area and the year the costs were suspended at December 31, 2014:
 
 
 
Year Costs Incurred(1)
millions
Total
 
2014
 
2013
 
2012
 
2011 and
prior
United States—Onshore
$
164

 
$
131

 
$
17

 
$
5

 
$
11

United States—Offshore
314

 
78

 
80

 
63

 
93

International
1,044

 
179

 
271

 
184

 
410

 
$
1,522

 
$
388

 
$
368

 
$
252

 
$
514

__________________________________________________________________
(1) 
Excludes additions subsequently reclassified to proved properties within the same year.

Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling were associated with 24 projects at December 31, 2014, primarily located in Brazil, Ghana, and the Gulf of Mexico. 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, well-test analysis, additional geological and geophysical data, facilities and infrastructure development options, development plan approval, and permitting. Projects with suspended exploratory well costs are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development and where management 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.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

7. Asset Retirement Obligations

The majority of Anadarko’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties. 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. The following summarizes changes in the Company’s AROs during 2014 and 2013:
millions
2014
 
2013
Carrying amount of asset retirement obligations at January 1
$
2,022

 
$
1,885

Liabilities incurred
119

 
182

Property dispositions
(70
)
 
(76
)
Liabilities settled
(443
)
 
(162
)
Accretion expense
93

 
110

Revisions in estimated liabilities
332

 
83

Carrying amount of asset retirement obligations at December 31
$
2,053

 
$
2,022


8. Goodwill and Other Intangible Assets

Goodwill  The Company’s 2014 annual impairment assessment of goodwill indicated no impairment. Procedures were also performed in the fourth quarter of 2014 to review any changes in circumstances subsequent to the annual test, including changes in commodity prices. These procedures also indicated no impairment. At December 31, 2014, the Company had $5.6 billion of goodwill allocated to the following reporting units: $5.1 billion to oil and gas exploration and production, $69 million to other gathering and processing, $379 million to WES gathering and processing, and $5 million to WES transportation.
Significant declines in commodity prices, difficulties 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, 2014
 
 
 
 
 
 
 
Offshore platform leases
$
33

 
$
(29
)
 
$
4

 
$

Customer contracts
1,004

 
(15
)
 
989

 
6

 
$
1,037

 
$
(44
)
 
$
993

 
$
6

December 31, 2013
 
 
 
 
 
 
 
Offshore platform leases
$
60

 
$
(50
)
 
$
10

 
$
3

Customer contracts
169

 
(9
)
 
160

 
4

 
$
229

 
$
(59
)
 
$
170

 
$
7


Customer contract intangible assets are primarily related to WES’s DBM acquisition in 2014. These contracts are being amortized over 30 years. See Note 2—Acquisitions, Divestitures, and Assets Held for Sale. The annual aggregate amortization expense for intangible assets is expected to be $31 million each of the next five years.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

9. Noncontrolling Interests

In December 2012, Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary formed to own substantially all of the partnership interests in WES previously owned by 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, for net proceeds of $411 million. During 2014, Anadarko sold approximately six million WGP common units to the public, raising net proceeds of $335 million. At December 31, 2014, Anadarko’s ownership interest in WGP consisted of an 88.3% limited partner interest and the entire non-economic general partner interest. The remaining 11.7% limited partner interest in WGP was owned by the public.
WES, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES issued approximately 10 million common units to the public raising net proceeds of $691 million in 2014, approximately 12 million common units to the public raising net proceeds of $725 million in 2013, and approximately 5 million common units to the public raising net proceeds of $212 million in 2012. In addition, WES issued 11 million Class C units to Anadarko in 2014 to partially fund the DBM acquisition. These units will receive distributions in the form of additional Class C units until the end of 2017. At December 31, 2014, WGP’s ownership interest in WES consisted of a 34.9% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At December 31, 2014, Anadarko also owned an 8.3% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 55% limited partner interest in WES was owned by the public.

10. 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, 2014. Anadarko has legal right of setoff and intends to net settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets in other long-term liabilities—other for all periods presented.
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 1.24% at December 31, 2014 and December 31, 2013. The note payable agreement contains a covenant that provides for a maximum Anadarko debt-to-capital ratio of 67%. Anadarko was in compliance with this covenant at December 31, 2014. Other (income) expense, net includes interest expense on the notes payable of $36 million in 2014, $37 million in 2013, and $42 million in 2012, and equity earnings from Anadarko’s investments in the investee entities of $(45) million in 2014, $(42) million in 2013, and $(43) million in 2012.

105

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

11. 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, Louisiana for natural gas and Cushing, Oklahoma or Sullom Voe, Scotland for oil. Basis swaps are periodically 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 interest-rate changes. The fair value of the Company’s current 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, gains and losses associated with derivative instruments are recognized currently 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. See Note 14—Accumulated Other Comprehensive Income (Loss).

Oil and Natural-Gas Production/Processing Derivative Activities  The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The following is a summary of the Company’s derivative instruments related to natural-gas production/processing derivative activities at December 31, 2014:
 
 
2015 Settlement  
Natural Gas
 
 
Three-Way Collars (thousand MMBtu/d)
 
635

Average price per MMBtu
 
 
Ceiling sold price (call)
 
$
4.76

Floor purchased price (put)
 
$
3.75

Floor sold price (put)
 
$
2.75

Extendable Fixed-Price Contracts (thousand MMBtu/d) (1)
 
170

Average price per MMBtu
 
$
4.17

__________________________________________________________________
(1) 
The extendable fixed-price contracts have a contract term of January 2015 to December 2015 with an option for the counterparty to extend the contract term to December 2016 at the same price.
MMBtu—million British thermal units
MMBtu/d—million British thermal units 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.
In 2014, the Company terminated or offset then-existing 2015 oil three-way collars with a notional volume of 25 thousand barrels per day due to lower oil prices, resulting in a cash receipt of $126 million.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

11. Derivative Instruments (Continued)

Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 6 billion cubic feet (Bcf) at December 31, 2014, and 16 Bcf at December 31, 2013, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

Interest-Rate Derivatives  Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. These 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 interest-rate swap portfolio with anticipated future debt financing, in 2014 the Company extended the reference-period start dates from June 2014 to September 2016 and adjusted the related fixed interest rates for interest-rate swaps with an aggregate notional principal amount of $1.1 billion, and in 2012 the Company extended the reference-period start dates from October 2012 to September 2016 and adjusted the related fixed interest rates for interest-rate swap agreements with an aggregate notional principal amount of $800 million. In addition, in anticipation of the July 2014 issuance of an aggregate $1.25 billion of Senior Notes, interest-rate swap agreements with an aggregate notional principal amount of $750 million were settled in 2014, resulting in a cash payment of $222 million. Interest-rate swap agreements with an aggregate notional principal amount of $200 million were also settled in October 2012, resulting in a cash payment of $64 million.
Derivative settlements are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element and, therefore settlements related to these extended interest-rate derivatives are classified as cash flows from financing activities.
The Company had the following outstanding interest-rate swaps at December 31, 2014:
millions except percentages
 
Reference Period
 
Weighted-Average
Notional Principal Amount
 
Start
 
End
 
Interest Rate
$
50

 
 
September 2016
 
September 2026
 
5.91%
$
1,850

 
 
September 2016
 
September 2046
 
6.05%


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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

11. Derivative Instruments (Continued)

Effect of Derivative InstrumentsBalance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31:
millions
 
Gross
Derivative Assets
 
Gross
Derivative Liabilities
Balance Sheet Classification          
 
2014
 
2013
 
2014
 
2013
Commodity derivatives
 
 
 
 
 
 
 
 
Other current assets
 
$
421

 
$
181

 
$
(118
)
 
$
(102
)
Other assets
 
1

 
89

 

 
(66
)
Accrued expenses
 
71

 
106

 
(114
)
 
(149
)
Other liabilities
 

 
4

 
(6
)
 
(15
)
 
 
493

 
380

 
(238
)
 
(332
)
Interest-rate and other derivatives
 
 
 
 
 
 
 
 
Accrued expenses
 

 

 

 
(480
)
Other liabilities
 

 

 
(1,217
)
 
(174
)
 
 

 

 
(1,217
)
 
(654
)
Total derivatives
 
$
493

 
$
380

 
$
(1,455
)
 
$
(986
)

Effect of Derivative InstrumentsStatement of Income  The following summarizes gains and losses related to derivative instruments:
millions
 
 
 
 
 
 
Classification of (Gain) Loss Recognized
 
2014
 
2013
 
2012
Commodity derivatives
 
 
 
 
 
 
Gathering, processing, and marketing sales (1)
 
$
10

 
$
6

 
$
18

(Gains) losses on derivatives, net
 
(589
)
 
141

 
(387
)
Interest-rate and other derivatives
 
 
 
 
 
 
(Gains) losses on derivatives, net
 
786

 
(539
)
 
61

Total (gains) losses on derivatives, net
 
$
207

 
$
(392
)
 
$
(308
)
__________________________________________________________________
(1) 
Represents the effect of Marketing and Trading Derivative Activities.


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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

11. 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 IntercontinentalExchange, Inc. 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 gains and 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 provide for contract termination and net settlement across derivative types. At December 31, 2014, $289 million of the Company’s $1.455 billion gross derivative liability balance, and at December 31, 2013, $76 million of the Company’s $986 million 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.
The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declined to below investment grade. However, most of the Company’s derivative counterparties maintained secured positions at December 31, 2014, with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility ($5.0 billion Facility). In January 2015, the Company’s $5.0 billion Facility was replaced by new unsecured facilities under which the Company’s derivative counterparties no longer maintain security interests in any of the Company’s assets. As a result, the Company may be required from time to time to post collateral of cash or letters of credit based on the negotiated terms of the individual derivative agreements. For information on the Company’s revolving credit facilities, see Note 12—Debt and Interest Expense—Anadarko Revolving Credit Facilities and Commercial Paper Program.
The aggregate fair value of unsecured derivative instruments with credit-risk-related contingent features for which a net liability position existed was $97 million (net of collateral) at December 31, 2014, and $42 million at December 31, 2013. The current portion of these amounts was included in accrued expenses and the long-term portion of these amounts was included in other long-term liabilitiesother on the Company’s Consolidated Balance Sheets.


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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

11. Derivative Instruments (Continued)

Fair Value  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 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. 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, discount factors and implied market volatility.
The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:
millions
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Collateral
 
Total
December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
 
 
 
 
 
 
 
 
 
 
Financial institutions
$

 
$
471

 
$

 
$
(187
)
 
$
(13
)
 
$
271

Other counterparties

 
22

 

 
(2
)
 

 
20

Total derivative assets
$

 
$
493

 
$

 
$
(189
)
 
$
(13
)
 
$
291

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
 
 
 
 
 
 
 
 
 
 
Financial institutions
$

 
$
(234
)
 
$

 
$
187

 
$
23

 
$
(24
)
Other counterparties

 
(4
)
 

 
2

 

 
(2
)
Interest-rate and other derivatives

 
(1,217
)
 

 

 

 
(1,217
)
Total derivative liabilities
$

 
$
(1,455
)
 
$

 
$
189

 
$
23

 
$
(1,243
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
 
 
 
 
 
 
 
 
 
 
Financial institutions
$

 
$
211

 
$

 
$
(153
)
 
$

 
$
58

Other counterparties

 
169

 

 
(126
)
 

 
43

Total derivative assets
$

 
$
380

 
$

 
$
(279
)
 
$

 
$
101

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
 
 
 
 
 
 
 
 
 
 
Financial institutions
$

 
$
(200
)
 
$

 
$
153

 
$
7

 
$
(40
)
Other counterparties

 
(132
)
 

 
126

 

 
(6
)
Interest-rate and other derivatives

 
(654
)
 

 

 

 
(654
)
Total derivative liabilities
$

 
$
(986
)
 
$

 
$
279

 
$
7

 
$
(700
)
__________________________________________________________________
(1) 
Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

12. 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 10—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
2014
 
2013
5.750% Senior Notes due 2014
$

 
$
275

7.625% Senior Notes due 2014

 
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

WES 2.600% Senior Notes due 2018
350

 
250

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

 
670

3.450% Senior Notes due 2024
625

 

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

4.500% Senior Notes due 2044
625

 

WES 5.450% Senior Notes due 2044
400

 

7.730% Debentures due 2096
61

 
61

7.500% Debentures due 2096
78

 
78

7.250% Debentures due 2096
49

 
49

WES revolving credit facility
510

 

Total debt at face value
$
16,687

 
$
15,202

Net unamortized discounts and premiums (1)
(1,616
)
 
(1,645
)
Total borrowings
$
15,071

 
$
13,557

Capital lease obligation
21

 
8

Less current portion of long-term debt

 
500

Total long-term debt
$
15,092

 
$
13,065

__________________________________________________________________
(1) 
Unamortized discounts and premiums are amortized over the term of the related debt.

111

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

12. 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 approximately $2.4 billion, reflecting a yield to maturity of 5.24%. The Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. The accreted value of the outstanding Zero Coupons was $765 million at December 31, 2014. Anadarko’s Zero Coupons are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt.

Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.4 billion at December 31, 2014, and $15.3 billion at December 31, 2013.

Debt Activity  The following summarizes the Company’s debt activity during 2014 and 2013:
millions
Carrying
Value
 
Description
Balance at December 31, 2012
$
13,269

 
 
Issuances
250

 
WES 2.600% Senior Notes due 2018
Borrowings
710

 
WES revolving credit facility
Repayments
(710
)
 
WES revolving credit facility
Other, net
38

 
Amortization of debt discounts and premiums
Balance at December 31, 2013
$
13,557

 
 
Issuances
101

 
WES 2.600% Senior Notes due 2018
 
394

 
WES 5.450% Senior Notes due 2044
 
624

 
3.450% Senior Notes due 2024
 
621

 
4.500% Senior Notes due 2044
Borrowings
1,160

 
WES revolving credit facility
Repayments
(500
)
 
7.625% Senior Notes due 2014
 
(275
)
 
5.750% Senior Notes due 2014
 
(650
)
 
WES revolving credit facility
Other, net
39

 
Amortization of debt discounts and premiums
Balance at December 31, 2014
$
15,071

 
 


112

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

12. Debt and Interest Expense (Continued)

Anadarko Revolving Credit Facilities and Commercial Paper Program  During 2014, the Company maintained the $5.0 billion Facility maturing in September 2015. Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko had to lenders or their affiliates pursuant to certain derivative instruments that were supported by the $5.0 billion Facility as discussed in Note 11—Derivative Instruments, were guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and were 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. During 2014, the Company had no outstanding borrowings under the $5.0 billion Facility.
In June 2014, Anadarko entered into a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). The new facilities (collectively, the New Credit Facilities) replaced the $5.0 billion Facility upon satisfaction of certain conditions, including the January 2015 settlement payment related to the Tronox Adversary Proceeding. For additional information, see Note 17—Contingencies—Tronox Litigation.
In January 2015, the Company borrowed $1.5 billion under the 364-Day Facility. Borrowings under the New Credit Facilities generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the Five-Year Facility denominated in Euro) or an alternate base rate, in each case plus an applicable margin ranging from 0.00% to 1.65% for the Five-Year Facility and 0.00% to 1.675% for the 364-Day Facility. The applicable margin will vary depending on Anadarko’s credit ratings.
The New Credit Facilities contain certain customary affirmative and negative covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65%, and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes.
In January 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes.

WES Borrowings  In February 2014, WES amended and restated its then-existing $800 million senior unsecured revolving credit facility by entering into a five-year, $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to a maximum of $1.5 billion. Borrowings under the RCF bear interest at LIBOR plus an applicable margin ranging from 0.975% to 1.45% depending on WES’s credit rating, or the greatest of (i) rates at a margin above the one-month LIBOR, (ii) the federal funds rate, or (iii) prime rates offered by certain designated banks. At December 31, 2014, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $510 million at an interest rate of 1.47%, and had available borrowing capacity of approximately $677 million ($1.2 billion capacity, less $510 million of outstanding borrowings and $13 million of outstanding letters of credit).


113

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

12. Debt and Interest Expense (Continued)

Scheduled Maturities  Total principal amount of debt maturities for the five years ending December 31, 2019, 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
2015
$

2016
1,750

2017
2,000

2018
464

2019
1,410


Interest Expense  The following summarizes interest expense for the years ended December 31:
millions
2014
 
2013
 
2012
Debt and other
$
973

 
$
949

 
$
963

Capitalized interest
(201
)
 
(263
)
 
(221
)
Total interest expense
$
772

 
$
686

 
$
742


114

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

13. Stockholders’ Equity

Common Stock  The following summarizes the changes in the Company’s outstanding shares of common stock:
millions
2014
 
2013
 
2012
Shares of common stock issued
 
 
 
 
 
Shares at January 1
523

 
519

 
516

Exercise of stock options
2

 
2

 
1

Issuance of restricted stock
1

 
2

 
2

Shares at December 31
526

 
523

 
519

Shares of common stock held in treasury
 
 
 
 
 
Shares at January 1
19

 
18

 
18

Shares received for restricted stock vested and options exercised

 
1

 

Shares at December 31
19

 
19

 
18

Shares of common stock outstanding at December 31
507

 
504

 
501


The following provides a reconciliation between basic and diluted EPS attributable to common stockholders for the years ended December 31:
millions except per-share amounts
2014
 
2013
 
2012
Net income (loss)
 
 
 
 
 
Net income (loss) attributable to common stockholders
$
(1,750
)
 
$
801

 
$
2,391

Less distributions on participating securities
4

 
2

 
1

Less undistributed income allocated to participating securities

 
4

 
14

Basic
$
(1,754
)
 
$
795

 
$
2,376

Diluted
$
(1,754
)
 
$
795

 
$
2,376

Shares
 
 
 
 
 
Average number of common shares outstanding—basic
506

 
502

 
500

Dilutive effect of stock options

 
3

 
2

Average number of common shares outstanding—diluted
506

 
505

 
502

Excluded (1)
11

 
4

 
6

Net income (loss) per common share
 
 
 
 
 
Basic
$
(3.47
)
 
$
1.58

 
$
4.76

Diluted
$
(3.47
)
 
$
1.58

 
$
4.74

 
 
 
 
 
 
Dividends per common share
$
0.99

 
$
0.54

 
$
0.36

__________________________________________________________________
(1) 
Inclusion of certain shares would have had an anti-dilutive effect.

115

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

14. Accumulated Other Comprehensive Income (Loss)

The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss):
millions
Interest-rate
Derivatives
Previously
Subject to Hedge
Accounting
 
Pension and Other Postretirement
Plans
 
Total
Balance at December 31, 2013
$
(54
)
 
$
(231
)
 
$
(285
)
Other comprehensive income (loss), before
   reclassifications

 
(256
)
 
(256
)
Reclassifications to Consolidated Statement of Income
6

 
18

 
24

Net other comprehensive income (loss)
6

 
(238
)
 
(232
)
Balance at December 31, 2014
$
(48
)
 
$
(469
)
 
$
(517
)

15. Share-Based Compensation

At December 31, 2014, 21 million shares of the 31 million shares of Anadarko common stock originally 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
2014
 
2013
 
2012
Restricted stock
$
144

 
$
122

 
$
103

Stock options
21

 
27

 
43

Other equity-classified awards
1

 
1

 
1

Value creation plan
136

 

 
(2
)
Performance-based unit awards
23

 
4

 
8

Other performance-based awards

 

 
165

Other liability-classified awards

 
1

 
2

Pretax compensation expense
$
325

 
$
155

 
$
320

Income tax benefit
$
120

 
$
57

 
$
117


Cash flows from financing activities included excess tax benefits related to share-based compensation of $22 million in 2014, $11 million in 2013, and $51 million in 2012. Cash received from stock option exercises was $99 million in 2014, $135 million in 2013, and $52 million in 2012.

116

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

15. Share-Based Compensation (Continued)

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, which are also considered restricted stock, 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.
The following summarizes the Company’s restricted stock activity:
 
Shares
(millions)
 
Weighted-
Average
Grant-Date
Fair Value
(per share)
Non-vested at January 1, 2014
3.22

 
$
82.53

Granted
2.05

 
$
87.42

Vested
(1.52
)
 
$
82.35

Forfeited
(0.15
)
 
$
84.49

Non-vested at December 31, 2014
3.60

 
$
85.31


The weighted-average grant-date fair value per share of restricted stock granted was $84.17 during 2013 and $79.97 during 2012. The total fair value of restricted shares vested was $132 million during 2014, $110 million during 2013, and $105 million during 2012, based on the market price at the vesting date. At December 31, 2014, total unrecognized compensation cost related to restricted stock of $199 million is expected to be recognized over a weighted-average remaining service period of 1.9 years.

117

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

15. Share-Based Compensation (Continued)

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 generally 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.
The fair value of stock option awards is determined using the Black-Scholes option-pricing model with the following assumptions:
Expected life—Based on historical exercise behavior.
Volatility—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—Based on the U.S. Treasury rate over the expected life of an option.
Dividend yield—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—Based on historical forfeiture experience.
The Company used the following weighted-average assumptions to estimate the fair value of stock options granted:
 
2014
 
2013
 
2012
Weighted-average grant-date fair value
$
23.55
 
 
$
26.27
 
 
$
25.84
 
Assumptions
 
 
 
 
 
 
 
 
Expected option life—years
4.9
 
 
4.8
 
 
4.9
 
Volatility
29.9
%
 
33.9
%
 
44.2
%
Risk-free interest rate
1.6
%
 
1.3
%
 
0.7
%
Dividend yield
1.1
%
 
0.8
%
 
0.5
%

The following summarizes the Company’s stock option activity:
 
Shares
(millions)
 
Weighted-
Average
Exercise
Price
(per share)
 
Weighted-
Average
Remaining
Contractual
Term
(years)
 
Aggregate
Intrinsic
Value
(millions)
Outstanding at January 1, 2014
7.72

 
$
63.30

 
 
 
 
Granted
0.95

 
$
93.34

 
 
 
 
Exercised (1)
(1.85
)
 
$
54.03

 
 
 
 
Forfeited or expired
(0.03
)
 
$
76.00

 
 
 
 
Outstanding at December 31, 2014
6.79

 
$
69.96

 
3.56
 
$
104.3

Vested or expected to vest at December 31, 2014
6.73

 
$
69.79

 
3.54
 
$
104.2

Exercisable at December 31, 2014
4.99

 
$
62.91

 
2.60
 
$
101.1

__________________________________________________________________
(1) 
The total intrinsic value of stock options exercised was $88 million during 2014, $80 million during 2013, and $49 million during 2012, based on the difference between the market price at the exercise date and the exercise price.

At December 31, 2014, total unrecognized compensation cost related to stock options of $40 million is expected to be recognized over a weighted-average remaining service period of 2.2 years.

118

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

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 zero during 2014 and 2013 related to the plan and $24 million during 2012. At December 31, 2014, the Company had $137 million outstanding liability attributable to the 2014 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 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 $12 million related to vested performance units in 2014, $15 million in 2013, and $37 million in 2012. At December 31, 2014, the Company’s liability under Performance Unit Award Agreements was $26 million, with total unrecognized compensation cost related to these awards of $43 million expected to be recognized over a weighted-average remaining performance period of 2.2 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 in settlement of obligations related to all awards then outstanding.

119

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

16. Commitments

Operating Leases  At December 31, 2014, the Company had $2.7 billion in long-term drilling rig commitments that satisfy operating lease criteria. The Company also had $324 million of various commitments under non-cancelable operating lease agreements 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 $53 million at December 31, 2014. No liability has been accrued for residual value guarantees. In addition, these operating leases include options to purchase the leased property during or at the end of the lease term for the fair market value or other specified amount at that time. The following summarizes future minimum lease payments under operating leases at December 31, 2014:
millions
 
2015
$
1,022

2016
833

2017
592

2018
324

2019
203

Later years
87

Total future minimum lease payments
$
3,061


Anadarko has entered into various agreements to secure drilling rigs necessary to support the execution of its drilling plans over the next several years. The table of future minimum lease payments above includes $2.5 billion related to seven offshore drilling vessels and $208 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 or impaired in future periods or written off as exploration expense.
Total rent expense, net of sublease income and amounts capitalized, amounted to $85 million in 2014, $119 million in 2013, and $136 million in 2012. Total rent expense includes contingent rent expense related to transportation and processing fees of $22 million in 2014, $24 million in 2013, and $28 million in 2012.

Other Commitments  In the normal course of business, the Company enters into other contractual agreements for processing, treating, transportation, and storage of natural gas, oil, and NGLs, as well as for other oil and gas activities. These agreements expire at various dates through 2036. At December 31, 2014, aggregate future payments under these contracts totaled $10.4 billion, of which $2.2 billion is expected to be paid in 2015, $1.6 billion in 2016, $1.3 billion in 2017, $1.2 billion in 2018, $1.0 billion in 2019, and $3.1 billion thereafter.

120

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies

Litigation  The Company is a defendant in a number of lawsuits, is involved in governmental proceedings, and is subject to regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. The Company’s Consolidated Balance Sheets include liabilities of $5.3 billion at December 31, 2014, and $854 million at December 31, 2013, for litigation-related contingencies. 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 condition, results of operations, or cash flows.

Tronox Litigation  On November 28, 2005, Tronox Incorporated (Tronox), at the time a subsidiary of Kerr-McGee Corporation, completed an IPO and was subsequently spun-off from Kerr-McGee Corporation. In August 2006, Anadarko acquired all of the stock of Kerr-McGee Corporation. In January 2009, Tronox 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 (Bankruptcy Court), which is the court that presided over the Adversary Proceeding (defined below). In May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) asserting several claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleged, among other things, that it was insolvent or undercapitalized at the date of its IPO and sought, among other things, to recover damages in excess of $18.85 billion from Kerr-McGee and Anadarko, as well as interest and attorneys’ fees and costs. In accordance with Tronox’s Bankruptcy Court-approved Plan of Reorganization (Plan), the Adversary Proceeding was pursued by a litigation trust (Litigation Trust). Pursuant to the Plan, the Litigation Trust was “deemed substituted” for the Tronox plaintiffs in the Adversary Proceeding. For purposes of this Form 10-K, references to “Tronox” after February 2011 refer to the Litigation Trust.
The U.S. government intervened 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). The Litigation Trust and the U.S. government agreed that the recovery of damages under the Adversary Proceeding, if any, would cover both the Adversary Proceeding and the FDCPA Complaint.

Liability Accrual  On April 3, 2014, Anadarko and Kerr-McGee entered into a settlement agreement with the Litigation Trust and the U.S. government (in its capacity as plaintiff-intervenor and acting for and on behalf of certain U.S. government agencies) to resolve all claims asserted in the Adversary Proceeding and FDCPA Complaint for $5.15 billion, which represents principal of approximately $3.98 billion plus 6% interest from the filing of the Adversary Proceeding on May 12, 2009, through April 3, 2014. In addition, the Company agreed to pay interest on the above amount from April 3, 2014, through the payment of the settlement, with an annual interest rate of 1.5% for the first 180 days and 1.5% plus the one-month LIBOR thereafter. Under the terms of the settlement agreement, the Litigation Trust, Anadarko, and Kerr-McGee agreed to mutually release all claims that were or could have been asserted in the Adversary Proceeding. The U.S. government (representing federal agencies that filed claims in the Tronox bankruptcy), Anadarko, and Kerr-McGee also provided covenants not to sue each other with respect to certain claims and causes of action. The U.S. government also provided contribution protection from third-party claims seeking reimbursement from Anadarko and certain of its affiliates for the sites identified in the settlement agreement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective.

121

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies (Continued)

Anadarko recognized Tronox-related contingent losses of $850 million in the fourth quarter of 2013 and $4.3 billion in the first quarter of 2014. In addition, Anadarko recognized settlement-related interest expense of $60 million, included in Tronox-related contingent loss in the Company’s Consolidated Statement of Income, during the year ended December 31, 2014, for an aggregate $5.2 billion Tronox-related contingent liability on the Company’s Consolidated Balance Sheet at December 31, 2014. For information on the tax effects of the Tronox settlement agreement, see Note 18—Income Taxes.

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, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated 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-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against penalties and fines, 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. Applicable accounting guidance requires the Company to accrue a liability if both (a) it is probable that a liability has been incurred and (b) the amount of that liability 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.

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.
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.

122

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies (Continued)

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 through the fourth quarter of 2011, 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 3, 2015, gross OPA-related environmental costs are estimated to be $11.0 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.

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 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.

123

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies (Continued)

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 the Company, seeking an assessment of civil penalties under the 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. The declaratory judgment, which was affirmed in June 2014 by the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit), addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko will follow a bench trial, which began in January 2015.
In July 2014, Anadarko filed a motion for rehearing with the Fifth Circuit requesting that the full court sit to reconsider Anadarko’s appeal concerning that portion of the February 2012 declaratory judgment which found Anadarko liable for civil penalties under the CWA. In September 2014, Anadarko filed a letter notifying the Fifth Circuit that the Louisiana District Court issued Findings of Fact and Conclusions of Law in the first phase of the Deepwater Horizon trial (Phase I Findings and Conclusions), which included facts that contradict certain key facts assumed by the Fifth Circuit panel in its June 2014 decision. In January 2015, the Fifth Circuit denied the petition for full court reconsideration with six of the thirteen participating justices filing a dissent.
Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability has been 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 liability arising from the future assessment of a civil penalty against Anadarko is probable. In an effort to resolve this matter, the Company made a settlement offer to the DOJ in July 2014 of $90 million and recorded a contingent liability for this amount at June 30, 2014. The Company subsequently engaged in further discussions regarding settlement, but the parties have not been able to reach agreement on either the amount of, or the terms and conditions governing, a settlement. The Company’s settlement offer of $90 million remains outstanding and the Company remains open to resolving the matter through settlement discussions. The Company believes that $90 million under a settlement scenario is a better estimate of loss at this time than any other amount. Based on the above accounting guidance, the Company’s contingent liability for CWA penalties and fines remains $90 million at December 31, 2014. However, the Company may ultimately incur a liability related to CWA penalties in excess of the current accrued liability.
The actual amount of a CWA penalty is subject to uncertainty, including whether the Company will be able to reach a settlement with the DOJ or will await the Louisiana District Court’s opinion following the bench trial. The CWA sets forth subjective criteria to be considered by the court in assessing the magnitude of any CWA penalty, including the degree of fault of the owner. In the Phase I and II trials (defined below) and again for the penalty phase trial in January 2015, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault may be presented. In addition, in its Phase I Findings and Conclusions, the Louisiana District Court did not allocate any fault to Anadarko. Given the subjective nature of the CWA criteria used to determine penalty assessments and the Louisiana District Court’s prior rulings related to culpability and allocation of fault, the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss if the matter is resolved by the Louisiana District Court following trial. However, given the Company’s lack of direct operational involvement in the event, the Louisiana District Court’s rulings excluding any evidence of Anadarko’s alleged culpability or fault, the Phase I Findings and Conclusions that did not allocate any fault to Anadarko, and the subjective criteria of the CWA, the Company believes that any CWA penalties assessed to it will not materially impact the Company’s financial condition, results of operations, or cash flows.

124

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies (Continued)

Events or factors that could assist the Company in estimating the amount of settlement or potential civil penalty or a range of potential loss related to such penalty include (i) an assessment by the DOJ, (ii) a ruling by a court of competent jurisdiction, or (iii) substantive settlement negotiations between the Company and the DOJ.
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 appealed, or 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. For example, eleven Louisiana Parish District Attorneys appealed that decision to the Fifth Circuit. In February 2014, the Fifth Circuit denied the appeal and upheld the Louisiana District Court’s decision. In October 2014, the United States Supreme Court denied the Parish District Attorneys’ petition to review the case. While that denial ends further appeal of that decision by the eleven Parish District Attorneys, any other party subject to the decision who has not yet appealed, including private parties who opted out of the BP settlement, the states, and other local governments, may do so after obtaining a final judgment on their damages claims. If any further appeal is taken and is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.

Natural Resource Damages  This category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.
The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior (DOI), and the Department of Defense. These governmental departments, along with the five affected states – Alabama, Florida, Louisiana, Mississippi, and Texas – are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning.
The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related state law claims against the Company in the Louisiana District Court. In November 2011, after ruling that only federal law applies, the Louisiana District Court dismissed all the NRD-related state law claims asserted against the Company by the states of Alabama and Louisiana. In April 2013, the states of Texas and Mississippi filed NRD-related state law claims against the Company, which were consolidated in the federal Multidistrict Litigation (MDL) action before the Louisiana District Court discussed below and are stayed until further order of the Louisiana District Court.
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.).

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 States of Alabama, Louisiana, Texas, and Mississippi, and several of their political subdivisions; the DOJ; environmental non-governmental organizations; 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.

125

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies (Continued)

This litigation has been consolidated into a federal 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 settlement agreement to resolve a substantial majority of the 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, other than those who previously appealed unsuccessfully, certain state and local governments 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. Certain Mexican states also have appealed the dismissal of their claims against BP, the Company, and others. 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 first phase of the trial in the MDL (Phase I) commenced in February 2013. The PSC, BP, BP America Production Company (BPAP), BP p.l.c., the United States, state and local governments, Halliburton Energy Services, Inc. (Halliburton), and certain subsidiaries of Transocean Ltd. (Transocean) participated in Phase I. Anadarko was excused from participation in Phase I. The issues tried in Phase I included the cause of the blowout and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. In September 2014, the Louisiana District Court issued its Phase I Findings and Conclusions. The Louisiana District Court found that BP and BPAP, Transocean, and Halliburton, but not Anadarko, are each liable under general maritime law for the blowout, explosion, and oil spill. The court determined that BP’s and BPAP’s conduct was reckless and that both Transocean’s and Halliburton’s conduct was negligent. The Louisiana District Court apportioned 67% of the fault to BP and BPAP, 30% to Transocean, and 3% to Halliburton. No fault was allocated to Anadarko. BP is challenging certain of the Louisiana District Court’s findings.
The second phase of trial (Phase II) began in September 2013 and in November 2013 the parties rested their Phase II cases. The issues tried in Phase II included spill-source control and quantification of the spill for the period from April 20, 2010, until the well was capped. The Company, the PSC, BP, BPAP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean participated in Phase II of the trial. In January 2015, the Louisiana District Court issued its Phase II Findings of Fact and Conclusions of Law. The Louisiana District Court found that, for purposes of calculating the maximum possible civil penalty under the CWA, 3.19 million barrels of oil were discharged into the Gulf of Mexico.
The penalty phase of the trial began in January 2015. Post-trial briefs are due in March and April 2015. The trial included Anadarko, BP, and the United States, and will assess findings and penalties under the CWA. In March 2014, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented during the penalty phase trial.
The State of Alabama previously brought actions against the Company and other parties for claims arising from the Deepwater Horizon event, including claims for penalties and fines under state environmental laws, which were subsequently dismissed by the Louisiana District Court. The Louisiana District Court has selected this case as its test case for valuing the damages sought by states for claims under federal laws arising from the Deepwater Horizon event. Trial is set for November 2015 and the parties are conducting discovery. The Louisiana District Court’s previous rulings apply to Alabama’s claims, including the court’s decision that only federal law, and not state law, applies; its decision allocating fault and liability among BP and BPAP, Transocean, and Halliburton; and its orders precluding evidence of alleged culpability by Anadarko, leaving only damages to be decided. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages.

126

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies (Continued)

Two separate class-action complaints were filed in June and August 2010, in the New York District Court on behalf of purported purchasers of the Company’s stock between June 12, 2009, and June 9, 2010, against Anadarko and certain of its officers. The consolidated action was subsequently transferred to the U.S. District Court for the Southern District of Texas - Houston Division (Texas District Court). The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In March 2014, the parties reached a settlement in this matter, which was approved by the Texas District Court in September 2014. The settlement was directly funded by the Company’s insurers.

Remaining Liability Outlook  It is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties 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 financial condition, 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 and BP’s creditworthiness.
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.
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 additional evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings.

Deepwater Horizon and Tronox Derivative Claims  In May 2013, an Anadarko shareholder filed a derivative action in the 215th District Court of Harris County, Texas (215th District Court) against Anadarko and certain current and former directors and officers (DWH Derivative Action). The shareholder purported to bring claims on behalf of Anadarko and alleged, among other things, that certain current and former directors and officers breached their fiduciary duty in connection with the Company’s investment in the Macondo lease.
In addition, in April 2014, the Company’s Board of Directors received a letter from a current shareholder demanding that the Board undertake an independent investigation of certain current and former officers and directors for alleged breach of fiduciary duty related to the Company’s April 2014 settlement of the Tronox Adversary Proceeding (Tronox Derivative Demand).
In May 2014, the parties reached an agreement to jointly resolve the DWH Derivative Action and the Tronox Derivative Demand in one settlement. In order to achieve the joint settlement, the petition in the DWH Derivative Action was amended to include the allegations asserted in the Tronox Derivative Demand. In August 2014, the 215th District Court approved the settlement. The settlement did not have a material impact on the Company’s financial condition, results of operations, or cash flows.

127

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

17. Contingencies (Continued)

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, $128 million, the amount of tax originally 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, 2014.
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. In August 2013, following a determination by an administrative court in a related matter that the amount of tax in dispute was not calculated properly, the Company filed a petition requesting the withdrawal of a portion of the judicial deposit to the extent it exceeds $42 million, the amount of tax currently in dispute, and any interest on such amount.
The Company believes that it will more likely than not prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at December 31, 2014. The Company continues to vigorously defend its position in Brazilian courts.

Guarantees and Indemnifications  The Company provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation, or tax matters existing at the date of disposition. In 2013, as a result of a Chapter 11 bankruptcy declaration by a third party, the DOI ordered Anadarko to perform the decommissioning of a production facility and related wells, which were previously sold to the third party. During 2013, the Company accrued costs of $117 million to decommission the production facility and related wells, reported in other (income) expense, net in the Consolidated Statement of Income. During 2014, the Company recognized a $22 million increase in the estimated decommissioning costs. Anadarko completed decommissioning of the production facility in 2014 and expects to complete decommissioning of the wells in 2015. Decommissioning obligations of $114 million were included in accrued expenses on the Consolidated Balance Sheet at December 31, 2014. Actual costs may vary from this estimate; however, the Company does not believe that any such change will materially impact its financial condition, results of operations, or cash flows.

Environmental Matters  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 for remediation and reclamation obligations of $126 million at December 31, 2014 and December 31, 2013. The current portion of these amounts was included in accounts payable and the long-term portion of these amounts was included in other long-term liabilitiesother on the Company’s Consolidated Balance Sheets. The Company continually monitors remediation and reclamation processes and adjusts its liability for these obligations as necessary.
The Company is one of numerous parties previously notified by the California Department of Toxic Substances Control (DTSC) that, as a result of a prior acquisition, it is a potentially responsible party with respect to a landfill located in West Covina, California. While no agreement is in place with the DTSC, the Company recorded a $50 million restoration liability in 2013 with respect to the site, representing the current estimated obligation, which is included in the Company’s liability balance at December 31, 2014. The Company could incur additional obligations if any of the potentially responsible parties are ultimately not able to fund their allocated share of the costs or if the DTSC requires a more costly remedial approach. It is possible that the Company’s current estimate of probable loss related to this matter could change, perhaps materially, in the future.


128

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

18. Income Taxes

The following summarizes components of income tax expense (benefit) for the years ended December 31:
millions
2014
 
2013
 
2012
Current
 
 
 
 
 
Federal
$
188

 
$
113

 
$
45

State
2

 
42

 
25

Foreign
1,574

 
873

 
891

 
1,764

 
1,028

 
961

Deferred
 
 
 
 
 
Federal
(389
)
 
94

 
(30
)
State
27

 
(9
)
 
115

Foreign
215

 
52

 
74

 
(147
)
 
137

 
159

Total income tax expense (benefit)
$
1,617

 
$
1,165

 
$
1,120


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 following summarizes the sources of these differences for the years ended December 31:
millions except percentages
2014
 
2013
 
2012
Income (loss) before income taxes
 
 
 
 
 
Domestic
$
(3,564
)
 
$
428

 
$
132

Foreign
3,618

 
1,678

 
3,433

Total
$
54

 
$
2,106

 
$
3,565

U.S. federal statutory tax rate
35
%
 
35
%
 
35
%
Tax computed at the U.S. federal statutory rate
$
19

 
$
737

 
$
1,248

Adjustments resulting from
 
 
 
 
 
State income taxes (net of federal income tax benefit)
(11
)
 
23

 
93

Tax impact from foreign operations
62

 
204

 
215

Non-deductible Algerian exceptional profits tax
193

 
144

 
188

Non-taxable Algeria exceptional profits tax settlement

 
13

 
(679
)
Net changes in uncertain tax positions
1,427

 
(29
)
 
28

Deferred tax adjustments
15

 
76

 
22

Non-deductible Tronox-related contingent loss
(36
)
 
36

 

Income attributable to noncontrolling interests
(66
)
 
(48
)
 
(24
)
Non-deductible Deepwater Horizon settlement
32

 

 

Federal manufacturing deduction
(27
)
 

 

Non-deductible goodwill
21

 

 
15

Other—net
(12
)
 
9

 
14

Total income tax expense (benefit)
$
1,617

 
$
1,165

 
$
1,120

Effective tax rate
2,994
%
 
55
%
 
31
%

129

Table of Contents
Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

18. Income Taxes (Continued)

The following summarizes components of total deferred taxes at December 31:
millions
2014
 
2013
Federal
$
(7,649
)
 
$
(8,246
)
State, net of federal
(341
)
 
(332
)
Foreign
(537
)
 
(307
)
Total deferred taxes
$
(8,527
)
 
$
(8,885
)

The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31:
millions
2014
 
2013
Current deferred tax assets
$
210

 
$
412

Settlement agreement related to the Tronox Adversary Proceeding
590

 

Valuation allowances on deferred tax assets not expected to be realized
(78
)
 
(52
)
Net current deferred tax assets
722

 
360

Oil and gas exploration and development operations
(8,418
)
 
(8,213
)
Mineral operations
(412
)
 
(410
)
Midstream and other depreciable properties
(1,611
)
 
(1,586
)
Other
(351
)
 
(499
)
Gross long-term deferred tax liabilities
(10,792
)
 
(10,708
)
Oil and gas exploration and development costs
177

 
94

Net operating loss carryforward
558

 
599

Foreign tax credit carryforward and alternative minimum tax credit carryforward
166

 
325

Other
1,428

 
1,211

Gross long-term deferred tax assets
2,329

 
2,229

Valuation allowances on deferred tax assets not expected to be realized
(786
)
 
(766
)
Net long-term deferred tax assets
1,543

 
1,463

Net long-term deferred tax liabilities
(9,249
)
 
(9,245
)
Total deferred taxes
$
(8,527
)
 
$
(8,885
)

Changes to valuation allowances, due to changes in judgment regarding the future realizability of deferred tax assets, were an increase of $2 million in 2013 and $23 million in 2012. There were no changes to valuation allowances due to changes in judgment regarding the future realizability of deferred tax assets in 2014.
The following summarizes changes in the balance of valuation allowances on deferred tax assets:
millions
2014
 
2013
 
2012
Balance at January 1
$
(818
)
 
$
(922
)
 
$
(555
)
Additions
(59
)
 
(38
)
 
(426
)
Reductions
13

 
142

 
59

Balance at December 31
$
(864
)
 
$
(818
)
 
$
(922
)

130

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

18. Income Taxes (Continued)

The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31:
Balance Sheet Classification
 
2014
 
2013
Income taxes receivable
 
 
 
 
Accounts receivable—other
 
$
93

 
$
66

Other assets
 
35

 
35

 
 
128

 
101

Income taxes (payable)
 
 
 
 
Accrued expense
 
(152
)
 
(82
)
Total net income taxes receivable (payable)
 
$
(24
)
 
$
19


Tax carryforwards available for use on future income tax returns at December 31, 2014, were as follows:
millions
Domestic
 
Foreign
 
Expiration
Net operating loss—foreign
$

 
$
1,165

 
2015 - Indefinite
Net operating loss—state
$
4,477

 
$

 
2015-2034
Foreign tax credits
$
167

 
$

 
2022-2023
Texas margins tax credit
$
34

 
$

 
2026

Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:
 
Assets (Liabilities)
millions
2014
 
2013
 
2012
Balance at January 1
$
(147
)
 
$
(46
)
 
$
(31
)
Increases related to prior-year tax positions
(11
)
 
(54
)
 
(17
)
Decreases related to prior-year tax positions
39

 
3

 
3

Increases related to current-year tax positions
(1,568
)
 
(72
)
 
(1
)
Settlements

 
5

 

Lapse of statute of limitations

 
17

 

Balance at December 31
$
(1,687
)
 
$
(147
)
 
$
(46
)

Included in the 2014 ending balance of unrecognized tax benefits presented above are potential benefits of $1.679 billion, of which, if recognized, $1.456 billion would affect the effective tax rate on income, and $188 million would be in the form of tax credits and net operating loss carryforwards that would attract a full valuation allowance. Also included in the 2014 ending balance are benefits of $8 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain.

131

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

18. Income Taxes (Continued)

In 2013, the Company recognized a deferred tax benefit of $274 million related to the $850 million loss for the Tronox-related contingent liability. In 2014, the Company recognized a deferred tax benefit of $316 million related to the additional $4.360 billion loss for the Tronox-related contingent liability. The total deferred tax benefit of $590 million is net of a $1.326 billion uncertain tax position due to the uncertainty related to the deductibility of the settlement payment. This uncertain tax position is presented in deferred income taxes and as a reduction to the associated deferred tax asset. The Company is a participant in the U.S. Internal Revenue Service’s (IRS) Compliance Assurance Process and has regular discussions with the IRS concerning the Company’s tax positions. Depending on the outcome of such discussions, it is reasonably possible that the amount of the uncertain tax position related to the settlement could change, perhaps materially. See Note 17—Contingencies—Tronox Litigation.
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. The Company estimates that $120 million to $130 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. 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 condition, results of operations, or cash flows.
The Company had accrued approximately $9 million of interest related to uncertain tax positions at December 31, 2014, and $8 million at December 31, 2013. The Company recognized interest and penalties in income tax expense (benefit) of $1 million during 2014 and $(20) million during 2013.
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 IRS for the tax years 2008 through 2014.
The following lists the tax years subject to examination by major tax jurisdiction:
 
Tax Years
United States
2008-2014
Algeria
2011-2014
Ghana
2006-2014

132

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

19. Supplemental Cash Flow Information

The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities for the years ended December 31:
millions
2014
 
2013
 
2012
Cash paid (received)
 
 
 
 
 
Interest, net of amounts capitalized
$
689

 
$
627

 
$
684

Income taxes, net of refunds
956

 
169

 
(300
)
Non-cash investing activities
 
 
 
 
 
Fair value of properties and equipment from non-cash transactions
$
18

 
$
62

 
$
65

Asset retirement cost additions
348

 
297

 
142

Accruals of property, plant, and equipment
1,156

 
1,446

 
1,205

Net liabilities assumed or divested in acquisitions and divestitures
(92
)
 
(80
)
 
(34
)
Non-cash investing and financing activities
 
 
 
 
 
Capital lease obligation
$
13

 
$
8

 
$

Floating production, storage, and offloading vessel construction
  period obligation
149

 
17

 


20. 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, oil, condensate, and NGLs, and plans for the development and operation of the Company’s LNG project in Mozambique. 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, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells much of Anadarko’s oil, natural-gas, and NGLs production, as well as third-party purchased volumes.

133

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

20. 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; exploration expense; DD&A; impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX 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. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
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 for the years ended December 31:
millions
2014
 
2013
 
2012
Income (loss) before income taxes
$
54

 
$
2,106

 
$
3,565

Exploration expense
1,639

 
1,329

 
1,946

DD&A
4,550

 
3,927

 
3,964

Impairments
836

 
794

 
389

Interest expense
772

 
686

 
742

Total (gains) losses on derivatives, net, less net cash from
  settlement of commodity derivatives
578

 
(307
)
 
443

Deepwater Horizon settlement and related costs
97

 
15

 
18

Algeria exceptional profits tax settlement

 
33

 
(1,797
)
Tronox-related contingent loss
4,360

 
850

 
(250
)
Certain other nonoperating items
22

 
110

 

Less net income attributable to noncontrolling interests
187

 
140

 
54

Consolidated Adjusted EBITDAX
$
12,721

 
$
9,403

 
$
8,966


134

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

20. 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 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 corporate costs, results from hard-minerals royalties, and net cash from settlement of commodity derivatives. The following summarizes selected financial information for Anadarko’s reporting segments:
millions
Oil and Gas
Exploration
& Production
 
Midstream
 
Marketing
 
Other and
Intersegment
Eliminations
 
Total
2014
 
 
 
 
 
 
 
 
 
Sales revenues
$
8,603

 
$
484

 
$
7,288

 
$

 
$
16,375

Intersegment revenues
6,225

 
1,338

 
(6,771
)
 
(792
)
 

Gains (losses) on divestitures and other, net
1,893

 
(3
)
 

 
205

 
2,095

Total revenues and other
16,721

 
1,819

 
517

 
(587
)
 
18,470

Operating costs and expenses (1)
4,216

 
972

 
740

 
17

 
5,945

Net cash from settlement of
  commodity derivatives

 

 

 
(377
)
 
(377
)
Other (income) expense, net (2)

 

 

 
(2
)
 
(2
)
Net income attributable to noncontrolling
  interests

 
187

 

 

 
187

Total expenses and other
4,216

 
1,159

 
740

 
(362
)
 
5,753

Total (gains) losses on derivatives, net
  included in marketing revenue, less net
  cash from settlement

 

 
4

 

 
4

Adjusted EBITDAX
$
12,505

 
$
660

 
$
(219
)
 
$
(225
)
 
$
12,721

Net properties and equipment
$
32,717

 
$
6,697

 
$

 
$
2,175

 
$
41,589

Capital expenditures
$
7,934

 
$
1,149

 
$

 
$
173

 
$
9,256

Goodwill
$
5,123

 
$
453

 
$

 
$

 
$
5,576

__________________________________________________________________
(1) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.
(2) 
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

20. Segment Information (Continued)
millions
Oil and Gas
Exploration
& Production
 
Midstream
 
Marketing
 
Other and
Intersegment
Eliminations
 
Total
2013
 
 
 
 
 
 
 
 
 
Sales revenues
$
7,090

 
$
387

 
$
7,390

 
$

 
$
14,867

Intersegment revenues
6,405

 
1,105

 
(6,859
)
 
(651
)
 

Gains (losses) on divestitures and other, net
(622
)
 
(1
)
 

 
337

 
(286
)
Total revenues and other
12,873

 
1,491

 
531

 
(314
)
 
14,581

Operating costs and expenses (1)
3,635

 
843

 
652

 
20

 
5,150

Net cash from settlement of
  commodity derivatives

 

 

 
(95
)
 
(95
)
Other (income) expense, net (2)

 

 

 
(21
)
 
(21
)
Net income attributable to noncontrolling
  interests

 
140

 

 

 
140

Total expenses and other
3,635

 
983

 
652

 
(96
)
 
5,174

Total (gains) losses on derivatives, net
  included in marketing revenue, less net
  cash from settlement

 

 
(4
)
 

 
(4
)
Adjusted EBITDAX
$
9,238

 
$
508

 
$
(125
)
 
$
(218
)
 
$
9,403

Net properties and equipment
$
33,409

 
$
5,408

 
$
9

 
$
2,103

 
$
40,929

Capital expenditures
$
7,008

 
$
1,248

 
$

 
$
267

 
$
8,523

Goodwill
$
5,317

 
$
175

 
$

 
$

 
$
5,492

2012
 
 
 
 
 
 
 
 
 
Sales revenues
$
6,752

 
$
325

 
$
6,230

 
$

 
$
13,307

Intersegment revenues
5,318

 
959

 
(5,734
)
 
(543
)
 

Gains (losses) on divestitures and other, net
(65
)
 
(8
)
 

 
177

 
104

Total revenues and other
12,005

 
1,276

 
496

 
(366
)
 
13,411

Operating costs and expenses (1)
3,505

 
748

 
616

 
295

 
5,164

Net cash from settlement of
  commodity derivatives

 

 

 
(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

Total (gains) losses on derivatives, net
  included in marketing revenue, less net
  cash from settlement

 

 
16

 

 
16

Adjusted EBITDAX
$
8,500

 
$
474

 
$
(104
)
 
$
96

 
$
8,966

Net properties and equipment
$
32,024

 
$
4,459

 
$
9

 
$
1,906

 
$
38,398

Capital expenditures
$
5,906

 
$
1,250

 
$

 
$
155

 
$
7,311

Goodwill
$
5,317

 
$
175

 
$

 
$

 
$
5,492

__________________________________________________________________
(1) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.
(2) 
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

136

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

20. 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
2014
 
2013
 
2012
Sales Revenues
 
 
 
 
 
United States
$
13,083

 
$
11,290

 
$
9,911

Algeria
2,435

 
2,184

 
2,182

Other International
857

 
1,393

 
1,214

Total sales revenues
$
16,375

 
$
14,867

 
$
13,307


 
December 31,
millions
2014
 
2013
Net Properties and Equipment
 
 
 
United States
$
37,186

 
$
35,486

Algeria
1,431

 
1,582

Other International
2,972

 
3,861

Total net properties and equipment
$
41,589

 
$
40,929


Major Customers  In 2014, there were no sales to individual customers that exceeded 10% of the Company’s total sales revenues. Sales to Total S.A. were $2.0 billion in 2013 and $1.9 billion in 2012. These amounts are included in the oil and gas exploration and production reporting segment.

21. 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.
While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2014, the Company monitors the status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. During 2014, the Company made contributions of $106 million to its funded pension plans, $15 million to its unfunded pension plans, and $15 million to its unfunded other postretirement benefit plans. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. The Company expects to contribute $5 million to its funded pension plans, $24 million to its unfunded pension plans, and $16 million to its unfunded other postretirement benefit plans in 2015.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

21. 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, 2014 and 2013, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2014 and 2013:
 
Pension Benefits
 
Other Benefits
millions
2014
 
2013
 
2014
 
2013
Change in benefit obligation
 
 
 
 
 
 
 
Benefit obligation at beginning of year
$
2,158

 
$
2,297

 
$
294

 
$
359

Service cost
99

 
85

 
7

 
9

Interest cost
99

 
78

 
15

 
14

Actuarial (gain) loss
337

 
(156
)
 
72

 
(74
)
Participant contributions
1

 

 
4

 
4

Benefit payments
(159
)
 
(149
)
 
(19
)
 
(18
)
Foreign-currency exchange-rate changes
(7
)
 
3

 

 

Benefit obligation at end of year (1)
$
2,528

 
$
2,158

 
$
373

 
$
294

Change in plan assets
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
$
1,754

 
$
1,462

 
$

 
$

Actual return on plan assets
111

 
278

 

 

Employer contributions
121

 
160

 
15

 
14

Participant contributions
1

 

 
4

 
4

Benefit payments
(159
)
 
(149
)
 
(19
)
 
(18
)
Foreign-currency exchange-rate changes
(10
)
 
3

 

 

Fair value of plan assets at end of year
$
1,818

 
$
1,754

 
$

 
$

 
 
 
 
 
 
 
 
Funded status of the plans at end of year
$
(710
)
 
$
(404
)
 
$
(373
)
 
$
(294
)
Total recognized amounts in the balance sheet consist of
 
 
 
 
 
 
 
Other assets
$
41

 
$
37

 
$

 
$

Accrued expenses
(24
)
 
(19
)
 
(15
)
 
(15
)
Other long-term liabilities—other
(727
)
 
(422
)
 
(358
)
 
(279
)
Total
$
(710
)
 
$
(404
)
 
$
(373
)
 
$
(294
)
Total recognized amounts in accumulated other
   comprehensive income consist of
 
 
 
 
 
 
 
Prior service cost (credit)
$
(1
)
 
$
(1
)
 
$
2

 
$
2

Net actuarial (gain) loss
740

 
441

 
1

 
(78
)
Total
$
739

 
$
440

 
$
3

 
$
(76
)
__________________________________________________________________
(1) 
The accumulated benefit obligation for all defined-benefit pension plans was $2.1 billion at December 31, 2014, and $1.8 billion at December 31, 2013.

138

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

21. 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:
millions
2014
 
2013
Projected benefit obligation
$
2,403

 
$
2,047

Accumulated benefit obligation
2,024

 
1,742

Fair value of plan assets
1,652

 
1,606


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
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Components of net periodic benefit cost
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
99

 
$
85

 
$
76

 
$
7

 
$
9

 
$
9

Interest cost
99

 
78

 
85

 
15

 
14

 
16

Expected return on plan assets
(106
)
 
(91
)
 
(91
)
 

 

 

Amortization of net actuarial loss (gain)
34

 
118

 
93

 
(7
)
 

 

Amortization of net prior service cost (credit)

 

 

 

 
1

 
2

Settlement loss

 
14

 

 

 

 

Net periodic benefit cost
$
126

 
$
204

 
$
163

 
$
15

 
$
24

 
$
27

Amounts recognized in other comprehensive
  income (expense)
 
 
 
 
 
 
 
 
 
 
 
Net actuarial gain (loss)
$
(333
)
 
$
342

 
$
(156
)
 
$
(72
)
 
$
74

 
$
1

Amortization of net actuarial (gain) loss
34

 
118

 
93

 
(7
)
 

 

Amortization of net prior service cost (credit)

 

 

 

 
1

 
2

Settlement loss

 
14

 

 

 

 

Total amounts recognized in other
  comprehensive income (expense)
$
(299
)
 
$
474

 
$
(63
)
 
$
(79
)
 
$
75

 
$
3


In 2015, an estimated $49 million of net actuarial loss for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost.
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
 
2014
 
2013
 
2014
 
2013
Discount rate
4.00
%
 
4.75
%
 
4.25
%
 
5.25
%
Rates of increase in compensation levels
5.25
%
 
5.00
%
 
5.25
%
 
5.25
%

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

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

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. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. 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
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Discount rate
4.75
%
 
3.50
%
 
4.50
%
 
5.25
%
 
4.00
%
 
4.75
%
Long-term rate of return on plan assets
6.75
%
 
7.00
%
 
7.00
%
 
N/A

 
N/A

 
N/A

Rates of increase in compensation levels
5.00
%
 
4.50
%
 
4.50
%
 
5.25
%
 
4.50
%
 
4.50
%

At December 31, 2014 and December 31, 2013, an 8.00% annual rate of increase in the per-capita cost of covered health care benefits for the next year was assumed for purposes of measuring other postretirement benefit obligations. This rate is expected to gradually decrease to 5.00% in 2020 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
$
40

 
$
(33
)

140

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

21. 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 equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 45%-55% equity securities, 20%-30% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines.
Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ collective fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2014 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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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

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

The fair value of the Company’s pension plan assets by asset class and input level within the fair-value hierarchy were as follows:
millions
 
 
 
 
 
 
 
December 31, 2014
Level 1
 
Level 2
 
Level 3
 
Total
Investments
 
 
 
 
 
 
 
Cash and cash equivalents
$
3

 
$
53

 
$

 
$
56

Fixed income
 
 
 
 
 
 
 
Mortgage-backed securities

 
51

 

 
51

U.S. government securities

 
56

 

 
56

Other fixed-income securities (1)
48

 
212

 

 
260

Equity securities
 
 
 
 
 
 
 
Domestic
446

 
130

 

 
576

International
124

 
299

 

 
423

Other
 
 
 
 
 
 
 
Real estate

 
56

 
94

 
150

Private equity

 

 
84

 
84

Hedge funds and other alternative strategies
9

 

 
126

 
135

Other
$

 
$
30

 
$

 
$
30

Total investments (2)
$
630

 
$
887

 
$
304

 
$
1,821

Liabilities
 
 
 
 
 
 
 
Hedge funds and other alternative strategies
$
(3
)
 
$

 
$

 
$
(3
)
Total liabilities
$
(3
)
 
$

 
$

 
$
(3
)
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
Investments
 
 
 
 
 
 
 
Cash and cash equivalents
$
17

 
$
80

 
$

 
$
97

Fixed income
 
 
 
 
 
 
 
Mortgage-backed securities

 
54

 

 
54

U.S. government securities

 
52

 

 
52

Other fixed-income securities (1)
42

 
197

 

 
239

Equity securities
 
 
 
 
 
 
 
Domestic
445

 
116

 

 
561

International
148

 
303

 

 
451

Other
 
 
 
 
 
 
 
Real estate

 
47

 
86

 
133

Private equity

 

 
72

 
72

Hedge funds and other alternative strategies
31

 

 
79

 
110

Total investments (2)
$
683

 
$
849

 
$
237

 
$
1,769

Liabilities
 
 
 
 
 
 
 
Hedge funds and other alternative strategies
$
(17
)
 
$

 
$

 
$
(17
)
Total liabilities
$
(17
)
 
$

 
$

 
$
(17
)
__________________________________________________________________
(1) 
Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities.
(2) 
Amount excludes receivables and payables, primarily related to Level 1 investments.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

21. 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, 2013
$
77

 
$
64

 
$
78

 
$
219

Acquisitions (dispositions), net
(6
)
 

 
2

 
(4
)
Actual return on plan assets
 
 
 
 
 
 
 
Relating to assets sold during the reporting period
1

 
4

 

 
5

Relating to assets still held at the reporting date
7

 
4

 
6

 
17

Balance at December 31, 2013
$
79

 
$
72

 
$
86

 
$
237

Acquisitions (dispositions), net
42

 

 
2

 
44

Actual return on plan assets
 
 
 
 
 
 
 
Relating to assets sold during the reporting period
2

 
5

 

 
7

Relating to assets still held at the reporting date
3

 
7

 
6

 
16

Balance at December 31, 2014
$
126

 
$
84

 
$
94

 
$
304


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 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 values, delinquencies or defaults, or both, and may be adversely affected by shifts in the market’s perception of the issuers and changes in interest rates.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

21. 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
2015
$
162

 
$
16

2016
175

 
17

2017
199

 
18

2018
194

 
18

2019
216

 
19

2020-2024
1,192

 
109


Defined-Contribution Plans  The Company maintains several defined-contribution benefit plans, the most significant of which is 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 $76 million for 2014, $78 million for 2013, and $55 million for 2012, related to these plans.


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Index to Financial Statements
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 2014, 2013, and 2012 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 and Ghana. The Company sold its Chinese subsidiary during 2014.

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 natural-gas liquids (NGLs) owned at each year end and changes in proved reserves during each of the last three years. Natural-gas volumes are presented in billions of 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, commodity prices, economic conditions, and governmental restrictions.
Prices used to compute the information presented in the following tables are adjusted only for fixed and determinable amounts under provisions in existing contracts. These prices, before adjustments, were $4.35, $3.67, and $2.76 per MMBtu of natural gas and $94.99, $96.78, and $94.71 per barrel of oil for 2014, 2013, and 2012. The benchmark price for NGLs used in the computation, previously the same as that for oil, was converted to a NGLs-specific price of $45.25 per barrel in 2014.
 

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

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

Revisions of prior estimates
1,276

 

 
1,276

 
96

 
21

 
117

Extensions, discoveries, and
other additions
416

 

 
416

 
52

 
14

 
66

Purchases in place
153

 

 
153

 
1

 

 
1

Sales in place
(4
)
 

 
(4
)
 
(10
)
 

 
(10
)
Production
(965
)
 

 
(965
)
 
(58
)
 
(32
)
 
(90
)
December 31, 2013
9,205

 

 
9,205

 
592

 
259

 
851

Revisions of prior estimates
710

 
31

 
741

 
167

 
18

 
185

Extensions, discoveries, and
other additions
196

 

 
196

 
25

 

 
25

Purchases in place

 

 

 

 

 

Sales in place
(492
)
 

 
(492
)
 
(6
)
 
(17
)
 
(23
)
Production
(951
)
 

 
(951
)
 
(74
)
 
(35
)
 
(109
)
December 31, 2014
8,668

 
31

 
8,699

 
704

 
225

 
929

Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
6,113

 

 
6,113

 
352

 
173

 
525

December 31, 2012
6,445

 

 
6,445

 
318

 
208

 
526

December 31, 2013
7,120

 

 
7,120

 
347

 
202

 
549

December 31, 2014
6,635

 
27

 
6,662

 
352

 
190

 
542

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
2,252

 

 
2,252

 
184

 
62

 
246

December 31, 2012
1,884

 

 
1,884

 
193

 
48

 
241

December 31, 2013
2,085

 

 
2,085

 
245

 
57

 
302

December 31, 2014
2,033

 
4

 
2,037

 
352

 
35

 
387

 

146

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Oil and Gas Reserves (Continued)
 
NGLs
(MMBbls)
 
Total
(MMBOE)
 
United States
 
International
 
Total
 
United States
 
International
 
Total
Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
361

 
13

 
374

 
2,291

 
248

 
2,539

Revisions of prior estimates (1)
65

 
(1
)
 
64

 
233

 
51

 
284

Extensions, discoveries, and
other additions
3

 

 
3

 
82

 

 
82

Purchases in place

 

 

 
4

 

 
4

Sales in place
(6
)
 

 
(6
)
 
(81
)
 

 
(81
)
Production
(30
)
 

 
(30
)
 
(237
)
 
(31
)
 
(268
)
December 31, 2012
393

 
12

 
405

 
2,292

 
268

 
2,560

Revisions of prior estimates (1)
17

 

 
17

 
326

 
21

 
347

Extensions, discoveries, and
other additions
10

 

 
10

 
131

 
14

 
145

Purchases in place
9

 

 
9

 
36

 

 
36

Sales in place
(1
)
 

 
(1
)
 
(12
)
 

 
(12
)
Production
(33
)
 

 
(33
)
 
(252
)
 
(32
)
 
(284
)
December 31, 2013
395

 
12

 
407

 
2,521

 
271

 
2,792

Revisions of prior estimates (1)
129

 
2

 
131

 
414

 
25

 
439

Extensions, discoveries, and
other additions
5

 

 
5

 
63

 

 
63

Purchases in place

 

 

 

 

 

Sales in place
(19
)
 

 
(19
)
 
(107
)
 
(17
)
 
(124
)
Production
(44
)
 
(1
)
 
(45
)
 
(276
)
 
(36
)
 
(312
)
December 31, 2014
466

 
13

 
479

 
2,615

 
243

 
2,858

Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
267

 

 
267

 
1,638

 
173

 
1,811

December 31, 2012
283

 

 
283

 
1,675

 
208

 
1,883

December 31, 2013
268

 

 
268

 
1,801

 
202

 
2,003

December 31, 2014
304

 
13

 
317

 
1,762

 
207

 
1,969

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
94

 
13

 
107

 
653

 
75

 
728

December 31, 2012
110

 
12

 
122

 
617

 
60

 
677

December 31, 2013
127

 
12

 
139

 
720

 
69

 
789

December 31, 2014
162

 

 
162

 
853

 
36

 
889

__________________________________________________________________
(1) 
Revisions of prior estimates include additions generated by Anadarko’s infill drilling programs of 577 MMBOE for 2014, 410 MMBOE for 2013, and 383 MMBOE for 2012.

147

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

In 2014, Anadarko added 63 MMBOE of proved reserves through extensions and discoveries primarily as a result of successful drilling in the Marcellus and Wolfcamp shale plays. Although shale plays represented only about 17% of the Company’s total proved reserves at December 31, 2014, growth in the shale plays contributed 49 MMBOE, or 78%, of the total extensions and discoveries. Total revisions include the effects of new infill drilling, changes in commodity prices and other updates reflecting changes in economic conditions, changes in reservoir performance, and changes to development plans. Total revisions in 2014 resulted in an increase of 439 MMBOE, or 16%, of the beginning-of-year reserves base. These revisions are primarily associated with a 577 MMBOE increase related to successful infill drilling in large onshore areas such as the Wattenberg area and the Eagleford and Haynesville shales. Partially offsetting these positive infill revisions was a net decrease of 138 MMBOE, primarily associated with the optimization of horizontal drilling locations and the discontinuation of vertical well workover plans in the Wattenberg area. In 2014, the Company sold properties or interests in properties containing 69 MMBOE of proved developed reserves and 55 MMBOE of proved undeveloped reserves. Sales included the divestiture of the Company’s interest in the Pinedale/Jonah assets in Wyoming, the Company’s Chinese subsidiary, and a portion of the Company’s working interest in the East Texas Chalk area.
In 2013, Anadarko added 145 MMBOE of proved reserves through extensions and discoveries as the result of successful drilling primarily in the Marcellus shale and the Gulf of Mexico. Although shale plays represented only about 13% of the Company’s total proved reserves at December 31, 2013, growth in the shale plays contributed 70 MMBOE, or 48%, of the total extensions and discoveries. Total revisions in 2013 resulted in an increase of 347 MMBOE, or 14%, of the beginning-of-year reserves base. Total 2013 revisions included an increase of 410 MMBOE related to successful infill drilling, primarily in large onshore areas such as Wattenberg, Greater Natural Buttes, and the Eagleford shale, and 30 MMBOE resulting from improved oil and natural-gas prices. Partially offsetting these positive revisions were decreases of 53 MMBbls of NGLs reserves due to lower ethane prices and 40 MMBOE due to other non-price-related revisions primarily in the Rocky Mountains Region (Rockies). In 2013, the Company sold U.S. properties or interests in U.S. properties containing 12 MMBOE of proved undeveloped reserves. Sales were almost exclusively associated with a partial sale of a working interest in the Gulf of Mexico Heidelberg development project. Acquisitions of proved reserves were 36 MMBOE, related to domestic assets almost exclusively in the Rockies.
In 2012, Anadarko added 82 MMBOE of proved reserves through extensions and discoveries as the result of successful drilling in the Marcellus shale and the Gulf of Mexico. Shale plays contributed 66 MMBOE of the total extensions and discoveries in 2012. Total revisions in 2012 were 284 MMBOE or 11% of the beginning-of-year reserves base. Total 2012 revisions included an increase of 383 MMBOE related to successful infill drilling, primarily in 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 from all other assets. In 2012, the Company sold U.S. properties or interests in U.S. properties containing 81 MMBOE of proved reserves, including 59 MMBOE of proved developed reserves and 22 MMBOE of proved undeveloped reserves. Sales included a portion of the Company’s 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, the Rockies, and North Louisiana.

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Capitalized Costs

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. Capitalized costs associated with activities of the Company’s midstream and marketing reporting segments, liquefied natural gas (LNG) facilities costs, and other corporate activities are not included.
millions
United States
 
International
 
Total
December 31, 2014
 
 
 
 
 
Capitalized
 
 
 
 
 
Unproved properties
$
3,858

 
$
1,291

 
$
5,149

Proved properties
53,545

 
4,895

 
58,440

 
57,403

 
6,186

 
63,589

Less accumulated DD&A
29,055

 
1,902

 
30,957

Net capitalized costs
$
28,348

 
$
4,284

 
$
32,632

December 31, 2013
 
 
 
 
 
Capitalized
 
 
 
 
 
Unproved properties
$
4,938

 
$
1,970

 
$
6,908

Proved properties
48,631

 
5,540

 
54,171

 
53,569

 
7,510

 
61,079

Less accumulated DD&A
25,560

 
2,333

 
27,893

Net capitalized costs
$
28,009

 
$
5,177

 
$
33,186

 

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

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

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities. Costs associated with activities of the Company’s midstream and marketing reporting segments, LNG facilities costs, and other corporate activities are not included.
millions
United States
 
International
 
Total
Year Ended December 31, 2014
 
 
 
 
 
Property acquisitions
 
 
 
 
 
Unproved
$
264

 
$
19

 
$
283

Proved
3

 

 
3

Exploration
1,095

 
616

 
1,711

Development
6,158

 
557

 
6,715

Total costs incurred
$
7,520

 
$
1,192

 
$
8,712

Year Ended December 31, 2013
 
 
 
 
 
Property acquisitions
 
 
 
 
 
Unproved
$
282

 
$
45

 
$
327

Proved
324

 

 
324

Exploration
1,031

 
939

 
1,970

Development
4,421

 
444

 
4,865

Total costs incurred
$
6,058

 
$
1,428

 
$
7,486

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

 

150

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Results of Operations

Results of operations for producing activities consist of all activities within the oil and gas exploration and production reporting segment. Net revenues from production include only the revenues from the production and sale of natural gas, oil, condensate, and NGLs. Gains (losses) on property dispositions represent net gains or losses on sales of oil and gas properties. Production costs are costs to operate and maintain the Company’s wells, related equipment, and supporting facilities used in oil and gas operations, including the cost of labor, well service and repair, location maintenance, power and fuel, gathering, processing, transportation, other taxes, and production-related general and administrative costs. 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 provided for the transfer of $1.7 billion of oil to the Company over a 12-month period ending in mid-2013. 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, 2014
 
 
 
 
 
Net revenues from production
 
 
 
 
 
Third-party sales
$
7,425

 
$
1,518

 
$
8,943

Sales to consolidated affiliates
4,453

 
1,773

 
6,226

Gains (losses) on property dispositions
(91
)
 
1,982

 
1,891

 
11,787

 
5,273

 
17,060

Production costs
 
 
 
 
 
Oil and gas operating
968

 
203

 
1,171

Oil and gas transportation and other
1,150

 
33

 
1,183

Production-related general and administrative expenses
394

 
32

 
426

Other taxes
652

 
535

 
1,187

 
3,164

 
803

 
3,967

Exploration expenses
1,218

 
421

 
1,639

Depreciation, depletion, and amortization
3,783

 
398

 
4,181

Impairments related to oil and gas properties
821

 

 
821

Deepwater Horizon settlement and related costs
97

 

 
97

 
2,704

 
3,651

 
6,355

Income tax expense
995

 
979

 
1,974

Results of operations
$
1,709

 
$
2,672

 
$
4,381

 

151

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Results of Operations (Continued)
millions
United States
 
International
 
Total
Year Ended December 31, 2013
 
 
 
 
 
Net revenues from production
 
 
 
 
 
Third-party sales
$
6,567

 
$
856

 
$
7,423

Sales to consolidated affiliates
3,685

 
2,720

 
6,405

Gains (losses) on property dispositions
(618
)
 
(3
)
 
(621
)
 
9,634

 
3,573

 
13,207

Production costs
 
 
 
 
 
Oil and gas operating
874

 
218

 
1,092

Oil and gas transportation and other
998

 
22

 
1,020

Production-related general and administrative expenses
332

 
5

 
337

Other taxes
569

 
455

 
1,024

 
2,773

 
700

 
3,473

Exploration expenses
611

 
718

 
1,329

Depreciation, depletion, and amortization
3,222

 
399

 
3,621

Impairments related to oil and gas properties
704

 

 
704

Algeria exceptional profits tax settlement

 
33

 
33

Deepwater Horizon settlement and related costs
15

 

 
15

 
2,309

 
1,723

 
4,032

Income tax expense
845

 
1,005

 
1,850

Results of operations
$
1,464

 
$
718

 
$
2,182

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


152

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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

Estimates of future net cash flows from proved reserves of natural gas, oil, condensate, and NGLs for 2014, 2013, and 2012 are computed based on the average beginning-of-the-month prices 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 $4.35, $3.67, and $2.76 per MMBtu of natural gas and $94.99, $96.78, and $94.71 per barrel of oil, for 2014, 2013, and 2012. The benchmark price for NGLs used in the computation, previously the same as that for oil, was converted to a NGLs-specific price of $45.25 per barrel in 2014. 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.
 

153

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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, 2014
 
 
 
 
 
Future cash inflows
$
114,384

 
$
23,795

 
$
138,179

Future production costs
36,390

 
6,061

 
42,451

Future development costs
14,794

 
1,356

 
16,150

Future income tax expenses
21,813

 
6,968

 
28,781

Future net cash flows
41,387

 
9,410

 
50,797

10% annual discount for estimated timing of cash flows
17,239

 
2,898

 
20,137

Standardized measure of discounted future net cash flows
$
24,148

 
$
6,512

 
$
30,660

December 31, 2013
 
 
 
 
 
Future cash inflows
$
102,765

 
$
28,454

 
$
131,219

Future production costs
33,271

 
6,819

 
40,090

Future development costs
12,285

 
1,501

 
13,786

Future income tax expenses
20,222

 
8,148

 
28,370

Future net cash flows
36,987

 
11,986

 
48,973

10% annual discount for estimated timing of cash flows
15,818

 
4,049

 
19,867

Standardized measure of discounted future net cash flows
$
21,169

 
$
7,937

 
$
29,106

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


154

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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
2014
 
 
 
 
 
Balance at January 1
$
21,169

 
$
7,937

 
$
29,106

Sales and transfers of oil and gas produced, net of production costs
(8,714
)
 
(2,492
)
 
(11,206
)
Net changes in prices and production costs
(4,046
)
 
(1,984
)
 
(6,030
)
Changes in estimated future development costs
(4,180
)
 
(250
)
 
(4,430
)
Extensions, discoveries, additions, and improved recovery, less
   related costs
963

 

 
963

Development costs incurred during the period
2,591

 
279

 
2,870

Revisions of previous quantity estimates
13,703

 
1,921

 
15,624

Purchases of minerals in place

 

 

Sales of minerals in place
(591
)
 
(696
)
 
(1,287
)
Accretion of discount
3,221

 
1,341

 
4,562

Net change in income taxes
(1,294
)
 
549

 
(745
)
Other
1,326

 
(93
)
 
1,233

Balance at December 31
$
24,148

 
$
6,512

 
$
30,660

2013
 
 
 
 
 
Balance at January 1
$
17,538

 
$
8,776

 
$
26,314

Sales and transfers of oil and gas produced, net of production costs
(7,478
)
 
(2,881
)
 
(10,359
)
Net changes in prices and production costs
1,394

 
(1,072
)
 
322

Changes in estimated future development costs
(2,326
)
 
(193
)
 
(2,519
)
Extensions, discoveries, additions, and improved recovery, less
   related costs
2,659

 
(128
)
 
2,531

Development costs incurred during the period
1,076

 
193

 
1,269

Revisions of previous quantity estimates
6,526

 
1,324

 
7,850

Purchases of minerals in place
253

 

 
253

Sales of minerals in place
284

 

 
284

Accretion of discount
2,671

 
1,465

 
4,136

Net change in income taxes
(1,865
)
 
401

 
(1,464
)
Other
437

 
52

 
489

Balance at December 31
$
21,169

 
$
7,937

 
$
29,106

 

155

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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
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


156

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Index to Financial Statements
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)


Quarterly Financial Data

The following summarizes quarterly financial data for 2014 and 2013:
millions except per-share amounts
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2014
 
 
 
 
 
 
 
Sales revenues
$
4,338

 
$
4,385

 
$
4,230

 
$
3,422

Gains (losses) on divestitures and other, net
1,506

 
54

 
780

 
(245
)
Deepwater Horizon settlement and related costs

 
93

 
3

 
1

Operating income (loss)
2,975

 
1,209

 
1,698

 
(479
)
Tronox-related contingent loss
4,300

 
19

 
19

 
22

Net income (loss)
(2,626
)
 
266

 
1,147

 
(350
)
Net income (loss) attributable to noncontrolling interests
43

 
39

 
60

 
45

Net income (loss) attributable to common stockholders
(2,669
)
 
227

 
1,087

 
(395
)
Earnings per share
 
 
 
 
 
 
 
Net income (loss) attributable to common stockholders—basic
$
(5.30
)
 
$
0.45

 
$
2.13

 
$
(0.78
)
Net income (loss) attributable to common stockholders—diluted
$
(5.30
)
 
$
0.45

 
$
2.12

 
$
(0.78
)
Average number common shares outstanding—basic
504

 
505

 
506

 
507

Average number common shares outstanding—diluted
504

 
507

 
508

 
507

 
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
 
Sales revenues
$
3,718

 
$
3,440

 
$
3,789

 
$
3,920

Gains (losses) on divestitures and other, net
175

 
57

 
64

 
(582
)
Algeria exceptional profits tax settlement
33

 

 

 

Deepwater Horizon settlement and related costs
3

 
4

 
5

 
3

Operating income (loss)
1,289

 
1,140

 
689

 
215

Tronox-related contingent loss

 

 

 
850

Net income (loss)
484

 
959

 
223

 
(725
)
Net income attributable to noncontrolling interests
24

 
30

 
41

 
45

Net income (loss) attributable to common stockholders
460

 
929

 
182

 
(770
)
Earnings per share
 
 
 
 
 
 
 
Net income (loss) attributable to common stockholders—basic
$
0.91

 
$
1.84

 
$
0.36

 
$
(1.53
)
Net income (loss) attributable to common stockholders—diluted
$
0.91

 
$
1.83

 
$
0.36

 
$
(1.53
)
Average number common shares outstanding—basic
501

 
502

 
503

 
504

Average number common shares outstanding—diluted
503

 
504

 
505

 
504


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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, as amended. 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, as amended, 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 the Company in reports that it files under the Securities Exchange Act of 1934, as amended, 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, 2014.

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 2014 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Form 10-K.

Item 9B.  Other Information

None.

158

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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—Committees of the Board, Corporate Governance—Board of Directors, 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 12, 2015 (to be filed with the Securities and Exchange Commission prior to April 2, 2015), 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/Responsibility/Good-Governance. 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 2014, Compensation and Benefits Committee Report on 2014 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 and Securities Authorized for Issuance under Equity Compensation Plans under Item 5 of this Form 10-K, which are 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 Accounting Fees and Services

See Independent Auditor in the Proxy Statement, which is incorporated herein by reference.


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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 84.

(2)
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith or double asterisk (**) and are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated.
Exhibit
Number
 
Description
 
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, filed as Exhibit 2.2 to Form 8-K filed on June 26, 2006
 
3
(i)
 
Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009
 
 
(ii)
 
By-Laws of Anadarko Petroleum Corporation, amended and restated as of November 6, 2014, filed as Exhibit 3.1 to Form 8-K filed on November 10, 2014
 
4
(i)
 
Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on September 19, 2006
 
 
(ii)
 
Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A., filed as Exhibit 4.1 to Form 8-K filed on October 6, 2006
 
 
(iii)
 
Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A., filed as Exhibit 4.2 to Form 8-K filed on October 6, 2006
 
 
(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, filed as Exhibit 4.1 to Form 8-K filed on March 6, 2009
 
 
(v)
 
Form of 7.625% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on March 6, 2009
 
 
(vi)
 
Form of 8.700% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on March 6, 2009
 
 
(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, filed as Exhibit 4.1 to Form 8-K filed on June 12, 2009
 
 
(viii)
 
Form of 5.75% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on June 12, 2009
 
 
(ix)
 
Form of 6.95% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on June 12, 2009
 
 
(x)
 
Form of 7.95% Senior Notes due 2039, filed as Exhibit 4.4 to Form 8-K filed on June 12, 2009
 
 
(xi)
 
Officers’ Certificate of Anadarko Petroleum Corporation dated March 9, 2010, establishing the 6.200% Senior Notes due 2040, filed as Exhibit 4.1 to Form 8-K filed on March 16, 2010
 
 
(xii)
 
Form of 6.200% Senior Notes due 2040, filed as Exhibit 4.2 to Form 8-K filed on March 16, 2010
 
 
(xiii)
 
Officers’ Certificate of Anadarko Petroleum Corporation dated August 9, 2010, establishing the 6.375% Senior Notes due 2017, filed as Exhibit 4.1 to Form 8-K filed on August 12, 2010

160

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Index to Financial Statements

Exhibit
Number
 
Description
 
4
(xiv)
 
Form of 6.375% Senior Notes due 2017, filed as Exhibit 4.2 to Form 8-K filed on August 12, 2010
 
 
(xv)
 
Officers’ Certificate of Anadarko Petroleum Corporation dated July 7, 2014, establishing the 3.45% Senior Notes due 2024 and the 4.50% Senior Notes due 2044, filed as Exhibit 4.1 to Form 8-K filed on July 7, 2014
 
 
(xvi)
 
Form of 3.45% Senior Notes due 2024, filed as Exhibit 4.2 to Form 8-K filed on July 7, 2014
 
 
(xvii)
 
Form of 4.50% Senior Notes due 2044, filed as Exhibit 4.3 to Form 8-K filed on July 7, 2014
10
(i)
 
1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998, filed as Appendix A to DEF 14A filed on March 16, 1998
 
(ii)
 
Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 17, 2005
 
(iii)
 
Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan, filed as Appendix A to DEF 14A filed on March 18, 2005
 
(iv)
 
Form of Anadarko Petroleum Corporation Executive 1999 Stock Incentive Plan Stock Option Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 17, 2005
 
(v)
 
Form of Anadarko Petroleum Corporation Non-Executive 1999 Stock Incentive Plan Stock Option Agreement, filed as Exhibit 10.3 to Form 8-K filed on November 17, 2005
 
(vi)
 
Form of Stock Option Agreement—1999 Stock Incentive Plan (UK Nationals), filed as Exhibit 10.4 to Form 8-K filed on November 17, 2005
 
(vii)
 
Amendment to Stock Option Agreement Under the Anadarko Petroleum Corporation 1999 Stock Incentive Plan, filed as Exhibit 10.1 to Form 8-K filed on January 23, 2007
 
(viii)
 
Anadarko Petroleum Corporation 1999 Stock Incentive Plan (Amendment to Performance Unit Agreement), filed as Exhibit 10.3 to Form 8-K filed on November 13, 2007
 
(ix)
 
Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement, filed as Exhibit 10(b)(xxiv) to Form 10-K for year ended December 31, 1999, filed on March 16, 2000
 
(x)
 
Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Unit Award Letter, filed as Exhibit 10.1 to Form 8-K filed on November 13, 2007
 
(xi)
 
The Approved UK Sub-Plan of the Anadarko Petroleum Corporation 1999 Stock Incentive Plan, filed as Exhibit 10(b)(xxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004
 
(xii)
 
Key Employee Change of Control Contract, filed as Exhibit 10(b)(xxii) to Form 10-K for year ended December 31, 1997, filed on March 18, 1998
 
(xiii)
 
First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract, filed as Exhibit 10(b) to Form 10-Q for quarter ended September 30, 2000, filed on November 13, 2000
 
(xiv)
 
Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract, filed as Exhibit 10(b)(ii) to Form 10-Q for quarter ended June 30, 2003, filed on August 11, 2003
 
(xv)
 
Form of Key Employee Change of Control Contract (2011), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2011, filed on July 27, 2011
 
(xvi)
 
Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004—Robert J. Allison, Jr., filed as Exhibit 10(b)(xxxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004
 
(xvii)
 
Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xxii) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010

161

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Index to Financial Statements

Exhibit
Number
 
Description
†*
10
(xviii)
 
First Amendment, dated July 1, 2010, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007)
†*
 
(xix)
 
Second Amendment, dated November 30, 2011, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007)
†*
 
(xx)
 
Third Amendment, dated December 18, 2014, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007)
 
(xxi)
 
Anadarko Retirement Restoration Plan (As Amended and Restated Effective as of November 7, 2007), filed as Exhibit 10.2 to Form 8-K filed on November 13, 2007
†*
 
(xxii)
 
First Amendment, dated November 30, 2011, to the Anadarko Retirement Restoration Plan (As Amended and Restated Effective January 1, 2007)
 
(xxiii)
 
Anadarko Petroleum Corporation Estate Enhancement Program, filed as Exhibit 10(b)(xxxiv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999
 
(xxiv)
 
Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives, filed as Exhibit 10(b)(xxxv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999
 
(xxv)
 
Estate Enhancement Program Agreements effective November 29, 2000, filed as Exhibit 10(b)(xxxxii) to Form 10-K for year ended December 31, 2000, filed on March 15, 2001
 
(xxvi)
 
Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002, filed as Exhibit 10(b)(xxxii) to Form 10-K for year ended December 31, 2002, filed on March 14, 2003
 
(xxvii)
 
First Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective June 30, 2003, filed as Exhibit 10(b)(xliii) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004
 
(xxviii)
 
Second Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective January 1, 2008, filed as Exhibit 10(xxix) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010
 
(xxix)
 
Anadarko Petroleum Corporation Officer Severance Plan, filed as Exhibit 10(b)(iv) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003
 
(xxx)
 
Form of Termination Agreement and Release of All Claims Under Officer Severance Plan, filed as Exhibit 10(b)(v) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003
 
(xxxi)
 
Form of Director and Officer Indemnification Agreement, filed as Exhibit 10 to Form 8-K filed on September 3, 2004
 
 
(xxxii)
 
$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, filed as Exhibit 10.1 to Form 8-K filed on September 8, 2010
 
 
(xxxiii)
 
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, filed as Exhibit 10(i) to Form 10-Q for quarter ended September 30, 2011, filed on October 31, 2011

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Exhibit
Number
 
Description
 
10
(xxxiv)
 
Second Amendment to Revolving Credit Agreement, dated as of March 26, 2014, to the Revolving Credit Agreement dated as of September 2, 2010, as amended on August 3, 2011, 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, filed as Exhibit 10(ii) to Form 10-Q for quarter ended March 31, 2014, filed on May 5, 2014
 
(xxxv)
 
Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, effective as of May 20, 2008, filed as Exhibit 10.1 to Form 8-K filed on May 27, 2008
 
(xxxvi)
 
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Stock Option Award Agreement, filed as Exhibit 10.3 to Form 8-K filed on November 13, 2009
 
(xxxvii)
 
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 13, 2009
 
(xxxviii)
 
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 13, 2009
 
(xxxvix)
 
Anadarko Petroleum Corporation 2008 Director Compensation Plan, effective as of May 20, 2008, filed as Exhibit 10.2 to Form 8-K filed on May 27, 2008
 
(xl)
 
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10.3 to Form 8-K filed on May 27, 2008
 
(xli)
 
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan (2013), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2013, filed on July 29, 2013
 
(xlii)
 
Anadarko Petroleum Corporation Benefits Trust Agreement, amended and restated effective as of November 5, 2008, filed as Exhibit 10(lvi) to Form 10-K for year ended December 31, 2008, filed on February 25, 2009
 
(xliii)
 
Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012), filed as Exhibit 10(i) to Form 10-Q for the quarter ended June 30, 2014, filed on July 29, 2014
 
(xliv)
 
First Amendment, dated December 17, 2013, to the Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012), filed as Exhibit 10(ii) to Form 10-Q for the quarter ended June 30, 2014, filed on July 29, 2014
 
 
(xlv)
 
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, filed as Exhibit 10 to Form 10-Q for quarter ended June 30, 2010, filed on August 3, 2010
 
 
(xlvi)
 
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., filed as Exhibit 10(xlii) to Form 10-K for year ended December 31, 2011, filed on February 21, 2012 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment)
 
(xlvii)
 
Severance Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated February 16, 2012, filed as Exhibit 10.2 to Form 8-K filed on February 21, 2012
 
(xlviii)
 
Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated May 15, 2012, filed as Exhibit 10(ii) to Form 10-Q for quarter ended June 30, 2012, filed on August 8, 2012

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Exhibit
Number
 
Description
10
(xlix)
 
Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, effective as of May 15, 2012, filed as Exhibit 10.1 to Form 8-K filed on May 15, 2012
 
(l)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Stock Option Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on May 15, 2012
 
(li)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.3 to Form 8-K filed on May 15, 2012
 
(lii)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.4 to Form 8-K filed on May 15, 2012
 
(liii)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 9, 2012
 
(liv)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 9, 2012
 
(lv)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement (2014), filed as Exhibit 10.1 to Form 8-K filed on November 10, 2014
 
(lvi)
 
Form of U.K. Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10.5 to Form 8-K filed on May 15, 2012
 
(lvii)
 
Amended and Restated Performance Unit Award Agreement, effective November 5, 2012, for R. A. Walker, filed as Exhibit 10.3 to Form 8-K filed on November 9, 2012
 
 
(lviii)
 
Settlement Agreement dated as of April 3, 2014, by and among (1) the Anadarko Litigation Trust, (2) the United States of America in its capacity as plaintiff-intervenor in the Tronox Adversary Proceeding and acting for and on behalf of certain U.S. government agencies and (3) Anadarko Petroleum Corporation, Kerr-McGee Corporation, and certain other subsidiaries, filed as exhibit 10.1 to Form 8-K filed on April 3, 2014
 
 
(lix)
 
Credit Agreement, dated as of June 17, 2014, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., Citibank, N.A., The Royal Bank of Scotland plc, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on June 23, 2014
 
 
(lx)
 
First Amendment to Credit Agreement, dated November 14, 2014, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on November 19, 2014
 
 
(lxi)
 
364-Day Revolving Credit Agreement, dated as of June 17, 2014, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., Citibank, N.A., The Royal Bank of Scotland plc, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.2 to Form 8-K filed on June 23, 2014
 
 
(lxii)
 
First Amendment to 364-Day Revolving Credit Agreement, dated November 14, 2014, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.2 to Form 8-K filed on November 19, 2014
*
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.

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Index to Financial Statements

Exhibit
Number
 
Description
*
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.

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.


165

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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 20, 2015
By:
 
/s/ ROBERT G. GWIN
 
 
 
Robert G. Gwin
Executive 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 20, 2015.
Name and Signature
  
Title
 
 
(i) Principal executive officer and director:
  
 
 
 
/s/ R. A. WALKER
  
Chairman, President and Chief Executive Officer
R. A. Walker
  
 
 
 
(ii) Principal financial officer:
  
 
/s/ ROBERT G. GWIN
  
Executive Vice President, Finance and Chief Financial Officer
Robert G. Gwin
  
 
 
 
(iii) Principal accounting officer:
  
 
 
 
/s/ M. CATHY DOUGLAS
  
Senior Vice President, Chief Accounting Officer and Controller
M. Cathy Douglas
  
 
 
 
(iv) Directors:*
  
 
ANTHONY R. CHASE
KEVIN P. CHILTON
H. PAULETT EBERHART
PETER J. FLUOR
RICHARD L. GEORGE
CHARLES W. GOODYEAR
JOSEPH W. GORDER
JOHN R. GORDON
MARK C. MCKINLEY
ERIC D. MULLINS
  
 
* Signed on behalf of each of these persons and on his own behalf:

By:
/s/ ROBERT G. GWIN
 
 
Robert G. Gwin, Attorney-in-Fact
 

166