10-K 1 apc201610k-10k.htm 10-K Document

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, 2016
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)
 
(Zip Code)
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
7.50% Tangible Equity Units
 
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.  ý
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, 2016, was $27.3 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 February 3, 2017, is shown below:
Title of Class
  
Number of Shares Outstanding
Common Stock, par value $0.10 per share
  
558,979,551
Documents Incorporated By Reference
Portions of the Definitive Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 10, 2017 (to be filed with the Securities and Exchange Commission prior to March 31, 2017), are incorporated by reference into Part III of this Form 10-K.


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.


COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. In addition, the following company or industry-specific terms and abbreviations are used throughout this report:

364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured revolving credit facility maturing in January 2018
3D - Three-dimensional
$5.0 Billion Facility - Anadarko’s $5.0 billion senior secured revolving credit facility, which was replaced in January 2015 with the Five-Year Facility and a 364-day facility
AROs - Asset retirement obligations
ASU - Accounting Standards Update
Bbl - Barrel
Bcf - Billion cubic feet
Bcf/d - Billion cubic feet per day
BOE - Barrels of oil equivalent
CGF(s) - Central gathering facility(ies)
COSF - Centralized oil stabilization facility
DBJV - Delaware Basin JV Gathering LLC
DBM - Delaware Basin Midstream, LLC
DD&A - Depreciation, depletion, and amortization
EOR - Enhanced oil recovery
EPA - U.S. Environmental Protection Agency
Fitch - Fitch Ratings
Five-Year Facility - Anadarko’s $3.0 billion five-year senior unsecured revolving credit facility maturing in January 2021
FPSO - Floating production, storage, and offloading unit
G&A - General and administrative expenses
GAAP - U.S. Generally Accepted Accounting Principles
GOM Acquisition - Acquisition of oil and natural-gas assets in the Gulf of Mexico, which closed on December 15, 2016
GPM - Gallons per Mcf
IPO - Initial public offering
km2 - Square kilometers
LIBOR - London Interbank Offered Rate
LNG - Liquefied natural gas
MBbls/d - Thousand barrels per day
MBOE/d - Thousand barrels of oil equivalent per day
Mcf - Thousand cubic feet
MMBbls - Million barrels
MMBOE - Million barrels of oil equivalent
MMBtu - Million British thermal units
MMBtu/d - Million British thermal units per day
MMcf/d - Million cubic feet per day

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Moody’s - Moody’s Investors Service
NGLs - Natural gas liquids
NYMEX - New York Mercantile Exchange
Oil - Includes crude oil and condensate
OPEC - Organization of the Petroleum Exporting Countries
PUDs - Proved undeveloped reserves
SEC - U.S. Securities and Exchange Commission
S&P - Standard and Poor’s
Sonatrach - The national oil and gas company of Algeria
Tcf - Trillion cubic feet
TEN - Tweneboa/Enyenra/Ntomme
TEU or TEUs - Tangible equity units
Tronox - Tronox Incorporated
TSR - Total shareholder return
UOP - Unit-of-production
VIE - Variable interest entity
WES - Western Gas Partners, LP, a limited partnership and publicly-traded consolidated subsidiary of Anadarko
WES RCF - WES’s $1.2 billion five-year senior unsecured revolving credit facility maturing in February 2020
WGEH - Western Gas Equity Holdings, LLC, the general partner of WGP
WGH - Western Gas Holdings, LLC, the general partner of WES
WGP - Western Gas Equity Partners, LP, a limited partnership and publicly-traded consolidated subsidiary of Anadarko
WGP RCF - WGP’s $250 million three-year senior secured revolving credit facility maturing in March 2019
Zero Coupons - Anadarko’s Zero-Coupon Senior Notes due 2036

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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 1.7 billion BOE of proved reserves at December 31, 2016. 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 and the Gulf of Mexico with high-potential worldwide exploration and development activities.
Anadarko’s portfolio includes U.S. onshore assets in the lower 48 states and Alaska. The Company is also among the largest independent producers in the deepwater Gulf of Mexico and has exploration and production activities internationally, including activities in Algeria, Ghana, Mozambique, Colombia, Côte d’Ivoire, 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 oil, natural gas, and NGLs and plans for the development and operation of the Company’s LNG project in Mozambique.

Midstream—This segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production as well as gathering and disposal of produced water. The Company owns and operates gathering, processing, treating, transportation, and produced-water disposal systems in the United States for oil, natural gas, NGLs, and produced water.

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 and oil, NGLs, and its anticipated LNG production from Mozambique internationally.

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 SEC. Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its website located at investors.anadarko.com/sec-filings. 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 Form 10-K, or any other filing, please contact Anadarko Petroleum Corporation, Investor Relations, P.O. Box 1330, Houston, Texas 77251-1330; 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 Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Anadarko, that file electronically with the SEC.

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OIL AND GAS PROPERTIES AND ACTIVITIES

The map below illustrates the locations of Anadarko’s significant oil and natural-gas exploration and production operations:
worldmap201701.jpg




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United States

Overview  Anadarko’s U.S. operations include oil and natural-gas exploration and production in the U.S. onshore, deepwater Gulf of Mexico, and Alaska. The Company’s U.S. operations accounted for 89% of sales volumes and 80% of sales revenues during 2016 and 90% of proved reserves at year-end 2016.

U.S. Onshore  Anadarko’s U.S. onshore properties include oil and natural-gas plays located in Colorado, Texas, Utah, Wyoming, Pennsylvania, Louisiana, and Kansas, where the Company operates approximately 12,700 wells and owns interests in approximately 3,500 nonoperated wells.
The map below illustrates the locations of Anadarko’s U.S. onshore oil and natural-gas exploration and production operations:
usonshore201701.jpg

Activities in the U.S. onshore during 2016 primarily focused on adding reserves through horizontal drilling and infill drilling, optimizing wellbore and completion design, improving cost structure, delivering efficient production, and delineating positions in the Delaware and DJ basins. Process improvements and optimization projects assisted in providing both lower costs and cycle-time improvements. The Company drilled 207 wells and completed 384 wells in the U.S. onshore during 2016. The Company also divested non-core U.S. onshore assets, primarily in West Texas, East Texas/Louisiana, Wyoming, and Kansas and expects to divest additional non-core U.S. onshore assets during the first quarter of 2017 as discussed further below. In 2017, the Company expects to continue its horizontal drilling program, focusing on the Delaware and DJ basins.

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The Company also has fee ownership of mineral rights, known as the Land Grant, under approximately eight million acres that pass through Colorado and Wyoming and into Utah. Management considers the Land Grant a significant competitive advantage for Anadarko as it enhances the Company’s economic returns from production, offers drilling opportunities for the Company without expiration, and allows the Company to capture royalty revenue from third-party activity on Land Grant acreage.

Delaware Basin  Anadarko holds interests in over 580,000 gross acres in the Delaware basin. Anadarko’s 2016 drilling activity primarily targeted the Wolfcamp shale play, liquids-rich Bone Spring 2 tight sands, and Avalon shale play. In 2016, Anadarko drilled 103 operated wells and participated in 36 nonoperated wells. The full-year 2016 average drilling cost per foot was reduced by approximately 26% and drilling cycle time was reduced by 11% relative to 2015. Significant infrastructure continues to be added to facilitate future growth from this asset as discussed in Midstream Properties and Activities. The Company had 6 operated drilling rigs in the first quarter of 2016, ended 2016 with 9 operated drilling rigs, and expects to increase to 14 operated drilling rigs by the end of the first quarter of 2017.
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 for increased efficiency. Included in these development concepts are multi-well pads, extended laterals, enhanced completion designs, and horizontal-well spacing. The Company has identified more than 7,000 potential short-lateral-equivalent drilling locations in the Wolfcamp formation that are expected to provide substantial opportunity for Anadarko’s future activity in the basin.

DJ Basin  Anadarko holds interests in over 350,000 net acres in its core position and operates approximately 5,200 vertical wells and 1,220 horizontal wells in the DJ basin. The field contains the Niobrara and Codell formations, which are naturally fractured formations that hold both liquids and natural gas. During 2016, the Company’s drilling program focused entirely on horizontal development, drilling 91 horizontal wells. Horizontal drilling results in the field continue to be strong, with economics that are enhanced by the Company’s ownership of the Land Grant and recent operational efficiencies in drilling and completions. In the second quarter of 2016, the Company commissioned its COSF, further discussed in Midstream Properties and Activities.
Drilling spud-to-rig-release cycle time average improved from 6.3 days in 2015 to 4.7 days in 2016. The full-year 2016 average drilling cost per foot was reduced by approximately 14% and completion capital was reduced by 23% relative to 2015. Operated well capital costs in 2016 have decreased to less than $2.5 million from approximately $3.5 million in 2015 for a short-lateral-equivalent well, driven by continued operational efficiencies and supply-chain savings. The Company had two operated drilling rigs in the first quarter of 2016, ended 2016 with five operated drilling rigs, and added a sixth drilling rig in January 2017.

Greater Natural Buttes  The Greater Natural Buttes area in eastern Utah is one of the Company’s major tight-gas assets. The Company has cryogenic and refrigeration processing facilities available in this area to extract NGLs from the natural-gas stream. The Company operated the field at a reduced activity level for the majority of 2016 due to capital being diverted to higher-margin projects. The Company operates approximately 2,930 wells in the area. Focus in the field shifted to increasing operating margins through the reduction of expenses and optimization of base production.

Eaglebine  Anadarko holds 172,000 gross acres in the Eaglebine shale in Southeast Texas, most of which is held by existing Austin Chalk production. In 2016, Anadarko continued to delineate and develop this acreage by drilling five operated horizontal wells with a one-rig program. Under a carried-interest arrangement entered into in 2014, which requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, Anadarko has generated positive cash flow in the challenged price environment of 2016. As of December 31, 2016, $151 million of the total $442 million carry obligation had been funded.

Greater Green River Basin  Anadarko operates over 960 wells in the Moxa field in Wyoming and also carries a nonoperated position in 430 wells. Much of this producing area is located within the Land Grant, which enhances the Company’s economics in projects in the area. During 2016, Anadarko drilled and completed three carried exploration wells on the Land Grant.

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Marcellus  The Company holds 195,000 net acres in the Marcellus shale of the Appalachian basin. In 2016, Anadarko participated in the drilling of two nonoperated horizontal wells. During the year, the field focused on water management and well optimization, decreasing expenses and increasing margins. In December 2016, the Company entered into an agreement to sell its Marcellus oil and natural-gas assets and certain related midstream assets for approximately $1.2 billion. This transaction is expected to close in the first quarter of 2017.

Eagleford  The Eagleford shale development in South Texas consists of approximately 155,000 net acres and over 1,400 producing wells. In 2016, the Company drilled 3 wells, completed 29 wells, and brought 74 wells online. In the last three quarters of 2016, the field shifted its focus to base production optimization by completing an artificial lift program that improved performance and continued optimization of its infield gathering system. In January 2017, the Company entered into an agreement to sell its Eagleford oil and natural-gas assets for approximately $2.3 billion. This transaction is expected to close in the first quarter of 2017.

Gulf of Mexico  Including the GOM Acquisition described below, as of December 31, 2016, Anadarko owns an average working interest of 70% in 327 blocks in the Gulf of Mexico, operates 10 active floating platforms, and holds interests in 39 fields. The Company continued an active deepwater development and appraisal program in the Gulf of Mexico during 2016 as it continues to take advantage of existing infrastructure to cost-effectively develop known resources.
The map below illustrates the locations of Anadarko’s Gulf of Mexico oil and natural-gas exploration and production operations:
gomoverview201701a01.jpg



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Acquisition
In December 2016, the Company closed the GOM Acquisition for approximately $1.8 billion using net proceeds from the September 2016 issuance of 40.5 million shares of its common stock. The GOM Acquisition expanded Anadarko’s operated infrastructure in the region, doubling its net oil production from the Gulf of Mexico to more than 160 MBbls/d. The GOM Acquisition doubled the Company’s ownership in the Lucius development, increased its ownership in the Company’s Heidelberg asset, and resulted in a 100% working interest in the Horn Mountain, Marlin, and Holstein fields. Drilling is expected to begin in the first quarter of 2017 on the newly acquired assets, which each have multiple high-quality tie-back opportunities. The acquired assets are expected to generate substantial cash flow over the next five years at current strip prices, enabling accelerated investment in Anadarko’s Delaware and DJ basin assets.

Development
Lucius  The Company successfully drilled and completed the seventh development well in 2016. The well encountered 475 net feet of high-quality oil pay and was brought online in early 2016. The field continues to demonstrate favorable connectivity and strong aquifer support, improving well deliverability. The spar, located in Keathley Canyon Block 875 at a water depth of 7,000 feet, reached peak production of more than 100 MBbls/d of oil in 2016, exceeding the facility nameplate capacity of 80 MBbls/d. The Company more than doubled its interest in the field from 23.8% to approximately 49% through the GOM Acquisition. Anadarko expects to drill and complete the eighth development well in 2017.

Caesar/Tonga  At Caesar/Tonga (33.75% working interest), the Company successfully drilled and completed a sixth development well, which came online in the first quarter of 2016. Anadarko also successfully completed a seventh development well in 2016, which encountered more than 500 net feet of oil pay and began producing in the second quarter of 2016. Continued success at Caesar/Tonga resulted in peak production of more than 60 MBbls/d of oil. The Company sanctioned a Phase 2 development plan during the fourth quarter of 2015 and manufactured and installed subsea infrastructure in 2016.

Constellation  The Company acquired a 33.33% operated working interest in the Constellation discovery (formerly Hopkins) and was named operator after reaching a co-development agreement with a third party. Development drilling is expected to begin in 2017, and the field is expected to be tied back to Anadarko’s Constitution spar.

K2 Complex  At K2 (41.8% working interest), the GC 561#3 development well, drilled in the second quarter of 2015, found 331 net feet of oil pay and was brought online in the second quarter of 2016. The GC 562#6 development well was drilled and completed in 2016, with production anticipated in the second quarter of 2017.

Heidelberg  The Company realized first production at the Anadarko-operated Heidelberg spar in January 2016, when the first three wells were brought online. The fourth well, which encountered 185 net feet of oil pay, came online in the third quarter of 2016. After encountering water in its first penetration, the fifth well was sidetracked and encountered 191 net feet of oil pay. The Company expects the well to be brought online in the first quarter of 2017.
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 commitment covered the majority of Anadarko’s capital costs through first production. In the third quarter of 2016, all of the carry obligation had been funded. The Company increased its working interest in the field from 31.5% to 44% through the GOM Acquisition.


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Appraisal
Shenandoah  Anadarko and its partners are continuing to work toward determining the commerciality of the Shenandoah field. The Company has selected a Semisubmersible concept to support the potential development as part of these efforts. The front-end engineering design (FEED) on the Semisubmersible will continue while Anadarko continues appraisal drilling to further delineate the opportunity before making a future sanctioning decision.
The Company spud the Shenandoah-5 well, the fourth appraisal well at the Shenandoah discovery (33% working interest), in the first quarter of 2016. The well encountered more than 1,040 net feet of oil pay, extending the resource in the central-to-eastern limits of the field. The well has been secured for potential future production operations. The Shenandoah-6 appraisal well was spud in the fourth quarter of 2016. The drilling objective is to establish the oil-water contact on the eastern flank of the field and to help quantify the resource potential of the basin. During 2016, Anadarko increased its working interest in Shenandoah from 30% to 33% by participating in a preferential-right process.

Phobos  The Phobos appraisal well (100% working interest) encountered more than 90 net feet of oil pay in the secondary objective Pliocene-aged reservoir and approximately 130 net feet of oil pay from the primary objective Wilcox-aged reservoirs. Phobos is located approximately 12 miles south of the Anadarko-operated Lucius facility. Phobos is currently being evaluated as a tie-back candidate to the Anadarko-operated Lucius spar.

Exploration
Warrior  The Warrior exploration well (65% working interest) encountered more than 210 net feet of oil pay in multiple high-quality Miocene-aged reservoirs. The Warrior discovery is located approximately three miles from the Anadarko-operated K2 field and is expected to be tied back to the Marco Polo production facility. Anadarko expects to drill the first appraisal well in 2017.

Alaska  Anadarko’s nonoperated (22% working interest) oil production and development activity in Alaska is concentrated on the North Slope. Gross production from the Colville River Unit averaged approximately 60 MBbls/d of oil during the fourth quarter of 2016.
The operator completed an active drilling campaign in 2016, including nine development wells, one appraisal well, and two successful exploration wells. The Willow oil discovery was announced by the operator during the first quarter of 2017. Initial production could occur as early as 2023 subject to appraisal results, development planning, and timely permit approvals.


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International

Overview  Anadarko’s international operations include oil, natural-gas, and NGLs production and development in Algeria and Ghana, along with activities in Mozambique, where the Company continues to make progress towards a final investment decision on an LNG development. The Company also has exploration acreage in Colombia, Côte d’Ivoire, Mozambique, and other countries. International locations accounted for 11% of Anadarko’s sales volumes and 20% of sales revenues during 2016 and 10% of proved reserves at year-end 2016. In 2017, the Company expects to focus its exploration and appraisal activity in Côte d’Ivoire and Colombia.

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, Sonatrach, and other partners. 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 (CPFs) in Block 404 and oil and NGLs through the El Merk CPF in Block 208. Gross production through these facilities averaged more than 376 MBbls/d in 2016, an increase of 8 MBbls/d from 2015. Production increases were driven by reservoir optimization at El Merk and completion of an increased water-handling project at the Ourhoud CPF, which doubled the water and gas handling capacities. The Company drilled two development wells in 2016. Late in 2016, members of OPEC agreed to reduce production output for the first six months of 2017. Anadarko expects minimal production impact from this reduction.

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 participating interest), which spans both the West Cape Three Points Block and the Deepwater Tano Block, averaged gross production of 74 MBbls/d of oil in 2016. An average of 59 MMcf/d of natural gas was exported from the Jubilee field to an onshore gas processing plant in satisfaction of a commitment established in conjunction with the Jubilee development plan. In 2016, the operator announced that damage to the FPSO turret bearing had occurred. As a result, new production and offtake procedures were implemented, and the partners agreed to a long-term solution to convert the FPSO to a permanently-moored facility. Interim mooring of the vessel commenced in the fourth quarter of 2016 and is expected to be completed during the first quarter of 2017. Final decisions and approvals will be sought for the long-term turret system solution in the first half of 2017. It is anticipated that a facility shutdown of up to 12 weeks may be required in the second half of 2017. The partnership is actively seeking optimization solutions to minimize the duration of any shutdown period. Including the impact of the potential facility shutdown, the operator expects the average gross production from the Jubilee field to be more than 68 MBbls/d in 2017.
The TEN project (19% nonoperated participating interest) is located in the Deepwater Tano Block. The TEN project uses an 80 MBbls/d-capacity FPSO for production from subsea wells. The project achieved first oil in the third quarter of 2016 and first liftings during the fourth quarter of 2016. Production rates ramped up from first production through the fourth quarter to a December 2016 average of approximately 54 MBbls/d.

Mozambique  Anadarko operates Offshore Area 1 (26.5% participating interest), which totals approximately 1.2 million gross acres. The Company is progressing three elements that will position the project for execution and deliver future value: the legal and contractual framework to develop LNG in Mozambique, project finance, and long-term LNG sales contracts.

Development  Anadarko continues to engage with the Government of Mozambique to conclude the legal and contractual framework required to support investment. The foundation for the legal and contractual framework is the Decree Law published in 2014 and ratified in July 2015. The Company continues to work with construction and installation contractors to identify opportunities to optimize costs and reduce execution risk once the project progresses to the construction phase. In 2016, Anadarko and its partners formally launched the project financing process and continued to progress significant LNG long-term sales contracts. During the fourth quarter of 2016, the Government of Mozambique approved the Resettlement Plan that was submitted in June 2016. This marks a critical step on the path to commence resettlement implementation, which will facilitate clearance of the project site to begin construction of the LNG facility. The Development Plan for the initial two-train onshore project was submitted to the Government of Mozambique in the fourth quarter of 2016.

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Exploration  In Offshore Area 1, the Company continues to reprocess 3D seismic data covering the Orca, Tubarão, and Tubarão Tigre discovery areas, in accordance with the appraisal program submitted to the Government of Mozambique in the first quarter of 2015.

Colombia  Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on eight blocks totaling approximately 15 million gross acres. The COL 1, COL 2, COL 6, and COL 7 blocks are operated at a 100% working interest, and the blocks in the Grand Fuerte area are operated at a 50% working interest.
In the Grand Fuerte area, the Purple Angel-1 exploration well (50% working interest) spud during the fourth quarter of 2016, and operations are ongoing. The well is designed to test objectives similar to those at Anadarko’s 2015 play-opening Kronos discovery. The rig will mobilize to drill the Gorgon prospect, also located in the Purple Angel Block, following the completion of operations at the Purple Angel-1 well. The Gorgon-1 exploration well will test an analogous structure along trend to the Kronos discovery.
In the Grand COL area, acquisition of the approximately 30-thousand km2 Esmeralda 3D seismic survey was completed in the third quarter of 2016.

Côte d’Ivoire  Anadarko owns an operated working interest in four offshore blocks totaling approximately 1.0 million gross acres, including CI-103, with a 65% working interest, and CI-527, CI-528, and CI-529, each with a 90% working interest.

Appraisal  At Paon (CI-103), appraisal continued in 2016. The Paon-5A horizontal well, Anadarko’s first horizontal deepwater well, encountered nearly 100 net feet of oil pay, successfully appraising the discovery. A second deepwater horizontal well was drilled at the Paon-3AR sidetrack and encountered approximately 120 net feet of oil pay. Following the appraisal drilling campaign, Anadarko completed a successful drillstem and interference testing program at Paon.

Exploration  Two exploration wells were drilled to the southeast of Paon during 2016, targeting similar-aged sands along trend to the Paon discovery. The Rossignol-1X well (CI-528) encountered well-developed sands and found approximately 15 feet of net oil pay on water. The Pelican-1X well (CI-527) encountered approximately 70 feet of net oil pay in two separate intervals. Anadarko is currently evaluating its 2017 Côte d’Ivoire drilling program.

Other  Anadarko also holds exploration interests in other offshore international areas including Canada, Kenya, New Zealand, and South Africa, among others.

13

Proved Reserves

Estimates of proved reserves volumes owned at year end, net of third-party royalty interests, are presented in Bcf at a pressure base of 14.73 pounds per square inch for natural gas and in MMBbls for oil and NGLs. Total volumes are presented in 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. For 2016, the International geographic area consisted of proved reserves located in Algeria and Ghana, which by country and in total represented less than 15% of the Company’s total proved reserves.

Summary of Proved Reserves
 
Oil
(MMBbls)
 
Natural Gas
(Bcf)
 
NGLs
(MMBbls)
 
Total
(MMBOE)
December 31, 2016
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
360

 
3,637

 
193

 
1,159

International
147

 
25

 
15

 
166

Undeveloped
 
 
 
 
 
 
 
United States
181

 
762

 
75

 
383

International
14

 
—

 
—

 
14

Total proved
702

 
4,424

 
283

 
1,722

 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
332

 
5,184

 
257

 
1,453

International
159

 
30

 
15

 
179

Undeveloped
 
 
 
 
 
 
 
United States
193

 
807

 
68

 
396

International
29

 
—

 
—

 
29

Total proved
713

 
6,021

 
340

 
2,057

 
 
 
 
 
 
 
 
December 31, 2014
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
352

 
6,635

 
304

 
1,762

International
190

 
27

 
13

 
207

Undeveloped
 
 
 
 
 
 
 
United States
352

 
2,033

 
162

 
853

International
35

 
4

 
—

 
36

Total proved
929

 
8,699

 
479

 
2,858


The Company’s proved reserves product mix increased to 57% liquids in 2016, compared to 52% in 2015 and 49% in 2014. The Company’s year-end 2016 proved reserves product mix was 40% oil, 43% natural gas, and 17% NGLs.

14

Changes to the Company’s proved reserves during 2016 are summarized in the table below:
MMBOE
2016
 
2015
 
2014
Proved Reserves
 
 
 
 
 
January 1
2,057

 
2,858

 
2,792

Reserves additions and revisions
 
 
 
 
 
Discoveries and extensions
40

 
29

 
63

Infill-drilling additions (1)
69

 
89

 
577

Drilling-related reserves additions and revisions
109

 
118

 
640

Other non-price-related revisions (1)
191

 
289

 
(137
)
Net organic reserves additions
300

 
407

 
503

Acquisition of proved reserves in place
97

 
1

 
—

Price-related revisions (1)
(147
)
 
(624
)
 
(1
)
Total reserves additions and revisions
250

 
(216
)
 
502

Sales in place
(294
)
 
(279
)
 
(124
)
Production
(291
)
 
(306
)
 
(312
)
December 31
1,722

 
2,057

 
2,858

Proved Developed Reserves
 
 
 
 
 
January 1
1,632

 
1,969

 
2,003

December 31
1,325

 
1,632

 
1,969

_______________________________________________________________________________
(1) 
Combined and reported as revisions of prior estimates in the Company’s Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K. Reserves related to infill-drilling additions are treated as positive revisions. Price-related revisions reflect the impact of current prices on the reserves balance at the beginning of each year. Other non-price-related revisions in 2016 are primarily a reflection of performance improvements coupled with the benefit of reduced year-end costs.

Proved reserves are estimated based on the average beginning-of-month prices during the 12-month period for the respective year. The average prices used to compute proved reserves at December 31, 2016, were $42.75 per Bbl for oil, $2.48 per MMBtu for natural gas, and $19.74 per Bbl for NGLs. 
The Company’s estimates of proved developed reserves, PUDs, and total proved reserves at December 31, 2016, 2015, and 2014, and changes in proved reserves during the last three years are presented in the 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, 2016. 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.

15

Changes in PUDs  Changes to PUDs during 2016 are summarized in the table below. 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, 2016
425

Revisions of prior estimates
70

Extensions, discoveries, and other additions
5

Conversions to developed
(118
)
Purchases
30

Sales
(15
)
PUDs at December 31, 2016
397


Revisions  Revisions of prior estimates reflect Anadarko’s ongoing evaluation of its asset portfolio. In 2016, PUDs were revised upward by 70 MMBOE.
MMBOE
December 31, 2016
Revisions due to changes in year-end prices (price impact to opening balance)
(74
)
Other revisions of prior estimates
 
Revisions due to performance
10

Revisions due to cost reductions
53

Revisions due to successful infill drilling
60

Revisions due to development plan updates
3

Other revisions
18

Total other revisions of prior estimates
144

Revisions of prior estimates
70

Negative revisions of 74 MMBOE were due to the decline in commodity prices. The negative price-related revisions were offset by a net increase of 144 MMBOE associated with the following:
•
Performance  The Company experienced an increase in PUDs primarily due to improved well performance in the DJ basin and U.S. shale play areas.
•
Cost reductions  Ongoing cost-optimization efforts and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in PUDs. The DJ basin and Eagleford areas experienced an increase of 45 MMBOE of PUDs associated with certain wells, included in the negative price-related revisions, which experienced restored economic producibility upon reduction of the cost structure. The remaining increase in PUDs due to the improved cost structure is attributable to several other areas across the Company.
•
Infill drilling  The Company added 60 MMBOE of infill PUDs during 2016, with a majority of the additions in the DJ basin and the K2 and Caesar/Tonga areas of the Gulf of Mexico.
•
Other revisions  Certain projects that had negative price-related revisions associated with the opening PUDs balance were also either converted to developed status during the year or moved to other unproved categories, primarily as a result of changes to development plans. In an effort to provide full transparency of price sensitivity, the price-related revisions and these other changes were disclosed completely and independently rather than as a net impact. The multi-step process to reconcile and explain changes in reserves resulted in an immaterial duplicative reduction of reserves. These other revisions eliminate the duplicative adjustments to the opening reserves balance.

16

Extensions, Discoveries, and Other Additions  During 2016, Anadarko added PUDs through the extension of proved acreage, primarily as a result of successful drilling in the Lucius area of the Gulf of Mexico and the Marcellus shale play.

Conversions  In 2016, the Company converted 118 MMBOE of PUDs to developed status, equating to 25% of total year-end 2015 PUDs when adjusted for revisions and sales. Approximately 55% of PUDs conversions occurred in U.S. onshore assets, 32% occurred in Gulf of Mexico assets, and the remaining 13% occurred in international assets.
Anadarko spent $0.9 billion to develop PUDs in 2016, of which approximately 50% related to U.S. onshore assets, including Alaska; 27% related to Gulf of Mexico assets; and 23% related to international assets.

Purchases  In 2016, PUDs increased by 30 MMBOE due to the GOM Acquisition.

Sales  In 2016, PUDs decreased due to the Company’s divestiture activities in U.S. onshore areas.

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 associated with arctic development, deepwater development, and international programs may take longer. At December 31, 2016, the Company had no material pre-2012 PUDs that remained undeveloped.

Technologies Used in Proved Reserves Estimation  The Company’s 2016 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.


17

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 of Corporate Reserves manages the CRG and reports 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 meets with management, members of the CRG, and the Company’s independent petroleum consultants, Miller and Lents, Ltd. (M&L), to discuss the results of procedures and methods reviews as discussed below as well as other matters and policies related to reserves.
The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserves estimates, has over 30 years of experience in the oil and gas industry, including over 16 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 Engineers, where he has been a member for over 30 years, and is also a member of the Society of Petroleum Evaluation Engineers. 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, 2016. 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 14 fields that included major assets in the United States and Africa and encompassed approximately 86% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2016. 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.


18

Sales Volumes, Prices, and Production Costs

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)
 
Oil 
(MMBbls)
 
Natural
Gas
(Bcf)
 
NGLs
(MMBbls)
 
Barrels of
Oil
Equivalent
(MMBOE)
 
Oil 
(Per Bbl)
 
Natural
Gas
(Per Mcf)
 
NGLs
(Per Bbl)
 
2016
 

 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg (DJ basin)
33

 
214

 
20

 
89

 
40.27

 
2.00

 
18.26

 
8.41

Other United States
52

 
552

 
24

 
168

 
38.29

 
2.06

 
20.21

 
6.80

Total United States
85

 
766

 
44

 
257

 
39.06

 
2.04

 
19.32

 
7.36

International
31

 
—

 
2

 
33

 
43.93

 
—

 
25.63

 
7.93

Total
116

 
766

 
46

 
290

 
40.34

 
2.04

 
19.64

 
7.42

2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg (DJ basin)
35

 
176

 
16

 
81

 
44.88

 
2.31

 
15.65

 
8.21

Other United States
50

 
676

 
29

 
191

 
45.08

 
2.37

 
17.83

 
8.55

Total United States
85

 
852

 
45

 
272

 
45.00

 
2.36

 
17.03

 
8.45

International
31

 
—

 
2

 
33

 
51.68

 
—

 
29.85

 
7.22

Total
116

 
852

 
47

 
305

 
46.79

 
2.36

 
17.61

 
8.31

2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg (DJ basin)
27

 
125

 
13

 
62

 
87.76

 
4.19

 
36.46

 
8.28

Other United States
47

 
820

 
30

 
213

 
88.13

 
4.05

 
35.03

 
9.04

Total United States
74

 
945

 
43

 
275

 
87.99

 
4.07

 
35.48

 
8.87

International
32

 
—

 
1

 
33

 
99.79

 
—

 
56.16

 
8.22

Total
106

 
945

 
44

 
308

 
91.58

 
4.07

 
36.01

 
8.80

 _______________________________________________________________________________
(1) 
Excludes the impact of commodity derivatives.
(2) 
Excludes ad valorem and severance taxes.

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.

19

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, 2016, Anadarko was contractually committed to deliver approximately 872 Bcf of natural gas to various customers in the United States through 2031. These contracts have various expiration dates, with approximately 36% of the Company’s current commitment to be delivered in 2017 and 79% by 2021. At December 31, 2016, Anadarko was also contractually committed to deliver approximately 40 MMBbls of oil to a customer in the United States through 2020. These contracts have various expiration dates, with approximately 40% of the Company’s current commitment to be delivered in 2017 and 100% by 2020. At December 31, 2016, Anadarko also was contractually committed to deliver approximately 10 MMBbls of oil to ports in Algeria and Ghana through 2017. The Company expects to fulfill these delivery commitments with existing proved developed reserves and PUDs, which the Company regularly monitors to ensure sufficient availability to meet its commitments. If production is not sufficient to meet contractual delivery commitments, the Company may purchase commodities in the market to satisfy its delivery commitments.

Properties and Leases

The following shows the developed lease, undeveloped lease, and fee mineral acres in which Anadarko held interests at December 31, 2016:
 
Developed
Lease
 
Undeveloped
Lease
 
Fee Mineral (1)
 
Total
thousands of acres
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Onshore
3,230

 
1,896

 
2,976

 
1,127

 
9,906

 
8,212

 
16,112

 
11,235

Offshore
351

 
198

 
1,525

 
1,144

 
—

 
—

 
1,876

 
1,342

Total United States
3,581

 
2,094

 
4,501

 
2,271

 
9,906

 
8,212

 
17,988

 
12,577

International
611

 
132

 
46,315

 
32,481

 
—

 
—

 
46,926

 
32,613

Total
4,192

 
2,226

 
50,816

 
34,752

 
9,906

 
8,212

 
64,914

 
45,190

 _______________________________________________________________________________
(1) 
The Company’s fee mineral acreage is primarily undeveloped.

At December 31, 2016, the Company had approximately six million net undeveloped lease acres scheduled to expire by December 31, 2017, 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. The net undeveloped lease acres scheduled to expire by December 31, 2017, primarily relate to 5.8 million net acres of international exploration acreage in New Zealand (2.0 million net acres), Kenya (1.8 million net acres), Colombia (1.1 million net acres), and Côte d’Ivoire (0.9 million net acres), where proved reserves have not been assigned. The Company does not expect a significant portion of its total net acreage position to expire in 2017.

Drilling Program

The Company’s 2016 drilling program focused on proven and emerging liquids-rich basins in the United States (onshore and deepwater Gulf of Mexico) and various international locations. Exploration activity in 2016 consisted of 11 gross completed U.S. onshore wells. Development activity in 2016 consisted of 516 gross completed wells, which included 494 U.S. onshore wells, 13 international wells, and 9 Gulf of Mexico wells.

20

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

Productive
 
Dry Holes
 
Total
 
Productive
 
Dry Holes
 
Total
 
2016
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
3.7

 
1.2

 
4.9

 
322.1

 
—

 
322.1

 
327.0

International
—

 
1.8

 
1.8

 
2.9

 
—

 
2.9

 
4.7

Total
3.7

 
3.0

 
6.7

 
325.0

 
—

 
325.0

 
331.7

2015
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
16.0

 
—

 
16.0

 
573.1

 
13.8

 
586.9

 
602.9

International
2.4

 
0.4

 
2.8

 
1.8

 
—

 
1.8

 
4.6

Total
18.4

 
0.4

 
18.8

 
574.9

 
13.8

 
588.7

 
607.5

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


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, 2016:
 
Wells in the process
of drilling or
in active completion
 
Wells suspended or
waiting on completion (1)
 
Exploration
 
Development
 
Exploration
 
Development (2)
United States
 
 
 
 
 
 
 
Gross
3

 
9

 
51

 
643

Net
2.1

 
5.8

 
21.9

 
375.3

International
 
 
 
 
 
 
 
Gross
2

 
—

 
54

 
11

Net
1.0

 
—

 
17.4

 
2.6

Total
 
 
 
 
 
 
 
Gross
5

 
9

 
105

 
654

Net
3.1

 
5.8

 
39.3

 
377.9

 _______________________________________________________________________________
(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.
(2) 
There were 106 MMBOE of PUDs assigned to U.S. onshore development wells suspended or waiting on completion at December 31, 2016. The Company expects to convert these reserves to developed status within five years of their initial disclosure.

21

Productive Wells

At December 31, 2016, the Company’s ownership interest in productive wells was as follows:
 
Oil Wells (1)
 
Gas Wells (1)
United States
 
 
 
Gross
3,949

 
12,615

Net
2,505.9

 
9,518.6

International
 
 
 
Gross
208

 
9

Net
37.4

 
2.2

Total
 
 
 
Gross
4,157

 
12,624

Net
2,543.3

 
9,520.8

________________________________________________________________
(1) 
Includes wells containing multiple completions as follows:
Gross
209

 
2,405

Net
182.4

 
2,089.0


MIDSTREAM PROPERTIES AND ACTIVITIES

Anadarko invests in and operates midstream (gathering, processing, treating, transportation, and produced-water disposal) 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, wellhead purchase, and keep-whole agreements. Anadarko’s midstream activities include those of WES, which acquires, owns, develops, and operates midstream assets. At December 31, 2016, Anadarko’s ownership interest in WGP consisted of an 81.6% limited partner interest and the entire non-economic general partner interest. At December 31, 2016, WGP’s ownership interest in WES consisted of a 29.9% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At December 31, 2016, Anadarko also owned an 8.6% limited partner interest in WES through other subsidiaries.
At the end of 2016, Anadarko had 34 gathering systems and 72 processing and treating facilities located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Pennsylvania, and Texas. In 2016, the Company’s midstream activity was concentrated in the Delaware basin to build infrastructure for present and future Wolfcamp development. In 2017, the Company expects to continue its midstream investment to focus on the Delaware and DJ basins.


22

Delaware Basin  In 2016, the Company expanded its midstream infrastructure for Bone Spring, Wolfcamp, and Avalon production in the Delaware basin of West Texas, installing over 200 miles of oil, water, and gas gathering lines. Three new CGFs were installed and five existing CGFs were expanded to add a total of approximately 620 MMcf/d of compression capacity. Additional CGFs within the field are planned for 2017.
In December 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of damage was to the liquid-handling facilities and the amine-treating units at the inlet of the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returned to service in December 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returned to full service in May 2016. There was no damage to Trains IV and V (each with a capacity of 200 MMcf/d), which were under construction at the time of the incident. Train IV was commissioned in the second quarter of 2016, and Train V and the high-pressure condensate stabilizer were both commissioned in the fourth quarter of 2016. As of December 31, 2016, the Company had received $33.8 million in cash proceeds from insurers related to the incident, including $16.3 million in proceeds from business interruption insurance claims and $17.5 million in proceeds from property insurance claims.
The DBM complex now includes 700 MMcf/d of cryogenic processing capacity, 1,400 GPM of amine-treating capacity, 18 MBbls/d of high-pressure condensate stabilization, and a rich-gas gathering system, with over 350 miles of high-pressure and low-pressure segments. Construction began on Train VI, a 200-MMcf/d cryogenic facility, in the fourth quarter of 2016, with expected commissioning by the end of 2017.

DJ Basin  Anadarko continued to optimize gathering and compression in 2016, which reduced gathering system pressures in the field, enhancing system efficiency and improving the base production profile. Management believes that Anadarko is well-positioned in the DJ basin with its oil and NGLs transportation capacity, which includes transport by pipeline, rail, and truck.
In the second quarter of 2016, the Company commissioned its COSF, capable of handling 100 MBbls/d. The primary benefit of the COSF is the removal of oil product storage tanks at Anadarko’s well pad sites, resulting in lower operating expenses, reduced emissions, and further reduced well site surface footprint.
Anadarko has a 20% equity ownership in Saddlehorn Pipeline Company, LLC, which owns 190 MBbls/d of capacity in a shared pipeline. The pipeline was brought into service in the third quarter of 2016 and delivers various grades of oil from the DJ basin to storage facilities in Cushing, Oklahoma.
The Company elected to participate in an expansion of the White Cliffs oil pipeline to increase the total capacity from 150 MBbls/d to approximately 215 MBbls/d. Construction is expected to be completed early in the second quarter of 2017.

Greater Natural Buttes  The Chipeta plant’s total processing capacity (cryogenic and refrigeration) is approximately 1 Bcf/d with cryogenic processing capacity of 550 MMcf/d. Chipeta’s third-party pipeline interconnect has added approximately 100 MMcf/d of natural-gas supply to the plant.

East Texas/North Louisiana  The Panola Valley NGL Pipeline expansion was completed in August of 2016. Anadarko has a 15% equity interest in the 248-mile pipeline. The pipeline ends at Mont Belvieu NGL Fractionation facility, where Anadarko has a 25% equity interest in fractionation trains VII and VIII. The trains each have 85 MBbls/d of gross NGLs processing capacity.

Marcellus  In the Marcellus shale, the Company efficiently maintained its operated gathering systems with approximately 260 MMcf/d of compression capacity in Lycoming, Clinton, and Centre Counties in Pennsylvania. In December 2016, Anadarko entered into an agreement to sell its operated and nonoperated oil and natural-gas assets and related operated midstream assets to a third-party; the midstream assets owned by WES were excluded from the agreement.

Eagleford  In the Eagleford shale, the Company continues to operate oil and gas gathering systems, with a 2016 average gross throughput of 70 MBbls/d of oil and 540 MMcf/d of natural gas. The 200 MMcf/d operated Brasada natural-gas cryogenic processing plant continued steady operations at capacity. In January 2017, Anadarko entered into an agreement to sell its oil and natural-gas assets to a third-party; the midstream assets owned by WES were excluded from the agreement.

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The following provides information regarding the Company’s midstream assets including gathering, processing, treating, transportation, and produced-water disposal by area (excluding divestitures closed in 2016):
Area
 
Miles of
Pipelines
 
Total
Horsepower
 
2016
Average Net
Throughput
(MMcf/d)
DJ basin
 
5,700

 
357,500

 
1,100

Delaware basin
 
1,600

 
275,900

 
500

Greater Natural Buttes
 
1,300

 
233,700

 
900

Marcellus
 
800

 
104,200

 
1,000

Eagleford
 
900

 
203,900

 
500

Other
 
6,200

 
245,800

 
900

Total
 
16,500

 
1,421,000

 
4,900



MARKETING ACTIVITIES

The Company’s marketing segment actively manages Anadarko’s worldwide oil, natural-gas, 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 oil, natural gas, and NGLs are generally made at market prices at the time of sale. The Company also purchases oil, natural gas, and NGLs from third parties, primarily near Anadarko’s production areas, to aggregate volumes so the Company is positioned to fully use its 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 oil, natural gas, and NGLs. The Company does not engage in market-making practices and limits its marketing activities to oil, natural-gas, NGLs, and LNG commodity contracts. The Company’s marketing-risk position is typically a net short position (reflecting agreements to sell oil, natural gas, 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 oil and natural-gas reserves). See Commodity-Price Risk under Item 7A of this Form 10-K.

Oil and NGLs  Anadarko’s oil 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. Oil from Ghana is sold by tanker as Jubilee and TEN Blend Crude Oil to customers around the world. Saharan Blend, Jubilee, and TEN Blend Oil are high-quality crudes that provide refiners with large quantities of premium products such as gasoline, diesel, and jet fuel.


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Natural Gas  Anadarko markets its U.S. 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.

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 integrated 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 25—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 4,500 employees at December 31, 2016.

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, local, and foreign 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, imposes various pre-construction, monitoring, and reporting requirements, which the EPA has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas emissions
•
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 and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States
•
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 obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities 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

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•
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 control over 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
•
the National Environmental Policy Act, which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment

These U.S. 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 permitting, development, or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Moreover, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. See Risk Factors under Item 1A of this Form 10-K for further discussion on hydraulic fracturing; ozone standards; induced seismicity regulatory developments; 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 continue to evolve.
Many states where the Company operates also have, or are developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. In addition, many foreign countries where the Company is conducting business also have, or may be developing, regulatory initiatives or analogous controls that regulate Anadarko’s environmental-related activities. While the legal requirements imposed under state or foreign law may be similar in form to U.S. laws and regulations, 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 permitting, development, or expansion of a project or substantially increase the cost of doing business. In addition, environmental and occupational health and safety laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental concerns such as air and water impacts, are expected to continue to have an increasing impact on the Company’s operations.

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The Company has incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, the Company’s environmental compliance costs have not had a material adverse effect on its results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on the Company’s business and operation results. 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.

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 more stringent requirements as 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 Oil Spill-Response Plans (Plans) for the Company’s Gulf of Mexico operations. The Plans set forth procedures for a rapid and effective response to spill events that may occur as a result of Anadarko’s operations. The Plans are reviewed by the Company at least annually and updated as necessary. Drills are conducted by the Company 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), Marine Spill Response Corporation (MSRC), and representatives of relevant governmental agencies. The Plans and any revisions to the Plans must be approved by the BSEE.
As part of the Company’s oil spill-response preparedness, and as set forth in the Plans, Anadarko maintains membership in CGA and has an employee representative on the executive committee of CGA. CGA was created to provide a means of effectively staging response equipment and to provide effective spill-response capability for its member companies operating in the Gulf of Mexico. CGA equipment includes, among other things, skimming vessels, barges, boom, and dispersants. CGA has executed a support contract with T&T Marine to coordinate bareboat charters and to provide for expanded response support. T&T Marine is responsible for inspecting, maintaining, storing, and staging 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 has service contracts in place with domestic environmental contractors as well as with other companies that provide for 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 MSRC cooperative. 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 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, among other things, skimmers, OSRVs, fast response vessels, barges, storage bladders, work boats, ocean boom, and dispersant.

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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 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. 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 several qualified environmental consulting firms 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 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 is intended to satisfy the requirements of relevant local or national authorities, describes the actions the Company is expected to take in the event of an incident, includes drills conducted by the Company 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. Anadarko also participates in supplementary service provided through OSRL, the Global Dispersant Stockpile (GDS). This additional service provides Anadarko access to dispersant and is available to Anadarko operations worldwide.
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, among other things, 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.

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 tracts 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.


28

EXECUTIVE OFFICERS OF THE REGISTRANT
Name
 
Age at
January 31,
2017
 
Position
R. A. Walker
 
59
 
Chairman, President and Chief Executive Officer
Robert G. Gwin
 
53
 
Executive Vice President, Finance and Chief Financial Officer
Darrell E. Hollek
 
59
 
Executive Vice President, Operations
Mitchell W. Ingram
 
54
 
Executive Vice President, Global LNG
Ernest A. Leyendecker
 
56
 
Executive Vice President, International and Deepwater Exploration
Robert K. Reeves
 
59
 
Executive Vice President, Law and Chief Administrative Officer
Christopher O. Champion
 
47
 
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 WGH and served as its Chairman of the Board from August 2007 to September 2009. Mr. Walker served as a director of WGEH from September 2012 until March 2013. Mr. Walker served as a director of Temple-Inland Inc. from November 2008 to February 2012 and a director of CenterPoint Energy, Inc. from April 2010 to April 2015 and has served as a director of BOK Financial Corporation since April 2013, where he is the Chairman of the Risk Committee.
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.
Mr. Hollek was named Executive Vice President, Operations in August 2016. Prior to this position, he served as Executive Vice President, U.S. Onshore Exploration and Production since April 2015; Senior Vice President, Deepwater Americas Operations since May 2013; and Vice President, Operations since May 2007. Mr. Hollek 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, where he began his career, including management roles in the Gulf of Mexico; U.S. onshore; and Environmental, Health, Safety and Regulatory. Mr. Hollek has served as a director of WGH and WGEH since May 2015.
Mr. Ingram was named Executive Vice President, Global LNG in November 2015. Prior to joining Anadarko, Mr. Ingram was with BG Group since 2006, where he served as a member of the Executive Committee in the role of Executive Vice President—Technical since March 2015. Previously, he held positions of increasing responsibility with the company’s LNG project in Queensland, Australia, where he served as Managing Director of QGC, a BG Group business, since April 2014; as Deputy Managing Director since September 2013; and as Project Director of the Queensland Curtis LNG project since May 2012. From 2006 to May 2012, Mr. Ingram was Asset General Manager of BG Group’s Karachaganak interest in Kazakhstan. He joined BG Group after 20 years with Occidental Oil & Gas, where he held several U.K. and international leadership positions in project management, development, and operations.

29

Mr. Leyendecker was named Executive Vice President, International and Deepwater Exploration in August 2016. Prior to this position, he served as Senior Vice President, International Exploration since April 2015 and Senior Vice President, Gulf of Mexico Exploration since February 2014. Prior to that, he served as Vice President, Gulf of Mexico Exploration since May 2011 and as Vice President of Corporate Planning and Gulf of Mexico Exploration since October 2010. Mr. Leyendecker 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 Exploration Manager for the Gulf of Mexico and General Manager for Worldwide Exploration, Engineering and Planning. Mr. Leyendecker began his career with Marathon Oil Company prior to pursuing a leadership role with Enterprise Oil Gulf of Mexico, which was acquired by Shell Oil in 2002.
Mr. Reeves was named Executive Vice President, Law and Chief Administrative Officer in September 2015 and previously served as Executive Vice President, General Counsel and Chief Administrative Officer since May 2013 and 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 served as a director of Key Energy Services, Inc., a publicly traded oilfield services company, from October 2007 to December 2016 and has served as a director of WGH since August 2007 and as a director of WGEH since September 2012.
Mr. Champion was named Senior Vice President, Chief Accounting Officer and Controller in February 2017 and previously served as Vice President, Chief Accounting Officer and Controller since June 2015. Prior to joining Anadarko, Mr. Champion was an Audit Partner with KPMG LLP since October 2003 and served as KPMG’s National Audit Leader for Oil and Natural Gas since 2008. He began his career at Arthur Andersen LLP in 1992 before joining KPMG LLP in 2002 as a senior audit manager.
Officers of Anadarko are elected each year at the first meeting of the Board following the annual meeting of stockholders, the next of which is expected to occur on May 10, 2017, 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 Form 10-K, 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
•
levels of oil, natural-gas, and NGLs reserves
•
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 oil, natural gas, 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, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, 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

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•
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, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, tribal, local, and foreign environmental laws and regulations
•
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 or refinance its debt, and the impact of changes in the Company’s credit ratings
•
uncertainties associated with acquired properties and businesses
•
disruptions in international oil and NGLs 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

Oil, natural-gas, and NGLs price volatility, including 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, NYMEX West Texas Intermediate oil prices have been volatile and ranged from a high of $107.26 per barrel in June 2014 to a low of $26.21 per barrel in February 2016. Also, NYMEX Henry Hub natural-gas prices have been volatile and ranged from a high of $6.15 per MMBtu in February 2014 to a low of $1.64 per MMBtu in March 2016. 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:
 
•
the domestic and worldwide supply of, and demand for, oil, natural gas, and NGLs
•
volatility and trading patterns in the commodity-futures markets
•
the cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs
•
the level of global oil and natural-gas inventories
•
weather conditions
•
the level of U.S. exports of oil, liquefied natural gas, or NGLs
•
the ability of the members of OPEC and other producing nations to agree to and maintain production levels
•
the worldwide military and political environment, civil and political unrest worldwide, including in Africa and the Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or acts of terrorism in the United States or elsewhere
•
the effect of worldwide energy conservation and environmental protection efforts
•
the price and availability of alternative and competing fuels

32

•
the level of foreign imports of oil, natural gas, and NGLs
•
domestic and foreign governmental laws, regulations, and taxes
•
shareholder activism or activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas in order to minimize emissions of carbon dioxide, a greenhouse gas (GHG)
•
the 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 affect our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations
•
reduce the amount of oil, natural gas, and NGLs that we can produce economically
•
cause us to delay or postpone some of our capital projects
•
reduce our revenues, operating income, or cash flows
•
reduce the amounts of our estimated proved oil, natural-gas, and NGLs reserves
•
reduce the carrying value of our oil, natural-gas, and midstream properties due to recognizing additional impairments of proved properties, unproved properties, exploration assets, and midstream facilities
•
reduce the standardized measure of discounted future net cash flows relating to oil, natural-gas, and NGLs reserves
•
limit our access to, or increasing the cost of, sources of capital such as equity and long-term debt
•
adversely affect the ability of our partners to fund their working interest capital requirements

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 international, provincial, federal, regional, state, tribal, local, and foreign laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:

•
issuance of permits in connection with exploration, drilling, production, and midstream activities
•
drilling activities on certain lands lying within wilderness, wetlands, and other protected areas
•
types, quantities, and concentrations of emissions, discharges, and authorized releases
•
generation, management, and disposition of waste materials
•
offshore oil and natural-gas operations and decommissioning of abandoned facilities
•
reclamation and abandonment of wells and facility sites
•
remediation of contaminated sites
•
protection of endangered species


33

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 permitting, development, or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Moreover, changes in, or reinterpretations of, environmental laws and regulations governing areas where we operate may negatively impact our operations. Examples of recent proposed and final regulations or other regulatory initiatives include the following:
•
Ground-Level Ozone Standards. In October 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is expected to make final geographical attainment designations and issue final non-attainment area requirements pursuant to this NAAQS rule by late 2017, and any designations or requirements that result in reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our operations. Compliance with this rule could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.
•
Reduction of Methane Emissions by the Oil and Gas Industry. In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural-gas production and natural-gas processing and transmission facilities. The EPA’s rule is comprised of New Source Performance Standards, known as Subpart Quad OOOOa, that require certain new, modified, or reconstructed facilities in the oil and natural-gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart Quad OOOOa standards will expand previously issued New Source Performance Standards published by the EPA in 2012, known as Subpart OOOO, by using certain equipment specific emissions control practices with respect to, among other things, hydraulically-fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural-gas processing plants and pneumatic pumps. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and natural-gas industry. The EPA has indicated that it intended to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry. Compliance with this rule could, among other things, require installation of new emission controls on some of our equipment and significantly increase our capital expenditures and operating costs.
•
Induced Seismic Activity Associated with Oilfield Disposal Wells. We dispose of wastewater generated from oil and natural-gas production operations directly or through the use of third parties. The legal requirements related to the disposal of wastewater in underground injections wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near injection wells used for the disposal of produced water resulting from oil and natural-gas activities. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission adopted similar permitting, operating, and reporting rules for disposal wells in 2014. In addition, ongoing class action lawsuits, to which we are not currently a party, allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.

34

•
Reduction of Greenhouse Gas Emissions. The U.S. Congress and the EPA, in addition to some state and regional efforts, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “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. 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. In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

These and other regulatory changes could significantly increase our capital expenditures and operating costs or could result in delays to or limitations on our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows. For a description of certain environmental proceedings in which we are involved, see Legal Proceedings under Item 3 and Note 16—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Changes in laws or regulations regarding hydraulic fracturing or other oil and natural-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 oil and natural gas 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 typically 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 issued an effluent limit guidelines final rule in June 2016 prohibiting the discharge of return water recovered from shale natural-gas extraction operations to publicly owned wastewater treatment plants. Also, the Bureau of Land Management (BLM) published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, finding that the BLM lacked congressional authority to promulgate the rule. That decision is currently being appealed by the federal government. Also, from time to time, legislation has been introduced, but not enacted, in the U.S. 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 new federal restrictions on the hydraulic-fracturing process are adopted in areas where we operate, we may incur significant additional costs or permitting requirements to comply with such federal requirements, and could experience added delays or curtailment in the pursuit of exploration, development, or production activities.

35

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 other regulatory requirements on hydraulic-fracturing operations, including subsurface water disposal. For example, in January 2016, the Colorado Oil and Gas Conservation Commission approved two new rules that require increased collaborative efforts between oil and natural-gas operators and local governments regarding the siting of large-scale oil and natural-gas facilities in certain urban mitigation areas, and require such operators to pursue certain registrations and/or notifications of local governments. States also could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective city limits in 2012 to 2013 but, since that time, local district courts struck down the ordinances for certain of those Colorado cities in 2014, which decisions were upheld by the Colorado Supreme Court in May 2016. Notwithstanding attempts at the local level to prohibit hydraulic fracturing, the opportunity exists for cities to adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions while regulating the time, place, and manner of those activities.
Additionally, certain interest groups in Colorado opposed to oil and natural-gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if approved, would allow revisions to the state constitution in a manner that would make such exploration and production activities in the state more difficult in the future. For example, proponents of such initiatives sought to include on the Colorado November 2016 ballot certain amendments that, if approved, could, among other things, authorize local governmental control over oil and natural-gas development in Colorado that could impose more stringent requirements than currently implemented under state law and impose a 2,500-foot mandatory setback between certain oil and natural-gas development facilities and specified occupied structures and areas of interest. These particular amendments failed to gather enough valid signatures to be placed on the November 2016 ballot. However, Amendment 71 was placed on the Colorado 2016 ballot and approved by voters, making it more difficult to place an initiative to amend the constitution on the state ballot. For an initiative to be placed on the state ballot, Amendment 71 requires signatures from 2% of registered voters from each of the state’s 35 Senate districts and it must be approved by 55% of the voters. In the event that ballot initiatives, local or state restrictions, or prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development, or production activities. In addition, we could 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 compliance costs and delays, curtailments, limitations, 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 have reviewed various environmental issues associated with hydraulic fracturing. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing “water cycle” activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

36

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

Our total debt was $15.3 billion at December 31, 2016. 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 Five-Year Facility and our 364-Day 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% (excluding the effect of non-cash write-downs), 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, 2016, our long-term debt was rated “BBB” with a stable outlook by S&P and Fitch. Our long-term debt was rated “Ba1” with a stable outlook by Moody’s, which is below investment grade. As of the time of filing this Form 10-K, no additional changes in our credit rating have occurred and we are not aware of any current plans of S&P, Fitch, or Moody’s to revise their respective credit ratings on our long-term debt. Any downgrade in our credit ratings could negatively impact our cost of capital and could also adversely affect our ability to effectively execute aspects of our strategy or to raise debt in the public debt markets.
As a result of Moody’s below-investment-grade rating of our long-term debt in February 2016, we became more likely to be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements such as pipeline transportation contracts and oil and gas sales contracts. The amount of letters of credit or cash provided as assurance of our performance under these types of contractual arrangements with respect to credit-risk-related contingent features was $274 million at December 31, 2016, and zero at December 31, 2015. Additionally, certain of these arrangements contain financial assurances language that may, under certain circumstances, permit our counterparties to request additional collateral.
Furthermore, as a result of Moody’s rating, the credit thresholds with certain derivative counterparties were reduced and in some cases eliminated, which required us to increase the amount of collateral posted with derivative counterparties when our net trading position is a liability in excess of the contractual threshold. No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.4 billion (net of $117 million of collateral) at December 31, 2016, and $1.3 billion (net of $58 million of collateral) at December 31, 2015. For additional information, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Additionally, in February 2016, Moody’s downgraded our commercial paper program credit rating, which eliminated our access to the commercial paper market.


37

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 Form 10-K 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, natural-gas, and NGLs 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:
 
•
estimated future production from an area is consistent with historical production from similar producing areas
•
assumed effects of regulation by governmental agencies and court rulings
•
assumptions concerning future oil, natural-gas, and NGLs prices, future operating costs, and capital expenditures
•
estimates of future severance and excise taxes, workover costs, and remedial costs

Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this Form 10-K 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. Therefore, reserves quantities will change when actual prices increase or decrease.

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.


38

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 provincial, federal, regional, state, tribal, local, and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, and hydraulic fracturing, induced seismicity, and environmental protection regulations. To the extent our domestic operations are offshore, we must also comply with requirements focused on oil and natural-gas exploration and production activities in coastal and outer continental shelf (OCS) waters. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various provincial, federal, 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 such as the adoption of government-payment-transparency regulations. In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and natural-gas companies. Such legislative changes have included, but not been limited to, the elimination of current deductions for intangible drilling and development costs, and the elimination of the deduction for certain domestic production activities. The U.S. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation to accompany lower federal income tax rates. Moreover, other more general features of tax-reform legislation, including changes to the rules related to cost recovery and foreign tax credits, and to the deductibility of interest expense, may be developed that also would change the taxation of oil and natural-gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural-gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations, and cash flows.

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 each contributed at various times 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 and impede the execution of long-term sales agreements or prices thereunder which are the basis for future LNG production; affect the ability of our vendors, suppliers, and customers to continue operations; and ultimately adversely impact our results of operations, liquidity, and financial condition.


39

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

We conduct offshore operations in the Gulf of Mexico, Ghana, Mozambique, Colombia, Côte d’Ivoire, and other countries. Our operations and financial results could be significantly impacted by conditions in some of these areas and are also vulnerable to certain unique risks associated with operating offshore, including those relating to the following:
 
•
hurricanes and other adverse weather conditions
•
geological complexities and water depths associated with such operations
•
limited number of partners available to participate in projects
•
oilfield service costs and availability
•
compliance with environmental, safety, 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
•
response capabilities for personnel, equipment, or environmental incidents

In addition, we conduct much of our exploration in deep waters (greater than 1,000 feet) where operations, support services, 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 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.


40

Additional domestic and international deepwater drilling laws, regulations, and other restrictions; delays in the processing and approval of drilling permits and exploration, development, oil spill-response, and decommissioning plans; and other related developments may have a material adverse effect on our business, financial condition, or results of operations.

In recent years, the Bureau of Ocean Energy Management (BOEM) and the BSEE, agencies of the U.S. Department of the Interior, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. For example, in 2016, BSEE finalized rule-making entitled Oil and Sulfur Operations on the Outer Continental Shelf — Blowout Prevention Systems and Well Control which focuses on well blowout preventer systems and well control with respect to operations on the OCS. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.
In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural-gas exploration and production operations conducted offshore. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissions requirements relating to offshore oil and natural-gas activity on federal OCS waters including in the Central Gulf of Mexico. In addition, in September 2016, the BOEM issued a Notice to Lessees and Operators that would bolster supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines, and other facilities. These regulatory actions, or any new rules, regulations, or legal initiatives 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 or result in the suspension or cancellation of leases. Moreover, under existing BOEM and BSEE rules relating to assignment of offshore leases and other legal interests on the OCS, assignors of such interests may be held jointly and severally liable for decommissioning of OCS facilities existing at the time the assignment was approved by the BOEM, in the event that the assignee is unable or unwilling to conduct required decommissioning. In the event that we, in the role of assignor, receive orders from the BSEE to decommission OCS facilities that one of our assignees of offshore facilities is unwilling or unable to perform, we could incur costs to perform those decommissioning obligations, which costs could be material.
Also, if material spill events were to occur in the future, the United States or other countries where such an event were to occur could elect to 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, regulations, or legal initiatives on our drilling operations or on the cost or availability of insurance to cover the risks associated with such operations. The overall costs to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete.
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 our oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to potential material events in the future.
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.


41

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

We have operations outside the United States, including in Algeria, Ghana, Mozambique, Colombia, Côte d’Ivoire, and other countries. 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
•
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 boundary 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 the TEN complex is located. In the event Côte d’Ivoire is successful in its maritime border claims, our operations in Ghana could be materially impacted.
Outbreaks of civil and political unrest and acts of terrorism have occurred in countries in Europe, Africa, and the Middle East, including countries close to or 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 our financial condition, results of operations, or cash flows.

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. The cost for such items may increase as a result of a variety of factors beyond our control, such as increases in the cost of electricity, steel, and other raw materials that we and our vendors rely upon; increased demand for labor, services, and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling rigs, equipment, supplies, or qualified personnel. However, if commodity prices rise, such costs may rise faster than increases in our revenue 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.

42

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 facilities 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 facilities. Moreover, to the extent that purchasers of our 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 us 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 natural gas, including blowouts; cratering and fire; environmental hazards such as natural-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.

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


43

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), enacted in 2010, requires the Commodity 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 position limits rule, remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time.
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, and (iii) reduce the availability and use of derivatives to protect against risks we encounter. 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 we transact with counterparties in foreign jurisdictions, those transactions may become subject to such regulations. At this time, the impact of such regulations is not clear.

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 and funding 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 integrated 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.


44

Our drilling activities may not encounter commercially productive oil or natural-gas reservoirs.

Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or natural-gas reservoirs. 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
•
lack of availability or delays in the delivery of technology, equipment, or resources for operations

As of December 31, 2016, we had $1.7 billion in suspended well and associated non-producing leasehold costs related to 11 U.S. offshore and international exploration projects, which includes approximately $800 million related to our Shenandoah project in the Gulf of Mexico. Certain of these future exploration and appraisal drilling activities may not be successful and, if unsuccessful, could result in a material 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 higher-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 or timing 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.


45

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

As a result of mergers and acquisitions, we had approximately $5.0 billion of goodwill on our Consolidated Balance Sheet at December 31, 2016. 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 reduce the fair value of a reporting unit such as our inability to replace the value of our 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 lead to an impairment of goodwill. An impairment of goodwill could have a substantial negative effect on our reported earnings.

Risks related to acquisitions may adversely affect our business, financial condition, and results of operations.

Any acquisition, including the recent GOM Acquisition, involves potential risks, including, among other things:

•
the validity of our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses, and costs
•
the assumption of environmental, decommissioning, and other liabilities, and losses or costs for which we are not indemnified or for which our indemnity is inadequate
•
a failure to attain or maintain compliance with environmental, safety, and other governmental regulations

If any of these risks materialize, the benefits of such acquisition may not be fully realized, if at all, and our business, financial condition, and results of operations could be negatively impacted.

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 those of third parties 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.

46

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. In response to the commodity-price environment, in February 2016, the Company decreased the quarterly dividend from $0.27 per share to $0.05 per share. The amount of cash dividends, if any, to be paid in the future is determined by our Board of Directors based on our financial condition, results of operations, cash flows, levels of capital and exploration expenditures, future business prospects, expected liquidity needs, and other 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 could be 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.


47

Item 3.  Legal Proceedings

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 personal injury and death claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, development, 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, tribal, 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.
WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA with respect to 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.
Anadarko E&P Onshore LLC, a wholly owned subsidiary of the Company, is currently in negotiations with the Pennsylvania Fish and Boat Commission and the Pennsylvania Department of Environmental Protection concerning enforcement over a produced water release in Pennsylvania in 2015. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of these matters will result in a fine or penalty in excess of $100,000.
Kerr-McGee Oil and Gas Onshore, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the State of Colorado’s Department of Public Health and Environment with respect to alleged noncompliance with the Colorado Air Quality Control Commission’s Regulations. 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 16—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.

48

PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

MARKET INFORMATION, HOLDERS, AND DIVIDENDS

At January 31, 2017, there were approximately 10,280 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 2016 and 2015:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2016
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
50.39

 
$
57.00

 
$
63.84

 
$
73.33

Low
$
28.16

 
$
43.52

 
$
50.23

 
$
58.59

Dividends
$
0.05

 
$
0.05

 
$
0.05

 
$
0.05

2015
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
90.10

 
$
95.94

 
$
78.70

 
$
73.87

Low
$
73.82

 
$
77.75

 
$
58.10

 
$
44.50

Dividends
$
0.27

 
$
0.27

 
$
0.27

 
$
0.27


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—Financing Activities—Common Stock Dividends and Distributions to Noncontrolling Interest Owners under Item 7 of this Form 10-K.

49

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, 2016:
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
 
6,620,252

 
$
76.10

 
33,927,750

Equity compensation plans not approved by security holders
 
—

 
—

 
—

Total
 
6,620,252

 
$
76.10

 
33,927,750


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 2016:
Period
 
Total
number of
shares
purchased (1)
 
Average
price paid
per share
 
Total number of
shares purchased
as part of publicly
announced plans
or programs
 
Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs
October 1-31, 2016
 
29,815

 
$
61.63

 
—

 
 
November 1-30, 2016
 
46,041

 
$
59.09

 
—

 
 
December 1-31, 2016
 
13,067

 
$
69.44

 
—

 
 
Total
 
88,923

 
$
61.46

 
—

 
$
—

 _______________________________________________________________________________
(1) 
During the fourth quarter of 2016, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans.

For additional information, see Note 21—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

50

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 two peer groups. The 11 companies included in the 2016 peer group are Apache Corporation; Chesapeake Energy Corporation; Chevron Corporation; ConocoPhillips; Devon Energy Corporation; EOG Resources, Inc.; Hess Corporation; Marathon Oil Corporation; Noble Energy, Inc.; Occidental Petroleum Corporation; and Pioneer Natural Resources Company. The 11 companies included in the 2015 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. Murphy Oil Corporation was removed from the peer group due to it being low in relative size after spinning off its retail marketing business and was replaced with Chesapeake Energy Corporation.

Comparison of 5-Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index,
the 2016 Peer Group, and the 2015 Peer Group
performnacegraph2016a01.jpg

Copyright© 2017 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 2016 and 2015 Peer Groups on December 31, 2011, and its relative performance is tracked through December 31, 2016. 
Fiscal Year Ended December 31
2011
 
2012
 
2013
 
2014
 
2015
 
2016
Anadarko Petroleum Corporation
$
100.00

 
$
97.84

 
$
105.07

 
$
110.47

 
$
66.07

 
$
95.18

S&P 500
100.00

 
116.00

 
153.58

 
174.60

 
177.01

 
198.18

2016 Peer Group
100.00

 
101.98

 
128.16

 
118.26

 
90.77

 
118.40

2015 Peer Group
100.00

 
101.04

 
127.81

 
117.70

 
89.44

 
116.70


51

Item 6.  Selected Financial Data
 
Summary Financial Information (1)
millions except per-share amounts
2016
 
2015
 
2014
 
2013
 
2012
Sales Revenues
$
8,447

 
$
9,486

 
$
16,375

 
$
14,867

 
$
13,307

Gains (Losses) on Divestitures and Other, net
(578
)
 
(788
)
 
2,095

 
(286
)
 
104

Total Revenues and Other
7,869

 
8,698

 
18,470

 
14,581

 
13,411

Other Operating (Income) Expense
 
 
 
 
 
 
 
 
 
Algeria Exceptional Profits Tax Settlement
—

 
—

 
—

 
33

 
(1,797
)
Operating Income (Loss)
(2,599
)
 
(8,809
)
 
5,403

 
3,333

 
3,727

Tronox-related Contingent Loss
—

 
5

 
4,360

 
850

 
(250
)
Income (Loss)
(2,808
)
 
(6,812
)
 
(1,563
)
 
941

 
2,445

Net Income (Loss) Attributable to Common Stockholders
(3,071
)
 
(6,692
)
 
(1,750
)
 
801

 
2,391

Per Common Share (amounts attributable to common stockholders)
 
 
 
 
 
 
 
 
 
Net Income (Loss)—Basic
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
 
$
1.58

 
$
4.76

Net Income (Loss)—Diluted
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
 
$
1.58

 
$
4.74

Dividends
$
0.20

 
$
1.08

 
$
0.99

 
$
0.54

 
$
0.36

Average Number of Common Shares Outstanding—Basic
522

 
508

 
506

 
502

 
500

Average Number of Common Shares Outstanding—Diluted
522

 
508

 
506

 
505

 
502

Cash Provided by (Used in) Operating Activities
3,000

 
(1,877
)
 
8,466

 
8,888

 
8,339

Capital Expenditures
$
3,314

 
$
5,888

 
$
9,256

 
$
8,523

 
$
7,311

Short-term Debt (4)
$
42

 
$
32

 
$
—

 
$
500

 
$
—

Long-term Debt (2) (4)
15,281

 
15,636

 
15,004

 
12,984

 
13,180

Total Debt (4)
$
15,323

 
$
15,668

 
$
15,004

 
$
13,484

 
$
13,180

Total Stockholders’ Equity
12,212

 
12,819

 
19,725

 
21,857

 
20,629

Total Assets
$
45,564

 
$
46,414

 
$
60,967

 
$
55,421

 
$
52,261

Annual Sales Volumes
 
 
 
 
 
 
 
 
 
Oil (MMBbls)
116

 
116

 
106

 
91

 
86

Natural Gas (Bcf)
766

 
852

 
945

 
968

 
913

Natural Gas Liquids (MMBbls)
46

 
47

 
44

 
33

 
30

Total (MMBOE) (3)
290

 
305

 
308

 
285

 
268

Average Daily Sales Volumes
 
 
 
 
 
 
 
 
 
Oil (MBbls/d)
316

 
317

 
292

 
248

 
233

Natural Gas (MMcf/d)
2,093

 
2,334

 
2,589

 
2,652

 
2,495

Natural Gas Liquids (MBbls/d)
128

 
130

 
119

 
91

 
83

Total (MBOE/d)
793

 
836

 
843

 
781

 
732

Proved Reserves
 
 
 
 
 
 
 
 
 
Oil Reserves (MMBbls)
702

 
713

 
929

 
851

 
767

Natural-gas Reserves (Tcf)
4.4

 
6.0

 
8.7

 
9.2

 
8.3

Natural-gas Liquids Reserves (MMBbls)
283

 
340

 
479

 
407

 
405

Total Proved Reserves (MMBOE)
1,722

 
2,057

 
2,858

 
2,792

 
2,560

Number of Employees
4,500

 
5,800

 
6,100

 
5,700

 
5,200

(1) 
Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
(2) 
Includes WGP debt of $28 million at December 31, 2016. Includes WES debt of $3.1 billion at December 31, 2016, $2.7 billion at December 31, 2015, $2.4 billion at December 31, 2014, $1.4 billion at December 31, 2013, and $1.2 billion at December 31, 2012.
(3) 
Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.
(4) 
As a result of adopting ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, the Company reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million in 2015, $88 million in 2014, $81 million in 2013, and $89 million in 2012. See Note 1 - Summary of Significant Accounting Policies in the Notes to the Consolidated Financial Statements under Item 8 of this Form 10-K.

52

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 Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.

MANAGEMENT OVERVIEW

In 2016, Anadarko optimized and further concentrated its portfolio on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely the Delaware and DJ basins in the U.S. onshore and deepwater Gulf of Mexico. As part of this effort, the Company closed or announced divestitures of numerous non-core U.S. onshore assets primarily located in South Texas, West Texas, East Texas/Louisiana, Wyoming, Kansas, and Pennsylvania while completing the GOM Acquisition. The GOM Acquisition expanded Anadarko’s operated infrastructure and substantial tie-back inventory, more than doubled the Company’s ownership interest in the Lucius development to approximately 49%, and doubled its net production from the Gulf of Mexico to more than 160 MBOE/d, more than 80% of which is comprised of oil. The acquired assets are expected to generate substantial cash flow over the next five years at current strip prices, allowing the Company to increase investment and growth in the Delaware and DJ basins. The Company expects to end the first quarter of 2017 with 14 operated drilling rigs in the Delaware basin and 6 operated drilling rigs in the DJ basin, which compares to 7 operated drilling rigs in the Delaware basin and 1 operated drilling rig in the DJ basin at the end of the third quarter of 2016. Recent successful exploration activity with the Warrior discovery and Phobos appraisal wells, which each provide tie-back opportunities, further demonstrate the value of the Company’s operated infrastructure and its hub-and-spoke capabilities in the deepwater Gulf of Mexico.
As with any oil and natural-gas exploration and production company, Anadarko’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly influenced by commodity prices, which affect the value the Company receives from its sales of oil, natural gas, and NGLs. Supply and demand have been slow to return to a sustained equilibrium following the decline in commodity prices in 2015 and 2016, although the November 2016 OPEC decision to cut production is expected to help accelerate the drawdown of global oil inventories. Recognizing the lower commodity-price environment, Anadarko enhanced its liquidity position by retiring and/or redeeming near-term debt maturities, primarily with proceeds from debt issued in the first quarter of 2016; executing the aforementioned monetization program; reducing capital expenditures by approximately 50% (excluding WES) relative to the prior year; enhancing operational efficiencies; and improving its cost structure through a dividend decrease and workforce reduction program. Anadarko believes that the actions taken in 2016 have positioned it well with the necessary financial flexibility to fund the Company’s current and long-term operations.

53

Significant 2016 operating and financial activities include the following:
Total Company
•
The Company’s oil sales volumes were flat year over year, while the Company’s 2016 capital budget (excluding WES) was reduced by nearly 50%.
•
The Company’s overall sales-volume product mix increased to 56% liquids in 2016 compared to 53% in 2015.
•
The Company improved its cost structure by approximately $800 million annually after 2016 through a dividend decrease and a workforce reduction program.
•
The Company closed approximately $4 billion of monetizations in 2016, including asset divestitures in the U.S. onshore, the sale of Anadarko’s interest in Springfield Pipeline LLC to WES, the sale of a portion of the Company’s common units in WGP to the public, and the Company’s conveyance of a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party.
U.S. Onshore
•
In December 2016, the Company entered into an agreement to sell its Marcellus oil and gas assets and certain related midstream assets for approximately $1.2 billion. In January 2017, the Company entered into an agreement to sell its Eagleford oil and gas assets for approximately $2.3 billion. These transactions are expected to close in the first quarter of 2017.
•
Total sales volumes in the DJ basin averaged 244 MBOE/d, representing a 9% or 20 MBOE/d increase from 2015.
•
Total sales volumes in the Delaware basin averaged 45 MBOE/d, representing a 41% or 13 MBOE/d increase from 2015. Oil sales volumes in the Delaware basin increased 8 MBbls/d, representing a 50% increase from 2015.
•
The Company increased rig activity in the Delaware and DJ basins during the year, ending 2016 with nine operated rigs in the Delaware basin and five operated rigs in the DJ basin, compared to six rigs in the Delaware basin and two in the DJ basin in the first quarter of 2016.
Gulf of Mexico
•
In December 2016, the Company acquired oil and gas assets in the Gulf of Mexico for $1.8 billion net of purchase-price adjustments, expanding its operated infrastructure and substantial tie-back inventory.
•
Oil sales volumes averaged 65 MBbls/d, representing a 23% increase from 2015, primarily due to new wells coming online in 2016 at Caesar/Tonga and K2, first oil from Heidelberg, and an increased flow rate at Lucius.
International
•
The TEN development project (19% nonoperated participating interest) in Ghana achieved first oil in the third quarter of 2016.
•
In 2016, the operator at the Jubilee field in Ghana announced that damage to the FPSO turret bearing had occurred. As a result, new production and offtake procedures were implemented and the partners agreed to a long-term solution to convert the FPSO to a permanently-moored facility. Interim mooring of the vessel commenced in the fourth quarter of 2016 and is expected to be completed during the first quarter of 2017. Final decisions and approvals will be sought for the long-term turret system solution in the first half of 2017. It is anticipated that a facility shutdown of up to 12 weeks may be required in the second half of 2017. The partnership is actively seeking optimization solutions to minimize the duration of any shutdown period.
•
The Company’s Algeria operations achieved the highest production rates since 2009 due to the completion of the increased water-handling project at the Ourhoud facility and obtaining approval of a new reservoir development plan for the El Merk fields allowing for higher plateau rates.
•
During the fourth quarter of 2016, the Development Plan for the initial two-train onshore LNG project in Mozambique was submitted to the Government of Mozambique.

54

Financial
•
The Company generated $3.0 billion of cash flow from operations and ended 2016 with $3.2 billion of cash.
•
During the second quarter of 2016, the Company used proceeds from a March 2016 public offering of Senior Notes totaling $3.0 billion due 2021, 2026, and 2046 to redeem its $1.750 billion Senior Notes due 2016 and to purchase and retire $1.25 billion of its Senior Notes due 2017. In the fourth quarter of 2016, Anadarko redeemed its remaining $750 million Senior Notes due 2017.
•
During the third quarter of 2016, the Company completed a public offering of 40.5 million shares of its common stock for net proceeds of $2.16 billion. Net proceeds were primarily used to fund the GOM Acquisition.

FINANCIAL RESULTS
millions except per-share amounts
2016
 
2015
 
2014
Oil, natural-gas, and NGLs sales
$
7,153

 
$
8,260

 
$
15,169

Gathering, processing, and marketing sales
1,294

 
1,226

 
1,206

Gains (losses) on divestitures and other, net
(578
)
 
(788
)
 
2,095

Revenues and other
$
7,869

 
$
8,698

 
$
18,470

Costs and expenses
10,468

 
17,507

 
13,067

Other (income) expense
1,230

 
880

 
5,349

Income tax expense (benefit)
(1,021
)
 
(2,877
)
 
1,617

Net income (loss) attributable to common stockholders
$
(3,071
)
 
$
(6,692
)
 
$
(1,750
)
Net income (loss) per common share attributable to common stockholders—diluted
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
Average number of common shares outstanding—diluted
522

 
508

 
506


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, 2016,” refer to the comparison of the year ended December 31, 2016, to the year ended December 31, 2015. Similarly, any increases or decreases “for the year ended December 31, 2015,” refer to the comparison of the year ended December 31, 2015, to the year ended December 31, 2014.


55

Revenues and Sales Volumes
millions
Oil
 
Natural
Gas
 
NGLs
 
Total
2015 sales revenues
$
5,420

 
$
2,007

 
$
833

 
$
8,260

Changes associated with prices
(745
)
 
(241
)
 
95

 
(891
)
Changes associated with sales volumes
(7
)
 
(202
)
 
(7
)
 
(216
)
2016 sales revenues
$
4,668

 
$
1,564

 
$
921

 
$
7,153

Increase/(decrease) vs. 2015
(14
)%
 
(22
)%
 
11
 %
 
(13
)%
 
 
 
 
 
 
 
 
2014 sales revenues
$
9,748

 
$
3,849

 
$
1,572

 
$
15,169

Changes associated with prices
(5,189
)
 
(1,462
)
 
(871
)
 
(7,522
)
Changes associated with sales volumes
861

 
(380
)
 
132

 
613

2015 sales revenues
$
5,420

 
$
2,007

 
$
833

 
$
8,260

Increase/(decrease) vs. 2014
(44
)%
 
(48
)%
 
(47
)%
 
(46
)%

The above table illustrates the effects of the lower commodity-price environment in 2015 and 2016 as decreases in commodity prices were the main driver of the Company’s sales revenue decreases year over year. 
Over the past few years, the Company’s investment focus has shifted towards high-margin oil assets and the Company has divested several non-core assets resulting in decreased natural-gas volumes in 2015 and 2016.

The following provides Anadarko’s sales volumes for the years ended December 31:
 
 
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
Barrels of Oil Equivalent
 
 
 
 
 
 
 
 
 
 
(MMBOE except percentages)
 
 
 
 
 
 
 
 
 
 
United States
 
257

 
(5
)%
 
272

 
(1
)%
 
275

International
 
33

 
(1
)
 
33

 
(1
)
 
33

Total barrels of oil equivalent
 
290

 
(5
)
 
305

 
(1
)
 
308

 
 
 
 
 
 
 
 
 
 
 
Barrels of Oil Equivalent per Day
 
 
 
 
 
 
 
 
 
 
(MBOE/d except percentages)
 
 
 
 
 
 
 
 
 
 
United States
 
704

 
(5
)%
 
745

 
(1
)%
 
751

International
 
89

 
(1
)
 
91

 
(1
)
 
92

Total barrels of oil equivalent per day
 
793

 
(5
)
 
836

 
(1
)
 
843

 

Sales volumes represent production volumes adjusted for changes in commodity inventories and natural-gas production volumes provided to satisfy a commitment established in conjunction with the Jubilee development plan in Ghana. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.


56

Oil Sales Revenues, Average Prices, and Volumes
 
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
Oil sales revenues (millions)
$
4,668

 
(14
)%
 
$
5,420

 
(44
)%
 
$
9,748

 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
85

 
1
 %
 
85

 
14
 %
 
74

MBbls/d
233

 
1

 
232

 
14

 
203

Price per barrel
$
39.06

 
(13
)
 
$
45.00

 
(49
)
 
$
87.99

 
 
 
 
 
 
 
 
 
 
International
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
31

 
(2
)%
 
31

 
(4
)%
 
32

MBbls/d
83

 
(2
)
 
85

 
(4
)
 
89

Price per barrel
$
43.93

 
(15
)
 
$
51.68

 
(48
)
 
$
99.79

 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
116

 
—
 %
 
116

 
9
 %
 
106

MBbls/d
316

 
—

 
317

 
9

 
292

Price per barrel
$
40.34

 
(14
)
 
$
46.79

 
(49
)
 
$
91.58


The following summarizes primary drivers for the change in oil sales revenues:
millions
Change in Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
2016 vs. 2015
$
(752
)
 
$
(745
)
 
$
(7
)
2015 vs. 2014
(4,328
)
 
(5,189
)
 
861


Oil Prices

The average oil price Anadarko received decreased from late 2014 through late 2016 primarily due to continued high global petroleum inventories and strong supply growth from OPEC. Oil prices began to improve in late 2016 following OPEC’s decision to curb production for the first six months of 2017.


57

Oil Sales Volumes

2016 vs. 2015 The Company’s oil sales volumes remained relatively flat.
U.S. Onshore
•
Sales volumes for the Delaware basin increased by 8 MBbls/d primarily due to continued field development.
•
Sales volumes for the DJ basin decreased by 6 MBbls/d primarily due to reduced capital activity.
•
Sales volumes decreased by 7 MBbls/d primarily due to the sale of certain EOR assets in 2015 and the sale of certain Wyoming and East Texas/Louisiana assets in 2016.

Gulf of Mexico
•
Sales volumes increased by 12 MBbls/d, primarily due to new wells coming online at K2 and Caesar/Tonga in the first half of 2016, an increased flow rate at Lucius, and the achievement of first oil at Heidelberg in January 2016.

International
•
Sales volumes for Ghana decreased by 7 MBbls/d primarily due to downtime during 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing. Shuttle tankers are conducting offtakes until the facility is permanently moored. The decrease in volumes at Jubilee were partially offset by TEN coming online late in the third quarter.

2015 vs. 2014 The Company’s oil sales volumes increased by 25 MBbls/d primarily due to the following:
U.S. Onshore
•
Sales volumes for the DJ basin increased by 21 MBbls/d primarily due to continued horizontal drilling activity.
•
Sales volumes for the Delaware basin increased by 3 MBbls/d primarily due to wells brought online as a result of additional infrastructure and continued drilling.
•
Sales volumes decreased by 10 MBbls/d primarily due to the sale of certain EOR assets in 2015.

Gulf of Mexico
•
Sales volumes for Lucius increased by 14 MBbls/d primarily due to the achievement of first oil in the first quarter of 2015.


58

Natural-Gas Sales Revenues, Volumes, and Average Prices
 
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
Natural-gas sales revenues (millions)
$
1,564

 
(22
)%
 
$
2,007

 
(48
)%
 
$
3,849

 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
Sales volumes—Bcf
766

 
(10
)%
 
852

 
(10
)%
 
945

MMcf/d
2,093

 
(10
)
 
2,334

 
(10
)
 
2,589

Price per Mcf
$
2.04

 
(14
)
 
$
2.36

 
(42
)
 
$
4.07


The following summarizes primary drivers for the change in natural-gas sales revenues:
millions
Change in Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
2016 vs 2015
$
(443
)
 
$
(241
)
 
$
(202
)
2015 vs 2014
(1,842
)
 
(1,462
)
 
(380
)

Natural-Gas Prices

The average natural-gas price Anadarko received decreased from 2014 through 2016 primarily due to strong year over year production growth in the northeast United States coupled with lower weather-driven residential and commercial demand in 2015, which led to high gas storage levels in 2016. High storage levels persisted through the majority of 2016.
 
Natural-Gas Sales Volumes

2016 vs. 2015 The Company’s natural-gas sales volumes decreased by 241 MMcf/d primarily due to the following:
U.S. Onshore
•
Sales volumes for the DJ basin increased by 98 MMcf/d primarily due to improved performance.
•
Sales volumes for the Delaware basin increased by 18 MMcf/d primarily due to continued field development.
•
Sales volumes decreased by 290 MMcf/d primarily due to the sale of certain coalbed methane properties and certain U.S. onshore properties and related midstream assets in East Texas in 2015 and the sale of certain Wyoming and East Texas/Louisiana assets in 2016.

Gulf of Mexico
•
Sales volumes decreased by 61 MMcf/d primarily as a result of the last producing well at Independence Hub going off line in December 2015.

2015 vs. 2014  The Company’s natural-gas sales volumes decreased by 255 MMcf/d primarily due to the following:
U.S. Onshore
•
Sales volumes for Marcellus shale decreased by 118 MMcf/d primarily due to production modulation and third-party infrastructure downtime.
•
Sales volumes for Greater Natural Buttes decreased by 89 MMcf/d primarily due to production modulation.
•
Sales volumes for the DJ basin increased by 144 MMcf/d primarily due to continued horizontal drilling activity.
•
Sales volumes decreased by 137 MMcf/d primarily due to the sale of certain U.S. onshore properties and related midstream assets in East Texas and the sale of certain coalbed methane properties in 2015.

Gulf of Mexico
•
Sales volumes decreased by 60 MMcf/d primarily due to natural production decline at Independence Hub.

59

Natural-Gas Liquids Sales Revenues, Volumes, and Average Prices
 
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
Natural-gas liquids sales revenues (millions)
$
921

 
11
 %
 
$
833

 
(47
)%
 
$
1,572

 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
44

 
(1
)%
 
45

 
6
 %
 
43

MBbls/d
122

 
(1
)
 
124

 
6

 
116

Price per barrel
$
19.32

 
13

 
$
17.03

 
(52
)
 
$
35.48

 
 
 
 
 
 
 
 
 
 
International
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
2

 
10
 %
 
2

 
91
 %
 
1

MBbls/d
6

 
10

 
6

 
91

 
3

Price per barrel
$
25.63

 
(14
)
 
$
29.85

 
(47
)
 
$
56.16

 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
Sales volumes—MMBbls
46

 
(1
)%
 
47

 
8
 %
 
44

MBbls/d
128

 
(1
)
 
130

 
8

 
119

Price per barrel
$
19.64

 
12

 
$
17.61

 
(51
)
 
$
36.01


The following summarizes primary drivers for the change in NGLs sales revenues:
millions
Change in Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
2016 vs. 2015
$
88

 
$
95

 
$
(7
)
2015 vs. 2014
(739
)
 
(871
)
 
132


NGLs Prices

The average NGLs price Anadarko received decreased from 2014 to 2015, primarily due to the related decline in oil prices over the same period. Prices began recovering in 2016 due to overall higher demand, resulting in an increase in NGLs prices in 2016.

NGLs Sales Volumes

NGLs sales represent revenues from the sale of products derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes remained relatively flat from 2014 through 2016.


60

Gathering, Processing, and Marketing
millions except percentages
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
Gathering, processing, and marketing sales
$
1,294

 
6
%
 
$
1,226

 
2
 %
 
$
1,206

Gathering, processing, and marketing expense
1,087

 
3

 
1,054

 
2

 
1,030

Total gathering, processing, and marketing, net
$
207

 
20

 
$
172

 
(2
)
 
$
176


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.

2016 vs. 2015  Gathering, processing, and marketing, net increased by $35 million. This increase primarily related to higher gas and NGLs throughput volumes at the DJ basin and DBM complex.

2015 vs. 2014  Gathering, processing, and marketing, net remained relatively flat.

Gains (Losses) on Divestitures and Other, net
millions except percentages
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
Gains (losses) on divestitures, net
$
(757
)
 
26
 %
 
$
(1,022
)
 
(154
)%
 
$
1,891

Other
179

 
(24
)
 
234

 
15

 
204

Total gains (losses) on divestitures and other, net
$
(578
)
 
27

 
$
(788
)
 
(138
)
 
$
2,095


Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues, including hard-minerals royalties, earnings from equity investments, and other revenues.
During 2016 and 2015, Anadarko divested of certain non-core U.S. onshore assets and recognized net losses of $757 million in 2016 and $1.0 billion in 2015.
In 2014, the Company recognized net gains of $1.9 billion primarily associated with the divestitures of a 10% working interest in Offshore Area 1 in Mozambique and the Company’s Chinese subsidiary.
See Note 3—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.

61

Costs and Expenses

The following provides Anadarko’s total costs and expenses for the years ended December 31:
millions
2016
 
2015
 
2014
Oil and gas operating
$
811

 
$
1,014

 
$
1,171

Oil and gas transportation
1,002

 
1,117

 
1,116

Exploration
946

 
2,644

 
1,639

Gathering, processing, and marketing
1,087

 
1,054

 
1,030

General and administrative
1,440

 
1,176

 
1,316

DD&A
4,301

 
4,603

 
4,550

Production, property, and other taxes
536

 
553

 
1,244

Impairments
227

 
5,075

 
836

Other operating expense
118

 
271

 
165

Total
$
10,468

 
$
17,507

 
$
13,067


Oil and Gas Operating and Transportation Expenses
 
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
Oil and gas operating (millions)
$
811

 
(20
)%
 
$
1,014

 
(13
)%
 
$
1,171

Oil and gas operating—per BOE
2.79

 
(16
)
 
3.32

 
(13
)
 
3.81

Oil and gas transportation (millions)
1,002

 
(10
)
 
1,117

 
—

 
1,116

Oil and gas transportation—per BOE
3.46

 
(5
)
 
3.66

 
1

 
3.63


Oil and Gas Operating Expenses
2016 vs. 2015  Oil and gas operating expenses decreased by $203 million primarily due to the following:
•
lower expenses of $112 million as a result of divestitures
•
lower workover costs of $28 million in the Gulf of Mexico and the U.S. onshore
•
lower surface maintenance costs of $16 million in the U.S. onshore and the Gulf of Mexico
The related costs per BOE decreased by $0.53 primarily due to continued cost reduction initiatives and efficiencies across the Company’s U.S. operating areas.

2015 vs. 2014  Oil and gas operating expenses decreased by $157 million primarily due to the following:
•
lower expenses of $73 million as a result of divestitures
•
lower workover costs of $49 million as a result of reduced activity primarily in the U.S. onshore
•
lower surface maintenance expenses of $21 million primarily in the U.S. onshore
The related costs per BOE decreased by $0.49 due to cost reduction initiatives and efficiencies across the Company’s U.S. operating areas.

Oil and Gas Transportation Expenses
2016 vs. 2015  Oil and gas transportation expenses decreased by $115 million due to overall lower gas sales volumes. Oil and gas transportation expenses per BOE decreased by $0.20 primarily due to lower costs as a result of lower gas sales volumes.

2015 vs. 2014  Oil and gas transportation expenses and expenses per BOE were relatively flat.


62

Exploration Expense
millions
2016
 
2015
 
2014
Dry hole expense
$
397

 
$
1,052

 
$
762

Impairments of unproved properties
216

 
1,215

 
483

Geological and geophysical expense
121

 
168

 
168

Exploration overhead and other
212

 
209

 
226

Total exploration expense
$
946

 
$
2,644

 
$
1,639


Dry Hole Expense
2016 
•
The Company expensed suspended exploratory well costs of $231 million related to certain wells in the Gulf of Mexico and $92 million related to certain wells in Mozambique. See Note 6—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
•
The Company expensed $39 million for a well in Côte d’Ivoire that finished drilling in the third quarter of 2016 and encountered noncommercial quantities of hydrocarbons.
•
Anadarko expensed $35 million due to unsuccessful drilling activities primarily associated with Gulf of Mexico and U.S. onshore properties.

2015
•
The Company expensed suspended exploratory well costs of $746 million in 2015, primarily related to Brazil where the Company does not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment and other considerations.
•
The Company expensed $306 million due to unsuccessful drilling activities in 2015 primarily in Colombia and the Gulf of Mexico.

2014
•
Anadarko expensed $762 million due to unsuccessful drilling activities in 2014 associated with wells in the Gulf of Mexico, U.S. onshore, and Mozambique.

Impairments of Unproved Properties
2016 
•
The Company recognized a $72 million impairment of unproved properties in the Gulf of Mexico and $92 million for unproved international properties primarily in Brazil and Tunisia due to the Company’s current intentions to not pursue future exploration activities.

2015
•
The Company recognized a $935 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unproved Gulf of Mexico property as a result of lower commodity prices.
•
The Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.


63

2014
•
The Company recognized impairments of $302 million primarily related to lower oil prices, a reduction of reserves, and the expiration of certain leases in the Gulf of Mexico.
•
The Company recognized impairments of $50 million due to the decision not to pursue further drilling in Sierra Leone.
•
The Company recognized impairments of $38 million in 2014 as a result of changes in the Company’s drilling plans for certain U.S. onshore oil and gas properties.

General and Administrative Expenses
millions except percentages
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
General and administrative
$
1,440

 
22
%
 
$
1,176

 
(11
)%
 
$
1,316


2016 vs. 2015  G&A for the year ended December 31, 2016, included $389 million of charges associated with a workforce reduction program initiated in March 2016. Excluding the workforce reduction expenses, G&A decreased by $125 million primarily due to lower employee-related expenses resulting from the workforce reduction. See Note 17—Restructuring Charges in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

2015 vs. 2014  G&A expense decreased by $140 million primarily due to lower bonus plan expense and lower legal fees, partially offset by increased benefit plan expense.

Depreciation, Depletion, and Amortization
millions except percentages
2016
 
Inc (Dec) 
 vs. 2015
 
2015
 
Inc (Dec) 
 vs. 2014
 
2014
DD&A
$
4,301

 
(7
)%
 
$
4,603

 
1
%
 
$
4,550


2016 vs. 2015  DD&A expense decreased by $302 million, primarily due to the following:
•
lower carrying value for U.S. onshore and midstream properties as a result of 2015 asset impairments and divestitures in 2015 and 2016
•
lower 2016 sales volumes associated with U.S. onshore properties

2015 vs. 2014  DD&A expense remained relatively flat.


64

Impairments

The Company recognized the following impairments for the years ended December 31:
millions
2016
 
2015
 
2014
Oil and gas exploration and production
 
 
 
 
 
U.S. onshore properties
$
28

 
$
3,684

 
$
545

Gulf of Mexico properties
27

 
349

 
276

Cost-method investment
59

 
3

 
3

Midstream
73

 
1,039

 
12

Other
40

 
—

 
—

Total impairments (1)
$
227

 
$
5,075

 
$
836

__________________________________________________________________
(1) 
In 2015, $3.0 billion of oil and gas exploration and production impairments and $482 million of midstream asset impairments related to Greater Natural Buttes.

Potential for Future Impairments At December 31, 2016, the Company’s estimates of undiscounted future cash flows attributable to a certain international asset group with a net book value of approximately $1.3 billion indicated that the carrying amount was expected to be recovered; however, this asset group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that a 10% decline in oil prices (with all other assumptions unchanged) could result in a non-cash impairment in excess of $550 million for the asset group. It is also reasonably possible that significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in other additional impairments.

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.

Other (Income) Expense

The following provides Anadarko’s other (income) expense for the years ended December 31:
millions
2016
 
2015
 
2014
Interest expense
$
890

 
$
825

 
$
772

Loss on early extinguishment of debt (1)
155

 
—

 
—

(Gains) losses on derivatives, net (2)
286

 
(99
)
 
197

Other (income) expense, net
(101
)
 
149

 
20

Tronox-related contingent loss (3)
—

 
5

 
4,360

Total
$
1,230

 
$
880

 
$
5,349

__________________________________________________________________
(1) 
See Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for information on early extinguishment of debt.
(2) 
See Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(3) 
See Note 16—Contingencies —Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


65

Interest Expense
millions
2016
 
2015
 
2014
Current debt, long-term debt, and other
$
1,022

 
$
989

 
$
973

Capitalized interest
(132
)
 
(164
)
 
(201
)
Total interest expense
$
890

 
$
825

 
$
772


2016 vs. 2015  Interest expense increased by $65 million.
•
Interest expense on debt and other increased by $33 million primarily related to WES debt issuances in 2015 and 2016 and interest expense related to the Ghana TEN capital lease commencement in the third quarter of 2016.
•
Capitalized interest decreased by $32 million primarily due to lower construction-in-progress balances for long-term capital projects in Brazil and the completion of the Heidelberg development, partially offset by higher construction in progress balances related to projects in Mozambique, Côte d’Ivoire, and Colombia.

2015 vs. 2014  Interest expense increased by $53 million.
•
Interest expense on debt and other increased by $16 million primarily due to higher debt outstanding during 2015, partially offset by decreased debt amortization costs for the $5.0 Billion Facility.
•
Capitalized interest decreased by $37 million primarily due to the completion of the Lucius development and lower construction-in-progress balances for long-term capital projects in Brazil, partially offset by higher construction-in-progress balances for long-term capital projects primarily in Ghana.

Income Tax Expense (Benefit)
millions except percentages
2016
 
2015
 
2014
Income tax expense (benefit)
$
(1,021
)
 
$
(2,877
)
 
$
1,617

Income (loss) before income taxes
(3,829
)
 
(9,689
)
 
54

Effective tax rate
27
%
 
30
%
 
2,994
%

The Company’s effective tax rate is impacted each year by the relative pre-tax income earned by the Company’s operations in the U.S., Algeria, and the rest of the world. Additionally, state income taxes (net of federal income tax benefit), non-deductible Algerian exceptional profits tax for Algerian income tax purposes, net changes in uncertain tax positions, and dispositions of non-deductible goodwill typically impact the Company’s effective tax rate. The 2014 effective tax rate of 2,994% was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding. The Company’s effective tax rate decreased from 30% in 2015 to 27% in 2016 primarily due to the reversal of non-deductible goodwill due to asset divestitures in 2016.
The Company generated a net operating loss in 2016 and will file a carryback claim for a tax refund of approximately $154 million in 2017.
For additional information on income taxes, see Note 12—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


66

LIQUIDITY AND CAPITAL RESOURCES
millions
2016
 
2015
 
2014
Net cash provided by (used in) operating activities
$
3,000

 
$
(1,877
)
 
$
8,466

Net cash provided by (used in) investing activities
(2,762
)
 
(4,771
)
 
(6,472
)
Net cash provided by (used in) financing activities
2,008

 
220

 
1,675


Overview  As of December 31, 2016, Anadarko had $3.2 billion of cash plus $5.0 billion of borrowing capacity under its revolving credit facilities. Substantially all of Anadarko’s cash balances at December 31, 2016, were domiciled in the United States and were available to support its worldwide operations. In addition, future excess cash flows generated from the Company’s international assets are available to support both its U.S. operations and corporate needs without incurring incremental U.S. income tax. Anadarko believes that its cash, anticipated operating cash flows, and proceeds from announced asset monetizations will be sufficient to fund the Company’s projected 2017 operational and capital programs, providing the flexibility to accelerate activity in the Delaware and DJ basins, and potential bolt-on acquisitions in these core areas. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions. The Company has a variety of funding sources available, including cash, 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, and the Company’s credit facilities. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company.

Effects of Moody’s Credit Rating Downgrade  As of December 31, 2016, our long-term debt was rated “BBB” with a stable outlook by S&P and Fitch. Our long-term debt was rated “Ba1” with a stable outlook by Moody’s, which is below investment grade.
As a result of Moody’s below-investment-grade rating of our long-term debt in February 2016, the Company’s credit thresholds with certain derivative counterparties were reduced and in some cases eliminated, which required the Company to increase the amount of collateral posted with derivative counterparties when the Company’s net trading position is a liability in excess of the contractual threshold. During the third quarter of 2016, Anadarko negotiated the increase of a credit threshold for an interest-rate derivative. As a result of the increased credit threshold, $200 million of collateral was returned to the Company. No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.4 billion (net of $117 million of collateral) at December 31, 2016, and $1.3 billion (net of $58 million of collateral) at December 31, 2015.
Furthermore, as a result of Moody’s rating, Anadarko is more likely to be required to post collateral in the form of letters of credit or cash as financial assurance of its performance under certain contractual arrangements such as pipeline transportation contracts and oil and gas sales contracts. The amount of letters of credit or cash provided as assurance of the Company’s performance under these types of contractual arrangements with respect to credit-risk-related contingent features was $274 million at December 31, 2016, and zero at December 31, 2015.
Additionally, in February 2016, Moody’s downgraded Anadarko’s commercial paper program credit rating, which eliminated the Company’s access to the commercial paper market. The Company has not issued commercial paper notes since the downgrade but instead has used the 364-Day Facility for short-term working capital requirements, as needed.

67

Operating Activities  

One of the primary sources of variability in the Company’s cash flows from operating activities is the 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 operations and interest payments related to the Company’s outstanding debt.
Cash provided by operating activities was $3.0 billion in 2016, $4.9 billion higher compared to 2015. This increase was a result of the $5.2 billion Tronox settlement payment in 2015 and an $881 million tax refund received in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback. These increases were partially offset by $247 million related to severance costs and retirement benefits settlements in connection with the workforce reduction program and the $159.5 million payment of the CWA penalty in 2016, with the remaining decrease primarily related to lower sales due to the impact of lower commodity prices.
Cash used in operating activities was $1.9 billion in 2015, $10.4 billion lower compared to 2014. This decrease was a result of the $5.2 billion Tronox settlement payment in 2015, with the remaining decrease primarily related to lower sales due to the impact of lower commodity prices.
See Note 16—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Investing Activities  

Capital Expenditures  The following presents the Company’s capital expenditures:
millions
2016
 
2015
 
2014
Cash Flows from Investing Activities
 
 
 
 
 
Additions to properties and equipment (1)
$
3,505

 
$
6,067

 
$
9,508

Adjustments for capital expenditures
 
 
 
 
 
Changes in capital accruals
(205
)
 
(226
)
 
(237
)
Other
14

 
47

 
(15
)
Total capital expenditures (2)
$
3,314

 
$
5,888

 
$
9,256

_______________________________________________________________________________
(1) 
Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells, whether or not they were deemed to have a commercially sufficient quantity of proved reserves.
(2) 
Includes WES capital expenditures of $491 million in 2016, $525 million in 2015, and $696 million in 2014. Capital expenditures exclude the FPSO capital lease asset; see Financing Activities—Capital Lease Obligations below.

During 2016, cash from operations and property divestitures were the primary sources for funding capital expenditures. The Company’s capital expenditures decreased by 44% for the year ended December 31, 2016, due to the following:
•
decreased development costs of $2.1 billion primarily in the U.S. onshore
•
decreased exploration costs of $432 million primarily in the U.S. onshore, Colombia, and Mozambique, partially offset by increased exploration costs of $251 million in the Gulf of Mexico and Côte d’Ivoire
•
decreased gathering, processing, and other capital costs of $284 million primarily in the U.S. onshore and Gulf of Mexico


68

The Company’s capital expenditures decreased by 36% for the year ended December 31, 2015, primarily due to reduced development and exploration activity, which resulted in the following:
•
decreased development costs of $2.1 billion primarily in the U.S. onshore
•
lower exploration costs of $710 million primarily in the U.S. onshore and Gulf of Mexico
•
lower gathering, processing, and other capital costs of $498 million primarily in the U.S. onshore
Carried-Interest Arrangements  In 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 2020. At December 31, 2016, $151 million of the $442 million carry obligation had been funded.
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. At September 30, 2016, the entire $860 million carry obligation had been funded.

Acquisitions  In December 2016, the Company closed the GOM Acquisition for $1.8 billion. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
In November 2014, WES acquired Nuevo Midstream, LLC (Nuevo), which owns and operates gathering and processing assets located in the Delaware basin in West Texas, for $1.6 billion, including $30 million of cash acquired. Following the acquisition, WES changed the name of Nuevo to DBM.

Divestitures  Anadarko received net proceeds related to property divestiture transactions of $2.4 billion in 2016, $1.4 billion in 2015, and $5.0 billion in 2014. In December 2016, the Company entered into an agreement to sell its Marcellus oil and gas assets and certain related midstream assets for approximately $1.2 billion. These assets were classified as held for sale as of December 31, 2016. In January 2017, the Company entered into an agreement to sell its Eagleford oil and gas assets for approximately $2.3 billion. The Company expects these transactions to close in the first quarter of 2017 generating approximately $3.5 billion in cash proceeds. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.




69

Financing Activities  
millions except percentages
2016
 
2015
Anadarko
$
12,204

 
$
12,977

WES
3,091

 
2,691

WGP
28

 
—

Total debt
$
15,323

 
$
15,668

Total equity
15,497

 
15,457

Debt to total capitalization ratio
49.7
%
 
50.3
%

Debt Activity  The following summarizes the Company’s borrowing activity: 
millions
2016
 
2015
 
2014
 
Description
Issuances
$
800

 
$
—

 
$
—

 
4.850% Senior Notes due 2021 (1)
 
1,100

 
—

 
—

 
5.550% Senior Notes due 2026 (1)
 
1,100

 
—

 
—

 
6.600% Senior Notes due 2046 (1)
 
500

 
—

 
—

 
WES 4.650% Senior Notes due 2026
 
—

 
500

 
—

 
WES 3.950% Senior Notes due 2025
 
—

 
101

 
—

 
TEUs - senior amortizing notes
 
—

 
—

 
625

 
3.450% Senior Notes due 2024
 
—

 
—

 
625

 
4.500% Senior Notes due 2044
 
—

 
—

 
100

 
WES 2.600% Senior Notes due 2018
 
200

 
—

 
400

 
WES 5.450% Senior Notes due 2044
Borrowings
1,750

 
1,800

 
—

 
364-Day Facility
 
—

 
1,500

 
—

 
$5.0 Billion Facility
 
600

 
400

 
1,160

 
WES RCF
 
28

 
—

 
—

 
WGP RCF
 
—

 
250

 
—

 
Commercial paper notes, net (2)
Repayments
(1,750
)
 
—

 
—

 
5.950% Senior Notes due 2016
 
(2,000
)
 
—

 
—

 
6.375% Senior Notes due 2017
 
—

 
—

 
(500
)
 
7.625% Senior Notes due 2014
 
—

 
—

 
(275
)
 
5.750% Senior Notes due 2014
 
(1,750
)
 
(1,800
)
 
—

 
364-Day Facility
 
—

 
(1,500
)
 
—

 
$5.0 Billion Facility
 
(900
)
 
(610
)
 
(650
)
 
WES RCF
 
(250
)
 
—

 
—

 
Commercial paper notes, net
 
(34
)
 
(16
)
 
—

 
TEUs - senior amortizing notes
__________________________________________________________________
(1) 
Represent senior notes issued in March 2016.
(2) 
Includes repayments of $(106) million related to commercial paper notes with maturities greater than 90 days.

Senior Notes  During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. In December 2016, the Company redeemed its remaining $750 million 6.375% Senior Notes due September 2017. The Company recognized losses of $155 million for the early retirement and redemption of these senior notes, which included $144 million of premiums paid.
In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion of the amount outstanding under the WES RCF. In October 2016, WES completed a public offering of $200 million aggregate principal amount of 5.450% Senior Notes due April 2044. Net proceeds were primarily used to repay amounts outstanding under the WES RCF and the remaining proceeds were used for general partnership purposes, including capital expenditures.

70

In 2015, net proceeds from the WES 3.950% Senior Notes were used to repay WES RCF borrowings. In 2014, net proceeds from the 3.450% Senior Notes and 4.500% Senior Notes were used for general corporate purposes, and net proceeds from the WES 2.600% Senior Notes and WES 5.450% Senior Notes were used to repay WES RCF borrowings and for general partnership purposes.

Anadarko Revolving Credit Facilities  Anadarko has a $3.0 billion Five-Year Facility that matures in January 2021 and a $2.0 billion 364-Day Facility. In January 2017, the Company extended the maturity date of the 364-Day Facility until January 2018.
During 2016, borrowings under the 364-Day Facility were primarily used for general short-term working capital needs. At December 31, 2016, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility.

WES and WGP Revolving Credit Facilities  WES has a $1.2 billion RCF, which is expandable to $1.5 billion. During 2016, WES borrowings were primarily used for general partnership purposes, including the funding of a portion of its acquisition of Springfield Pipeline LLC and capital expenditures. In December 2016, WES amended the WES RCF to extend the maturity date to February 2020. At December 31, 2016, WES was in compliance with all covenants contained in its RCF, had no outstanding borrowings under its RCF, had outstanding letters of credit of $5 million, and had available borrowing capacity of $1.195 billion.
In March 2016, WGP entered into a $250 million three-year senior secured revolving credit facility maturing in March 2019 (WGP RCF), which is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. During 2016, WGP borrowings were used to fund the purchase of WES common units. At December 31, 2016, WGP had outstanding borrowings under the WGP RCF of $28 million at an interest rate of 2.77% and had available borrowing capacity of $222 million.
For additional information on the Company’s revolving credit facilities, such as years of maturity, interest rates, and covenants, see Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Commercial Paper Program  The Company has a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. As a result of Moody’s downgrade of Anadarko’s commercial paper program credit rating, the Company’s access to the commercial paper market was eliminated. The Company repaid $250 million of commercial paper notes during the first quarter of 2016, and at December 31, 2016, there were no outstanding borrowings under the commercial paper program. See Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.

Debt Maturities  At December 31, 2016, Anadarko’s scheduled debt maturities during 2017 consisted of $34 million related to the senior amortizing notes associated with the TEUs. Anadarko’s 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 $883 million at the next put date in October 2017.
For additional information on the Company’s debt instruments and capital lease obligations, such as transactions during the period, years of maturity, and interest rates, see Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Capital Lease Obligations  Construction of the FPSO for the Company’s TEN field operations in Ghana commenced in 2013. The Company recognized an asset and related obligation during the construction period. Upon completion of the construction during the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s share of the fair value of the FPSO. The Company expects to make the first payment related to the FPSO in the first quarter of 2017. At December 31, 2016, Anadarko’s scheduled payments associated with capital lease obligations were $57 million during 2017. Principal payments related to capital lease obligations are reported in financing activities and interest payments related to capital lease obligations are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. See Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.


71

Equity Transactions  In September 2016, Anadarko completed a public offering of 40.5 million shares of its common stock for net proceeds of $2.16 billion. Net proceeds were primarily used to fund the GOM Acquisition. The remaining net proceeds were used for general corporate purposes.
Anadarko sold 12.5 million of its WGP common units to the public for net proceeds of $476 million in 2016, 2.3 million WGP common units to the public for net proceeds of $130 million in 2015, and approximately 6 million WGP common units to the public for net proceeds of $335 million in 2014. The proceeds for all periods were used for general corporate purposes. At December 31, 2016, Anadarko owned 179 million WGP common units, which represents an 81.6% interest in WGP.
During the second quarter of 2015, Anadarko issued 9.2 million 7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for WGP common units, subject to Anadarko’s right to elect to issue and deliver shares of Anadarko’s common stock in lieu of WGP common units, and a senior amortizing note due in June 2018. See Note 10—Tangible Equity Units in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.
During 2016, WES issued 14 million Series A Preferred units to private investors for net proceeds of $440 million and an additional 8 million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, for net proceeds of $247 million.
WES can issue common units to the public under its $500 million continuous offering program, which allows for the issuance of up to an aggregate of $500 million of WES common units. The remaining amount available to be issued under this program was $442 million of WES common units at December 31, 2016. During 2015, WES issued approximately 874 thousand common units to the public and raised net proceeds of $57 million. The proceeds were used for general partnership purposes, including capital expenditures. During 2014, WES issued approximately 10 million common units to the public and raised net proceeds of $691 million. The proceeds were used to partially fund a portion of the DBM acquisition. WES used all the capacity to issue units under its $125 million continuous offering program as of the end of the third quarter of 2014.

Derivative Instruments  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 is subject to changes in interest rates. Interest-rate swap agreements were settled for total cash payments of $266 million in 2016 and $222 million in 2014. For information on derivative instruments, including cash flow treatment, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Effects of Moody’s Credit Rating Downgrade above.

Conveyance of Future Hard Minerals Royalty Revenues  During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. The Company made the first semi-annual payment of $25 million for royalties in 2016. For additional information on the cash flow treatment, expected timing, and scheduled payments of the conveyed royalties, see Note 14—Conveyance of Future Hard Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Common Stock Dividends  Anadarko paid dividends to its common stockholders of $105 million in 2016, $553 million in 2015, and $505 million in 2014. The Company increased the quarterly dividend paid to common stockholders from $0.18 per share during the first quarter of 2014 to $0.27 per share during the second quarter of 2014. In response to the commodity-price environment, the Company decreased the quarterly dividend to $0.05 per share in February 2016. 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 is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial conditions, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.


72

Distributions to Noncontrolling Interest Owners  Distributions to noncontrolling interest owners primarily relate to the following:
millions
2016
 
2015
 
2014
WES distributions to unitholders (excluding Anadarko and WGP) (1)
$
258

 
$
231

 
$
175

WES distributions to Series A Preferred unit holders (2)
31

 
—

 
—

WGP distributions to unitholders (excluding Anadarko) (3)
59

 
37

 
24

__________________________________________________________________
(1) 
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 $0.860 per common unit for the fourth quarter of 2016 (paid in February 2017).
(2) 
WES has made distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders quarterly since the unit issuances in March and April 2016.
(3) 
WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.46250 per unit for the fourth quarter of 2016 (to be paid in February 2017).

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, restoration and redrill, and sudden and accidental pollution; (b) $1.2 billion 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.

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 oil, natural gas, and NGLs as well as for other oil and gas activities as discussed below in Obligations. 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.

73

Obligations

The following is a summary of the Company’s obligations at December 31, 2016:
 
 
 
Obligations by Period
millions
Note Reference (1)
 
2017
 
2018-2019
 
2020-2021
 
2022 and beyond
 
Total
Total debt
 
 
 
 
 
 
 
 
 
 
 
Principal—total borrowings (2)
 
$
34

 
$
1,409

 
$
1,300

 
$
13,963

 
$
16,706

Interest on borrowings

 
862

 
1,667

 
1,506

 
9,332

 
13,367

Capital lease obligation and interest

 
57

 
84

 
85

 
391

 
617

Investee entities’ debt and interest (3)
 
61

 
167

 
196

 
5,060

 
5,484

Operating leases
 
673

 
714

 
110

 
23

 
1,520

Oil and gas activities (4)
 
478

 
542

 
178

 
125

 
1,323

Midstream and marketing activities
 
850

 
1,666

 
1,433

 
1,099

 
5,048

AROs
 
137

 
234

 
520

 
2,040

 
2,931

Derivative liabilities (5)
 
159

 
803

 
438

 
—

 
1,400

Uncertain tax positions
 
70

 
85

 
—

 
1,301

 
1,456

Other (6)
 
 
19

 
166

 
71

 
96

 
352

Total (7)
 
 
$
3,400

 
$
7,537

 
$
5,837

 
$
33,430

 
$
50,204

 _______________________________________________________________________________
(1) 
For additional information, see the Notes to the 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 2021. 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 $883 million in October 2017 (the next potential put date).
(3) 
The obligations and related investments are presented net on the Company’s Consolidated Balance Sheets in other long-term liabilities-other for all periods presented. Future interest payments are estimated using the relevant forward LIBOR rate curve. Further, the above table does not reflect the preferred return that Anadarko receives on its investment in these entities.
(4) 
The table includes long-term drilling and work-related commitments of $1.3 billion, comprised of approximately $1.1 billion related to the United States and $180 million related to international locations. These amounts are presented on an undiscounted basis and do not include purchase commitments for jointly owned fields and facilities where the Company is not the operator.
(5) 
Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties.
(6) 
Includes environmental liabilities; for additional information, see Note 16—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(7) 
This table does not include litigation-related contingent liabilities, the Company’s pension and postretirement benefit obligations, or payments related to the conveyance of future hard minerals royalty revenues. See Note 16—Contingencies, Note 18—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans, and Note 14—Conveyance of Future Hard Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.




74

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP 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

Methodology Anadarko estimates its proved oil and gas reserves according to the definition of proved reserves provided by the SEC and the Financial Accounting Standards Board. 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. 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.

Judgments and uncertainties Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. 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, development plans, reservoir performance, prices, economic conditions, and governmental restrictions as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date.
A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A and could result in property impairments. If the estimates of proved reserves used in the UOP calculations had been lower by five percent across all properties, DD&A in 2016 would have increased by approximately $211 million.


75

Exploratory Costs

Methodology Under the successful efforts method of accounting, exploratory drilling costs are initially capitalized pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. 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.
 
Judgments and uncertainties Significant management judgment is required to determine whether sufficient progress has been made in assessing the reserves and the economic and operating viability of the project to continue capitalization of the exploratory drilling costs. In making this determination all relevant facts and circumstances shall be evaluated, and no single indicator is determinative. Relevant facts and circumstances include, but are not limited to, commitment of project personnel, costs being incurred to assess the reserves and their potential development, assessment in progress covering the economic, legal, political, and environmental aspects of the potential development, and the existence or active negotiations of agreements with governments or sales contracts with customers. The determination of proved reserves 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.
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.

Fair Value

Methodology The Company estimates fair value of 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.

Judgments and uncertainties 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 or income 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 future net cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. 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, 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.


76

Impairments of Proved Oil and Natural-Gas Properties

Methodology Proved oil and natural-gas properties are assessed for impairment when facts and circumstances indicate that net book values may not be recoverable. When impairment indicators are present, 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, the property’s fair value is estimated and an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value.

Judgments and uncertainties The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs. In most cases, the assumption that generates the most variability in undiscounted future net cash flows is future oil and natural-gas prices. For impairment testing, the Company used the five-year forward strip prices for oil and natural gas, with prices subsequent to the fifth year held constant as the benchmark price in the undiscounted future net cash flows. Due to the volatility of crude oil, natural gas, and NGL prices, these cash flow estimates are inherently imprecise. Capital and operating costs were estimated assuming 0% escalation for years where the average oil strip price was below $50 per Bbl and 1% escalation for years where the average oil strip price exceeded $50 per Bbl.
Unfavorable changes in any of the primary assumptions could result in a reduction in undiscounted future cash flows and could indicate property impairment. Uncertainties related to the primary assumptions could affect the timing of an impairment.

Impairments of Unproved Oil and Natural-Gas Properties

Methodology Acquisition costs of unproved oil and natural-gas 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. The Company has classified unproved oil and natural-gas properties into three categories: significant, significant where probable and possible reserve estimations are available, and individually insignificant. Significant undeveloped leases are assessed individually for impairment and a valuation allowance is provided if impairment is indicated. In situations where fair values have been allocated to a significant unproved property based on estimations of probable and/or possible reserves as the result of a business combination or other purchase of proved and unproved properties, a future cash flow analysis is used to assess the property for impairment in addition to consideration of reserve volumes needed to transfer the balance of unproved property to proved leasehold. 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.

Judgments and uncertainties In determining whether a significant unproved property is impaired numerous factors are considered including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property, and the remaining months in the lease term for the property. In situations where probable and possible reserves are available, cash flows used in the impairment analysis are determined based upon management’s estimates of probable and possible reserves, future commodity prices, and future costs to produce the reserves. If undiscounted future net cash flows are less than the carrying value of the property, indicating impairment, the cash flows are discounted and compared to the carrying value for determining the amount of the impairment loss to record. The Company utilizes the same pricing assumptions discussed above in Impairments of Proved Oil and Natural-Gas Properties. Uncertainties related to the primary assumptions or unfavorable revisions in estimated reserve quantities could cause a reduction in the value of a property and therefore indicate an impairment. Management’s assessment of the results of exploration activities, availability of funds for future activities, and the current and projected political and regulatory climate in areas in which we operate also impact the amounts and timing of impairment provisions.

77

Purchase Price Allocations

Methodology In connection with a business combination accounted for under the acquisition method, the acquiring company must recognize and measure assets acquired and liabilities assumed at fair value as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of the purchase price over fair value assigned to assets and liabilities is recorded as goodwill. Any excess of fair value assigned to assets and liabilities over the purchase price is recorded as a gain from a bargain purchase. The amount of goodwill or gain from a bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

Judgments and uncertainties In estimating the fair values of assets acquired and liabilities assumed in a business combination, various assumptions are made. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, estimates of the fair value of crude oil, natural-gas and NGL reserves are prepared. Estimates of future prices to apply to the estimated reserves quantities acquired and estimates of future operating and development costs are used to estimate future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based discount rate determined appropriate at the time of the acquisition. Estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Estimated fair values of assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses, and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.


78

Goodwill Impairments

Methodology The Company tests goodwill for impairment annually in October (or more frequently as circumstances dictate). The Company first assesses whether an impairment of goodwill is indicated through a qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is less than its carrying amount, including goodwill. If the Company concludes it is more likely than not that fair value of the reporting unit exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary. If the qualitative assessment 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.
When evaluating whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company assesses relevant events and circumstances, including the following:
•
significant changes in the stock price of Anadarko, WES, and WGP
•
significant declines in commodity prices
•
significant increases in cost factors such as costs of drilling, production costs, and gathering, processing, and other transportation costs
•
impairments recognized by the Company
•
acquisitions and disposals of assets
•
changes to the Company’s reserves, including changes due to fluctuations in commodity prices and updates to the Company’s plans or forecasts
•
significant declines in trading multiples for midstream peers

Judgments and uncertainties 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 information available 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 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.
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 production reporting unit as a whole rather than as individual properties that are part of an oil and gas portfolio.
The Company estimates fair value for the WES gathering and processing, WES transportation, and other gathering and processing reporting units 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 significant declines in commodity prices, decreases in proved reserves, changes in exploration or development plans, significant property impairments, increases in operating or drilling costs, significant changes in regulations, or other negative changes to the economic environment in which Anadarko operates.


79

Contingencies

Methodology The Company is subject to various legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses 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. The Company’s in-house legal counsel 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.

Judgments and uncertainties Management makes judgments and estimates when it establishes liabilities for 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 made pre-trial, during trial, 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.

Income Taxes

Methodology We are subject to income taxes in numerous taxing jurisdictions worldwide. 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 deferred tax assets may be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company routinely assesses 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.
The Company also routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts, including interest where appropriate. 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.

Judgments and uncertainties 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. The assessment of potential uncertain tax positions requires a significant amount of judgment and are reviewed and adjusted on a periodic basis, taking into consideration the progress of ongoing tax audits, case law, and new legislation. 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. Additionally, numerous judgments and assumptions are inherent in our estimates of future taxable income used to assess the realizability of certain deferred tax assets. The estimates used are based on assumptions of proved oil and gas reserves, selling prices, and development assumptions that are consistent with the Company’s internal business plans.

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.

80

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. These risks can affect revenues and cash flows, and 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 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 9—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 oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. 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 33 MMBbls of oil, 354 Bcf of natural gas, and 1 MMBbls of NGLs at December 31, 2016, with a net derivative liability position of $136 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $199 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $168 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes  At December 31, 2016, the Company had a net derivative asset position of $6 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  Borrowings, if any, under each of the 364-Day Facility, the Five-Year Facility, the WES RCF, and the WGP RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of LIBOR-based obligations that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two noncontrolled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in LIBOR would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.
At December 31, 2016, the Company had a net derivative liability position of $1.3 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by $90 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

81

Item 8.  Financial Statements and Supplementary Data

ANADARKO PETROLEUM CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

82

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 regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
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, 2016. This assessment was based on criteria established in the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Based on our assessment, we believe that the Company’s internal control over financial reporting was effective as of December 31, 2016.
KPMG LLP has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2016.
 
/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 17, 2017


83

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, 2016, 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, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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, 2016 and 2015, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2016, and our report dated February 17, 2017 expressed an unqualified opinion on those consolidated financial statements.
 
/s/ KPMG LLP
 
Houston, Texas
February 17, 2017

84

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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three–year period ended December 31, 2016, 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, 2016, 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 17, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
 
/s/ KPMG LLP
 
Houston, Texas
February 17, 2017


85

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME 
 
Years Ended December 31,
millions except per-share amounts
2016
 
2015
 
2014
Revenues and Other
 
 
 
 
 
Oil sales
$
4,668

 
$
5,420

 
$
9,748

Natural-gas sales
1,564

 
2,007

 
3,849

Natural-gas liquids sales
921

 
833

 
1,572

Gathering, processing, and marketing sales
1,294

 
1,226

 
1,206

Gains (losses) on divestitures and other, net
(578
)
 
(788
)
 
2,095

Total
7,869

 
8,698

 
18,470

Costs and Expenses
 
 
 
 
 
Oil and gas operating
811

 
1,014

 
1,171

Oil and gas transportation
1,002

 
1,117

 
1,116

Exploration
946

 
2,644

 
1,639

Gathering, processing, and marketing
1,087

 
1,054

 
1,030

General and administrative
1,440

 
1,176

 
1,316

Depreciation, depletion, and amortization
4,301

 
4,603

 
4,550

Production, property, and other taxes
536

 
553

 
1,244

Impairments
227

 
5,075

 
836

Other operating expense
118

 
271

 
165

Total
10,468

 
17,507

 
13,067

Operating Income (Loss)
(2,599
)
 
(8,809
)
 
5,403

Other (Income) Expense
 
 
 
 
 
Interest expense
890

 
825

 
772

Loss on early extinguishment of debt
155

 
—

 
—

(Gains) losses on derivatives, net
286

 
(99
)
 
197

Other (income) expense, net
(101
)
 
149

 
20

Tronox-related contingent loss
—

 
5

 
4,360

Total
1,230

 
880

 
5,349

Income (Loss) Before Income Taxes
(3,829
)
 
(9,689
)
 
54

Income tax expense (benefit)
(1,021
)
 
(2,877
)
 
1,617

Net Income (Loss)
(2,808
)
 
(6,812
)
 
(1,563
)
Net income (loss) attributable to noncontrolling interests
263

 
(120
)
 
187

Net Income (Loss) Attributable to Common Stockholders
$
(3,071
)
 
$
(6,692
)
 
$
(1,750
)
 
 
 
 
 
 
Per Common Share
 
 
 
 
 
Net income (loss) attributable to common stockholders—basic
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
Net income (loss) attributable to common stockholders—diluted
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
Average Number of Common Shares Outstanding—Basic
522

 
508

 
506

Average Number of Common Shares Outstanding—Diluted
522

 
508

 
506

Dividends (per Common Share)
$
0.20

 
$
1.08

 
$
0.99



See accompanying Notes to Consolidated Financial Statements.
86

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 
 
Years Ended December 31,
millions
2016
 
2015
 
2014
Net Income (Loss)
$
(2,808
)
 
$
(6,812
)
 
$
(1,563
)
Other Comprehensive Income (Loss)
 
 
 
 
 
Adjustments for derivative instruments
 
 
 
 
 
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
8

 
10

 
9

Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
(3
)
 
(4
)
 
(3
)
Total adjustments for derivative instruments, net of taxes
5

 
6

 
6

Adjustments for pension and other postretirement plans
 
 
 
 
 
Net gain (loss) incurred during period
(175
)
 
49

 
(405
)
Income taxes on net gain (loss) incurred during period
68

 
(18
)
 
149

Prior service credit (cost) incurred during period
—

 
89

 
—

Income taxes on prior service credit (cost) incurred during period
—

 
(33
)
 
—

Amortization of net actuarial (gain) loss to general and administrative expense
188

 
63

 
27

Income taxes on amortization of net actuarial (gain) loss to general and administrative expense
(73
)
 
(20
)
 
(9
)
Amortization of net prior service (credit) cost to general and administrative expense
(34
)
 
(4
)
 
—

Income taxes on amortization of net prior service (credit) cost to general and administrative expense
13

 
2

 
—

Total adjustments for pension and other postretirement plans, net of taxes
(13
)
 
128

 
(238
)
Total
(8
)
 
134

 
(232
)
Comprehensive Income (Loss)
(2,816
)
 
(6,678
)
 
(1,795
)
Comprehensive income (loss) attributable to noncontrolling interests
263

 
(120
)
 
187

Comprehensive Income (Loss) Attributable to Common Stockholders
$
(3,079
)
 
$
(6,558
)
 
$
(1,982
)


See accompanying Notes to Consolidated Financial Statements.
87

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS 
 
December 31,
millions
2016
 
2015
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents ($359 and $100 related to VIEs)
$
3,184

 
$
939

Accounts receivable (net of allowance of $14 and $11)
 
 
 
   Customers ($70 and $81 related to VIEs)
1,007

 
652

   Others ($80 and $84 related to VIEs)
721

 
1,817

Other current assets
354

 
573

Total
5,266

 
3,981

Properties and Equipment
 
 
 
Cost
69,013

 
70,683

Less accumulated depreciation, depletion, and amortization
36,845

 
36,932

Net properties and equipment ($5,050 and $4,859 related to VIEs)
32,168

 
33,751

Other Assets ($609 and $644 related to VIEs)
2,226

 
2,268

Goodwill and Other Intangible Assets ($1,221 and $1,220 related to VIEs)
5,904

 
6,331

Total Assets
$
45,564

 
$
46,331

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
 
 
Accounts payable ($239 and $179 related to VIEs)
$
2,288

 
$
2,850

Accrued expenses
386

 
424

Interest payable
244

 
247

Production, property, and other taxes payable ($24 and $18 related to VIEs)
239

 
318

Current asset retirement obligations
129

 
309

Short-term debt
42

 
32

Total
3,328

 
4,180

Long-term Debt
15,281

 
15,636

Other Long-term Liabilities
 
 
 
Deferred income taxes
4,324

 
5,400

Asset retirement obligations ($140 and $127 related to VIEs)
2,802

 
1,750

Other
4,332

 
3,908

Total
11,458

 
11,058

 
 
 
 
Equity
 
 
 
Stockholders’ equity
 
 
 
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 572.0 million and 528.3 million shares issued)
57

 
52

Paid-in capital
11,875

 
9,265

Retained earnings
1,704

 
4,880

Treasury stock (20.8 million and 20.0 million shares)
(1,033
)
 
(995
)
Accumulated other comprehensive income (loss)
(391
)
 
(383
)
Total Stockholders’ Equity
12,212

 
12,819

Noncontrolling interests
3,285

 
2,638

Total Equity
15,497

 
15,457

Total Liabilities and Equity
$
45,564

 
$
46,331

__________________________________________________________________
Parenthetical references reflect amounts as of December 31, 2016, and December 31, 2015.

See accompanying Notes to Consolidated Financial Statements.
88

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, 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

Net income (loss)
—

 
—

 
(6,692
)
 
—

 
—

 
(120
)
 
(6,812
)
Common stock issued
—

 
209

 
—

 
—

 
—

 
—

 
209

Dividends—common stock
—

 
—

 
(553
)
 
—

 
—

 
—

 
(553
)
Repurchase of common stock
—

 
—

 
—

 
(55
)
 
—

 
—

 
(55
)
Subsidiary equity transactions
—

 
51

 
—

 
—

 
—

 
99

 
150

Issuance of tangible equity units
—

 
—

 
—

 
—

 
—

 
348

 
348

Distributions to noncontrolling interest owners
—

 
—

 
—

 
—

 
—

 
(282
)
 
(282
)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
—

 
—

 
—

 
—

 
6

 
—

 
6

Adjustments for pension and other postretirement plans
—

 
—

 
—

 
—

 
128

 
—

 
128

Balance at December 31, 2015
52

 
9,265

 
4,880

 
(995
)
 
(383
)
 
2,638

 
15,457

Net income (loss)
—

 
—

 
(3,071
)
 
—

 
—

 
263

 
(2,808
)
Common stock issued
5

 
2,347

 
—

 
—

 
—

 
—

 
2,352

Dividends—common stock
—

 
—

 
(105
)
 
—

 
—

 
—

 
(105
)
Repurchase of common stock
—

 
—

 
—

 
(38
)
 
—

 
—

 
(38
)
Subsidiary equity transactions
—

 
263

 
—

 
—

 
—

 
746

 
1,009

Distributions to noncontrolling interest owners
—

 
—

 
—

 
—

 
—

 
(362
)
 
(362
)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
—

 
—

 
—

 
—

 
5

 
—

 
5

Adjustments for pension and other postretirement plans
—

 
—

 
—

 
—

 
(13
)
 
—

 
(13
)
Balance at December 31, 2016
$
57

 
$
11,875

 
$
1,704

 
$
(1,033
)
 
$
(391
)
 
$
3,285

 
$
15,497




See accompanying Notes to Consolidated Financial Statements.
89

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS 
 
Years Ended December 31,
millions
2016
 
2015
 
2014
Cash Flows from Operating Activities
 
 
 
 
 
Net income (loss)
$
(2,808
)
 
$
(6,812
)
 
$
(1,563
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
 
 
 
 
 
Depreciation, depletion, and amortization
4,301

 
4,603

 
4,550

Deferred income taxes
(1,238
)
 
(3,152
)
 
(105
)
Dry hole expense and impairments of unproved properties
613

 
2,267

 
1,245

Impairments
227

 
5,075

 
836

(Gains) losses on divestitures, net
757

 
1,022

 
(1,891
)
Loss on early extinguishment of debt
155

 
—

 
—

Total (gains) losses on derivatives, net
292

 
(100
)
 
207

Operating portion of net cash received (paid) in settlement of derivative instruments
267

 
335

 
371

Other
342

 
320

 
327

Changes in assets and liabilities
 
 
 
 
 
Tronox-related contingent liability
—

 
(5,210
)
 
4,360

(Increase) decrease in accounts receivable
677

 
(2
)
 
103

Increase (decrease) in accounts payable and accrued expenses
(669
)
 
(995
)
 
97

Other items, net
84

 
772

 
(71
)
Net cash provided by (used in) operating activities
3,000


(1,877
)

8,466

Cash Flows from Investing Activities
 
 
 
 
 
Additions to properties and equipment
(3,505
)
 
(6,067
)
 
(9,508
)
Acquisition of businesses
(1,740
)
 
(3
)
 
(1,527
)
Divestitures of properties and equipment and other assets
2,356

 
1,415

 
4,968

Other, net
127

 
(116
)
 
(405
)
Net cash provided by (used in) investing activities
(2,762
)

(4,771
)

(6,472
)
Cash Flows from Financing Activities
 
 
 
 
 
Borrowings, net of issuance costs
6,042

 
4,632

 
2,879

Repayments of debt
(6,832
)
 
(4,033
)
 
(1,425
)
Financing portion of net cash received (paid) for derivative instruments
(333
)
 
(35
)
 
(222
)
Increase (decrease) in outstanding checks
(103
)
 
(23
)
 
62

Dividends paid
(105
)
 
(553
)
 
(505
)
Repurchase of common stock
(38
)
 
(55
)
 
(45
)
Issuance of common stock, including tax benefit on share-based compensation awards
2,188

 
34

 
121

Sale of subsidiary units
1,163

 
187

 
1,026

Issuance of tangible equity units — equity component
—

 
348

 
—

Distributions to noncontrolling interest owners
(362
)
 
(282
)
 
(216
)
Proceeds from conveyance of future hard minerals royalty revenues,
net of transaction costs
413

 
—

 
—

Payments of future hard minerals royalty revenues conveyed
(25
)
 
—

 
—

Net cash provided by (used in) financing activities
2,008


220


1,675

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

Net Increase (Decrease) in Cash and Cash Equivalents
2,245

 
(6,430
)
 
3,671

Cash and Cash Equivalents at Beginning of Period
939

 
7,369

 
3,698

Cash and Cash Equivalents at End of Period
$
3,184

 
$
939

 
$
7,369


See accompanying Notes to Consolidated Financial Statements.
90
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of oil, natural gas, and NGLs, and in the marketing of anticipated production of LNG. In addition, the Company engages in the gathering, processing, treating, and transporting of oil, natural gas, and NGLs. The Company also participates in the hard-minerals business through royalty arrangements.

Basis of Presentation  The consolidated financial statements have been prepared in conformity with GAAP. Certain prior-period amounts have been reclassified to conform to the current-year presentation.
The consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. 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 noncontrolled entities, over which Anadarko has the ability to exercise significant influence over operating and financial policies, and VIEs for which Anadarko is not the primary beneficiary 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 included in other assets.

Use of Estimates  The preparation of financial statements in accordance with 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; AROs; 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 unadjusted quoted prices in active markets for identical assets or liabilities (for example, exchange-traded futures contracts for which parties are willing to transact at the exchange-quoted price).

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).


91
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies (Continued)

In determining fair value, the Company uses observable market data when available, or models that incorporate observable market data. 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 or income 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 future net cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. 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, 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.
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 Company’s 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 11—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, AROs, exit or disposal costs, and capital lease assets and liabilities where the present value of lease payments is greater than the fair value of the leased asset.

Revenues  The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers.
The Company recognizes sales revenues for oil, natural gas, 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 services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income.
Marketing margins related to the Company’s production are included in oil, natural-gas, 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 Company’s Consolidated Statements of Income.

92
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies (Continued)

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 Company’s 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. The cash equivalents balance at December 31, 2016, includes commercial paper and investments in government money market funds in which the carrying value approximates fair value.

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 DD&A. Costs of improvements that extend the lives of existing properties 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 in the Company’s Consolidated Statements of Income.

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. Exploratory drilling costs are initially capitalized pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. 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.

93
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies (Continued)

Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved 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 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 Company’s Consolidated Statements of Income.

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 11—Debt and Interest Expense.

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 and is included in DD&A in the Company’s Consolidated Statements of Income. If estimated future costs of AROs change, an adjustment is recorded to both the ARO 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 13—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 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.

94
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies (Continued)

Goodwill and Other Intangible Assets  Anadarko has allocated goodwill to the following reporting units: oil and gas exploration and production; WES gathering and processing; WES transportation; and other gathering and processing. Goodwill is subject to annual impairment testing in October (or more frequent testing as circumstances dictate). Anadarko’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, the Company will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, acquisitions, or divestitures. See Note 7—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 7—Goodwill and Other Intangible Assets.

Derivative Instruments  Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. 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 (loss) and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 9—Derivative Instruments.

Accounts Payable  Accounts payable included liabilities of $262 million at December 31, 2016, and $365 million at December 31, 2015, 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 16—Contingencies.


95
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies (Continued)

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 16—Contingencies.

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 22—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 12—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 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.
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 21—Share-Based Compensation.


96
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies (Continued)

Recently Adopted Accounting Standards  ASU 2017-04, Intangibles—Goodwill and Other (Topic 350), eliminates Step 2 from the goodwill impairment test in an effort to simplify the subsequent measurement of goodwill. This ASU is effective for annual and interim periods beginning in 2020 and is required to be adopted using a prospective approach, with early adoption permitted for goodwill impairment tests performed after January 1, 2017. The Company adopted this ASU on January 1, 2017, and it will only be applicable to the extent that the Company determines its goodwill is impaired.
ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements as goodwill would not be allocated to divestitures or recorded for acquisitions that are not considered to be businesses.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a modified retrospective approach, with early adoption permitted. The Company adopted this ASU on January 1, 2017, and will recognize a cumulative adjustment to retained earnings of $31 million during the first quarter of 2017.
ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows, and accounting for forfeitures. The Company adopted this ASU on January 1, 2017, and it will not have a material impact on the Company’s future consolidated financial statements.
ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015.
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis was adopted on January 1, 2016. In accordance with the new ASU, WGP and WES are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model. After adoption, WGP and WES were consolidated by the Company under the variable interest model. While this ASU requires additional financial statement disclosure, it has no impact on the Company’s consolidated results of operations, cash flows, or financial position. See Note 23—Variable Interest Entities.


97
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

1. Summary of Significant Accounting Policies (Continued)

New Accounting Standards Issued But Not Yet Adopted  ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Company does not expect the adoption of this ASU to have a material impact on its Consolidated Statement of Cash Flows.
ASU 2014-09, Revenue from Contracts with Customers (Topic 606) supersedes current revenue recognition requirements and industry-specific guidance. The codification 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. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Company has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is currently analyzing whether total revenues and total expenses may increase as a result of recognizing both revenue for noncash consideration for services provided by our midstream business and revenue and associated cost of product for the subsequent sale of commodities received as such noncash consideration. Anadarko continues to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.
ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. The provisions of ASU 2016-02 also modify the definition of a lease and outline the requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. This ASU is effective for annual and interim periods beginning after December 15, 2018. The Company is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.

2. Inventories

The following summarizes the major classes of inventories included in other current assets at December 31:
millions
2016
 
2015
Oil
$
169

 
$
116

Natural gas
38

 
36

NGLs
106

 
64

Total inventories
$
313

 
$
216


98
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

3. Acquisitions, Divestitures, and Assets Held for Sale

Acquisitions  On December 15, 2016, the Company closed the GOM Acquisition for $1.8 billion using a portion of the net proceeds from the September 2016 issuance of 40.5 million shares of its common stock. This acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. This acquisition expanded Anadarko’s operated infrastructure and tie-back inventory, more than doubled the Company’s ownership in the Lucius development to approximately 49%, and doubled its net production from the Gulf of Mexico. The following summarizes the preliminary fair value of assets acquired and liabilities assumed at the acquisition date, pending customary closing adjustments and valuation adjustments:
millions
 
 
Current assets
 
$
8

Properties and equipment
 
2,471

Other assets
 
145

AROs
 
(813
)
Net assets acquired
 
$
1,811

Accounts receivable
 
91

Accounts payable
 
(5
)
Other long-term liabilities
 
(98
)
Cash paid at closing
 
$
1,799


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 primarily based on income and cost approaches. As part of the acquisition, Anadarko agreed to pay the seller, on a quarterly basis, a proportionate amount of gross proceeds from a certain contract until the amount paid equals approximately $150 million. The fair value of the contingent consideration of $103 million was estimated using the income approach and is included in accounts payable and other long-term liabilities in the table above. The assets acquired and liabilities assumed are included within the oil and gas exploration and production reporting segment. Results of operations attributable to the acquisition are included in the Company’s Consolidated Statements of Income from the acquisition date and are not material to the Company’s Consolidated Statements of Income.
The following summarizes the unaudited pro forma condensed financial information of the Company as if the acquisition had occurred on January 1, 2015:
millions
2016
 
2015
Revenues
$
8,849

 
$
9,786

Net income (loss)
(2,623
)
 
(6,560
)

The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed at January 1, 2015, nor is it necessarily indicative of future operating results of the combined entity. The pro forma information includes adjustments for revenues and direct expenses based on historical results of the acquired assets and DD&A based on the purchase price allocated to property, plant, and equipment and estimated useful lives. Adjustments are not included for the acquired assets’ historical property impairments as they were made under the full cost method of accounting. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The unaudited pro forma information does not reflect any cost savings anticipated as a result of the acquisition or any future acquisition related expenses.


99
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

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

Property Exchange In February 2017, WES entered into an agreement with a third party whereby WES will acquire the third party’s 50% nonoperated interest in the DBJV system in exchange for (a) WES’s 33.75% interest in nonoperated Marcellus midstream assets and (b) $155 million in cash. WES currently holds a 50% interest in, and operates, the DBJV system. WES expects to fund the cash consideration through borrowings under the WES RCF and to close the transaction, subject to standard closing conditions and adjustments, in the first quarter of 2017.

Divestitures and Assets Held for Sale  The following summarizes the proceeds received and gains (losses) recognized on divestitures and assets held for sale for the years ended December 31:
millions
2016
 
2015
 
2014
Proceeds received, net of closing adjustments
$
2,356

 
$
1,415

 
$
4,968

Gains (losses) on divestitures, net (1)
(757
)
 
(1,022
)
 
1,891

__________________________________________________________________
(1) 
Includes goodwill allocated to divestitures of $397 million in 2016, $184 million in 2015, and $152 million in 2014.

2016  During the year ended December 31, 2016, the Company’s divestitures were primarily related to the following U.S. onshore assets:
•
certain East Texas/Louisiana assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of $1.0 billion and a net loss of $439 million
•
certain Kansas assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of $159 million and a loss of $4 million
•
certain East Texas assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of $89 million and a loss of $64 million
•
certain West Texas assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of $221 million and a loss of $52 million
•
certain Wyoming assets in the oil and gas exploration and production reporting segment for net proceeds of $588 million and a loss of $58 million
Losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. Certain Marcellus U.S. onshore assets located in Pennsylvania included in the oil and gas exploration and production and midstream reporting segments satisfied criteria to be considered held for sale during the fourth quarter of 2016, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $129 million. The sale of these assets is expected to close in the first quarter of 2017. At December 31, 2016, the Company’s Consolidated Balance Sheet included long-term assets of $1.2 billion, which includes $193 million of goodwill, and long-term liabilities of $66 million associated with assets held for sale.
In January 2017, the Company entered into an agreement to sell certain Eagleford U.S. onshore assets located in South Texas included in the oil and gas exploration and production reporting segment for $2.3 billion. The transaction is expected to close during the first quarter of 2017.


100
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

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

2015  During the year ended December 31, 2015, the Company’s divestitures were primarily related to the following U.S. onshore assets:
•
certain coalbed methane assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of $154 million and a loss of $538 million
•
certain assets in the oil and gas exploration and production and midstream reporting segments in East Texas for net proceeds of $425 million and a loss of $110 million
•
certain EOR assets in the oil and gas exploration and production reporting segment for net proceeds of $675 million and a loss of $350 million, in addition to the loss recognized in 2014 when the asset was originally held for sale as discussed below

2014  During the year ended December 31, 2014, the Company’s divestitures primarily related to the following assets included in the oil and gas exploration and production reporting segment:
•
a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion and a gain of $1.5 billion
•
a Chinese subsidiary for $1.075 billion and a gain of $510 million
•
interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for $500 million and a gain of $237 million
•
interest in the Pinedale/Jonah assets in Wyoming for $581 million
During the fourth quarter of 2014, Anadarko considered certain U.S. onshore EOR assets to be held for sale and recognized losses of $456 million. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement. Due to a reduced probability that the assets would be sold within one year, the assets were no longer considered held for sale at December 31, 2014.

4. Properties and Equipment
The following summarizes properties and equipment by segment at December 31:
millions
2016
 
2015
Oil and gas exploration and production (1)
$
57,581

 
$
59,389

Midstream
8,613

 
8,458

Other
2,819

 
2,836

Gross properties and equipment
$
69,013

 
$
70,683

Less accumulated DD&A
36,845

 
36,932

Net properties and equipment
$
32,168

 
$
33,751

__________________________________________________________________
(1) 
Includes costs associated with unproved properties of $4.1 billion at December 31, 2016, and $3.5 billion at December 31, 2015.


101
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

5. Impairments

Impairments of Long-Lived Assets  Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment at December 31:
 
2016
 
2015
 
2014
millions
Impairment
 
Fair Value (1)
 
Impairment
 
Fair Value (1)
 
Impairment
 
Fair Value (1)
Oil and gas exploration and production
 
 
 
 
 
 
 
 
 
 
 
U.S. onshore properties
$
28

 
$
617

 
$
3,684

 
$
1,253

 
$
545

 
$
552

Gulf of Mexico properties
27

 
61

 
349

 
65

 
276

 
223

Cost-method investment (2)
59

 
—

 
3

 
59

 
3

 
62

Midstream
73

 
32

 
1,039

 
212

 
12

 
—

Other
40

 
—

 
—

 
—

 
—

 
—

Total impairments
$
227

 
$
710

 
$
5,075

 
$
1,589

 
$
836

 
$
837

__________________________________________________________________
(1) 
Measured as of the impairment date using the income approach and Level 3 inputs.
(2) 
The after-tax net investment fair value was $32 million at December 31, 2015 and 2014.

2016  Impairments were primarily related to the uncertain recovery of the Company’s Venezuelan cost-method investment, negative developments related to commercial negotiations of a certain midstream asset, impairment of an office building, changes in development plans for certain U.S. onshore oil and gas assets, and a reduction in estimated future cash flows related to an oil and gas property in the Gulf of Mexico.

2015  Impairments were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties, certain other U.S. onshore oil and gas and midstream properties, and oil and gas properties in the Gulf of Mexico, all of which were impaired due to lower forecasted commodity prices.

2014  Certain U.S. onshore and Gulf of Mexico oil and gas properties were impaired primarily due to lower forecasted commodity prices.

Impairments of Unproved Properties  Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. In 2016, the Company recognized a $72 million impairment of unproved properties in the Gulf of Mexico and $92 million of unproved international properties primarily in Brazil and Tunisia due to the Company’s current intentions to not pursue future exploration activities. In 2015, the Company recognized a $935 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unproved Gulf of Mexico property as a result of lower commodity prices. Also in 2015, the Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.

Potential for Future Impairments  At December 31, 2016, the Company’s estimate of undiscounted future cash flows attributable to a certain international asset group with a net book value of approximately $1.3 billion indicated that the carrying amount was expected to be recovered; however, this asset group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that a 10% decline in oil prices (with all other assumptions unchanged) could result in a non-cash impairment in excess of $550 million for the asset group. It is also reasonably possible that significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in other additional impairments.

102
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

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
2016
 
2015
 
2014
Balance at January 1
$
1,124

 
$
1,522

 
$
2,232

Additions pending the determination of proved reserves
490

 
461

 
421

Divestitures and other (1)
(11
)
 
(33
)
 
(913
)
Reclassifications to proved properties
(50
)
 
(104
)
 
(100
)
Charges to exploration expense (2) (3) (4)
(323
)
 
(722
)
 
(118
)
Balance at December 31
$
1,230

 
$
1,124

 
$
1,522

__________________________________________________________________
(1) 
Includes $(744) million during 2014 related to the Company’s sale of a 10% working interest in Offshore Area 1 in Mozambique.
(2) 
Includes $(565) million during 2015 related to Brazil. The Company does not expect to have substantive exploration and development activities in Brazil in the foreseeable future.
(3) 
Includes $(92) million during 2016 related to Mozambique. The Tubarão Tigre discovery wells were expensed based on the outlook for development viability, the commodity market conditions, and the complexity introduced by the depth and characteristics of the reservoir. The Orca-4 well was expensed after additional reservoir analysis and the determination that the well was not associated with the first three Orca wells.
(4) 
Includes $(231) million during 2016 for the Gulf of Mexico primarily related to the Yeti project, as the Company does not expect to have exploration activities on this prospect in the foreseeable future, and a Shenandoah well that was expensed, as it was no longer reasonably possible that the wellbore could be used in the development of the project, if a final investment decision is reached.

The following provides an aging of suspended well balances at December 31:
millions
2016
 
2015
 
2014
Exploratory well costs capitalized for a period of one year or less
$
460

 
$
452

 
$
393

Exploratory well costs capitalized for a period greater than one year
770

 
672

 
1,129

Balance at December 31
$
1,230

 
$
1,124

 
$
1,522



103
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

6. Suspended Exploratory Well Costs (Continued)

The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2016:
millions except projects
Number of Projects
 
Total
 
2015
 
2014
 
2013 and
prior
U.S. Onshore
15
 
$
58

 
$
12

 
$
25

 
$
21

U.S. Offshore
3
 
296

 
86

 
13

 
197

International
5
 
416

 
184

 
49

 
183

 
23
 
$
770

 
$
282

 
$
87

 
$
401


Projects with suspended exploratory well costs include wells that have sufficient reserves to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling at December 31, 2016, primarily related to the Gulf of Mexico, Ghana, Colombia, Mozambique, and Côte d’Ivoire.

Gulf of Mexico  Exploratory well costs are primarily related to the Shenandoah discovery and have been suspended pending further appraisal activities, including drilling and analysis of well results. Appraisal activities undertaken at the Shenandoah discovery include the acquisition of core and pressure data across the primary reservoir interval, the processing and analysis of seismic data, reservoir simulation modeling, and analysis of well results. Remaining activities required to classify the associated reserves as proved for the Shenandoah discovery include completion of geologic, reservoir, and economic modeling; the drilling of additional wells to test the structure; product development testing; and pre-front end engineering and design (FEED) and FEED engineering studies.

Ghana  Exploratory well costs are suspended pending development plan approval. During the fourth quarter of 2015, the Company and its partners submitted the Jubilee full field development plan to include the Mahogany East and Teak areas, and work is ongoing to gain government approval. Remaining activities required to classify the associated reserves as proved include approval of development plans and project sanctioning.

Colombia  Exploratory well costs are related to the Kronos discovery. Well costs have been suspended pending ongoing appraisal activities, including analysis of well results and geologic and geophysical studies. Remaining activities required to classify the associated reserves as proved for the Kronos discovery include additional exploratory and appraisal drilling, geologic and geophysical studies, reservoir modeling and simulation, economic modeling, pre-development studies, approval of development plans, and project sanctioning.

Mozambique  Exploratory well costs are primarily related to the Golfinho-Atum discovery and have been suspended pending a final investment decision (FID). The Company is progressing three elements that will position the project to take FID: the legal and contractual framework to develop LNG in Mozambique, project finance, and long-term LNG sales contracts. During the fourth quarter of 2016, the Company and its partners submitted the Golfinho-Atum Development Plan to the Government of Mozambique. Approval of the Development Plan and conclusion of the three elements discussed above are required to achieve an affirmative FID and classify the associated reserves as proved.


104
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

6. Suspended Exploratory Well Costs (Continued)

Côte d’Ivoire  Exploratory well costs are related to the Paon discovery and have been suspended pending further appraisal activities. Appraisal activities at Paon in 2016 included drilling a successful horizontal appraisal well at the Paon-5A, successfully drilling a horizontal sidetrack at the Paon-3AR, and performing a drillstem and interference testing program. Additional activities included the analysis of well results and integration into reservoir simulation modeling. Remaining activities required to classify the associated reserves as proved for the Paon discovery include further appraisal drilling; continued geologic, reservoir, and economic modeling; FEED studies; approval of development plans; and project sanctioning.

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.

7. Goodwill and Other Intangible Assets

Goodwill  At December 31, 2016, the Company had $5.0 billion of goodwill allocated to the following reporting units: $4.6 billion to oil and gas exploration and production, $413 million to WES gathering and processing, $5 million to WES transportation, and $32 million to other gathering and processing. During 2016, goodwill decreased $395 million primarily related to asset divestitures. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale. The Company’s 2016 annual qualitative impairment assessment of goodwill indicated no impairment.

Other Intangible Assets  Intangible assets and associated amortization expense were as follows at December 31:
millions
2016
 
2015
Gross carrying amount
$
1,013

 
$
1,013

Accumulated amortization
(109
)
 
(77
)
Net carrying amount
$
904

 
$
936

Amortization expense
$
32

 
$
33


Intangible assets are primarily related to customer contracts associated with WES’s 2014 acquisition of DBM (previously Nuevo). These contracts are being amortized over 30 years. The annual aggregate amortization expense for intangible assets is expected to be $31 million each of the next five years.


105
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

8. 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 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, each with a 35-year term. 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, 2016. Anadarko’s noncontrolling interest may be redeemed beginning in 2022 by Anadarko or the owner of the controlling interest. Anadarko’s interest is mandatorily redeemable in 2037. 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 investment for each entity and the related obligation are presented net on the Company’s Consolidated Balance Sheets. Other long-term liabilities—other included $48 million at December 31, 2016, and $43 million at December 31, 2015, and other assets included $2 million at December 31, 2016 and 2015, related to these investments.
Interest on the notes issued by Anadarko is variable, and is equivalent to LIBOR plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.96% at December 31, 2016, and 1.51% at December 31, 2015. The note payable agreement contains a quarterly covenant that provides for a maximum Anadarko debt-to-capital ratio of 67% (excluding the effect of non-cash write-downs). Anadarko was in compliance with this covenant at December 31, 2016. Other (income) expense, net includes interest expense on the notes payable of $49 million in 2016, $37 million in 2015, and $36 million in 2014, and equity (earnings) losses from Anadarko’s investments in the investee entities of $(33) million in 2016, $15 million in 2015, and $(45) million in 2014.

9. 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 Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. 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 is subject to changes in interest rates.
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 20—Accumulated Other Comprehensive Income (Loss).

106
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

9. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The oil prices listed below are a combination of NYMEX West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at December 31, 2016:
 
 
2017 Settlement  
 
2018 Settlement
Oil
 
 
 
 
Three-Way Collars (MBbls/d)
 
91

 
—

Average price per barrel
 
 
 
 
Ceiling sold price (call)
 
$
59.80

 
$
—

Floor purchased price (put)
 
$
50.00

 
$
—

Floor sold price (put)
 
$
40.00

 
$
—

Natural Gas
 
 
 
 
Three-Way Collars (thousand MMBtu/d)
 
682

 
250

Average price per MMBtu
 
 
 
 
Ceiling sold price (call)
 
$
3.60

 
$
3.54

Floor purchased price (put)
 
$
2.75

 
$
2.75

Floor sold price (put)
 
$
2.00

 
$
2.00

Fixed-Price Contracts (thousand MMBtu/d)
 
37

 
—

Average price per MMBtu
 
$
3.23

 
$
—

NGLs
 
 
 
 
Fixed-Price Contracts (MBbls/d)
 
2

 
—

Average price per barrel
 
$
15.84

 
$
—


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

Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 2 Bcf at December 31, 2016, and 8 Bcf at December 31, 2015, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.


107
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

9. Derivative Instruments (Continued)

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.
In 2015, the Company extended the reference-period start dates and amended the mandatory termination dates on certain interest-rate swaps so that, at the start of the reference period, Anadarko will receive quarterly payments based on the floating rate and make semi-annual payments based on the fixed interest rate. The interest-rate swaps are required to be settled in full at the mandatory termination date. As part of these interest-rate swap modifications, the fixed interest rates on the swaps were also adjusted, and the Company recognized a loss of $137 million, which is included in gains (losses) on derivatives, net in the Company’s Consolidated Statement of Income, and increased the related derivative liability. In February 2016, in exchange for amended terms with certain counterparties, the Company modified the mandatory termination dates from 2021 to 2018 and, in some cases, the related fixed interest rates on interest-rate swaps with an aggregate notional principal amount of $500 million.
At December 31, 2016, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or at September 2021 that will manage interest-rate risk associated with the potential refinancing of the Company’s $900 million Senior Notes due 2019 and the Zero Coupons, should the Zero Coupons be put to the Company prior to the swap termination dates. At the next put date in October 2017, the accreted value of the Zero Coupons will be $883 million. See Note 11—Debt and Interest Expense. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps.
Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization 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, any settlements or collateralization related to these extended interest-rate derivatives are classified as cash flows from financing activities. Interest-rate swap agreements were settled for total cash payments of $266 million in 2016 and $222 million in 2014.
The Company had the following outstanding interest-rate swaps at December 31, 2016:
millions except percentages
 
 
 
Mandatory
 
Weighted-Average
Notional Principal Amount
 
Reference Period
 
Termination Date
 
Interest Rate
$
500

 
 
September 2016 – 2046
 
September 2018
 
6.559%
$
300

 
 
September 2016 – 2046
 
September 2020
 
6.509%
$
450

 
 
September 2017 – 2047
 
September 2018
 
6.445%
$
100

 
 
September 2017 – 2047
 
September 2020
 
6.891%
$
250

 
 
September 2017 – 2047
 
September 2021
 
6.570%


108
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

9. Derivative Instruments (Continued)

Effect of Derivative Instruments—Balance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31:
millions
 
Gross
Derivative Assets
 
Gross
Derivative Liabilities
Balance Sheet Classification          
 
2016
 
2015
 
2016
 
2015
Commodity derivatives
 
 
 
 
 
 
 
 
Other current assets
 
$
10

 
$
462

 
$
(3
)
 
$
(177
)
Other assets
 
9

 
8

 
—

 
—

Accrued expenses
 
66

 
—

 
(201
)
 
(3
)
Other liabilities
 
—

 
—

 
(12
)
 
—

 
 
85

 
470

 
(216
)
 
(180
)
Interest-rate derivatives
 
 
 
 
 
 
 
 
Other current assets
 
8

 
2

 
—

 
—

Other assets
 
23

 
54

 
—

 
—

Accrued expenses
 
—

 
—

 
(48
)
 
(54
)
Other liabilities
 
—

 
—

 
(1,328
)
 
(1,488
)
 
 
31

 
56

 
(1,376
)
 
(1,542
)
Total derivatives
 
$
116

 
$
526

 
$
(1,592
)
 
$
(1,722
)

Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:
millions
 
 
 
 
 
 
Classification of (Gain) Loss Recognized
 
2016
 
2015
 
2014
Commodity derivatives
 
 
 
 
 
 
Gathering, processing, and marketing sales (1)
 
$
6

 
$
(1
)
 
$
10

(Gains) losses on derivatives, net
 
147

 
(367
)
 
(589
)
Interest-rate derivatives
 
 
 
 
 
 
(Gains) losses on derivatives, net
 
139

 
268

 
786

Total (gains) losses on derivatives, net
 
$
292

 
$
(100
)
 
$
207

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


109
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

9. Derivative Instruments (Continued)

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines and assesses the impact on the 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.
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 portfolio 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 declines to a level that is below investment grade. In February 2016, Moody’s downgraded the Company’s long-term debt credit rating from investment grade (Baa2) to below investment grade (Ba1). The downgrade triggered credit-risk-related features with certain derivative counterparties and required the Company to post collateral under its derivative instruments. During the third quarter of 2016, Anadarko negotiated the increase of a credit threshold for an interest-rate derivative. As a result of the increased credit threshold, $200 million of collateral was returned to the Company. No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.4 billion (net of $117 million of collateral) at December 31, 2016, and $1.3 billion (net of $58 million of collateral) at December 31, 2015.


110
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

9. Derivative Instruments (Continued)

Fair Value  Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate 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, 2016
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
2

 
$
83

 
$
—

 
$
(69
)
 
$
—

 
$
16

Interest-rate derivatives
—

 
31

 
—

 
—

 
—

 
31

Total derivative assets
$
2

 
$
114

 
$
—

 
$
(69
)
 
$
—

 
$
47

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(3
)
 
$
(213
)
 
$
—

 
$
69

 
$
6

 
$
(141
)
Interest-rate derivatives
—

 
(1,376
)
 
—

 
—

 
117

 
(1,259
)
Total derivative liabilities
$
(3
)
 
$
(1,589
)
 
$
—

 
$
69

 
$
123

 
$
(1,400
)
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
10

 
$
460

 
$
—

 
$
(178
)
 
$
(8
)
 
$
284

Interest-rate derivatives
—

 
56

 
—

 
—

 
—

 
56

Total derivative assets
$
10

 
$
516

 
$
—

 
$
(178
)
 
$
(8
)
 
$
340

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(1
)
 
$
(179
)
 
$
—

 
$
178

 
$
—

 
$
(2
)
Interest-rate derivatives
—

 
(1,542
)
 
—

 
—

 
58

 
(1,484
)
Total derivative liabilities
$
(1
)
 
$
(1,721
)
 
$
—

 
$
178

 
$
58

 
$
(1,486
)
__________________________________________________________________
(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.

111
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

10. Tangible Equity Units

In June 2015, the Company issued 9.2 million 7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification.
Anadarko allocated the proceeds from the issuance of the TEUs to equity and debt based on the relative fair values of their respective components as follows:
millions, except price per TEU
Equity Component
 
Debt Component
 
Total
Price per TEU
$
39.05

 
$
10.95

 
$
50.00

Gross proceeds
359

 
101

 
460

Less issuance costs
11

 
4

 
15

Net proceeds
$
348

 
$
97

 
$
445


The prepaid equity purchase contracts were recorded in noncontrolling interests, net of issuance costs, and the senior amortizing notes were recorded in short-term debt and long-term debt on the Company’s Consolidated Balance Sheet.

Equity Component  Unless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC Shares) in lieu of delivering WGP common units at settlement. The Company will deliver WGP common units (or APC Shares) on the settlement date at the settlement rate based upon the applicable market value of WGP common units (or APC Shares) as follows:
 
 
Settlement Rate per Purchase Contract (1)
Applicable Market Value of WGP Common Units (1)
 
WGP Common Units
 
APC Shares (if elected) 
Exceeds $69.1181 (Threshold Appreciation Price)
 
0.7234 units (Minimum Settlement Rate)
 
a number of shares equal to (a) the Minimum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC Shares
Less than or equal to the Threshold Appreciation Price, but greater than or equal to $57.5901 (Reference Price)
 
a number of units equal to $50.00, divided by the applicable market value of WGP common units
 
a number of shares equal to $50.00, divided by 98% of the applicable market value of APC Shares
Less than the Reference Price
 
0.8682 units (Maximum Settlement Rate)
 
a number of shares equal to (a) the Maximum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC Shares
 __________________________________________________________________
(1) 
The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC Shares) for the 20 consecutive trading days beginning on, and including, the 23rd scheduled trading day immediately preceding June 7, 2018.


112
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

10. Tangible Equity Units (Continued)

The WGP common units underlying the purchase contract are currently issued and outstanding, and are owned by a wholly owned subsidiary of Anadarko. In the event Anadarko elects to settle in APC Shares, the number of such shares issued and delivered upon settlement of each purchase contract is subject to adjustment and cannot exceed the APC Share cap of 4.0629 shares under any circumstance. The above fixed settlement rates for WGP common units and the APC Share cap are subject to adjustment upon the occurrence of certain specified dilutive events such as certain increases in the WGP distribution rate or the payment of dividends by Anadarko.

Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. Beginning September 7, 2015, Anadarko began paying equal quarterly cash installments of $0.9375 per amortizing note (except for the September 7, 2015 installment payment, which was $0.9063 per amortizing note). The payments constitute a payment of interest and partial repayment of principal, with the aggregate per-year payments of principal and interest equating to a 7.50% cash payment with respect to each TEU. The senior amortizing notes have a final installment payment date of June 7, 2018, and are senior unsecured obligations of the Company. For activity related to the senior amortizing notes, see Note 11—Debt and Interest Expense.


113
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

11. Debt and Interest Expense

Debt Activity  The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions:
 
Carrying Value
 
 
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
 
Description
Balance at December 31, 2014
$
2,409

 
$
—

 
$
12,574

 
$
14,983

 
 
Issuances
490

 
—

 
—

 
490

 
WES 3.950% Senior Notes due 2025
 
—

 
—

 
97

 
97

 
TEUs - senior amortizing notes
Borrowings
—

 
—

 
1,500

 
1,500

 
$5.0 Billion Facility
 
—

 
—

 
1,800

 
1,800

 
364-Day Facility
 
400

 
—

 
—

 
400

 
WES RCF
 
—

 
—

 
250

 
250

 
Commercial paper notes, net (3)
Repayments
—

 
—

 
(1,500
)
 
(1,500
)
 
$5.0 Billion Facility
 
—

 
—

 
(1,800
)
 
(1,800
)
 
364-Day Facility
 
(610
)
 
—

 
—

 
(610
)
 
WES RCF
 
—

 
—

 
(16
)
 
(16
)
 
TEUs - senior amortizing notes
Other, net
2

 
—

 
52

 
54

 
Amortization of discounts, premiums, and debt issuance costs
Balance at December 31, 2015
$
2,691

 
$
—

 
$
12,957

 
$
15,648

 
 
Issuances
—

 
—

 
794

 
794

 
4.850% Senior Notes due 2021 (4)
 
—

 
—

 
1,088

 
1,088

 
5.550% Senior Notes due 2026 (4)
 
—

 
—

 
1,088

 
1,088

 
6.600% Senior Notes due 2046 (4)
 
495

 
—

 
—

 
495

 
WES 4.650% Senior Notes due 2026
 
203

 
—

 
—

 
203

 
WES 5.450% Senior Notes due 2044
Borrowings
—

 
—

 
1,750

 
1,750

 
364-Day Facility
 
600

 
—

 
—

 
600

 
WES RCF
 
—

 
28

 
—

 
28

 
WGP RCF
Repayments
—

 
—

 
(1,749
)
 
(1,749
)
 
5.950% Senior Notes due 2016
 
—

 
—

 
(1,994
)
 
(1,994
)
 
6.375% Senior Notes due 2017
 
—

 
—

 
(1,750
)
 
(1,750
)
 
364-Day Facility
 
(900
)
 
—

 
—

 
(900
)
 
WES RCF
 
—

 
—

 
(250
)
 
(250
)
 
Commercial paper notes, net
 
—

 
—

 
(34
)
 
(34
)
 
TEUs - senior amortizing notes
Other, net
2

 
—

 
59

 
61

 
Amortization of discounts, premiums, and debt issuance costs
Balance at December 31, 2016
$
3,091

 
$
28

 
$
11,959

 
$
15,078

 
 
__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.
(3) 
Includes repayments of $(106) million related to commercial paper notes with maturities greater than 90 days.
(4) 
Represent senior notes issued in March 2016.

During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. In December 2016, the Company redeemed its remaining $750 million 6.375% Senior Notes due September 2017. The Company recognized losses of $155 million for the early retirement and redemption of these senior notes, which included $144 million of premiums paid.

114
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

11. Debt and Interest Expense (Continued)

Debt  See Note 8—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, including capital lease obligations, after eliminating the effect of intercompany transactions:
 
December 31, 2016
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
7.050% Debentures due 2018
$
—

 
$
—

 
$
114

 
$
114

TEUs - senior amortizing notes due 2018
—

 
—

 
51

 
51

WES 2.600% Senior Notes due 2018
350

 
—

 
—

 
350

6.950% Senior Notes due 2019
—

 
—

 
300

 
300

8.700% Senior Notes due 2019
—

 
—

 
600

 
600

4.850% Senior Notes due 2021
—

 
—

 
800

 
800

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

 
625

6.950% Senior Notes due 2024
—

 
—

 
650

 
650

WES 3.950% Senior Notes due 2025
500

 
—

 
—

 
500

WES 4.650% Senior Notes due 2026
500

 
—

 
—

 
500

5.550% Senior Notes due 2026
—

 
—

 
1,100

 
1,100

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

 
625

WES 5.450% Senior Notes due 2044
600

 
—

 
—

 
600

6.600% Senior Notes due 2046
—

 
—

 
1,100

 
1,100

7.730% Debentures due 2096
—

 
—

 
61

 
61

7.500% Debentures due 2096
—

 
—

 
78

 
78

7.250% Debentures due 2096
—

 
—

 
49

 
49

WGP RCF
—

 
28

 
—

 
28

Total borrowings at face value
$
3,120

 
$
28

 
$
13,558

 
$
16,706

Net unamortized discounts, premiums, and debt issuance costs (3)
(29
)
 
—

 
(1,599
)
 
(1,628
)
Total borrowings (4)
3,091

 
28

 
11,959

 
15,078

Capital lease obligations
—

 
—

 
245

 
245

Less short-term debt
—

 
—

 
42

 
42

Total long-term debt
$
3,091

 
$
28

 
$
12,162

 
$
15,281


115
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

11. Debt and Interest Expense (Continued)

 
December 31, 2015
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
Commercial paper
$
—

 
$
—

 
$
250

 
$
250

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

TEUs - senior amortizing notes due 2018
—

 
—

 
85

 
85

WES 2.600% Senior Notes due 2018
350

 
—

 
—

 
350

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

 
625

6.950% Senior Notes due 2024
—

 
—

 
650

 
650

WES 3.950% Senior Notes due 2025
500

 
—

 
—

 
500

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

 
625

WES 5.450% Senior Notes due 2044
400

 
—

 
—

 
400

7.730% Debentures due 2096
—

 
—

 
61

 
61

7.500% Debentures due 2096
—

 
—

 
78

 
78

7.250% Debentures due 2096
—

 
—

 
49

 
49

WES RCF
300

 
—

 
—

 
300

Total borrowings at face value
$
2,720

 
$
—

 
$
14,592

 
$
17,312

Net unamortized discounts, premiums, and debt issuance costs (3)
(29
)
 
—

 
(1,635
)
 
(1,664
)
Total borrowings (4)
2,691

 
—

 
12,957

 
15,648

Capital lease obligations
—

 
—

 
20

 
20

Less short-term debt
—

 
—

 
32

 
32

Total long-term debt
$
2,691

 
$
—

 
$
12,945

 
$
15,636

__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.
(3) 
Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.
(4) 
The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

116
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

11. Debt and Interest Expense (Continued)

In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the 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 $849 million at December 31, 2016. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2016, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.

Scheduled Maturities  Total principal amount of debt maturities related to borrowings for the five years ending December 31, 2021, excluding the potential repayment of the outstanding Zero Coupons that may be put by the holders to the Company annually, were as follows:
 
Principal Amount of Debt Maturities
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
2017
$
—

 
$
—

 
$
34

 
$
34

2018
350

 
—

 
131

 
481

2019
—

 
28

 
900

 
928

2020
—

 
—

 
—

 
—

2021
500

 
—

 
800

 
1,300

__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.

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 $17.1 billion at December 31, 2016, and $15.7 billion at December 31, 2015.


117
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

11. Debt and Interest Expense (Continued)

Anadarko Revolving Credit Facilities and Commercial Paper Program  Anadarko has a $3.0 billion five-year senior unsecured revolving credit facility maturing in January 2021 (Five-Year Facility). In addition, the Company has a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). In January 2017, the Company extended the maturity date of the 364-Day Facility until 2018.
Borrowings under the Five-Year Facility and the 364-Day Facility (collectively, the 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 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% (excluding the effect of non-cash write-downs), and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes. At December 31, 2016, the Company had no outstanding borrowings under the Credit Facilities and was in compliance with all related covenants.
In January 2015, the Company initiated a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Five-Year Facility. The maturities of the commercial paper notes may vary, but may not exceed 397 days. In February 2016, Moody’s downgraded the Company’s commercial paper program credit rating, which eliminated the Company’s access to the commercial paper market. The Company has not issued commercial paper notes since the downgrade and had no outstanding borrowings under the commercial paper program at December 31, 2016.

WES and WGP Borrowings  In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion of the amount outstanding under WES’s $1.2 billion five-year senior unsecured revolving credit facility previously maturing in February 2019 (WES RCF), which is expandable to $1.5 billion. In October 2016, WES completed a public offering of $200 million aggregate principal amount of 5.450% Senior Notes due April 2044. Net proceeds were primarily used to repay amounts outstanding under the WES RCF, and the remaining proceeds were used for general partnership purposes, including capital expenditures. In December 2016, WES amended the WES RCF to extend the maturity date to February 2020.
Borrowings under the WES 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, 2016, WES had no outstanding borrowings under its RCF, had outstanding letters of credit of $5 million, and had available borrowing capacity of $1.195 billion. At December 31, 2016, WES was in compliance with all related covenants.
In March 2016, WGP entered into a $250 million three-year senior secured revolving credit facility maturing in March 2019 (WGP RCF), which is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES), as well as all equity interests owned by WGP. Borrowings under the WGP RCF bear interest at LIBOR (with a floor of 0%), plus applicable margins ranging from 2.00% to 2.75% depending on WGP’s consolidated leverage ratio, or at a base rate equal to the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50%, or (iii) LIBOR plus 1.00%, in each case plus applicable margins ranging from 1.00% to 1.75% based upon WGP’s consolidated leverage ratio. At December 31, 2016, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of 2.77%, had available borrowing capacity of $222 million, and was in compliance with all related covenants.


118
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

11. Debt and Interest Expense (Continued)

Capital Lease Obligations  Construction of a FPSO for the Company’s TEN field in Ghana commenced in 2013. The Company recognized an asset and related obligation for its approximate 19% nonoperated working interest share during the construction period. Upon completion of the construction in the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s proportionate share of the fair value of the FPSO. The FPSO lease provides for an initial term of 10 years with annual renewal periods for an additional 10 years, annual purchase options that decrease over time, and no residual value guarantees. The capital lease asset will be depreciated over the estimated proved reserves of the TEN field using the UOP method, with the associated depreciation included in DD&A in the Company’s Consolidated Statement of Income. The capital lease obligation will be accreted to the present value of the minimum lease payments using the effective interest method. The Company expects to make the first payment related to the FPSO in the first quarter of 2017.
At December 31, 2016, future minimum lease payments related to the Company’s capital leases were:
millions
 
2017
$
57

2018
42

2019
42

2020
43

2021
42

Remaining years
391

Total future minimum lease payments
$
617

Less portion representing imputed interest
372

Capital lease obligations
$
245


Interest Expense  The following summarizes interest expense for the years ended December 31:
millions
2016
 
2015
 
2014
Debt and other
$
1,022

 
$
989

 
$
973

Capitalized interest
(132
)
 
(164
)
 
(201
)
Total interest expense
$
890

 
$
825

 
$
772



119
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

12. Income Taxes

The following summarizes components of income tax expense (benefit) for the years ended December 31:
millions
2016
 
2015
 
2014
Current
 
 
 
 
 
Federal
$
(140
)
 
$
(177
)
 
$
188

State
(1
)
 
(18
)
 
2

Foreign
378

 
495

 
1,574

 
237

 
300

 
1,764

Deferred
 
 
 
 
 
Federal
(1,020
)
 
(2,929
)
 
(389
)
State
(148
)
 
(145
)
 
27

Foreign
(90
)
 
(103
)
 
215

 
(1,258
)
 
(3,177
)
 
(147
)
Total income tax expense (benefit)
$
(1,021
)
 
$
(2,877
)
 
$
1,617


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
2016
 
2015
 
2014
Income (loss) before income taxes
 
 
 
 
 
Domestic
$
(3,728
)
 
$
(9,155
)
 
$
(3,564
)
Foreign
(101
)
 
(534
)
 
3,618

Total
$
(3,829
)
 
$
(9,689
)
 
$
54

U.S. federal statutory tax rate
35
%
 
35
%
 
35
%
Tax computed at the U.S. federal statutory rate
$
(1,340
)
 
$
(3,391
)
 
$
19

Adjustments resulting from
 
 
 
 
 
State income taxes (net of federal income tax benefit)
(108
)
 
(81
)
 
(11
)
Tax impact from foreign operations
80

 
299

 
62

Non-deductible Algerian exceptional profits tax
106

 
102

 
193

Net changes in uncertain tax positions
90

 
54

 
1,427

(Income) loss attributable to noncontrolling interests
(92
)
 
42

 
(66
)
Dispositions of non-deductible goodwill
205

 
62

 
21

Other, net
38

 
36

 
(28
)
Total income tax expense (benefit)
$
(1,021
)
 
$
(2,877
)
 
$
1,617

Effective tax rate
27
%
 
30
%
 
2,994
%


120
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

12. Income Taxes (Continued)

The following summarizes components of total deferred taxes at December 31:
millions
2016
 
2015
Federal
$
(3,805
)
 
$
(4,721
)
State, net of federal
(173
)
 
(248
)
Foreign
(332
)
 
(431
)
Total deferred taxes
$
(4,310
)
 
$
(5,400
)

The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31:
millions
2016
 
2015
Deferred tax liabilities
 
 
 
Oil and gas exploration and development operations
$
(5,054
)
 
$
(5,643
)
Midstream and other depreciable properties
(870
)
 
(1,049
)
Mineral operations
(550
)
 
(492
)
Other
(147
)
 
(470
)
Gross long-term deferred tax liabilities
(6,621
)
 
(7,654
)
Deferred tax assets
 
 
 
Foreign and state net operating loss carryforwards
648

 
586

U.S. foreign tax credit carryforwards
1,834

 
1,254

Compensation and benefit plans
672

 
615

Mark to market on derivatives
324

 
441

Other
588

 
761

Gross long-term deferred tax assets
4,066

 
3,657

Valuation allowances on deferred tax assets not expected to be realized
(1,755
)
 
(1,403
)
Net long-term deferred tax assets
2,311

 
2,254

Total deferred taxes
$
(4,310
)
 
$
(5,400
)

The valuation allowance primarily relates to U.S. foreign tax credit carryforwards and foreign and state net operating loss carryforwards, which reduces the Company’s net deferred tax asset to an amount that will more likely than not be realized within the carryforward period.
The following summarizes changes in the balance of valuation allowances on deferred tax assets:
millions
2016
 
2015
 
2014
Balance at January 1
$
(1,403
)
 
$
(864
)
 
$
(818
)
Changes due to U.S. foreign tax credits
(477
)
 
(384
)
 
11

Changes due to foreign and state net operating loss carryforwards
13

 
10

 
64

Changes due to foreign capitalized costs
112

 
(165
)
 
(121
)
Balance at December 31
$
(1,755
)
 
$
(1,403
)
 
$
(864
)



121
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

12. Income Taxes (Continued)

Tax carryforwards available for use on future income tax returns, prior to valuation allowance, at December 31, 2016, were as follows:
millions
Domestic
 
Foreign
 
Expiration
Net operating loss—foreign
$
—

 
$
1,498

 
2017 - Indefinite
Net operating loss—state
$
4,888

 
$
—

 
2017-2036
Foreign tax credits
$
1,834

 
$
—

 
2023-2027
Texas margins tax credit
$
34

 
$
—

 
2026

The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31:
millions
 
 
 
 
Balance Sheet Classification
 
2016
 
2015
Income taxes receivable
 
 
 
 
Accounts receivable—other
 
$
180

 
$
1,046

Other assets
 
67

 
61

 
 
247

 
1,107

Income taxes (payable)
 
 
 
 
Accrued expense
 
(6
)
 
(9
)
Total net income taxes receivable (payable)
 
$
241

 
$
1,098


Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:
 
Assets (Liabilities)
millions
2016
 
2015
 
2014
Balance at January 1
$
(1,780
)
 
$
(1,687
)
 
$
(147
)
Increases related to prior-year tax positions
(86
)
 
(99
)
 
(11
)
Decreases related to prior-year tax positions
436

 
89

 
39

Increases related to current-year tax positions
(26
)
 
(263
)
 
(1,568
)
Settlements
—

 
180

 
—

Balance at December 31
$
(1,456
)
 
$
(1,780
)
 
$
(1,687
)

Included in the 2016 ending balance of unrecognized tax benefits presented above are potential benefits of $1.424 billion, of which, if recognized, $1.397 billion would affect the effective tax rate on income. Also included in the 2016 ending balance are benefits of $33 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain.

122
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

12. Income Taxes (Continued)

As of December 31, 2016, the Company had recorded a total tax benefit of $576 million related to the Tronox-related contingent liability. This benefit is net of a $1.3 billion uncertain tax position due to the uncertainty related to the deductibility of the settlement payment. It is reasonably possible that the amount of the uncertain tax position related to the settlement could change, perhaps materially. See Note 16—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 16—Contingencies—Other Litigation. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $50 million to $100 million due to settlements with taxing authorities or lapse in statutes of limitation. With the exception of the deductibility of the Tronox settlement payment discussed above, 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 $31 million of interest related to uncertain tax positions at December 31, 2016, and $11 million at December 31, 2015. The Company recognized interest and penalties in income tax expense (benefit) of $21 million during 2016 and $2 million during 2015.
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 following lists the tax years subject to examination by major tax jurisdiction:
 
Tax Years
United States
2012-2015
Algeria
2012-2015
Ghana
2006-2015

13. 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:
millions
2016
 
2015
Carrying amount at January 1
$
2,059

 
$
2,053

Liabilities acquired (1)
813

 
—

Liabilities incurred
93

 
104

Property dispositions
(88
)
 
(108
)
Liabilities settled
(225
)
 
(298
)
Accretion expense
100

 
102

Revisions in estimated liabilities
179

 
206

Carrying amount at December 31
$
2,931

 
$
2,059

__________________________________________________________________
(1) 
In December 2016, the Company closed the GOM Acquisition. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale for additional information.


123
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

14. Conveyance of Future Hard Minerals Royalty Revenues

During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. Such conveyance entitles the third party to receive up to $553 million in future royalty revenue over a period of not less than 10 years and not greater than 15 years. Additionally, such third party is entitled to receive 3% of the aggregate royalties earned during the first 10 years between $800 million and $900 million and 4% of the aggregate royalties earned during the first 10 years that exceed $900 million. Generally, such third party relies solely on the royalty payments to recover its investment and, as such, has the risk of the royalties not being sufficient to recover its investment over the term of the conveyance.
Proceeds from this transaction were accounted for as deferred revenues and are included in accrued expenses and other long-term liabilities on the Company’s Consolidated Balance Sheet. The deferred revenues will be amortized to other revenues, included in gains (losses) on divestitures and other, net on a unit-of-revenue basis over the term of the agreement. Net proceeds received from the third party were reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Semi-annual payments to the third party are scheduled on March 1 and September 1 of each year through March 1, 2026. The specified future amounts that the Company expects to pay and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the conveyance. Royalties received by Anadarko under this agreement are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. The semi-annual payments to the third party, up to the aggregate amount of the $413 million net proceeds the Company received for the conveyance in the first quarter of 2016, are reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Any additional payments to the third party are reported in operating activities on the Company’s Consolidated Statement of Cash Flows to offset the royalties received.
During the year ended December 31, 2016, the Company amortized $37 million of deferred revenues as a result of this agreement. The Company made the first semi-annual payment of $25 million for royalties in 2016. The following summarizes the remaining amounts that the Company expects to pay, prior to the potential 3% to 4% of any excess described above:
millions
 
2017
$
50

2018
50

2019
52

2020
56

2021
57

Later years
263

Total
$
528



124
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

15. Commitments

Operating Leases  At December 31, 2016, the Company had $1.2 billion in long-term drilling rig commitments that are accounted for as operating leases. The Company also had $320 million of various commitments under non-cancelable operating lease agreements for production platforms and equipment, buildings, facilities, compressors, aircraft, and vessels. 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 of $82 million at December 31, 2016. No liability was 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, 2016:
millions
 
2017
$
673

2018
480

2019
234

2020
81

2021
29

Later years
23

Total future minimum lease payments
$
1,520


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 $1.15 billion related to five offshore drilling vessels and $50 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 $73 million in 2016, $77 million in 2015, and $85 million in 2014. Total rent expense included contingent rent expense related to transportation and processing fees of $6 million in 2016, $17 million in 2015, and $22 million in 2014.

Other Commitments  Anadarko has various long-term contractual commitments pertaining to oil and natural-gas activities such as work-related commitments for drilling wells, obtaining and processing seismic data, and fulfilling rig commitments. Anadarko also enters into various processing, transportation, storage, and purchase agreements to access markets and provide flexibility to sell its oil, natural gas, and NGLs in certain areas. These agreements expire at various dates through 2033. The following summarizes the gross aggregate future payments under these contracts at December 31, 2016:
millions
 
2017
$
1,328

2018
1,207

2019
1,001

2020
934

2021
677

Later years
1,224

Total future minimum lease payments (1)
$
6,371

__________________________________________________________________
(1) 
Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.

125
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

16. 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 personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, 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 $7 million at December 31, 2016, and $269 million at December 31, 2015, 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.

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 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. 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.
Numerous Deepwater Horizon event-related civil lawsuits were filed against BP and other parties, including the Company. Generally, the plaintiffs sought actual damages, punitive damages, declaratory judgment, and/or injunctive relief. This litigation was consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court).

BP Consent Decree In July 2015, BP announced a settlement agreement in principle with the U.S. Department of Justice (DOJ) and certain states and local government entities regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event (BP Settlement) and, in October 2015, lodged a proposed consent decree with the Louisiana District Court. In April 2016, the Louisiana District Court approved the consent decree. As a result of the BP Settlement and approval of the consent decree, all liability relating to OPA-related environmental costs was resolved and all NRD claims and claims by the United States and the Gulf states impacted by the event relating to the MDL action were dismissed. For any remaining claims relating to the MDL action, the Company is fully indemnified by BP against any losses pursuant to the Settlement Agreement.


126
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

16. Contingencies (Continued)

Penalties and Fines  In December 2010, the DOJ on behalf of the United States, filed a civil lawsuit in the Louisiana District Court against several parties, including the Company, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. After previously finding that Anadarko, as a nonoperating investor in the Macondo well, was not culpable with respect to the Deepwater Horizon events, the Louisiana District Court found Anadarko liable for civil penalties under Section 311 of the CWA as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. Neither party appealed the decision and the Company paid the penalty in the first quarter of 2016. 

Tronox Litigation  In August 2006, Anadarko acquired all of the stock of Kerr-McGee Corporation. In January 2009, Tronox, a former subsidiary of Kerr-McGee Corporation which completed an IPO in November 2005 (Tronox), and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. 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.
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). Pursuant to Tronox’s Plan of Reorganization, a litigation trust (Litigation Trust) pursued the Adversary Proceeding against the Company.
On April 3, 2014, Anadarko and Kerr-McGee entered into a settlement agreement with the Litigation Trust and the U.S. government (on behalf of itself and 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. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective.
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, included in Tronox-related contingent loss in the Company’s Consolidated Statements of Income, of $60 million during 2014 and $5 million during the first quarter of 2015. At December 31, 2016 and 2015, there was no Tronox-related contingent liability on the Company’s Consolidated Balance Sheet. For information on the tax effects of the Tronox settlement agreement, see Note 12—Income Taxes.


127
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

16. 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. In December 2008, the Company deposited the amount of tax originally in dispute in a Brazilian real-denominated judicially-controlled Brazilian bank account pending final resolution of the matter. At December 31, 2016, the deposit of $104 million is included in other assets on the Company’s Consolidated Balance Sheet.
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 appeal to the Brazilian Supreme Court has been stayed pending a decision in the Superior Court appeal.
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 the amount of tax currently in dispute and any interest on such excess amount. In April 2015, the Company’s petition was denied. The Company appealed this decision. The appeal was denied in November 2015.
The Company believes that it will more likely than not prevail in the Brazilian Superior Court and the Brazilian Supreme Court. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at December 31, 2016. 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 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. At December 31, 2015, the Company had a decommissioning obligation recorded of $116 million. Anadarko completed the decommissioning obligations, and at December 31, 2016, the Company had no remaining liability recorded.

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 $118 million at December 31, 2016, and $145 million at December 31, 2015. 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 liabilities—other on the Company’s Consolidated Balance Sheets. The Company continually monitors remediation and reclamation processes and adjusts its liability for these obligations as necessary.

128
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

17. Restructuring Charges

In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. All restructuring charges were recognized in 2016, with the exception of an estimated $42 million of settlement expense for retirement benefits to be recognized in 2017. The 2017 settlement expense is expected to be triggered by lump-sum payments to terminated participants and the amount could vary depending on market conditions and participant elections. The following summarizes the total expected restructuring charges and the amounts expensed during the year ended December 31, 2016, which are included in general and administrative expenses in the Company’s Consolidated Statements of Income:
millions
Total
Expected Costs
 
Year Ended December 31, 2016
Costs by category
 
 
 
Cash severance
$
153

 
$
153

Retirement benefits (1)
239

 
197

Share-based compensation
39

 
39

Total
$
431

 
$
389

__________________________________________________________________
(1) 
Includes termination benefits, curtailments, and settlements. See Note 18—Pension Plans and Other Postretirement Benefits.

The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet:
millions
2016
Balance at January 1
$
—

Accruals
153

Payments
(145
)
Balance at December 31
$
8


129
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

18. 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.
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, 2016 and 2015, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2016 and 2015:
 
Pension Benefits
 
Other Benefits
millions
2016
 
2015
 
2016
 
2015
Change in benefit obligation
 
 
 
 
 
 
 
Benefit obligation at beginning of year
$
2,431

 
$
2,528

 
$
266

 
$
373

Service cost
99

 
118

 
3

 
9

Interest cost
95

 
101

 
12

 
15

Plan amendments
—

 
—

 
—

 
(89
)
Actuarial (gain) loss (1)
211

 
(115
)
 
34

 
(27
)
Participant contributions
—

 
—

 
4

 
5

Benefit payments
(513
)
 
(194
)
 
(23
)
 
(20
)
Foreign-currency exchange-rate changes
(22
)
 
(7
)
 
—

 
—

Benefit obligation at end of year (2)
$
2,301

 
$
2,431

 
$
296

 
$
266

Change in plan assets
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
$
1,674

 
$
1,818

 
$
—

 
$
—

Actual return on plan assets
107

 
16

 
—

 
—

Employer contributions
101

 
43

 
19

 
15

Participant contributions
—

 
—

 
4

 
5

Benefit payments
(513
)
 
(194
)
 
(23
)
 
(20
)
Foreign-currency exchange-rate changes
(29
)
 
(9
)
 
—

 
—

Fair value of plan assets at end of year
$
1,340

 
$
1,674

 
$
—

 
$
—

 
 
 
 
 
 
 
 
Funded status of the plans at end of year
$
(961
)
 
$
(757
)
 
$
(296
)
 
$
(266
)
 
 
 
 
 
 
 
 
Total recognized amounts in the balance sheet consist of







Other assets
$
44


$
41


$
—


$
—

Accrued expenses
(66
)

(24
)

(23
)

(16
)
Other long-term liabilities—other
(939
)

(774
)

(273
)

(250
)
Total
$
(961
)

$
(757
)

$
(296
)

$
(266
)
 
 
 
 
 
 
 
 
Total recognized amounts in accumulated other comprehensive income consist of







Prior service cost (credit)
$
—


$
(1
)

$
(50
)

$
(84
)
Net actuarial (gain) loss
616


655


—


(25
)
Total
$
616


$
654


$
(50
)

$
(109
)
__________________________________________________________________
(1) 
Includes $44 million of termination benefits, $2 million related to curtailment for pension, and $9 million related to curtailment for other benefits at December 31, 2016, associated with the Company’s workforce reduction program initiated in the first quarter of 2016. See Note 17—Restructuring Charges.
(2) 
The accumulated benefit obligation for all defined-benefit pension plans was $2.0 billion at December 31, 2016 and $2.1 billion at December 31, 2015.

130
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

18. 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
2016
 
2015
Projected benefit obligation
$
2,175

 
$
2,309

Accumulated benefit obligation
1,866

 
1,954

Fair value of plan assets
1,171

 
1,511


The following summarizes the Company’s pension and other postretirement benefit cost for the years ended December 31:
 
Pension Benefits
 
Other Benefits
millions
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Components of net periodic benefit cost
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
99

 
$
118

 
$
99

 
$
3

 
$
9

 
$
7

Interest cost
95

 
101

 
99

 
12

 
15

 
15

Expected (return) loss on plan assets
(97
)
 
(109
)
 
(106
)
 
—

 
—

 
—

Amortization of net actuarial loss (gain)
42

 
52

 
34

 
—

 
—

 
(7
)
Amortization of net prior service cost (credit)
—

 
—

 
—

 
(25
)
 
(4
)
 
—

Settlement expense (1)
146

 
11

 
—

 
—

 
—

 
—

Termination benefits expense (1)
44

 
—

 
—

 
—

 
—

 
—

Curtailment expense (1)
8

 
—

 
—

 
—

 
—

 
—

Net periodic benefit cost
$
337

 
$
173

 
$
126

 
$
(10
)
 
$
20

 
$
15

__________________________________________________________________
(1) 
During 2016, settlement expenses, termination benefits expense, and curtailment expense primarily relate to the workforce reduction program initiated in the first quarter of 2016. See Note 17—Restructuring Charges.

The following summarizes the amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31:
 
Pension Benefits
 
Other Benefits
millions
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Amounts recognized in other comprehensive income (expense)
 
 
 
 
 
 
 
 
 
 
 
Net actuarial gain (loss)
$
(150
)
 
$
22

 
$
(333
)
 
$
(25
)
 
$
27

 
$
(72
)
Amortization of net actuarial (gain) loss
188

 
63

 
34

 
—

 
—

 
(7
)
Net prior service (cost) credit
—

 
—

 
—

 
—

 
89

 
—

Amortization of net prior service cost (credit)
—

 
—

 
—

 
(34
)
 
(4
)
 
—

Total amounts recognized in other comprehensive income (expense)
$
38

 
$
85

 
$
(299
)
 
$
(59
)
 
$
112

 
$
(79
)

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. In 2017, an estimated $20 million of net actuarial loss and $24 million of net prior service credit for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost.

131
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

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

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 inflation (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.
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 pension and other postretirement benefit obligations and net periodic benefit cost for the years ended December 31:
 
Pension Benefits
 
Other Benefits
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Benefit obligation assumptions
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.06
%
 
4.50
%
 
4.00
%
 
4.26
%
 
5.00
%
 
4.25
%
Rates of increase in compensation levels
5.40
%
 
5.25
%
 
5.25
%
 
5.48
%
 
5.50
%
 
5.25
%
Net periodic benefit cost assumptions
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.62
%
 
4.00
%
 
4.75
%
 
5.00
%
 
4.25
%
 
5.25
%
Long-term rate of return on plan assets
6.77
%
 
6.75
%
 
6.75
%
 
N/A

 
N/A

 
N/A

Rates of increase in compensation levels
5.34
%
 
5.25
%
 
5.00
%
 
5.41
%
 
5.25
%
 
5.25
%

An annual rate of increase indexed to the Consumer Price Index is assumed for purposes of measuring other postretirement benefit obligations. A rate of 2.00% at December 31, 2016, and 1.75% at December 31, 2015, was assumed for purposes of measuring other postretirement benefit obligations.



132
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

18. 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 2016 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.

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.


133
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

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

Investments in securities traded in active markets are measured based on unadjusted quoted prices, which represent Level 1 inputs. Investments based on Level 2 inputs include direct investments in corporate debt and other fixed-income securities. Investments included as Level 3 inputs are not observable from objective sources.
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, 2016
Level 1
 
Level 2
 
Level 3 (3)
 
Total
Investments
 
 
 
 
 
 
 
Cash and cash equivalents
$
2

 
$
—

 
$
—

 
$
2

Fixed income
 
 
 
 
 
 
 
Mortgage-backed securities
—

 
1

 
—

 
1

Other fixed-income securities
59

 
32

 
—

 
91

Equity securities
 
 
 
 
 
 
 
Domestic
248

 
—

 
—

 
248

International
99

 
—

 
—

 
99

Other
 
 
 
 
 
 
 
Real estate
—

 
—

 
10

 
10

Other
—

 
28

 
—

 
28

Investments measured at net asset value (1)
—

 
—

 
—

 
861

Total investments (2)
$
408

 
$
61

 
$
10

 
$
1,340

 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
Investments
 
 
 
 
 
 
 
Cash and cash equivalents
$
5

 
$
—

 
$
—

 
$
5

Fixed income
 
 
 
 
 
 
 
Mortgage-backed securities
—

 
1

 
—

 
1

U.S. government securities
—

 
1

 
—

 
1

Other fixed-income securities
46

 
32

 
—

 
78

Equity securities
 
 
 
 
 
 
 
Domestic
330

 
—

 
—

 
330

International
130

 
—

 
—

 
130

Other
 
 
 
 
 
 
 
Real estate
—

 
—

 
13

 
13

Hedge funds
7

 
—

 
—

 
7

Other
—

 
30

 
—

 
30

Investments measured at net asset value (1)
—

 
—

 
—

 
1,081

Total investments (2)
$
518

 
$
64

 
$
13

 
$
1,676

Liabilities
 
 
 
 
 
 
 
Hedge funds
$
(3
)
 
$
—

 
$
—

 
$
(3
)
Total liabilities
$
(3
)
 
$
—

 
$
—

 
$
(3
)
__________________________________________________________________
(1) 
Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.
(2) 
Amount excludes receivables and payables, primarily related to Level 1 investments.
(3) 
The changes in level 3 investments of $(3) million for the year ended December 31, 2016, and $1 million for the year ended December 31, 2015, were attributable to the actual return on plan assets still held at the reporting date.

134
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

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

Cash Contributions and Expected Benefit Payments While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2016, the Company monitors the status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. Contributions to funded plans increase plan assets, while contributions to unfunded plans are used to fund current benefit payments.
The following summarizes the Company’s contributions for 2016 and expected contributions for 2017:
millions
Expected 2017
 
2016
Funded pension plans
$
140

 
$
3

Unfunded pension plans
67

 
98

Unfunded other postretirement plans
24

 
19

Total
$
231

 
$
120


The following summarizes estimated benefit payments for the next 10 years, including benefit increases due to continuing employee service:
millions
Pension
Benefit
Payments
 
Other
Benefit
Payments
2017
$
302

 
$
24

2018
147

 
20

2019
166

 
20

2020
164

 
20

2021
171

 
19

2022-2026
1,009

 
93


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 related to these plans of $64 million for 2016, and $76 million for both 2015 and 2014.


135
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

19. Stockholders’ Equity

Common Stock  In September 2016, the Company completed a public offering of 40.5 million shares of its common stock at a price of $53.23 per share. Net proceeds of $2.16 billion from this equity issuance were primarily used to fund the GOM Acquisition. The remaining net proceeds were used for general corporate purposes. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale. The following summarizes the changes in the Company’s outstanding shares of common stock:
millions
2016
 
2015
 
2014
Shares of common stock issued
 
 
 
 
 
Shares at January 1
528

 
526

 
523

Exercise of stock options
1

 
1

 
2

Issuance of common stock
41

 
—

 
—

Issuance of restricted stock
2

 
1

 
1

Shares at December 31
572

 
528

 
526

Shares of common stock held in treasury
 
 
 
 
 
Shares at January 1
20

 
19

 
19

Shares received for restricted stock vested and stock options exercised
1

 
1

 
—

Shares at December 31
21

 
20

 
19

Shares of common stock outstanding at December 31
551

 
508

 
507


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 and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, TEUs, and WES Series A Preferred units, if the inclusion of these items is dilutive.
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
2016
 
2015
 
2014
Net income (loss)
 
 
 
 
 
Net income (loss) attributable to common stockholders
$
(3,071
)
 
$
(6,692
)
 
$
(1,750
)
Income (loss) effect of TEUs
(6
)
 
—

 
—

Less distributions on participating securities
1

 
3

 
4

Basic
$
(3,078
)
 
$
(6,695
)
 
$
(1,754
)
Income (loss) effect of TEUs
(1
)
 
—

 
—

Diluted
$
(3,079
)
 
$
(6,695
)
 
$
(1,754
)
Shares
 
 
 
 
 
Average number of common shares outstanding—basic
522

 
508

 
506

Average number of common shares outstanding—diluted
522

 
508

 
506

Excluded due to anti-dilutive effect
11

 
11

 
11

Net income (loss) per common share
 
 
 
 
 
Basic
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
Diluted
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)

136
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

20. 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
)
Other comprehensive income (loss), before reclassifications
—

 
87

 
87

Reclassifications to Consolidated Statement of Income
6

 
41

 
47

Net other comprehensive income (loss)
6

 
128

 
134

Balance at December 31, 2015
$
(42
)
 
$
(341
)
 
$
(383
)
Other comprehensive income (loss), before reclassifications
—

 
(107
)
 
(107
)
Reclassifications to Consolidated Statement of Income
5

 
94

 
99

Net other comprehensive income (loss)
5

 
(13
)
 
(8
)
Balance at December 31, 2016
$
(37
)
 
$
(354
)
 
$
(391
)

21. Share-Based Compensation

At December 31, 2016, 34 million shares of the 42 million shares of Anadarko common stock authorized for awards under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. The following summarizes share-based compensation expense for the years ended December 31:
millions
2016
 
2015
 
2014
Restricted stock (1)
$
175

 
$
157

 
$
144

Stock options (1)
20

 
19

 
21

Other equity-classified awards
2

 
1

 
1

Value creation plan
—

 
(4
)
 
136

Performance-based unit awards (1)
38

 
(1
)
 
23

Pretax share-based compensation expense
$
235

 
$
172

 
$
325

Income tax benefit
$
86

 
$
64

 
$
120

__________________________________________________________________
(1) 
Includes restructuring charges of $31 million for restricted stock, $1 million for stock options, and $7 million for performance-based unit awards in 2016. See Note 17—Restructuring Charges for further discussion.


137
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

21. Share-Based Compensation (Continued)

Cash flows from financing activities included excess tax benefits related to share-based compensation of zero in 2016, $6 million in 2015, and $22 million in 2014. Cash received from stock option exercises was $30 million in 2016, $28 million in 2015, and $99 million in 2014.

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 generally up to three years and is not considered issued and outstanding for accounting purposes 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, 2016
3.98

 
$
82.39

Granted
3.11

 
$
52.03

Vested
(2.43
)
 
$
81.19

Forfeited
(0.12
)
 
$
63.78

Non-vested at December 31, 2016
4.54

 
$
62.74


The weighted-average grant-date fair value per share of restricted stock granted was $79.40 during 2015 and $87.42 during 2014. The total fair value of restricted shares vested was $114 million during 2016, $141 million during 2015, and $132 million during 2014, based on the market price at the vesting date. At December 31, 2016, total unrecognized compensation cost related to restricted stock of $188 million is expected to be recognized over a weighted-average remaining service period of 2.0 years.

138
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

21. 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:
 
2016
 
2015
 
2014
Weighted-average grant-date fair value
$
15.92
 
 
$
18.18
 
 
$
23.55
 
Assumptions
 
 
 
 
 
 
 
 
Expected option life—years
4.1
 
 
4.9
 
 
4.9
 
Volatility
38.2
%
 
32.4
%
 
29.9
%
Risk-free interest rate
1.3
%
 
1.4
%
 
1.6
%
Dividend yield
0.6
%
 
1.4
%
 
1.1
%

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, 2016
7.05

 
$
71.86

 
 
 
 
Granted
1.38

 
$
67.74

 
 
 
 
Exercised (1)
(0.90
)
 
$
33.69

 
 
 
 
Forfeited or expired
(0.91
)
 
$
72.40

 
 
 
 
Outstanding at December 31, 2016
6.62

 
$
76.10

 
3.18
 
$
10.6

Vested or expected to vest at December 31, 2016
6.56

 
$
76.15

 
3.16
 
$
10.4

Exercisable at December 31, 2016
5.05

 
$
78.61

 
2.22
 
$
3.5

__________________________________________________________________
(1) 
The total intrinsic value of stock options exercised was $7 million during 2016, $23 million during 2015, and $88 million during 2014, based on the difference between the market price at the exercise date and the exercise price.

At December 31, 2016, total unrecognized compensation cost related to stock options of $28 million is expected to be recognized over a weighted-average remaining service period of 2.0 years.

139
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

21. Share-Based Compensation (Continued)

Liability-Classified Awards

Value Creation Plan  As a part of its employee compensation program, the Company offered an incentive compensation program that provided 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 $134 million during 2015 related to the plan and zero during 2014. The Value Creation Plan was discontinued as an active plan beginning in 2015.

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 each 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. Following the end of each performance period, the value of the vested performance units, if any, is paid in cash. The Company paid $6 million related to vested performance units in 2016, $9 million in 2015, and $12 million in 2014. At December 31, 2016, the Company’s liability under Performance Unit Award Agreements was $49 million, with total unrecognized compensation cost related to these awards of $47 million expected to be recognized over a weighted-average remaining performance period of 2.1 years.

22. Noncontrolling Interests

WES is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During the first quarter of 2016, WES issued 14 million Series A Preferred units to private investors for net proceeds of $440 million, and issued 1.3 million common units to the Company. Proceeds from these issuances were used to acquire interests in Springfield Pipeline LLC from the Company. During the second quarter of 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and raised net proceeds of $247 million.
WES issued approximately 874 thousand common units to the public and raised net proceeds of $57 million in 2015, and issued approximately 10 million common units to the public and raised net proceeds of $691 million in 2014. In addition, WES issued 11 million Class C units to Anadarko in 2014 to partially fund the DBM acquisition. These units will receive quarterly distributions in the form of additional Class C units until the end of 2017, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 946 thousand Class C units to Anadarko during 2016 and 498 thousand Class C units during 2015.
WGP is a limited partnership formed by Anadarko to own interests in WES. Anadarko sold 12.5 million WGP common units to the public for net proceeds of $476 million in 2016, 2.3 million WGP common units to the public for net proceeds of $130 million in 2015, and approximately 6 million WGP common units to the public for net proceeds of $335 million in 2014. In June 2015, Anadarko issued 9.2 million TEUs, which include an equity component that may be settled in WGP common units. For additional disclosure of the TEU effect on noncontrolling interests, see Note 10—Tangible Equity Units. At December 31, 2016, Anadarko’s ownership interest in WGP consisted of an 81.6% limited partner interest and the entire non-economic general partner interest. The remaining 18.4% limited partner interest in WGP was owned by the public.
At December 31, 2016, WGP’s ownership interest in WES consisted of a 29.9% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At December 31, 2016, Anadarko also owned an 8.6% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 60.0% limited partner interest in WES was owned by the public.


140
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

23. Variable Interest Entities

Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES; therefore, Anadarko is considered the primary beneficiary and consolidates WGP and WES. See Note 22—Noncontrolling Interests for additional information on WGP and WES.

Assets and Liabilities of VIEs The assets of WGP and WES cannot be used by Anadarko for general corporate purposes and are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP and WES for which the creditors do not have recourse to other assets of the Company are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.
All outstanding debt for WES at December 31, 2016 and 2015, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at December 31, 2016 and 2015, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note 11—Debt and Interest Expense for additional information on WGP and WES long-term debt balances.

VIE Financing WGP’s sources of liquidity include borrowings under its RCF and distributions from WES. WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under its RCF, the issuance of additional partnership units, or debt offerings. See Note 11—Debt and Interest Expense and Note 22—Noncontrolling Interests for additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $17 million for each of the years ended December 31, 2016 and 2015. The note receivable and related interest income are eliminated in consolidation.
In March 2015, WES acquired the Company’s interest in DBJV. The acquisition was financed using a deferred purchase price obligation which requires a cash payment from WES to the Company due on March 31, 2020. The cash payment due to the Company is equal to eight multiplied by the average of WES’s share in DBJV Net Earnings for 2018 and 2019 less WES’s share of capital expenditures incurred for DBJV from March 1, 2015 to February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses, and property taxes. The net present value of this obligation was $41 million at December 31, 2016, and $189 million at December 31, 2015. The reduction in the value of the deferred purchase price obligation was primarily due to revisions reflecting an increase in WES’s estimate of capital expenditures to be incurred by DBJV, partially offset by an increase in WES’s estimate of future Net Earnings.
Anadarko has commodity price swap agreements in place with WES expiring on December 31, 2017. WES has recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for the amount by which the swap price exceeds the applicable market price. WES recorded a $46 million capital contribution from Anadarko for the year ended December 31, 2016, and a capital contribution of $18 million for the year ended December 31, 2015.


141
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

24. Supplemental Cash Flow Information

Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells whether or not they were deemed to have a commercially sufficient quantity of proved reserves. For the year ended December 31, 2015, the Company’s Consolidated Statement of Cash Flows included an $881 million increase in tax receivable related to the Tronox settlement included in (increase) decrease in accounts receivable, offset by an $881 million uncertain tax position included in other items, net.
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
2016
 
2015
 
2014
Cash paid (received)
 
 
 
 
 
Interest, net of amounts capitalized (1)
$
856

 
$
2,019

 
$
689

Income taxes, net of refunds (2)
(882
)
 
26

 
956

Non-cash investing activities
 
 
 
 
 
Fair value of properties and equipment from non-cash transactions
$
3

 
$
178

 
$
18

Asset retirement cost additions
298

 
273

 
348

Accruals of property, plant, and equipment
549

 
754

 
1,177

Net liabilities assumed (divested) in acquisitions and divestitures
723

 
(114
)
 
(92
)
Property insurance receivable
—

 
49

 
—

Acquisition receivable
(32
)
 
—

 
—

Non-cash investing and financing activities
 
 
 
 
 
Acquisition contingent consideration
$
103

 
$
—

 
$
—

Capital lease obligation (3)
10

 
—

 
13

FPSO construction period obligation (3)
11

 
59

 
128

Deferred drilling lease liability
30

 
—

 
—

__________________________________________________________________
(1) 
Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.
(2) 
Includes $881 million from a tax refund related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.
(3) 
Upon completion of the FPSO in the third quarter of 2016, the Company reported the construction period obligation as a capital lease obligation based on the fair-value of the FPSO. See Note 11—Debt and Interest Expense.

25. 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 oil, natural gas, 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.

142
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

25. 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; gains (losses) on divestitures, net; 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 (loss) attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included restructuring charges related to the workforce reduction program included in general and administrative expenses, Deepwater Horizon settlement and related costs included in other operating expenses, loss on early extinguishment of debt, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators 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 (loss) 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 Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial performance across periods. 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. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes for the years ended December 31:
millions
2016
 
2015
 
2014
Income (loss) before income taxes
$
(3,829
)
 
$
(9,689
)
 
$
54

(Gains) losses on divestitures, net
757

 
1,022

 
(1,891
)
Exploration expense
946

 
2,644

 
1,639

DD&A
4,301

 
4,603

 
4,550

Impairments
227

 
5,075

 
836

Interest expense
890

 
825

 
772

Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
559

 
235

 
578

Restructuring charges
389

 
—

 
—

Other operating expense
1

 
74

 
97

Loss on early extinguishment of debt
155

 
—

 
—

Tronox-related contingent loss
—

 
5

 
4,360

Certain other nonoperating items
(58
)
 
22

 
22

Less net income (loss) attributable to noncontrolling interests
263

 
(120
)
 
187

Consolidated Adjusted EBITDAX
$
4,075

 
$
4,936

 
$
10,830


143
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

25. 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
2016
 
 
 
 
 
 
 
 
 
Sales revenues
$
4,191

 
$
635

 
$
3,621

 
$
—

 
$
8,447

Intersegment revenues
2,651

 
1,403

 
(3,094
)
 
(960
)
 
—

Other
—

 
—

 
—

 
179

 
179

Total revenues and other (1)
6,842

 
2,038

 
527

 
(781
)
 
8,626

Operating costs and expenses (2)
3,238

 
978

 
691

 
(303
)
 
4,604

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(265
)
 
(265
)
Other (income) expense, net (3)
—

 
—

 
—

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

 
263

 
—

 
—

 
263

Total expenses and other
3,238

 
1,241

 
691

 
(611
)
 
4,559

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

 
—

 
8

 
—

 
8

Adjusted EBITDAX
$
3,604

 
$
797

 
$
(156
)
 
$
(170
)
 
$
4,075

Net properties and equipment
$
24,251

 
$
5,913

 
$
—

 
$
2,004

 
$
32,168

Capital expenditures
$
2,685

 
$
550

 
$
—

 
$
79

 
$
3,314

Goodwill
$
4,550

 
$
450

 
$
—

 
$
—

 
$
5,000

__________________________________________________________________
(1) 
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(2) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
(3) 
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

144
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

25. Segment Information (Continued)
millions
Oil and Gas
Exploration
& Production
 
Midstream
 
Marketing
 
Other and
Intersegment
Eliminations
 
Total
2015
 
 
 
 
 
 
 
 
 
Sales revenues
$
4,734

 
$
727

 
$
4,025

 
$
—

 
$
9,486

Intersegment revenues
3,178

 
1,207

 
(3,476
)
 
(909
)
 
—

Other
—

 
—

 
—

 
234

 
234

Total revenues and other (1)
7,912

 
1,934

 
549

 
(675
)
 
9,720

Operating costs and expenses (2)
3,456

 
998

 
743

 
(86
)
 
5,111

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(335
)
 
(335
)
Other (income) expense, net (3)
—

 
—

 
—

 
127

 
127

Net income (loss) attributable to noncontrolling interests
—

 
(120
)
 
—

 
—

 
(120
)
Total expenses and other
3,456

 
878

 
743

 
(294
)
 
4,783

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

 
—

 
(1
)
 
—

 
(1
)
Adjusted EBITDAX
$
4,456

 
$
1,056

 
$
(195
)
 
$
(381
)
 
$
4,936

Net properties and equipment
$
25,742

 
$
5,876

 
$
—

 
$
2,133

 
$
33,751

Capital expenditures
$
5,029

 
$
770

 
$
—

 
$
89

 
$
5,888

Goodwill
$
4,945

 
$
450

 
$
—

 
$
—

 
$
5,395

2014
 
 
 
 
 
 
 
 
 
Sales revenues
$
8,603

 
$
484

 
$
7,288

 
$
—

 
$
16,375

Intersegment revenues
6,225

 
1,338

 
(6,771
)
 
(792
)
 
—

Other
—

 
—

 
—

 
204

 
204

Total revenues and other (1)
14,828

 
1,822

 
517

 
(588
)
 
16,579

Operating costs and expenses (2)
4,216

 
972

 
740

 
17

 
5,945

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(377
)
 
(377
)
Other (income) expense, net (3)
—

 
—

 
—

 
(2
)
 
(2
)
Net income (loss) 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
$
10,612

 
$
663

 
$
(219
)
 
$
(226
)
 
$
10,830

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)
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(2) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
(3) 
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

145
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014

25. 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
2016
 
2015
 
2014
Sales Revenues
 
 
 
 
 
United States
$
7,049

 
$
7,819

 
$
13,083

Algeria
1,103

 
1,189

 
2,435

Other International
295

 
478

 
857

Total sales revenues
$
8,447

 
$
9,486

 
$
16,375


 
December 31,
millions
2016
 
2015
Net Properties and Equipment
 
 
 
United States
$
28,024

 
$
29,625

Algeria
1,117

 
1,271

Other International
3,027

 
2,855

Total net properties and equipment
$
32,168

 
$
33,751




146
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 2016, 2015, and 2014 has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas and the SEC’s final rule, Modernization of Oil and Gas Reporting. Disclosures by geographic area include the United States and International. For 2016, the International geographic area consisted 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 PUDs, net of third-party royalty interests, of oil, natural gas, and NGLs owned at each year end and changes in proved reserves during each of the last three years. Oil and NGLs volumes are presented in MMBbls and natural-gas volumes are presented in Bcf at a pressure base of 14.73 pounds per square inch. Total volumes are presented in 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.
The prices below were used to compute the information presented in the following tables and are adjusted only for fixed and determinable amounts under provisions in existing contracts:
 
 
Oil
per Bbl
 
Natural Gas per MMBtu
 
NGLs
per Bbl
December 31, 2016
 
$
42.75

 
$
2.48

 
$
19.74

December 31, 2015
 
$
50.28

 
$
2.59

 
$
19.47

December 31, 2014
 
$
94.99

 
$
4.35

 
$
45.25




147
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Oil and Gas Reserves (Continued)
 
Oil
(MMBbls)
 
Natural Gas
(Bcf)
 
United States
 
International
 
Total
 
United States
 
International
 
Total
Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
592

 
259

 
851

 
9,205

 
—

 
9,205

Revisions of prior estimates
167

 
18

 
185

 
710

 
31

 
741

Extensions, discoveries, and other additions
25

 
—

 
25

 
196

 
—

 
196

Purchases in place
—

 
—

 
—

 
—

 
—

 
—

Sales in place
(6
)
 
(17
)
 
(23
)
 
(492
)
 
—

 
(492
)
Production
(74
)
 
(35
)
 
(109
)
 
(951
)
 
—

 
(951
)
December 31, 2014
704

 
225

 
929

 
8,668

 
31

 
8,699

Revisions of prior estimates
2

 
(6
)
 
(4
)
 
(888
)
 
4

 
(884
)
Extensions, discoveries, and other additions
15

 
—

 
15

 
60

 
—

 
60

Purchases in place
—

 
—

 
—

 
8

 
—

 
8

Sales in place
(111
)
 
—

 
(111
)
 
(1,003
)
 
—

 
(1,003
)
Production
(85
)
 
(31
)
 
(116
)
 
(854
)
 
(5
)
 
(859
)
December 31, 2015
525

 
188

 
713

 
5,991

 
30

 
6,021

Revisions of prior estimates
11

 
3

 
14

 
310

 
—

 
310

Extensions, discoveries, and other additions
24

 
—

 
24

 
59

 
—

 
59

Purchases in place
81

 
—

 
81

 
68

 
—

 
68

Sales in place
(14
)
 
—

 
(14
)
 
(1,263
)
 
—

 
(1,263
)
Production
(86
)
 
(30
)
 
(116
)
 
(766
)
 
(5
)
 
(771
)
December 31, 2016
541

 
161

 
702

 
4,399

 
25

 
4,424

Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
347

 
202

 
549

 
7,120

 
—

 
7,120

December 31, 2014
352

 
190

 
542

 
6,635

 
27

 
6,662

December 31, 2015
332

 
159

 
491

 
5,184

 
30

 
5,214

December 31, 2016
360

 
147

 
507

 
3,637

 
25

 
3,662

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
245

 
57

 
302

 
2,085

 
—

 
2,085

December 31, 2014
352

 
35

 
387

 
2,033

 
4

 
2,037

December 31, 2015
193

 
29

 
222

 
807

 
—

 
807

December 31, 2016
181

 
14

 
195

 
762

 
—

 
762

 

148
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, 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

Revisions of prior estimates (1)
(99
)
 
4

 
(95
)
 
(245
)
 
(1
)
 
(246
)
Extensions, discoveries, and other additions
4

 
—

 
4

 
29

 
—

 
29

Purchases in place
—

 
—

 
—

 
1

 
—

 
1

Sales in place
(1
)
 
—

 
(1
)
 
(279
)
 
—

 
(279
)
Production
(45
)
 
(2
)
 
(47
)
 
(272
)
 
(34
)
 
(306
)
December 31, 2015
325

 
15

 
340

 
1,849

 
208

 
2,057

Revisions of prior estimates (1)
45

 
2

 
47

 
108

 
5

 
113

Extensions, discoveries, and other additions
6

 
—

 
6

 
40

 
—

 
40

Purchases in place
5

 
—

 
5

 
97

 
—

 
97

Sales in place
(69
)
 
—

 
(69
)
 
(294
)
 
—

 
(294
)
Production
(44
)
 
(2
)
 
(46
)
 
(258
)
 
(33
)
 
(291
)
December 31, 2016
268

 
15

 
283

 
1,542

 
180

 
1,722

Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
268

 
—

 
268

 
1,801

 
202

 
2,003

December 31, 2014
304

 
13

 
317

 
1,762

 
207

 
1,969

December 31, 2015
257

 
15

 
272

 
1,453

 
179

 
1,632

December 31, 2016
193

 
15

 
208

 
1,159

 
166

 
1,325

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
127

 
12

 
139

 
720

 
69

 
789

December 31, 2014
162

 
—

 
162

 
853

 
36

 
889

December 31, 2015
68

 
—

 
68

 
396

 
29

 
425

December 31, 2016
75

 
—

 
75

 
383

 
14

 
397

__________________________________________________________________
(1) 
Revisions of prior estimates include the effects of new infill drilling, changes in commodity prices, and other updates, including changes in economic conditions, changes in reservoir performance, and changes to development plans. Additions generated by Anadarko’s infill drilling programs were 69 MMBOE for 2016, 89 MMBOE for 2015, and 577 MMBOE for 2014.

149
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Total proved reserves decreased by 335 MMBOE in 2016 primarily due to the following:
Revisions of prior estimates  Prior estimates of proved reserves were revised upward by 113 MMBOE.
MMBOE
December 31, 2016
Revisions due to changes in year-end prices (price impact to opening balance)
(147
)
Other revisions of prior estimates
 
Revisions due to performance
74

Revisions due to cost reductions
100

Revisions due to successful infill drilling
69

Revisions due to development plan updates
(3
)
Other revisions
20

Total other revisions of prior estimates
260

Revisions of prior estimates
113

Negative revisions of 147 MMBOE were due to the decline in commodity prices. The negative price-related revisions were offset by a net increase of 260 MMBOE associated with the following:
•
Performance The Company experienced an increase of 74 MMBOE in proved reserves. Upward revisions of 102 MMBOE are primarily due to improved well performance in the DJ basin, certain U.S. shale plays, and select wells in the Gulf of Mexico. Downward revisions of 28 MMBOE are primarily due to performance updates associated with select wells in the Gulf of Mexico.
•
Cost reductions Ongoing cost-optimization efforts, and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in proved reserves. The Eagleford and the DJ basin areas experienced an increase of 94 MMBOE of proved reserves associated with certain wells, included in the negative price-related revisions, which experienced restored economic producibility upon reduction of the cost structure. The remaining increase in proved reserves due to the improved cost structure is attributable to numerous areas across the Company.
•
Infill drilling activities The Company added 69 MMBOE of proved reserves associated with infill drilling activities, the majority of which were in the DJ basin and the K2 and Caesar/Tonga areas of the Gulf of Mexico.
•
Other revisions Other revisions resulted from the Company’s multi-step reserves reconciliation process and the elimination of duplicative adjustments to the opening reserves balance.
Extensions and discoveries  Proved reserves increased by 40 MMBOE through the extension of proved acreage, primarily as a result of successful drilling in the Delaware basin. Although shale plays represented only 20% of the Company’s total proved reserves at December 31, 2016, growth in the shale plays contributed a majority of the total extensions and discoveries.
Purchases in place Proved reserves increased by 97 MMBOE due to the GOM Acquisition. The increase is comprised of 67 MMBOE of proved developed reserves and 30 MMBOE of PUDs.
Sales in place  Proved reserves decreased by 294 MMBOE due to the divestiture of certain U.S. onshore properties. The decrease is comprised of 279 MMBOE of proved developed reserves and 15 MMBOE of PUDs.

150
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Total proved reserves decreased by 801 MMBOE in 2015 primarily due to the following:
Revisions of prior estimates  Prior estimates of proved reserves were revised downward by 246 MMBOE.
MMBOE
December 31, 2015
Revisions due to changes in year-end prices (price impact to opening balance)
(624
)
Other revisions of prior estimates
 
Revisions due to performance
222

Revisions due to cost reductions
139

Revisions due to successful infill drilling
89

Revisions due to development plan updates
(126
)
Other revisions
54

Total other revisions of prior estimates
378

Revisions of prior estimates
(246
)
Negative revisions of 624 MMBOE were due to the decline in commodity prices and include a reduction to NGLs reserves of 43 MMBOE associated with price-induced ethane rejection. The negative price-related revisions were partially offset by a net increase of 378 MMBOE associated with the following:
•
Performance The Company experienced an increase of 169 MMBOE in proved reserves due primarily to increases to planned lateral lengths in the Eagleford area of South Texas combined with improved well performance in the Eagleford area, the DJ basin, and the Marcellus area of the Appalachian basin. All other performance increases are a result of minor improvements from numerous areas throughout the Company.
•
Cost reductions Capital spent in 2015 associated with ongoing drilling and completion activities, ongoing cost-optimization efforts, and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in proved reserves. The DJ basin and Greater Natural Buttes areas and the Eagleford area experienced an increase of 81 MMBOE of proved reserves due to drilling activity associated with certain wells, included in the negative price-related revisions, which experienced restored economic producibility upon reduction of the capital cost structure. An increase of 14 MMBOE in proved reserves is associated with the Marcellus area where certain wells, included in the negative price-related revisions, experienced extended economic limits as a result of reductions to operating expenses during 2015. The remaining increase in proved reserves due to the improved cost structure is attributable to numerous areas across the Company.
•
Infill drilling activities The Company added 89 MMBOE of proved reserves associated with infill drilling activities during 2015, the majority of which were in the DJ basin.
•
Development plan updates The majority of revisions associated with updates to development plans occurred in the DJ basin due to a significantly reduced development pace related to the decrease in commodity prices.
•
Other revisions Other revisions resulted from the Company’s multi-step reserves reconciliation process and the elimination of duplicative adjustments to the opening reserves balance.
Extensions and discoveries  Proved reserves increased by 29 MMBOE through the extension of proved acreage, primarily as a result of successful drilling in the Delaware basin. Although shale plays represented only 20% of the Company’s total proved reserves at December 31, 2015, growth in the shale plays contributed almost all of the total extensions and discoveries.
Sales in place  Proved developed reserves decreased by 238 MMBOE primarily associated with the divestiture of a portion of the Company’s East Texas assets and EOR and coalbed methane assets. PUDs decreased by 41 MMBOE primarily associated with divestiture activities in the U.S. onshore.

151
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)

Total proved reserves increased by 66 MMBOE in 2014 primarily due to the following:
Revisions of prior estimates  Prior estimates of proved reserves were revised upward by 439 MMBOE.
MMBOE
December 31, 2014
Revisions due to changes in year-end prices (price impact to opening balance)
(1
)
Other revisions of prior estimates
 
Revisions due to performance
42

Revisions due to successful infill drilling
577

Revisions due to development plan updates
(179
)
Total other revisions of prior estimates
440

Revisions of prior estimates
439

Positive revisions of 439 MMBOE were associated with the following:
•
Performance The Company experienced an increase in proved reserves primarily due to improved well performance in the DJ basin as well as in certain shale and international assets.
•
Infill drilling activities The Company added 577 MMBOE of proved reserves associated with infill drilling primarily in large onshore areas such as the DJ basin and the Eagleford and Haynesville shales.
•
Development plan updates The majority of the revisions associated with updates to development plans occurred in the DJ basin due to the optimization of horizontal drilling locations and the discontinuation of vertical well workover plans.
Extensions and discoveries  Proved reserves increased by 63 MMBOE primarily as a result of successful drilling in the Marcellus and Delaware basin shale plays. Although shale plays represented only 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.
Sales in place  Proved developed reserves decreased by 69 MMBOE and PUDs decreased by 55 MMBOE due to divestitures, including 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.

152
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, LNG facilities costs, and other corporate activities are not included.
millions
United States
 
International
 
Total
December 31, 2016
 
 
 
 
 
Capitalized
 
 
 
 
 
Unproved properties
$
3,332

 
$
804

 
$
4,136

Proved properties
47,476

 
5,752

 
53,228

 
50,808

 
6,556

 
57,364

Less accumulated DD&A
30,675

 
2,655

 
33,330

Net capitalized costs
$
20,133

 
$
3,901

 
$
24,034

December 31, 2015
 
 
 
 
 
Capitalized
 
 
 
 
 
Unproved properties
$
2,742

 
$
739

 
$
3,481

Proved properties
50,275

 
5,472

 
55,747

 
53,017

 
6,211

 
59,228

Less accumulated DD&A
31,366

 
2,281

 
33,647

Net capitalized costs
$
21,651

 
$
3,930

 
$
25,581

 

153
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 AROs established in the current year as well as increases or decreases to the AROs 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, 2016
 
 
 
 
 
Property acquisitions
 
 
 
 
 
Unproved
$
178

 
$
9

 
$
187

Proved
2,498

 
—

 
2,498

Exploration
398

 
433

 
831

Development
1,780

 
337

 
2,117

Total costs incurred
$
4,854

 
$
779

 
$
5,633

Year Ended December 31, 2015
 
 
 
 
 
Property acquisitions
 
 
 
 
 
Unproved
$
293

 
$
1

 
$
294

Proved
81

 
—

 
81

Exploration
503

 
609

 
1,112

Development
3,660

 
606

 
4,266

Total costs incurred
$
4,537

 
$
1,216

 
$
5,753

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


154
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 oil, natural gas, 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 labor; well service and repair; location maintenance; power and fuel; gathering; processing; transportation; production, property, and 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. Other operating expense includes Deepwater Horizon settlement and related costs. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A 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, 2016
 
 
 
 
 
Net revenues from production
 
 
 
 
 
Third-party sales
$
3,884

 
$
619

 
$
4,503

Sales to consolidated affiliates
1,871

 
779

 
2,650

Gains (losses) on property dispositions
(855
)
 
(6
)
 
(861
)
 
4,900

 
1,392

 
6,292

Production costs
 
 
 
 
 
Oil and gas operating
607

 
204

 
811

Oil and gas transportation
964

 
38

 
1,002

Production-related general and administrative expenses
317

 
20

 
337

Production, property, and other taxes
189

 
282

 
471

 
2,077

 
544

 
2,621

Exploration expenses
541

 
405

 
946

DD&A
3,512

 
395

 
3,907

Impairments related to oil and gas properties
55

 
—

 
55

Other operating expense
62

 
49

 
111

 
(1,347
)
 
(1
)
 
(1,348
)
Income tax expense (benefit)
(494
)
 
155

 
(339
)
Results of operations
$
(853
)
 
$
(156
)
 
$
(1,009
)
 

155
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, 2015
 
 
 
 
 
Net revenues from production
 
 
 
 
 
Third-party sales
$
4,409

 
$
673

 
$
5,082

Sales to consolidated affiliates
2,184

 
994

 
3,178

Gains (losses) on property dispositions
(976
)
 
(14
)
 
(990
)
 
5,617

 
1,653

 
7,270

Production costs
 
 
 
 
 
Oil and gas operating
815

 
199

 
1,014

Oil and gas transportation
1,083

 
34

 
1,117

Production-related general and administrative expenses
398

 
11

 
409

Production, property, and other taxes
218

 
270

 
488

 
2,514

 
514

 
3,028

Exploration expenses
1,447

 
1,197

 
2,644

DD&A
3,785

 
399

 
4,184

Impairments related to oil and gas properties
4,033

 
—

 
4,033

Other operating expense
150

 
—

 
150

 
(6,312
)
 
(457
)
 
(6,769
)
Income tax expense (benefit)
(2,332
)
 
252

 
(2,080
)
Results of operations
$
(3,980
)
 
$
(709
)
 
$
(4,689
)
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
1,084

 
33

 
1,117

Production-related general and administrative expenses
394

 
32

 
426

Production, property, and other taxes
652

 
535

 
1,187

 
3,098

 
803

 
3,901

Exploration expenses
1,218

 
421

 
1,639

DD&A
3,783

 
398

 
4,181

Impairments related to oil and gas properties
821

 
—

 
821

Other operating expense
163

 
—

 
163

 
2,704

 
3,651

 
6,355

Income tax expense (benefit)
995

 
979

 
1,974

Results of operations
$
1,709

 
$
2,672

 
$
4,381


156
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

Estimates of future net cash flows from proved reserves are computed based on the average beginning-of-the-month prices during the 12-month period for the year. 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 GAAP.
The present value of future net cash flows is not an estimate of the fair value of Anadarko’s oil and gas properties. 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. 
millions
United States
 
International
 
Total
December 31, 2016
 
 
 
 
 
Future cash inflows
$
33,513

 
$
7,328

 
$
40,841

Future production costs
16,921

 
3,290

 
20,211

Future development costs
7,292

 
566

 
7,858

Future income tax expenses
2,606

 
1,408

 
4,014

Future net cash flows
6,694

 
2,064

 
8,758

10% annual discount for estimated timing of cash flows
1,658

 
470

 
2,128

Standardized measure of discounted future net cash flows
$
5,036

 
$
1,594

 
$
6,630

December 31, 2015
 
 
 
 
 
Future cash inflows
$
42,919

 
$
10,392

 
$
53,311

Future production costs
21,100

 
3,829

 
24,929

Future development costs
7,209

 
637

 
7,846

Future income tax expenses
4,146

 
2,423

 
6,569

Future net cash flows
10,464

 
3,503

 
13,967

10% annual discount for estimated timing of cash flows
3,372

 
910

 
4,282

Standardized measure of discounted future net cash flows
$
7,092

 
$
2,593

 
$
9,685

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


157
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
2016
 
 
 
 
 
Balance at January 1
$
7,092

 
$
2,593

 
$
9,685

Sales and transfers of oil and gas produced, net of production costs
(3,678
)
 
(856
)
 
(4,534
)
Net changes in prices and production costs
(1,953
)
 
(1,607
)
 
(3,560
)
Changes in estimated future development costs
742

 
(126
)
 
616

Extensions, discoveries, additions, and improved recovery, less related costs
429

 
—

 
429

Development costs incurred during the period
1,223

 
203

 
1,426

Revisions of previous quantity estimates
1,388

 
320

 
1,708

Purchases of minerals in place
193

 
—

 
193

Sales of minerals in place
(1,277
)
 
—

 
(1,277
)
Accretion of discount
949

 
431

 
1,380

Net change in income taxes
690

 
717

 
1,407

Other
(762
)
 
(81
)
 
(843
)
Balance at December 31
$
5,036

 
$
1,594

 
$
6,630

2015
 
 
 
 
 
Balance at January 1
$
24,148

 
$
6,512

 
$
30,660

Sales and transfers of oil and gas produced, net of production costs
(4,079
)
 
(1,153
)
 
(5,232
)
Net changes in prices and production costs
(28,967
)
 
(8,010
)
 
(36,977
)
Changes in estimated future development costs
4,408

 
221

 
4,629

Extensions, discoveries, additions, and improved recovery, less related costs
219

 
—

 
219

Development costs incurred during the period
2,311

 
379

 
2,690

Revisions of previous quantity estimates
(1,890
)
 
47

 
(1,843
)
Purchases of minerals in place
30

 
—

 
30

Sales of minerals in place
(2,262
)
 
—

 
(2,262
)
Accretion of discount
3,648

 
1,143

 
4,791

Net change in income taxes
9,940

 
3,193

 
13,133

Other
(414
)
 
261

 
(153
)
Balance at December 31
$
7,092

 
$
2,593

 
$
9,685

 

158
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
2014
 
 
 
 
 
Balance at January 1
$
21,169

 
$
7,937

 
$
29,106

Sales and transfers of oil and gas produced, net of production costs
(8,780
)
 
(2,492
)
 
(11,272
)
Net changes in prices and production costs
(3,981
)
 
(1,984
)
 
(5,965
)
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
1,327

 
(93
)
 
1,234

Balance at December 31
$
24,148

 
$
6,512

 
$
30,660


159
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)


Quarterly Financial Data

The following summarizes quarterly financial data for 2016 and 2015:
millions except per-share amounts
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2016
 
 
 
 
 
 
 
Sales revenues
$
1,634

 
$
1,985

 
$
2,251

 
$
2,577

Gains (losses) on divestitures and other, net
40

 
(70
)
 
(358
)
 
(190
)
Impairments
16

 
18

 
27

 
166

Operating income (loss)
(864
)
 
(332
)
 
(793
)
 
(610
)
Net income (loss)
(998
)
 
(611
)
 
(747
)
 
(452
)
Net income (loss) attributable to noncontrolling interests
36

 
81

 
83

 
63

Net income (loss) attributable to common stockholders
(1,034
)
 
(692
)
 
(830
)
 
(515
)
Earnings per share
 
 
 
 
 
 
 
Net income (loss) attributable to common stockholders—basic
$
(2.03
)
 
$
(1.36
)
 
$
(1.61
)
 
$
(0.94
)
Net income (loss) attributable to common stockholders—diluted
$
(2.03
)
 
$
(1.36
)
 
$
(1.61
)
 
$
(0.94
)
Average number common shares outstanding—basic
509

 
510

 
517

 
551

Average number common shares outstanding—diluted
509

 
510

 
517

 
551

 
 
 
 
 
 
 
 
2015
 
 
 
 
 
 
 
Sales revenues
$
2,585

 
$
2,637

 
$
2,230

 
$
2,034

Gains (losses) on divestitures and other, net
(264
)
 
(1
)
 
(542
)
 
19

Impairments
2,783

 
30

 
758

 
1,504

Operating income (loss)
(4,208
)
 
90

 
(2,549
)
 
(2,142
)
Net income (loss)
(3,236
)
 
108

 
(2,160
)
 
(1,524
)
Net income (loss) attributable to noncontrolling interests
32

 
47

 
75

 
(274
)
Net income (loss) attributable to common stockholders
(3,268
)
 
61

 
(2,235
)
 
(1,250
)
Earnings per share
 
 
 
 
 
 
 
Net income (loss) attributable to common stockholders—basic
$
(6.45
)
 
$
0.12

 
$
(4.41
)
 
$
(2.45
)
Net income (loss) attributable to common stockholders—diluted
$
(6.45
)
 
$
0.12

 
$
(4.41
)
 
$
(2.45
)
Average number common shares outstanding—basic
507

 
508

 
508

 
508

Average number common shares outstanding—diluted
507

 
509

 
508

 
508


160

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 SEC, and to ensure that the information required to be disclosed by the Company in reports that it files or submits 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, 2016.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING


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 2016 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.

161

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 Definitive Proxy Statement (Proxy Statement) for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 10, 2017 (to be filed with the SEC prior to March 31, 2017), 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 2016, Compensation and Benefits Committee Report on 2016 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 SEC, 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, each of which is incorporated herein by reference.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

See Corporate Governance—Board of Directors and Transactions with Related Persons in the Proxy Statement, each of which is incorporated herein by reference.

Item 14.  Principal Accounting Fees and Services

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


162

PART IV

Item 15.  Exhibits, Financial Statement Schedules
 
a)    EXHIBITS

The following documents are filed as part of this Form 10-K or incorporated by reference:
 
(1)
The Consolidated Financial Statements of Anadarko Petroleum Corporation are listed on the Index to this Form 10-K, page 82.

(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 September 15, 2015, filed as Exhibit 3.1 to Form 8-K filed on September 21, 2015
 
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)
 
Third Supplemental Indenture, dated as of June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.2 to Form 8-K filed on June 10, 2015
 
 
(iii)
 
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
 
 
(iv)
 
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
 
 
(v)
 
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
 
 
(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 6.95% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on June 12, 2009
 
 
(ix)
 
Form of 7.95% Senior Notes due 2039, filed as Exhibit 4.4 to Form 8-K filed on June 12, 2009
 
 
(x)
 
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

163

Exhibit
Number
 
Description
 
4
(xi)
 
Form of 6.200% Senior Notes due 2040, filed as Exhibit 4.2 to Form 8-K filed on March 16, 2010
 
 
(xii)
 
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
 
 
(xiii)
 
Form of 6.375% Senior Notes due 2017, filed as Exhibit 4.2 to Form 8-K filed on August 12, 2010
 
 
(xiv)
 
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
 
 
(xv)
 
Form of 3.45% Senior Notes due 2024, filed as Exhibit 4.2 to Form 8-K filed on July 7, 2014
 
 
(xvi)
 
Form of 4.50% Senior Notes due 2044, filed as Exhibit 4.3 to Form 8-K filed on July 7, 2014
 
 
(xvii)
 
Purchase Contract Agreement, dated June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on June 10, 2015
 
 
(xviii)
 
Form of Unit (included in Exhibit 4.xvii)
 
 
(xix)
 
Form of Purchase Contract (included in Exhibit 4.xvii)
 
 
(xx)
 
Form of Amortizing Note (included in Exhibit 4.ii)
 
 
(xxi)
 
Officers’ Certificate of Anadarko Petroleum Corporation dated March 17, 2016, establishing the 4.85% Senior Notes due 2021 and the 5.55% Senior Notes due 2026, and the 6.60% Senior Notes due 2046, filed as Exhibit 4.1 to Form 8-K filed on March 17, 2016
 
 
(xxii)
 
Form of 4.85% Senior Notes due 2021, filed as Exhibit 4.2 to Form 8-K filed on March 17, 2016
 
 
(xxiii)
 
Form of 5.55% Senior Notes due 2026, filed as Exhibit 4.3 to Form 8-K filed on March 17, 2016
 
 
(xxiv)
 
Form of 6.60% Senior Notes due 2046, filed as Exhibit 4.4 to Form 8-K filed on March 17, 2016
†
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

164

Exhibit
Number
 
Description
†
10
(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)
 
Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract (Applicable to Vice Presidents Other Than Executive Officers as of October 2013), filed as Exhibit 10(ii) to Form 10-Q for quarter ended March 31, 2015, filed on May 4, 2015
†*
 
(xvii)
 
Form of Anadarko Petroleum Corporation Key Employee Change of Control Contract for Executive Vice Presidents
†
 
(xviii)
 
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
†
 
(xix)
 
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
†
 
(xx)
 
First Amendment, dated July 1, 2010, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xviii) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
†
 
(xxi)
 
Second Amendment, dated November 30, 2011, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xix) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
†
 
(xxii)
 
Third Amendment, dated December 18, 2014, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xx) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
†
 
(xxiii)
 
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
†
 
(xxiv)
 
First Amendment, dated November 30, 2011, to the Anadarko Retirement Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xxii) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
†
 
(xxv)
 
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
†
 
(xxvi)
 
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
†
 
(xxvii)
 
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
†
 
(xxviii)
 
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

165

Exhibit
Number
 
Description
†
10
(xxix)
 
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
†
 
(xxx)
 
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
†
 
(xxxi)
 
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
†
 
(xxxii)
 
Form of Termination Agreement and Release of All Claims Under Officer Severance Plan, filed as Exhibit 10.1 to Form 8-K filed on August 24, 2016
†
 
(xxxiii)
 
Form of Director and Officer Indemnification Agreement, filed as Exhibit 10 to Form 8-K filed on September 3, 2004
†
 
(xxxiv)
 
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
†
 
(xxxv)
 
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
†
 
(xxxvi)
 
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
†
 
(xxxvii)
 
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
†
 
(xxxviii)
 
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
†
 
(xxxix)
 
First Amendment to Anadarko Petroleum Corporation 2008 Director Compensation Plan, dated February 8, 2016, filed as Exhibit 10(xli) to Form 10-K for year ended December 31, 2015, filed on February 17, 2016
†
 
(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)
 
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan Annual Deferred Shares (2016), filed as Exhibit 10(iii) to Form 10-Q for quarter ended March 31, 2016, filed on May 2, 2016
†
 
(xliii)
 
Terms and Conditions of Elective Deferred Share Awards for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10(iv) to Form 10-Q for quarter ended March 31, 2016, filed on May 2, 2016
†
 
(xliv)
 
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 quarter ended June 30, 2014, filed on July 29, 2014
†
 
(xlv)
 
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 quarter ended June 30, 2014, filed on July 29, 2014
 
 
(xlvi)
 
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

166

Exhibit
Number
 
Description
 
10
(xlvii)
 
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)
†
 
(xlviii)
 
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
†
 
(xlix)
 
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
†
 
(l)
 
First Amendment to Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated June 2, 2015, filed as Exhibit 10(ii) to Form 10-Q for quarter ended June 30, 2015, filed on July 28, 2015
†
 
(li)
 
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
†
 
(lii)
 
Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, filed as Exhibit 10.1 to Form 8-K filed on May 16, 2016
†
 
(liii)
 
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
†
 
(liv)
 
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
†
 
(lv)
 
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
†
 
(lvi)
 
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
†
 
(lvii)
 
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
†
 
(lviii)
 
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
†
 
(lix)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Stock Option Award Agreement, filed as Exhibit 10(i) to Form 10-Q for quarter ended September 30, 2016, filed on October 31, 2016
†
 
(lx)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Restricted Stock Unit Award Agreement, filed as Exhibit 10(ii) to Form 10-Q for quarter ended September 30, 2016, filed on October 31, 2016
†
 
(lxi)
 
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Performance Unit Award Agreement, filed as Exhibit 10(iii) to Form 10-Q for quarter ended September 30, 2016, filed on October 31, 2016
†
 
(lxii)
 
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
†
 
(lxiii)
 
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

167

Exhibit
Number
 
Description
 
10
(lxiv)
 
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
 
 
(lxv)
 
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
 
 
(lxvi)
 
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
 
 
(lxvii)
 
Amendment and Maturity Extension Agreement, dated December 14, 2015, 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 December 18, 2015
 
 
(lxviii)
 
Form of Commercial Paper Dealer Agreement for Commercial Paper Program, filed as Exhibit 10.1 to Form 8-K filed on January 21, 2015
†
 
(lxix)
 
Anadarko Petroleum Corporation Key Employee Change of Control Contract, dated June 1, 2015, for Christopher O. Champion, filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2015, filed on July 28, 2015
 
 
(lxx)
 
364-Day Revolving Credit Agreement, dated as of January 19, 2016, 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., The Bank of Tokyo-Mitsubishi UFJ, Ltd., Citibank, N.A., and Mizuho Bank, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 25, 2016
 
 
(lxxi)
 
First Amendment to 364-Day Revolving Credit Agreement, dated January 13, 2017, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 20, 2017
†*
 
(lxxii)
 
Retention Agreement, dated as of November 1, 2015, between Anadarko Petroleum Corporation and Mitchell W. Ingram
†*
 
(lxxiii)
 
First Amendment to Retention Agreement, dated December 13, 2016
*
12
 
 
Computation of Ratios of Earnings to Fixed Charges
*
21
 
 
List of Subsidiaries
*
23
(i)
 
Consent of KPMG LLP
*
23
(ii)
 
Consent of Miller and Lents, Ltd.
*
24
 
 
Power of Attorney
*
31
(i)
 
Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*
31
(ii)
 
Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**
32
 
 
Section 1350 Certifications
*
99
 
 
Report of Miller and Lents, Ltd.
*
101
.INS
 
XBRL Instance Document
*
101
.SCH
 
XBRL Schema Document
*
101
.CAL
 
XBRL Calculation Linkbase Document
*
101
.DEF
 
XBRL Definition Linkbase Document
*
101
.LAB
 
XBRL Label Linkbase Document
*
101
.PRE
 
XBRL Presentation Linkbase Document
_________________________________________________________________
†
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.

168

The total amount of securities of the registrant authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrants and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the SEC, to furnish copies of any or all of such instruments to the SEC.

b)    FINANCIAL STATEMENT SCHEDULES

Financial statement schedules have been omitted because they are not required, not applicable, or the information is included in the Company’s Consolidated Financial Statements.

169

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 17, 2017
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 17, 2017.
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/ CHRISTOPHER O. CHAMPION
  
Senior Vice President, Chief Accounting Officer and Controller
Christopher O. Champion
  
 
 
 
(iv) Directors:*
  
 
ANTHONY R. CHASE
KEVIN P. CHILTON
DAVID E. CONSTABLE
H. PAULETT EBERHART
CLAIRE S. FARLEY
PETER J. FLUOR
RICHARD L. GEORGE
JOSEPH W. GORDER
JOHN R. GORDON
SEAN GOURLEY
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
 

170