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.


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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.

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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

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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


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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.

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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.

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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.

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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.


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Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or assumptions underlying our reserves estimates could cause the quantities and net present value of our reserves to be overstated or understated.

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated or understated. The reserves information included or incorporated by reference in this 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.


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Our domestic operations are subject to governmental risks that may impact our operations.

Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex 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.


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

We conduct offshore operations in the Gulf of Mexico, Ghana, Mozambique, 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.


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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.


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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.

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

We have exposure to different counterparties. For example, we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds, and other institutions. These transactions expose us to credit risk in the event of default by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit 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


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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