10-K 1 apc201710k-10k.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
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  þ    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  þ
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  þ    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  þ    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.  þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  þ    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨ Emerging growth company  ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  þ
The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 30, 2017, was $25.2 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 8, 2018, is shown below:
Title of Class
  
Number of Shares Outstanding
Common Stock, par value $0.10 per share
  
532,487,194
Documents Incorporated By Reference
Portions of the Definitive Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 15, 2018 (to be filed with the Securities and Exchange Commission prior to April 5, 2018), 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.
Item 16.



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:

$3.0 Billion Share-Repurchase Program - A program approved by the Anadarko Board of Directors, in September 2017, authorizing the repurchase of $2.5 billion of Anadarko’s common stock, which was expanded to $3.0 billion in February 2018. The program extends through the end of 2018.
364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured RCF
3D - Three-dimensional
$5.0 Billion Facility - Anadarko’s $5.0 billion senior secured RCF, which was replaced in January 2015 with the APC RCF and a 364-day facility
APC RCF - Anadarko’s $3.0 billion senior unsecured RCF
AROs - Asset retirement obligations
ASR Agreement - An accelerated share-repurchase agreement with an investment bank to repurchase the Company’s common stock
ASU - Accounting Standards Update
Bbl - Barrel
Bcf - Billion cubic feet
BOE - Barrels of oil equivalent
CBM - Coalbed methane
COSF - Centralized oil stabilization facility
DBJV - Delaware Basin JV Gathering LLC
DBJV System - A gathering system and related facilities located in the Delaware basin in Loving, Ward, Winkler, and Reeves Counties in West Texas
DBM Complex - The processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving, and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico
DD&A - Depreciation, depletion, and amortization
EOR - Enhanced oil recovery
EPA - U.S. Environmental Protection Agency
FASB - Financial Accounting Standards Board
FID - Final investment decision
Fitch - Fitch Ratings
FPSO - Floating production, storage, and offloading unit
G&A - General and administrative expenses
GAAP - U.S. Generally Accepted Accounting Principles
GOM Acquisition - The acquisition of oil and natural-gas assets in the Gulf of Mexico that closed on December 15, 2016
IPO - Initial public offering
IRS - U.S. Internal Revenue Service
LIBOR - London Interbank Offered Rate
LNG - Liquefied natural gas
MBbls/d - Thousand barrels per day
MBOE/d - Thousand barrels of oil equivalent per day

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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
Moody’s - Moody’s Investors Service
MTPA - Million tonnes per annum
NGLs - Natural gas liquids
NM - Not meaningful
NTSB - National Transportation Safety Board
NYMEX - New York Mercantile Exchange
Oil - Includes crude oil and condensate
OPEC - Organization of the Petroleum Exporting Countries
PUD or PUDs - Proved undeveloped reserves
RCF - Revolving credit facility
ROTF - Regional oil treating facility
SEC - U.S. Securities and Exchange Commission
S&P - Standard and Poor’s
Sonatrach - The national oil and gas company of Algeria
Tax Reform Legislation - The U.S. Tax Cuts and Jobs Act signed into law on December 22, 2017
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 or VIEs - Variable interest entity
WES - Western Gas Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko
WES RCF - WES’s $1.2 billion senior unsecured RCF
WTI - West Texas Intermediate
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 publicly traded limited partnership, which is a consolidated subsidiary of Anadarko
WGP RCF - WGP’s $250 million three-year senior secured RCF
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 1.4 billion BOE of proved reserves at December 31, 2017. 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 positioned to deliver 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 assets in the Delaware and DJ basins in the U.S. onshore. 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, and other countries.
Anadarko’s strategy is to explore for, develop and commercialize resources globally; ensure health, safety, and environmental excellence; and focus on financial discipline, flexibility, and value creation, while demonstrating the Company’s core values of integrity and trust, servant leadership, people and passion, commercial focus, and open communication in all business activities.
Anadarko previously presented three reportable segments in its quarterly and annual filings: Oil and Gas Exploration and Production, Midstream, and Marketing. In the first half of 2017, Anadarko substantially completed a repositioning of its asset portfolio to focus on higher-margin liquids production. This shift resulted in a substantial decrease in the number of U.S. operating areas. Since the portfolio repositioning, the chief operating decision maker has reviewed operating results for Exploration and Production and Midstream when making operating and capital allocation decisions. Accordingly, Anadarko no longer identifies marketing activities as a separate reportable segment. Also, in prior periods, the Company aggregated its two midstream operating segments, WES Midstream and Other Midstream, into one Midstream reporting segment due to similar financial and operating characteristics. While the aggregation criteria continues to be met, the Company will no longer aggregate these operating segments in order to provide additional information about its midstream operations. Accordingly, Anadarko now has three reporting segments: Exploration and Production, WES Midstream, and Other Midstream, which include their respective marketing results.

Exploration and Production—This segment is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing its Mozambique LNG project toward FID.

WES Midstream and Other Midstream—These two segments engage 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 WES Midstream segment consists of Western Gas Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko. The Other Midstream segment consists of the Company’s other midstream assets.

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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EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITIES

The Company’s Exploration and Production segment actively manages Anadarko’s worldwide oil, natural-gas, and NGLs sales of its equity production, 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 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, Algerian condensate, refrigerated propane, and refrigerated butane to customers primarily in the Mediterranean and Western European area. Oil from Ghana is sold by tanker as Jubilee crude oil and TEN Blend crude oil to customers around the world. Saharan Blend, Jubilee, and TEN Blend are high-quality crudes that provide refiners with large quantities of premium products such as gasoline, diesel, and jet fuel.

Natural Gas  Anadarko markets its U.S. natural-gas production to maximize value and to reduce the inherent risks of physical commodity markets. 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. From time to time, 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.


6


United States

Overview  Anadarko’s U.S. operations include oil and natural-gas exploration and production in the U.S. onshore and deepwater Gulf of Mexico. The Company’s U.S. operations accounted for 86% of sales volumes and 80% of sales revenues during 2017 and 88% of proved reserves at year-end 2017.

U.S. Onshore  Anadarko’s U.S. onshore properties include significant oil and natural-gas plays located in Colorado, Texas, Utah, and Wyoming, where the Company operates approximately 9,250 wells and owns interests in approximately 2,500 nonoperated wells.
The map below illustrates the locations of Anadarko’s U.S. onshore oil and natural-gas exploration and production operations:
apcusonshore201701.jpg

Activities in the U.S. onshore during 2017 primarily focused on adding reserves through horizontal drilling, optimizing wellbore and completion design, improving cost structure, and delivering efficient production. The Company also focused on capturing operatorship within its premier position in the Delaware basin. Process improvements and optimization projects assisted in providing both well performance and cycle-time improvements across all assets. The Company drilled 541 wells and completed 396 wells in the U.S. onshore during 2017. The Company also divested non-core U.S. onshore assets, primarily in South Texas, Southeast Texas, Pennsylvania, Wyoming, and Utah. In 2018, 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 approximately 590,000 gross (240,000 net) acres in the Delaware basin in West Texas. Anadarko’s 2017 drilling activity primarily targeted the Wolfcamp shale play, while also testing the liquids-rich Bone Spring tight sands and Avalon shale play. In 2017, Anadarko drilled 192 operated wells and participated in 93 nonoperated wells. The Company was focused on increasing operatorship through the drilling program for the majority of the year, averaging 14 operated drilling rigs through the third quarter of 2017 and ending 2017 with 10 operated drilling rigs. Prior to the conclusion of a participation agreement in July 2017, Anadarko completed all of the well proposals required to secure operatorship on approximately 70% of its joint venture acreage. Additionally, joint-operating agreements have been established in all areas where operatorship has been defined. The wells associated with operatorship capture are scheduled to be completed and turned to sales throughout 2018. During 2018, the Company plans to average seven operated rigs and six completion crews and grow year-over-year sales volumes by more than 50%.
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 approximately 5,500 potential mid-lateral-equivalent drilling locations in the Wolfcamp A formation that are expected to provide substantial opportunity for Anadarko’s future activity in the basin. The Company plans to continue to add significant infrastructure to facilitate future growth from this asset as discussed in Midstream Properties and Activities.

DJ Basin  Anadarko holds interests in over 400,000 net acres in its core position and operates over 4,600 vertical wells and 1,400 horizontal wells in the DJ basin in Colorado. The field contains the Niobrara and Codell formations, which are naturally fractured formations that hold both liquids and natural gas. During 2017, the Company’s drilling program focused entirely on horizontal development, drilling 348 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 2017, the Company implemented a new completion design, which has resulted in a 20% improvement in average well recovery. In the third quarter of 2017, the Company sanctioned the Latham plant, which is expected to provide an additional 400 MMcf/d in cryogenic processing.
Drilling spud-to-rig-release cycle time average for a mid-lateral equivalent well improved from 5.7 days in 2016 to 5.1 days in 2017. The full-year 2017 average drilling cost per foot was reduced by approximately 19% and completion capital was reduced by 11% relative to 2016. Operated well capital costs in 2017 decreased to less than $2.9 million from approximately $3.5 million in 2016 for a mid-lateral-equivalent well, driven by continued operational efficiencies and supply-chain savings. The Company had six operated drilling rigs in the first quarter of 2017 and ended 2017 with six operated drilling rigs. Anadarko expects to increase year-over-year oil sales volumes from the DJ Basin by more than 30% and plans to average five operated rigs and three completion crews in the basin during 2018.

Greater Natural Buttes  The Greater Natural Buttes area in eastern Utah is a tight-gas asset. The Company uses cryogenic and refrigeration processing facilities 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 2017 due to capital being allocated to higher-margin projects. Focus in the field shifted to increasing operating margins through the reduction of expenses and optimization of base production. The Company operates approximately 2,850 wells in the area.


8


Gulf of Mexico  Anadarko owns a working interest in 319 blocks in the Gulf of Mexico, operates 10 active floating platforms, and holds interests in 37 fields. The Company continued an active deepwater development and appraisal program in the Gulf of Mexico during 2017 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:
gomoverview201704.jpg

9


Development
Horn Mountain  At Horn Mountain (100% working interest), the Company is successfully executing on its tie-back strategy. The first development well from the GOM Acquisition was drilled in the first quarter of 2017. The well encountered more than 70 net feet of oil pay in the prolific Miocene sands and was tied back to the Horn Mountain facility. The well was completed and brought online in the second quarter of 2017. The second development well was drilled in the third quarter of 2017 and encountered 120 feet of high-quality oil pay. The well was tested in two Miocene sands and brought online in the first of these sands during the third quarter of 2017. These wells were drilled and brought to first production in approximately 110 days for the first well and approximately 80 days for the second well. A third well was drilled in the fourth quarter of 2017 and encountered 42 feet of high-quality oil pay with favorable structural position and good connectivity to existing wells. Completion and first production are expected in the first half of 2018. Additional drilling around the Horn Mountain facility is scheduled in 2018.

Marlin  At Marlin (100% working interest), the Company successfully drilled a tie-back development well in the King field in the third quarter of 2017. The well encountered 134 feet of high-quality oil pay in three separate Miocene zones. The well was completed in three sands and had a successful flow test. First production is anticipated in the first quarter of 2018.

Lucius  At Lucius (48.9% working interest), the Company successfully drilled and completed the eighth development well during 2017. The well encountered 217 net feet of oil pay in the primary objective Miocene sands and was brought online in the third quarter of 2017. The field continues to demonstrate favorable connectivity and strong aquifer support and is maintaining strong well deliverability. The Company entered into an agreement with partners to expand the Lucius unit to encompass the adjacent Hadrian North discovery in late 2017. The project was sanctioned and development of this tie-back opportunity commenced in 2018, with first production expected in 2019. The initial development phase is targeting high-quality Pliocene reservoir sands with similar rock and fluid properties as the Lucius producing wells.

Constitution Spar  At the Constitution Spar (100% working interest), the Company completed planned maintenance that was designed to improve future uptime, further enhance safety, and facilitate the tieback of Constellation for first production.

Caesar/Tonga  At Caesar/Tonga (33.75% working interest), the Company spud the eighth development well during the fourth quarter of 2017 and anticipates first production in the second quarter of 2018, when the well is tied back to Anadarko’s Constitution spar.

Constellation  At Constellation (33.33% working interest), the Company successfully drilled and completed the first development well in the second quarter of 2017. The well encountered more than 120 feet of net oil pay and had a strong flow test. First production is expected in late 2018 or early 2019, when the well is tied back to Anadarko’s Constitution spar.

K2 Complex  At the K2 Complex (41.8% working interest), the GC 562#6 development well, drilled and completed in 2016, was brought online in the second quarter of 2017. With the completion of this well, the field reached a nine-year production high of 38 MBOE/d.

Heidelberg  At Heidelberg (44% working interest), the GC 859 #5 ST1 well encountered 216 net feet of oil pay and became the field’s fifth producing well in the first quarter of 2017.

Holstein  At Holstein (100% working interest), the Company certified the permanently installed platform drilling rig and initiated a four-well drilling program in the fourth quarter of 2017. These wells are anticipated to be brought online during 2018.


10


Exploration and Appraisal
Warrior  The Warrior exploration well (70% working interest) encountered more than 210 net feet of oil pay in multiple high-quality Miocene-aged reservoirs. The first Warrior appraisal well and subsequent side track completed drilling in the northern portion of the field in the third quarter of 2017. The well encountered approximately 109 net feet of dispersed oil pay. Despite finding oil, this northern appraisal well found insufficient quantities of oil pay to justify the development of the northern portion of the field in the current price environment. Evaluation of tie-back opportunities in the southern portion of the field is ongoing.

Calpurnia  The Calpurnia exploration well (76% working interest), located near the Anadarko-operated Caesar/Tonga, Heidelberg and Holstein fields, finished drilling during the first quarter of 2017. The well encountered approximately 20 feet of net oil pay on water in a well-developed Miocene-aged sand. The well was subsequently sidetracked updip where it found nearly 60 net feet of oil pay. The wellbore was temporarily abandoned and is expected to be utilized for future production as a tieback to one of the Company’s nearby operated facilities.

Shenandoah  The Shenandoah-6 appraisal well and subsequent sidetrack (33% working interest), which completed appraisal activities in April 2017, did not encounter oil in the eastern portion of the field. Given the results of this well and the commodity-price environment, the Company suspended further appraisal activities.

Phobos  The first Phobos appraisal well (100% working interest), drilled in the first quarter of 2017, encountered approximately 130 net feet of oil pay from the primary objective Wilcox-aged reservoirs and more than 90 net feet of oil pay in the secondary objective Pliocene-aged reservoir. The second appraisal well, drilled in the third quarter of 2017, encountered approximately 136 net feet of oil pay from the primary objective Wilcox-aged reservoirs. These wells found insufficient quantities of oil pay to justify development in the current price environment.

Alaska  Anadarko’s nonoperated (22% working interest) oil production and development activity in Alaska is concentrated on the North Slope. Net production from the Colville River Unit averaged approximately 11 MBbls/d of oil during the fourth quarter of 2017. The operator completed an active drilling campaign in 2017, which included seven development wells. Subsequent to year end, the Company divested its nonoperated interest in Alaska for net proceeds of $383 million. The transaction is subject to regulatory approval.


11


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 toward FID on an LNG development. The Company also has exploration acreage in Colombia, Mozambique, and other countries. International locations accounted for 14% of Anadarko’s sales volumes and 20% of sales revenues during 2017 and 12% of proved reserves at year-end 2017. In 2018, the Company expects to focus its drilling activity in Ghana and continue preparing the site of the future onshore LNG park in Mozambique.

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 (PSA) between Anadarko, Sonatrach, and other partners. Under this PSA, the Company is responsible for 24.5% of the development and production costs. 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 337 MBbls/d in 2017, inclusive of approximately 34 days of planned downtime for statutory maintenance at the El Merk CPF. The Company drilled seven development wells in 2017. Late in 2017, Algeria and other members of OPEC agreed to extend the previously agreed upon reduction in production output through the end of 2018. Anadarko had minimal production impact from this reduction during 2017 and expects minimal impact in 2018.

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 89 MBbls/d of oil in 2017. An average of 86 MMcf/d of natural gas was exported to an onshore natural-gas processing plant in satisfaction of a commitment established in conjunction with the Jubilee development plan. In October 2017, the partnership received Ghanaian government approval for the full-field plan of development, with drilling operations expected to commence in 2018.
In 2016, the operator of the Jubilee field 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 spread-moored facility. Interim spread mooring of the FPSO commenced in the fourth quarter of 2016 and was completed during the first quarter of 2017. In early 2018, the operator will start the first of three shutdown periods that are expected to occur in 2018 to effectively stabilize the turret and rotate the FPSO to its permanent heading. In October, the partnership received Ghanaian Government approval for the full-field plan of development, with drilling operations expected to commence in 2018. Including the impact of the potential facility shutdown, the operator expects the average gross production from the Jubilee field to be more than 75 MBbls/d in 2018.
The TEN project (19% nonoperated participating interest), located in the Deepwater Tano Block, uses an 80 MBbls/d-capacity FPSO for production from subsea wells. After achieving first oil in the third quarter of 2016 and first liftings during the fourth quarter of 2016, the project averaged gross production of 56 MBbls/d of oil in 2017. The International Tribunal for the Law of the Sea issued a ruling in September 2017 regarding the delimitation of the maritime boundary between Ghana and Côte d’Ivoire in the Atlantic Ocean. The new maritime boundary, as determined by the tribunal, does not affect the TEN fields, and the operator now plans to resume development drilling in 2018.


12


Mozambique  Anadarko operates Offshore Area 1 (26.5% working interest), which totals approximately 1.2 million gross acres. With the delivery of the legal and contractual framework necessary for the development of LNG in Mozambique, the commencement of resettlement, and progress towards the delivery of project finance and long-term LNG sales contracts, the Company continues to advance the initial two-train Golfinho/Atum project toward FID.

Development  Anadarko, its Area 1 co-venturers, and the Government of Mozambique completed the foundational legal and contractual framework required to support investment in the Company’s onshore LNG project. Based on these project advances and the approved Resettlement Plan, the Company commenced resettlement activities during the fourth quarter of 2017. This will facilitate site preparation and position the onshore area for construction of the LNG facilities. Additionally, the Company continues to work with construction and installation contractors to finalize costs and contracts and identify opportunities to reduce execution risk once the project progresses to the construction phase. In 2017, Anadarko and its co-venturers reached agreement on the project’s first long-term sales and purchase agreement (SPA) for 2.6 MTPA of LNG with PTT Public Company Limited (PTT), Thailand’s national oil and gas company. The SPA is subject to the approval of the Government of Thailand. The Company continues to progress additional LNG long-term sales contracts and advance the project finance process. The Development Plan for the initial two-train Golfinho/Atum project is in the final stages of the Government of Mozambique’s approval process.

Exploration  In Offshore Area 1, the Company continues to interpret re-processed 3D seismic data covering the Orca, Tubarão, and Tubarão-Tigre discovery areas, in accordance with the appraisal program submitted to the Government of Mozambique.

Colombia  Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on six blocks totaling approximately 14 million gross acres. In the Grand Fuerte area, the COL 5 and Purple Angel blocks are operated at a 50% working interest. In 2017, Anadarko withdrew from the Fuerte Norte and Fuerte Sur blocks. In the Grand COL area, the COL 1, COL 2, COL 6, and COL 7 blocks are operated at a 100% working interest.
In Grand Fuerte, the Purple Angel-1 exploration well concluded drilling in the first quarter of 2017. The well encountered approximately 70 to 110 net feet of gas pay and confirmed a gas column greater than 1,700 feet. The well successfully tested objectives establishing pressure connectivity to Anadarko’s 2015 play-opening Kronos discovery. The rig mobilized to the Gorgon prospect, also located in the Purple Angel Block, where it successfully tested an analogous structure along trend to the Kronos discovery. The Gorgon-1 well completed drilling in the second quarter and encountered approximately 260 to 350 net feet of gas pay. Whole cores were obtained at both wells to assess the potential deliverability of the primary reservoirs.
While evaluation of the Kronos and Gorgon discovery areas continue, all of the Company’s suspended exploratory well costs related to wells in the Grand Fuerte area were expensed in 2017 due to insufficient progress on contractual and fiscal reforms needed for deepwater gas development. See Note 6—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
In Grand COL, interpretations of the Esmeralda 3D seismic survey are ongoing. A sea floor sampling campaign was completed in the third quarter of 2017, which supports the potential presence of liquid hydrocarbons in Grand COL.

Côte d’Ivoire   Appraisal and exploration activity continued in 2017. The Paon-6A appraisal well, an up-dip appraisal of the South Channel, completed drilling in the third quarter of 2017 and did not encounter hydrocarbons. The Colibri-1X exploration well completed drilling in the third quarter of 2017 and encountered non-commercial quantities of hydrocarbons. During the fourth quarter of 2017, after further evaluation of the recent well results, the Company withdrew from all blocks in Côte d’Ivoire.

Other  Anadarko also holds exploration interests in other offshore international areas, including Canada, South Africa, Gabon, Guyana, and Peru.


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 2017, 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, 2017
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
361

 
2,640

 
176

 
977

International
136

 
24

 
10

 
150

Undeveloped
 
 
 
 
 
 
 
United States
140

 
553

 
56

 
288

International
21

 
13

 
1

 
24

Total proved
658

 
3,230

 
243

 
1,439

 
 
 
 
 
 
 
 
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


The Company’s proved reserves product mix increased to 63% liquids in 2017, compared to 57% in 2016 and 52% in 2015. The Company’s year-end 2017 proved reserves product mix was 46% oil, 37% natural gas, and 17% NGLs. This shift to liquids and the reduction in proved reserves was largely a result of divesting the Company’s lower-margin, non-core assets throughout the last three years.

14


Changes to the Company’s proved reserves during 2017 are summarized in the table below:
MMBOE
2017
 
2016
 
2015
Proved Reserves
 
 
 
 
 
January 1
1,722

 
2,057

 
2,858

Reserves additions and revisions
 
 
 
 
 
Discoveries and extensions
114

 
40

 
29

Infill-drilling additions (1)
71

 
69

 
89

Drilling-related reserves additions and revisions
185

 
109

 
118

Other non-price-related revisions (1)
59

 
191

 
289

Net organic reserves additions
244

 
300

 
407

Acquisition of proved reserves in place
3

 
97

 
1

Price-related revisions (1)
92

 
(147
)
 
(624
)
Total reserves additions and revisions
339

 
250

 
(216
)
Sales in place
(379
)
 
(294
)
 
(279
)
Production
(243
)
 
(291
)
 
(306
)
December 31
1,439

 
1,722

 
2,057

Proved Developed Reserves
 
 
 
 
 
January 1
1,325

 
1,632

 
1,969

December 31
1,127

 
1,325

 
1,632

_______________________________________________________________________________
(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 reflect the net change of performance and cost updates, updates to development plans, and all other year-end updates.

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, 2017 were $51.34 per Bbl for oil, $2.98 per MMBtu for natural gas, and $31.83 per Bbl for NGLs.
The Company’s estimates of proved developed reserves, PUDs, and total proved reserves at December 31, 2017, 2016, and 2015, 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, 2017. 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 2017 are summarized in the table below. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years unless specific circumstances warrant a longer development time horizon.
MMBOE
 
PUDs at January 1, 2017
397

Revisions of prior estimates
103

Extensions, discoveries, and other additions
22

Conversions to developed
(132
)
Purchases
1

Sales
(79
)
PUDs at December 31, 2017
312


Revisions  Revisions of prior estimates reflect Anadarko’s ongoing evaluation of its asset portfolio. In 2017, PUDs were revised upward by 103 MMBOE.
MMBOE
December 31, 2017
Revisions due to changes in year-end prices (price impact to opening balance)

Other revisions of prior estimates
 
Revisions due to performance
32

Revisions due to cost updates

Revisions due to successful infill drilling
64

Revisions due to development plan updates
7

Other revisions

Total other revisions of prior estimates
103

Revisions of prior estimates
103


Prior estimates were revised upward by a total of 103 MMBOE and were associated with the following:
Performance  The Company experienced an overall increase in PUDs of 32 MMBOE due to performance. Upward revisions of 39 MMBOE were driven primarily by performance improvements in the DJ and Delaware basin areas. Downward revisions of 7 MMBOE were primarily due to performance based reductions in various areas in the Gulf of Mexico.
Infill-drilling activities  The Company added 64 MMBOE of PUDs associated with infill-drilling activities, of which 46 MMBOE was in the DJ basin, 13 MMBOE in the Lucius and Holstein areas in the Gulf of Mexico and the remaining in the Ghana Jubilee field.
Development plan updates  The majority of revisions associated with updates to development plans occurred in the DJ basin due to ongoing optimization of development activity.
Extensions, discoveries, and other additions  During 2017, PUDs increased by 22 MMBOE primarily through the extension of proved acreage. Projects in the Delaware basin, Alaska, Gulf of Mexico, and Ghana contributed to the increase.

Conversions  In 2017, the Company converted 132 MMBOE of PUDs to developed status, equating to 31% of total year-end 2016 PUDs when adjusted for revisions and sales. Approximately 81% of PUD conversions occurred in U.S. onshore assets, including Alaska; 17% in Gulf of Mexico assets, and the remaining in international assets.
Anadarko spent $1.0 billion to develop PUDs in 2017, of which approximately 72% related to U.S. onshore assets, including Alaska; 26% related to Gulf of Mexico assets; and the remaining related to international assets.

Sales in place  In 2017, PUDs decreased by 79 MMBOE due to the Company’s divestiture activities in the Eagleford and Marcellus areas.
 

16


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, 2017, the Company had no material pre-2013 PUDs that remained undeveloped. However, the Company did have 19 MMBOE of PUDs scheduled to be developed more than five years from their initial date of booking. Approximately 12 MMBOE of these PUDs are associated with recompletion projects in the Gulf of Mexico, where project timing is dependent upon the current producing horizon achieving its economic limit. The remaining 7 MMBOE are primarily associated with international drilling projects, which are being developed according to government approved development plans. The Company did not have any U.S. onshore PUDs scheduled for development more than five years from initial booking.

Technologies Used in Proved Reserves Estimation  The Company’s 2017 proved reserves additions were based on estimates generated through the integration of relevant geological, engineering, and production data, using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in these integrated assessments included information obtained directly from the subsurface through wellbores such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data used also included subsurface information obtained through indirect measurements such as seismic data. The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir was based on the unique circumstances of each reservoir and the dataset available at the time of the estimate.

Internal Controls over Reserves Estimation  Anadarko’s estimates of proved reserves and associated future net cash flows were made solely by the Company’s engineers and are the responsibility of management. The Company requires that reserves estimates be made by qualified reserves estimators (QREs) as defined by the Society of Petroleum Engineers’ standards. The QREs are assigned to specific assets within the Company’s regions. The QREs interact with engineering, land, and geoscience personnel to obtain the necessary data for projecting future production, net cash flows, and ultimate recoverable reserves. Management within each region approves the QREs’ reserves estimates. All QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group (CRG).
The CRG ensures confidence in the Company’s reserves estimates by maintaining internal policies for estimating and recording reserves in compliance with applicable SEC definitions and guidance. Compliance with the SEC reserves guidelines is the primary responsibility of Anadarko’s CRG.
The CRG is managed through the Company’s finance department, which is separate from its operating regions, and is responsible for overseeing internal reserves reviews and approving the Company’s reserves estimates. The Director 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 31 years of experience in the oil and gas industry, including over 17 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 31 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.


17


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, 2017. 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 11 fields that included major assets in the United States and Africa and encompassed approximately 92% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2017. 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)
 
2017
 

 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DJ basin
31

 
212

 
21

 
88

 
49.73

 
2.55

 
27.46

 
10.23

Other United States
66

 
266

 
13

 
123

 
49.57

 
3.03

 
32.24

 
9.38

Total United States
97

 
478

 
34

 
211

 
49.62

 
2.82

 
29.24

 
9.73

International
32

 

 
2

 
34

 
53.77

 

 
35.64

 
7.01

Total
129

 
478

 
36

 
245

 
50.66

 
2.82

 
29.54

 
9.34

2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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

 _______________________________________________________________________________
(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 G&A 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, 2017, Anadarko was contractually committed to deliver approximately 1,488 Bcf of natural gas to various customers in the United States through 2032. These contracts have various expiration dates, with approximately 21% of the Company’s current commitment to be delivered in 2018 and 76% by 2022. At December 31, 2017, Anadarko was also contractually committed to deliver approximately 22 MMBbls of oil to a customer in the United States through 2020. These contracts have various expiration dates, with approximately 45% of the Company’s current commitment to be delivered in 2018 and 100% by 2020. At December 31, 2017, Anadarko also was contractually committed to deliver approximately 8 MMBbls of oil to ports in Algeria and Ghana through 2018. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves, 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. In areas where Anadarko no longer has production due to asset divestitures, the Company has entered into long-term purchase commitments to satisfy its existing 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, 2017:
 
Developed
Lease
 
Undeveloped
Lease
 
Fee
Mineral (1)
 
Total
thousands of acres
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Onshore
2,417

 
1,486

 
1,797

 
681

 
9,891

 
8,192

 
14,105

 
10,359

Offshore
352

 
198

 
1,483

 
1,098

 

 

 
1,835

 
1,296

Total United States
2,769

 
1,684

 
3,280

 
1,779

 
9,891

 
8,192

 
15,940

 
11,655

International
636

 
138

 
39,440

 
31,690

 

 

 
40,076

 
31,828

Total
3,405

 
1,822

 
42,720

 
33,469

 
9,891

 
8,192

 
56,016

 
43,483

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

At December 31, 2017, the Company had approximately 21 million net undeveloped lease acres scheduled to expire by December 31, 2018, if the Company does not establish production or take any other action to extend the terms. The net undeveloped lease acres scheduled to expire by December 31, 2018, if not amended, primarily relate to 20.5 million net acres of international exploration acreage in South Africa (16.0 million net acres) and Colombia (4.5 million net acres) where proved reserves have not yet been assigned. The Company plans to continue the terms of many of these licenses and concession areas through operational or administrative actions and does not expect a significant portion of its total net acreage position to expire in 2018.

Drilling Program

The Company’s 2017 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 2017 consisted of 10 gross completed wells, which included 8 U.S. onshore wells and 2 Gulf of Mexico wells. Development activity in 2017 consisted of 554 gross completed wells, which included 548 U.S. onshore wells and 6 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
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
6.6

 
3.6

 
10.2

 
359.1

 
2.4

 
361.5

 
371.7

International

 
7.3

 
7.3

 

 

 

 
7.3

Total
6.6

 
10.9

 
17.5

 
359.1

 
2.4

 
361.5

 
379.0

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


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, 2017:
 
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

 
23

 
14

 
543

Net

 
20.4

 
8.6

 
396.2

International
 
 
 
 
 
 
 
Gross

 

 
28

 
15

Net

 

 
7.8

 
3.5

Total
 
 
 
 
 
 
 
Gross

 
23

 
42

 
558

Net

 
20.4

 
16.4

 
399.7

 _______________________________________________________________________________
(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 107 MMBOE of PUDs primarily assigned to U.S. onshore development wells suspended or waiting on completion at December 31, 2017. The Company expects to convert these reserves to developed status within five years of their initial disclosure.


21


Productive Wells

At December 31, 2017, the Company’s ownership interest in productive wells was as follows:
 
Oil Wells (1)
 
Gas Wells (1)
United States
 
 
 
Gross
3,571

 
8,574

Net
2,309.2

 
7,182.0

International
 
 
 
Gross
208

 
9

Net
37.3

 
2.2

Total
 
 
 
Gross
3,779

 
8,583

Net
2,346.5

 
7,184.2

________________________________________________________________
(1) 
Includes wells containing multiple completions as follows:
Gross
411

 
2,997

Net
355.1

 
2,697.1



22


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, 2017, 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, 2017, WGP’s ownership interest in WES consisted of a 29.8% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At December 31, 2017, Anadarko also owned a 9.1% limited partner interest in WES through other subsidiaries.

WES Midstream

At the end of 2017, WES Midstream included 20 gathering systems and 51 processing and treating facilities located throughout major onshore producing basins in Wyoming, Colorado, Utah, Pennsylvania, Texas, and New Mexico. In 2017, the WES Midstream activity was concentrated in the Delaware basin to build infrastructure for present and future Wolfcamp development. In 2018, the Company expects to continue to focus its midstream investment on the Delaware and DJ basins.

Delaware Basin  In 2017, the Company expanded its midstream infrastructure for Bone Spring, Wolfcamp, and Avalon production in the Delaware basin of West Texas, installing over 150 miles of gas and water gathering lines. Four new central gathering facilities (CGFs) were installed and seven existing CGFs were expanded to add a total of approximately 495 MMcf/d of compression capacity. Two produced-water disposal systems were placed into service during the second quarter of 2017, with combined capacity of 90,000 barrels of water per day. Additional compressor station expansions within the field are planned for 2018.
In the first quarter of 2017, Anadarko completed the divestiture of its Marcellus 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 divestiture; however, during the first quarter of 2017, WES entered into a property exchange whereby it exchanged its 33.75% nonoperated interest in certain Marcellus assets, commonly referred to as the Liberty and Rome systems, plus $155 million in cash for a third party’s 50% nonoperated interest in the DBJV System. The property exchange increased WES’s interest in the DBJV System to 100%.
With the completion of Train VI, a 200 MMcf/d cryogenic facility, at the end of 2017, the DBM Complex now includes 900 MMcf/d of cryogenic processing capacity, 1,400 gallons per minute of amine-treating capacity, 18 MBbls/d of high-pressure condensate stabilization, and a rich-gas gathering system, with over 400 miles of high-pressure and low-pressure segments. Construction has begun on the Mentone plant, which will add 400 MMcf/d of cryogenic processing capacity and is expected to come online in 2018.
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 processing facility. 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 came online in May 2016 and Train V came online in October 2016.
During the second quarter of 2017, the Company reached a settlement with insurers and final proceeds were received related to the December 2015 incident at the DBM Complex. As of December 31, 2017, the Company had received a total of $86.7 million in cash proceeds from insurers related to the incident, including $46.2 million in proceeds from business interruption insurance claims and $40.5 million in proceeds from property insurance claims.


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DJ Basin  The Company continued to optimize gathering and compression in 2017, which reduced gathering system pressures in the field, enhancing system efficiency and improving the base production profile. Management believes that the Company is well-positioned in the DJ basin with its oil and NGLs transportation capacity, which includes transport by pipeline, rail, and truck.
In 2017, the Company expanded its midstream infrastructure to support DJ basin production, adding a total of approximately 100 MMcf/d of compression capacity to three of its compressor stations. In the third quarter of 2017, the Company sanctioned the construction of the Latham plant consisting of two cryogenic processing trains, which will increase processing capacity by 400 MMcf/d. Construction is expected to start in 2018, and the plant is expected to be online in 2019. Additional compressor stations and expansions to existing compressor stations are also planned for 2018.
The Company elected to participate in an expansion of the White Cliffs oil pipeline, which was completed during 2017, increasing total capacity from 150 MBbls/d to approximately 180 MBbls/d.

Eagleford  In the Eagleford shale, the Company continues to operate oil and gas gathering systems, with a 2017 average gross throughput of 55 MBbls/d of oil and 450 MMcf/d of natural gas. The 200 MMcf/d operated Brasada natural-gas cryogenic processing plant continued steady operations at capacity. In the first quarter of 2017, Anadarko completed the divestiture of its oil and natural-gas assets to a third party; the midstream assets owned by WES were not divested.

The following provides information regarding the WES Midstream assets including gathering, processing, treating, transportation, and produced-water disposal by area (excluding divestitures closed in 2017):
Area
 
Miles of
Pipelines
 
Total
Horsepower
 
2017 Average Net
Throughput (MMcf/d)
 
2017 Average Net
Throughput (MBbls/d)
DJ basin
 
4,680

 
319,200

 
950

 
50

Delaware basin
 
1,300

 
316,100

 
810

 
30

Greater Natural Buttes
 
40

 
74,900

 
420

 
10

Wyoming
 
4,750

 
173,300

 
800

 

Eagleford
 
870

 
200,100

 
450

 
30

Other
 
870

 
34,600

 
80

 
80

Total
 
12,510

 
1,118,200

 
3,510

 
200



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Other Midstream

At the end of 2017, Anadarko’s Other Midstream assets included 8 gathering systems and 20 processing and treating facilities located throughout major onshore producing basins in Colorado, Utah, Texas, and New Mexico. In 2017, Anadarko’s Other Midstream activity was concentrated in the Delaware basin to build infrastructure for present and future Wolfcamp development. In 2018, the Company expects to continue to focus its midstream investment on the Delaware and DJ basins.

Delaware Basin  In 2017, the Company expanded its midstream infrastructure for Bone Spring, Wolfcamp, and Avalon production in the Delaware basin of West Texas, installing over 60 miles of oil and water gathering lines. In addition, oil processing capacity increased by 20 MBbls/d in 2017 with the expansion of the Avalon central production facility in Loving County, and capacity is expected to increase significantly in 2018 with two ROTFs, each with capacity of 60 MBbls/d, expected to come online. Several new oil pumping stations and produced-water disposal facilities are also planned for 2018.
In the first quarter of 2017, Anadarko purchased an additional interest in the Bone Spring Plant from a third party, increasing its ownership in the plant from 33% to 50%.

DJ Basin  In 2017, the Company completed certain projects at its COSF, increasing the facility’s capacity from 100 MBbls/d to 125 MBbls/d. Construction has begun on a sixth stabilizer train at the COSF, which will add 25 MBbls/d of capacity.

The following provides information regarding Anadarko’s Other Midstream assets including gathering, processing, treating, transportation, and produced-water disposal by area (excluding divestitures closed in 2017):
Area
 
Miles of
Pipelines
 
Total
Horsepower
 
2017 Average Net
Throughput (MMcf/d)
 
2017 Average Net
Throughput (MBbls/d)
DJ basin
 
1,050

 
50,200

 
190

 
110

Delaware basin
 
540

 
44,500

 
130

 
80

Greater Natural Buttes
 
1,180

 
152,100

 
330

 

Other
 
300

 
7,000

 

 
10

Total
 
3,070

 
253,800

 
650

 
200


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 26—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 4,400 employees at December 31, 2017.


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REGULATORY AND ENVIRONMENTAL MATTERS

Environmental and Occupational Health and Safety Regulations

Anadarko’s business operations are subject to numerous international, provincial, federal, regional, state, tribal, 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 (GHG) emissions
the U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act, 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, 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
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
the U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency response preparedness


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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 GHG 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 existing standards are subject to change and 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 a considerable impact on the Company’s operations.
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 or imposition of penalties resulting from the Company’s operations, could have a material adverse effect on Anadarko and its results of operations.


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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 rapid and effective responses 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 includes the participation of spill-response contractors and other third parties. 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 Clean Gulf Associates (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. Anadarko is also a member of the Marine Preservation Association, which provides full access to the Marine Spill Response Corporation (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.
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 U.S. 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 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.
In addition to Anadarko’s membership in or access to CGA, MSRC, OSRL, and MWCC, the Company participates in industry-wide task forces, which are currently studying improvements in both gaining access to and controlling blowouts in subsea environments. Two such task forces are the Subsea Well Control and Containment Task Force and the Oil Spill Task Force.

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TITLE TO PROPERTIES

As is customary in the oil and gas industry, a preliminary title review is conducted at the time properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, thorough title examinations of the drill site 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.

EXECUTIVE OFFICERS OF THE REGISTRANT
Name
 
Age at
January 31, 2018
 
Position
R. A. Walker
 
60
 
Chairman, President and Chief Executive Officer
Robert G. Gwin
 
54
 
Executive Vice President, Finance and Chief Financial Officer
Daniel E. Brown
 
42
 
Executive Vice President, U.S. Onshore Operations
Mitchell W. Ingram
 
55
 
Executive Vice President, International & Deepwater Operations and Project Management
Ernest A. Leyendecker
 
57
 
Executive Vice President, Exploration
Robert K. Reeves
 
60
 
Executive Vice President, Law and Chief Administrative Officer
Christopher O. Champion
 
48
 
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.


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Mr. Brown was named Executive Vice President, U.S. Onshore Operations in October 2017. Prior to this position, he served as Executive Vice President, International and Deepwater Operations since May 2017; Senior Vice President, International and Deepwater Operations since August 2016; Vice President, Operations (Southern and Appalachia) since August 2013; and Vice President, Corporate Planning since May 2013. Mr. Brown 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 General Manager of the Maverick basin and the Company’s Freestone/Chalk area, Business Advisor for Planning and Reserves Administration in the Gulf of Mexico, and in engineering positions in both the U.S. onshore and the Gulf of Mexico. Mr. Brown has served as a director of WGH and WGEH since November 2017.
Mr. Ingram was named Executive Vice President, International & Deepwater Operations and Project Management in October 2017. He joined the Company as 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.
Mr. Leyendecker was named Executive Vice President, Exploration in October 2017. Prior to this position, he served as Executive Vice President, International and Deepwater Exploration since August 2016; 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. He joined the Company as Vice President, Chief Accounting Officer and Controller in 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 15, 2018, and hold office until their successors are duly elected and qualified. There are no family relationships between any directors or executive officers of Anadarko.


30


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 and other operational risks
processing volumes, pipeline throughput, and produced water disposal
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
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


31


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
the Company’s ability to successfully complete its share-repurchase program
uncertainties associated with acquired properties and businesses
disruptions in international oil and NGLs cargo shipping activities
physical, digital, cyber, 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
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the NTSB related to the Company’s operations in Colorado, and continued or additional disruptions in operations that may occur as the Company complies with regulatory orders or other state or local changes in laws or regulations in Colorado
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


32


RISK FACTORS

Our business and operations are subject to significant hazards and risks, such as the risks described below. Such risks may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. Each of these risks could adversely affect our business, financial condition and results of operations, as well as adversely affect the value of an investment in our common stock. The following risk factors should be read in conjunction with the other information contained herein, including the consolidated financial statements and the related notes.

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. 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, LNG, 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
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 limit certain sources of funding for the energy sector or restrict the exploration, development, and production of oil and natural gas
the proximity to, and capacity of, natural-gas pipelines and other transportation facilities
general economic conditions worldwide


33


The long-term effect of these and other factors on the prices of oil, natural gas, and NGLs is uncertain. Prolonged or substantial decline 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, produced water disposal, and other 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 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 did not meet the October 1, 2017 deadline for designating non-attainment areas but, on November 6, 2017, issued final designations for areas in the United States that are in attainment with the 70 parts per billion standard, representing approximately 85% of the U.S. counties that became effective on January 18, 2018. For the remaining areas of the United States, the EPA has not yet prepared final designations, but is expected to do so in a separate future action in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified facilities in new designated non-attainment areas. Also, states that are designated as non-attainment are expected to implement more stringent regulations, which 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 under the New Source Performance Standards, Subpart OOOOa, that requires 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 OOOOa standards would expand previously issued New Source Performance Standards, Subpart OOOO, published by the EPA in 2012 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 pneumatic pumps. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 standards remain in effect, but future implementation of the standards are uncertain at this time. Furthermore, in June 2017, the Bureau of Land Management (BLM) stayed a rule published in November 2016 imposing requirements to reduce methane emissions from venting, flaring, and leaking on public lands. On October 4, 2017, the U.S. District Court for the Northern District of California struck down the June 2017 stay. However, on December 8, 2017, the BLM published a final rule that will temporarily suspend certain requirements contained in the November 2016 final rule until January 17, 2019. The December 2017 compliance extension was challenged by non-governmental organizations and several states on December 19, 2017. Notwithstanding the current uncertainty, we have taken measures to enter into a voluntary regime, together with certain other oil and natural gas exploration and production operators, to reduce methane emissions. At the state level, some states are considering and others have issued requirements, including Colorado where we conduct operations, for the performance of leak-detection programs that identify and repair methane leaks at certain oil and natural-gas sources. Compliance with these rules or future methane regulations will, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs.


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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, Colorado developed and follows guidance when issuing underground injection control permits to limit the maximum injection pressure, rate, and volume of water. Oklahoma has issued rules for wastewater disposal wells 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 has also adopted similar permitting, operating, and reporting rules for disposal wells. 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.
Reduction of Greenhouse Gas Emissions. The U.S. Congress and the EPA, in addition to some state and regional authorities, 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 legislation, 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 prepared an agreement requiring 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. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Climate Agreement, which would result in an effective exit date of November 2020. Notwithstanding any withdrawal from this agreement, the implementation of substantial limitations on GHG emissions in areas where we conduct operations 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 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


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Laws and regulations regarding hydraulic fracturing or other oil and natural-gas operations could increase our costs of doing business, result in additional operating restrictions or delays, limit the areas in which we can operate, 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 or alternative proppant, and chemical 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 and similar agencies. However, several federal agencies have also asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published a final rule prohibiting the discharge of return water recovered from shale natural-gas extraction operations to publicly owned wastewater treatment plants. Also, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian land. This rule was struck down by a Wyoming federal judge, but in June 2016, the decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit. However, in July 2017, the BLM published a proposed rule to rescind the 2015 final rule. In September 2017, the Tenth Circuit Court issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in light of the BLM’s proposed rulemaking. The timing of a final rulemaking to rescind the 2015 rule is uncertain and, as a result of these developments, future implementation of the 2015 rule is uncertain at this time. 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.
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”.
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 or other oil and natural-gas operations, including subsurface water disposal. For instance, in May 2017, the Colorado Oil & Gas Conservation Commission (COGCC) issued a two-phase Notice to Operators (NTO) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and inspect and complete abandonment of all inactive flowlines regardless of distance to a building unit. Furthermore, in August 2017, following a three month review of oil and gas operations, the Governor of Colorado announced several policy initiatives designed to enhance public safety, which are to be implemented through rulemaking or legislation. As part of these policy initiatives, on February 13, 2017, the COGCC approved new regulations addressing the operation of flowlines and related infrastructure associated with oil and natural-gas development, including more stringent requirements relating to design, installation, maintenance, testing, tracking, and abandoning of flowlines.
States also could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. 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 beginning in 2012 but, since that time, local district courts have struck down the ordinances for certain of those Colorado cities, which decisions were upheld by the Colorado Supreme Court in 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.


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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 or expensive in the future. However, an amendment on the Colorado 2016 ballot was approved by voters, making it more difficult to place an initiative to amend the constitution on the state ballot by requiring signatures from 2% of registered voters from each of the state’s 35 Senate districts and approval 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.

Our Tronox settlement may not be deductible for income tax purposes, and we may be required to repay the tax refund of $881 million received in 2016 related to the deduction of the Tronox settlement payment, which may have a material adverse effect on our results of operations, liquidity, and financial condition.

In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement for $5.15 billion, resolving all claims that were or could have been asserted in the Tronox Adversary Proceeding. After the settlement became effective in January 2015, we paid $5.2 billion and deducted this payment on our 2015 federal income tax return. Due to the deduction, we had a net operating loss carryback for 2015, which resulted in a tentative tax refund of $881 million in 2016. In our financial statements, we have recorded an uncertain tax position greater than the amount of the tentative tax refund received.
The IRS has audited our tax position regarding the deductibility of the payment and issued a draft notice of proposed adjustment denying our deduction in its entirety. We disagree and plan to defend our tax position. It is possible that we may not ultimately succeed in defending this deduction. We could be required to repay all or a portion of the tentative refund received, with interest, prior to determining the final outcome of our tax position either upon IRS request or litigation of the matter in District or Federal Claims Court. If the payment is ultimately determined not to be deductible, we would be required to repay the tentative refund received plus interest and reverse the net benefit of $346 million previously recognized in our consolidated financial statements, which could have a material adverse effect on our results of operations, liquidity, and financial condition. For additional information on income taxes, see Note 13—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


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

At December 31, 2017, our total debt of $15.7 billion consisted of $12.2 billion related to Anadarko and $3.5 billion related to WES and WGP. 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 the APC RCF 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, 2017, 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; however, we cannot be assured that our credit ratings will not be further downgraded. Any further 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 are 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 $263 million at December 31, 2017, and $274 million at December 31, 2016. 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. We may be required to post additional collateral with respect to our derivative instruments if our credit ratings decline below current levels. For example, based on year-end derivative positions, if Anadarko’s credit rating were to be downgraded one level by either S&P or Moody’s, we would be required to post additional collateral of up to approximately $50 million. 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 $170 million of collateral) at December 31, 2017, and $1.4 billion (net of $117 million of collateral) at December 31, 2016. For additional information, see Note 10—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.

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.


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Future economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.

During the last few years, concerns over inflation, potential default on U.S. debt, energy costs, geopolitical issues, the availability and cost of credit, and uncertainties with regard to European sovereign debt, have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. Continued concerns could cause demand for petroleum products to diminish or stagnate, which could impact the price at which we can sell our oil, natural gas, and NGLs 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.

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, 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 or 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 some 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; however, since the BOEM’s issuance of the Notice to Lessees, the agency has delayed the implementation timeline for most of those facilities so that BOEM could further assess this financial assurance program, but this delay is expected to be temporary. 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.
In addition, our offshore development activities rely on subcontractors to perform certain offshore construction and installation activities. The Jones Act requires that vessels engaged in U.S. coastwise trade be built in the United States, registered under the U.S. flag, manned by predominantly U.S. crews, and owned and operated by U.S. citizens within the meaning of the Jones Act. Under existing U.S. Customs & Border Protection (CBP) rulings, the Jones Act is not applicable to foreign vessels conducting certain construction and pipeline installation activities on the OCS. Recently, the U.S. Marine Vessel Owners Association filed a lawsuit seeking to compel CBP to revoke a number of long-standing ruling letters relating to this exemption. The outcome of this litigation is uncertain. However, if the litigation is successful and the rulings are revoked, foreign flagged vessels could no longer perform certain operations for us in compliance with the Jones Act. The existing fleet of U.S. vessels are currently incapable of performing these construction and installation activities. As a result, certain of our development efforts could be delayed, disrupted or even suspended.
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 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.

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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.

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, 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

Outbreaks of civil and political unrest and acts of terrorism have occurred in countries in Europe, Africa, South America, 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.


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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.

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.

Exploration, development, and production activities carry inherent risk. These activities could result in liability exposure or the loss of production and revenues. In addition, we are not insured against all of the operating risks to which our business is exposed.

Our business is subject to all of the hazards and 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. Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, resulting in loss of equipment or otherwise negatively impacting the projected economic performance of our projects. Any of these risks or hazards can result in injuries and/or deaths of employees, supplier personnel or other individuals, loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others, regulatory investigations, litigation, fines, and penalties or restricted access to our properties.
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.


44


Our commodity-price risk-management and trading activities may prevent us from fully benefiting from price increases and may expose us to regulatory and 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

We are required to observe the market-related regulations enforced by the Commodity Futures Trading Commission and other agencies with regard to our commodity-price risk-management activities, which hold substantial enforcement authority. Failures to comply with such regulations, as interpreted and enforced, could materially and adversely affect our results of operations and financial condition.

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, tankers, 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.


45


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

Certain of our future 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 a portion of our capital budget is 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 and deliver our oil, natural-gas, and NGLs production could be materially harmed if adequate gathering, processing, compression, transportation, and disposal facilities and equipment are unavailable.

The marketability of our production depends in part on the availability, proximity, and capacity of gathering, processing, compression, transportation, tankers, pipeline, and produced water facilities. These facilities may be temporarily unavailable to us due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions. 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 natural-gas. In addition, in certain newer plays, the capacity of gathering, processing, compression, transportation, and disposal facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. Construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression, transportation, and disposal facilities and equipment, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery or disposing of produced water.
Any significant change in market or other conditions affecting gathering, processing, compression, transportation, or disposal facilities and equipment or the availability of these facilities, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.


46


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

As a result of mergers and acquisitions, we had approximately $4.8 billion of goodwill on our Consolidated Balance Sheet at December 31, 2017. 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 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 cyber threats, and other disruptions.

As an oil and gas producer, we face various security threats, including cyber threats such as attempts to gain unauthorized access to, or control of, sensitive information or to render data or systems corrupted or 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. We continuously work to install new, and upgrade existing, information technology systems and provide employee awareness training on phishing, malware, and other cyber risks to help ensure that we are protected, to the extent possible, against cyber risks and security breaches. We also perform periodic drills for responding to cyber incidences. There can be no assurance that such safeguards, procedures, and controls will be sufficient to prevent security breaches from occurring. Cyber attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to, or control of our data, systems, or facilities, 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 or systems, which could have an adverse effect on our reputation, financial condition, results of operations, or cash flows.
While we have experienced cyber 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 cyber 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 cyber vulnerabilities.


47


Provisions in our corporate documents and Delaware law could delay or prevent a change of control of Anadarko, even if that change would be beneficial to our stockholders.

Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the nomination and removal of directors, the prohibition of stockholder action by written consent and regulation of stockholders’ ability to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.
In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

We may reduce or cease to pay dividends on our common stock.

We can provide no assurance that we will continue to pay dividends at the current rate or at all. As of February 2018, our quarterly dividend was $0.25 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.

Difficulty attracting and retaining experienced technical personnel could reduce our competitiveness and prospects for future success.

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.


48


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 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.
Kerr-McGee Gathering, LLC, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA and the Department of Justice with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Fort Lupton complex. 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.
In December 2017, the Company entered into a consent agreement and final order with the EPA with respect to alleged violations of the U.S. Resource Conservation and Recovery Act at certain facilities associated with the Gulf of Mexico and agreed to pay a penalty of approximately $1.4 million. There were no allegations that waste was improperly disposed of or released into the environment.
Delaware Basin Midstream, LLC, a subsidiary of the Company, is currently in negotiations with the EPA with respect to alleged noncompliance with certain Risk Management Plan regulations under the Clean Air Act at its Ramsey Gas Plant. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.
See Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.

Item 4.  Mine Safety Disclosures

Not applicable.


49


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, 2018, there were approximately 9,680 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 2017 and 2016:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2017
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
72.32

 
$
64.15

 
$
50.16

 
$
54.45

Low
$
59.34

 
$
43.45

 
$
39.96

 
$
46.75

Dividends
$
0.05

 
$
0.05

 
$
0.05

 
$
0.05

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


The amount of future common stock dividends will depend on the Company’s earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors and will be determined by the Board of Directors on a quarterly basis. In February 2018, the Company announced an increase in the quarterly dividend to $0.25 per share of common stock. 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.


50


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, 2017:
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
 
6,567,944

 
$
71.44

 
27,094,327

Equity compensation plans not approved by security holders
 

 

 

Total
 
6,567,944

 
$
71.44

 
27,094,327


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 2017:
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 (2)
 
Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs (2)
October 1-31, 2017 (3)
 
15,698,241

 
$
48.13

 
15,679,096

 
$
1,745,327,838

November 1-30, 2017
 
44,950

 
$
51.09

 

 
$
1,745,327,838

December 1-31, 2017 (3)
 
6,239,532

 
$
48.84

 
6,236,398

 
$
1,440,745,052

Total
 
21,982,723

 
$
48.34

 
21,915,494

 


 _______________________________________________________________________________
(1) 
During the fourth quarter of 2017, (i) 21.9 million shares were purchased under the $3.0 Billion Share-Repurchase Program and (ii) 67 thousand shares were purchased 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 22—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(2) 
At December 31, 2017, the Company had repurchased, through open-market and private transactions, approximately $1.1 billion of common stock under its share-repurchase program in place at year end, which was expanded by $500 million in February 2018 under the $3.0 Billion Share-Repurchase Program. In February 2018, the Company completed the repurchase of an additional 8.5 million shares as part of an ASR Agreement. For additional information, see Note 20—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(3) 
In October 2017, the Company entered into an ASR Agreement to complete $1.0 billion of the $3.0 Billion Share-Repurchase Program and received an initial delivery of 15.7 million shares. The transaction was completed in December 2017, at which time the Company received an additional 5.1 million shares to settle the agreement. The settlement price was determined by the volume-weighted average price of the shares during the term less a negotiated settlement price adjustment. During the fourth quarter of 2017, the Company repurchased an additional 1.1 million shares for $59 million through open-market purchases. For additional information, see Note 20—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


51


PERFORMANCE GRAPH

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall the information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

The following graph compares the cumulative five-year total return to stockholders of Anadarko’s common stock relative to the cumulative total returns of the S&P 500 index and a peer group of 11 companies. The companies included in the peer group are Apache Corporation; 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.

Comparison of 5-Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index, and a Peer Group
performancegraph201701.jpg

Copyright© 2018 Standard & Poor's, a division of S&P Global. All rights reserved.

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the S&P 500 Index, and in the peer group on December 31, 2012, and its relative performance is tracked through December 31, 2017
Fiscal Year Ended December 31
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Anadarko Petroleum Corporation
$
100.00

 
$
107.39

 
$
112.91

 
$
67.53

 
$
97.28

 
$
75.14

S&P 500
100.00

 
132.39

 
150.51

 
152.59

 
170.84

 
208.14

Peer Group
100.00

 
126.49

 
116.48

 
88.51

 
115.49

 
119.42




52


Item 6.  Selected Financial Data
 
Summary Financial Information (1)
millions except per-share amounts
2017
 
2016
 
2015
 
2014
 
2013
Sales Revenues
$
10,969

 
$
8,447

 
$
9,486

 
$
16,375

 
$
14,867

Gains (Losses) on Divestitures and Other, net
939

 
(578
)
 
(788
)
 
2,095

 
(286
)
Total Revenues and Other
11,908

 
7,869

 
8,698

 
18,470

 
14,581

Operating Income (Loss)
(672
)
 
(2,599
)
 
(8,809
)
 
5,403

 
3,333

Tronox-related Contingent Loss

 

 
5

 
4,360

 
850

Net Income (Loss) (2)
(211
)
 
(2,808
)
 
(6,812
)
 
(1,563
)
 
941

Net Income (Loss) Attributable to Common Stockholders
(456
)
 
(3,071
)
 
(6,692
)
 
(1,750
)
 
801

Per Common Share (amounts attributable to common stockholders)
 
 
 
 
 
 
 
 
 
Net Income (Loss)—Basic
$
(0.85
)
 
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
 
$
1.58

Net Income (Loss)—Diluted
$
(0.85
)
 
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
 
$
1.58

Dividends
$
0.20

 
$
0.20

 
$
1.08

 
$
0.99

 
$
0.54

Average Number of Common Shares Outstanding—Basic
548

 
522

 
508

 
506

 
502

Average Number of Common Shares Outstanding—Diluted
548

 
522

 
508

 
506

 
505

Cash Provided by (Used in) Operating Activities (3)
4,009

 
3,000

 
(1,877
)
 
8,466

 
8,888

Capital Expenditures
$
5,300

 
$
3,314

 
$
5,888

 
$
9,256

 
$
8,523

Short-term Debt - Anadarko (4)
$
142

 
$
42

 
$
32

 
$

 
$
500

Long-term Debt - Anadarko (4)
12,054

 
12,162

 
12,945

 
12,595

 
11,576

Long-term Debt - WES and WGP
3,493

 
3,119

 
2,691

 
2,409

 
1,408

Total Debt
$
15,689

 
$
15,323

 
$
15,668

 
$
15,004

 
$
13,484

Total Stockholders’ Equity
10,696

 
12,212

 
12,819

 
19,725

 
21,857

Total Assets
$
42,086

 
$
45,564

 
$
46,331

 
$
60,879

 
$
55,340

Annual Sales Volumes
 
 
 
 
 
 
 
 
 
Oil (MMBbls)
129

 
116

 
116

 
106