Company Quick10K Filing
Quick10K
Anadarko Petroleum
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$63.60 502 $31,920
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-04-11 Other Events, Exhibits
8-K 2019-04-11 Enter Agreement, Officers, Amend Bylaw, Other Events, Exhibits
8-K 2019-02-19 Officers
8-K 2019-02-11 Regulation FD, Exhibits
8-K 2019-02-05 Earnings, Regulation FD, Exhibits
8-K 2018-12-20 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-11-15 Regulation FD, Exhibits
8-K 2018-11-14 Officers, Amend Bylaw, Other Events, Exhibits
8-K 2018-11-07 Enter Agreement, Regulation FD, Exhibits
8-K 2018-10-30 Earnings, Regulation FD, Exhibits
8-K 2018-08-16 Officers, Exhibits
8-K 2018-07-31 Earnings, Regulation FD, Exhibits
8-K 2018-07-12 Other Events, Exhibits
8-K 2018-05-15 Shareholder Vote
8-K 2018-02-20 Other Events
8-K 2018-02-06 Earnings, Regulation FD, Exhibits
8-K 2018-01-12 Enter Agreement, Off-BS Arrangement, Exhibits
BL Blackline 2,690
TCPC Blackrock Tcp Capital 846
KURA Kura Oncology 585
FIF Financial Federal 283
TSBK Timberland Bancorp 231
RCKY Rocky Brands 185
HIL Hill International 153
WAYS Wave Sync 0
SMGI SMG Industries 0
SN Sanchez Energy 0
APC 2018-12-31
Part I
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers, and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
EX-21 apc201810k-exhibit21.htm
EX-23.I apc201810k-exhibit23i.htm
EX-23.II apc201810k-exhibit23ii.htm
EX-24 apc201810k-exhibit24.htm
EX-31.I apc201810k-exhibit31i.htm
EX-31.II apc201810k-exhibit31ii.htm
EX-32 apc201810k-exhibit32.htm
EX-99 apc201810k-exhibit99.htm

Anadarko Petroleum Earnings 2018-12-31

APC 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 apc201810k-10k.htm 10-K Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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
anadarkonamelogo.jpg
(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
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 every Interactive Data File required to be submitted 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 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, 2018, was $37.2 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 1, 2019, is shown below:
Title of Class
  
Number of Shares Outstanding
Common Stock, par value $0.10 per share
  
499,575,992
Documents Incorporated By Reference
Portions of the Definitive Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 14, 2019 (to be filed with the Securities and Exchange Commission prior to April 4, 2019), 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,” “we”, “our”, and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. In addition, the following Company or industry-specific terms and abbreviations are used throughout this report:

364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured RCF
3D - Three-dimensional
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, part of the West Texas Complex effective January 1, 2018
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, part of the West Texas Complex effective January 1, 2018
DD&A - Depreciation, depletion, and amortization
DJ - Denver-Julesberg
DJ Basin Complex - The Platte Valley system, Wattenberg system, and Lancaster plant, which were combined into a single complex in Colorado in the first quarter of 2014 to serve production in the DJ basin
E&P - Exploration and production
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
GHG - Greenhouse gas
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
Mcf - Thousand cubic feet
MMBbls - Million barrels

2 | APC 2018 FORM 10-K



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
N/A - Not applicable
NGL or NGLs - Natural-gas liquids
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
S&P - Standard and Poor’s
SEC - U.S. Securities and Exchange Commission
Share-Repurchase Program - A program authorizing the repurchase of Anadarko’s common stock
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 364-Day Facility - WES’s $2.0 billion 364-day senior unsecured credit agreement
WES Merger - A merger, which is expected to close in the first quarter of 2019, whereby a wholly owned subsidiary of WGP will merge with and into WES
WES RCF - WES’s $1.5 billion senior unsecured RCF
West Texas Complex - The DBM Complex and DBJV and Haley systems, all of which were combined into a single complex effective January 1, 2018.
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 $35 million senior secured RCF
Zero Coupons - Anadarko’s Zero-Coupon Senior Notes due 2036


APC 2018 FORM 10-K | 3



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 NGL 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 volume, 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 or other oil and natural-gas operations; retroactive royalty or production tax regimes; deepwater and onshore 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


4 | APC 2018 FORM 10-K


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, successfully complete its debt-reduction program, and the impact of changes in the Company’s credit ratings
the Company’s ability to successfully complete its Share-Repurchase Program
the Company’s ability to successfully plan, secure additional government and partner approvals, enter into additional long-term sales contracts, make a final investment decision and the timing thereof, finance, build, and operate the necessary infrastructure and LNG park in Mozambique
uncertainties and liabilities associated with acquired and divested properties and businesses
disruptions in international oil and NGL cargo shipping activities
physical, digital, internal, and external security breaches
supply and demand, technological, political, governmental, and commercial conditions associated with long-term development and production projects in domestic and international locations
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board 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
the completion of the simplification transaction between WES and WGP and the corresponding sale of substantially all of the Company’s Other Midstream assets to WES
other factors discussed below and elsewhere in this Form 10-K, the Company’s subsequent Quarterly Reports on Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

APC 2018 FORM 10-K | 5


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BUSINESS AND PROPERTIES
GENERAL


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 1.5 billion BOE of proved reserves at December 31, 2018. Anadarko’s mission is to deliver competitive and sustainable return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Successful execution of Anadarko’s mission requires a firm commitment to operating safely and in a socially responsible and environmentally friendly manner. Anadarko’s strategic objectives are 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’s asset portfolio is positioned to deliver long-term value to stakeholders by combining cash-generating conventional oil developments in the Gulf of Mexico, Algeria, and Ghana, with a large inventory of significant and proven high-growth unconventional resources in the U.S. onshore. Anadarko’s U.S. onshore assets include the Delaware and DJ basins and an emerging play in the Powder River basin. Anadarko’s asset portfolio also includes a world-class natural-gas discovery in Mozambique as well as other worldwide exploration and development opportunities.
Anadarko’s Exploration and Production and Midstream business segments are managed separately when making operating and capital allocation decisions due to distinct operational differences. The Company’s three reporting segments are as follows:

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 an FID in the first half of 2019.

WES Midstream and Other Midstream—These two segments engage in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGL production as well as gathering and disposal of produced water. The WES Midstream segment consists of assets owned by 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 midstream assets not owned by WES. At the end of 2018, Anadarko announced the planned contribution and sale of substantially all of its Other Midstream assets to its consolidated subsidiary WES. The sale is expected to close in the first quarter of 2019, after which the Company will have one midstream segment. See Midstream Properties and Activities below.

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 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.


6 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITIES
The Company’s Exploration and Production segment actively manages Anadarko’s worldwide oil, natural-gas, and NGL sales of its 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 mainly under indexed market price agreements but also from time to time will enter into 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, NGL, 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.

APC 2018 FORM 10-K | 7


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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


ANADARKO’S EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITIES
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Oil and NGLs  Anadarko’s oil revenues are derived from production in the United States, Algeria, and Ghana. NGL revenues are derived from production in the United States and Algeria. The Company’s U.S. oil and NGL production is generally sold under contracts with prices based on relevant market indices, adjusted for location, quality, and transportation. The Company’s Algerian and Ghanaian oil is sold into international markets receiving a Brent-linked price. The Company controls firm transportation and fractionation capacity that ensures access to downstream markets, which enables the Company to maximize the value of its oil and NGL production. 

Natural Gas  Anadarko’s natural-gas revenue is derived from production in the United States and is generally sold under contracts with prices based on relevant market indices, adjusted for location and transportation. The Company controls firm-transportation capacity that ensures access to downstream markets, which enables the Company to maximize the value of its natural-gas production. 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) against stored natural gas.

8 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


United States

Anadarko’s U.S. operations include oil and natural-gas exploration and production in the U.S. onshore and deepwater Gulf of Mexico.
 
2018 U.S. OPERATIONS
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U.S. Onshore  Anadarko’s U.S. onshore properties include significant oil and natural-gas plays located in Texas, Colorado, Wyoming, and Utah.

U.S. ONSHORE OIL AND NATURAL-GAS EXPLORATION AND PRODUCTION OPERATIONS
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APC 2018 FORM 10-K | 9


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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Activities in the U.S. onshore during 2018 primarily focused on optimizing wellbore and completion design, improving cost structure, delivering efficient production, and maximizing margin per barrel. The Company also focused on building out infrastructure within its premier positions in the Delaware and DJ basins, while enhancing its acreage position in the Powder River basin. Throughout 2018, the Company continued its efforts to explore for U.S. onshore opportunities that compete within Anadarko’s portfolio. In addition, during 2018 the Company divested its nonoperated interests in Alaska. In 2019, the Company expects to continue its horizontal drilling programs in the Delaware and DJ basins, while commencing appraisal activity within the Powder River basin.
The Company also has fee ownership of mineral rights, known as the Land Grant, under 7.3 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 earn royalty revenue from third-party activity on Land Grant acreage.
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Delaware Basin  Anadarko operates approximately 750 wells and owns interests in approximately 450 nonoperated wells in the Delaware basin. The Company’s 2018 drilling activity primarily targeted the Wolfcamp shale play, while also testing the liquids-rich Bone Spring tight sands. Having secured operatorship on a majority of its legacy joint venture acreage, the Company continued to build out one of the most expansive and integrated infrastructure positions in the region, primarily in Reeves and Loving counties. In 2018, the Company focused on securing sufficient oil takeaway capacity, ending the year with approximately 46% of its Delaware basin operated oil volume being sold at Gulf Coast markets via the Enterprise pipeline. This capacity is expected to increase to 100% when the Cactus II pipeline is in full service. Anadarko ended 2018 with eight operated drilling rigs and five completion crews.
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 optimized horizontal-well spacing. The Company expects the Wolfcamp shale play to provide substantial opportunity for Anadarko’s future activity in the basin.
The Reeves and Loving ROTFs and the first train at the Mentone natural-gas processing plant were placed into service in 2018, adding 120 MBbls/d and 200 MMcf/d of nameplate oil and gas processing capacity to the area. See Midstream Properties and Activities for additional discussion on the significant infrastructure added during 2018 to facilitate growth from this asset.


10 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


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DJ Basin  Anadarko operates approximately 3,400 vertical wells and 1,700 horizontal wells in the Niobrara and Codell formations in the DJ basin. Horizontal drilling results in the field continue to be strong, with enhanced economics realized through the Company’s ownership of the Land Grant and operational efficiencies in drilling and completions.
Anadarko continues to drive drilling efficiencies in its DJ basin operations. In 2018, the Company increased its horizontal lateral length by approximately 16% and improved its footage drilled per rig-day by approximately 30% from 2017. The Company ended 2018 with four operated drilling rigs and two completion crews.
The sixth COSF train was placed in service during the third quarter of 2018, adding 30 MBbls/d of oil-stabilization capacity. Construction activities have commenced at the Latham plant, which will deliver 400 MMcf/d of increased natural-gas processing capacity. See Midstream Properties and Activities for additional discussion.
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Powder River Basin  In the southern Powder River basin, Anadarko’s acreage is mainly located in Converse County, Wyoming. The field contains the Turner, Niobrara, and Mowry formations that hold both liquids and natural gas. In 2018, the Company invested $181 million on lease acquisitions, accumulating a 300,000 gross-acre position in the southern Powder River basin area, with significant stacked-oil potential.

APC 2018 FORM 10-K | 11


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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


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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. There was minimal activity in this field during 2018 due to capital being allocated to higher-margin projects.



12 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Gulf of Mexico  Anadarko owns a working interest in 231 blocks in the Gulf of Mexico, operates 10 active floating platforms, and holds interests in 34 fields. The Company continued an active deepwater development and exploration program in the Gulf of Mexico during 2018, and continues to take advantage of existing infrastructure to cost-effectively develop known resources. The Company plans to operate up to two floating drillships and two platform rigs in 2019.

GULF OF MEXICO OIL AND NATURAL-GAS EXPLORATION AND PRODUCTION OPERATIONS
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Development
Horn Mountain (100% working interest)
At Horn Mountain, the Company is successfully executing on its tie-back strategy as oil production continues to exceed expectations. The third development 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. This well was completed in the first quarter of 2018 and came online in the second quarter of 2018. A platform rig program is currently underway at the spar. The lower platform-rig day rate provides capital-efficient opportunities to increase oil rates in the field. Horn Mountain continues to outperform expectations with total facility gross oil production up by more than 400% since its acquisition in late 2016.

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Marlin (100% working interest)
At Marlin, the first tie-back development well was drilled and completed in the King field in the fourth quarter of 2017. The well was brought online in the first quarter of 2018. The Company drilled a second tie-back development well in the Dorado field in the first quarter of 2018. The well encountered 35 feet of high-quality Miocene oil pay and was completed and brought online in the third quarter of 2018. Marlin continues to produce at or near its highest oil rates since the facility was acquired in late 2016.
Additionally, the Company leveraged its infrastructure position to generate revenue with production-handling and cost-sharing agreements on third-party volume. The Crown and Anchor field, which is owned and operated by third parties, was successfully tied back to Marlin and began producing in the second quarter of 2018.
Holstein (100% working interest)
At Holstein, the Company certified the permanently installed platform drilling rig and initiated a four-well drilling program in the fourth quarter of 2017. The first two wells came online in the third quarter of 2018, and the third development well was drilled during the fourth quarter of 2018. Results for the third well were in line with expectations and first production is expected in the first quarter of 2019. Based on the success of this program, the Company plans to drill additional wells in 2019.
Caesar Tonga (33.75% working interest)
At Caesar/Tonga, the Company completed its eighth development well in the second quarter of 2018. The well was tied back to Anadarko’s Constitution Spar and came online in the third quarter of 2018. This field continues to produce at or near record-high oil production rates.
Constellation (33.33% working interest)
At Constellation, the Company successfully drilled and completed the first development well in the second quarter of 2017. The well was tied back to Anadarko’s Constitution spar and first production was achieved in early 2019.
Lucius (48.9% working interest)
At Lucius, the Company successfully drilled the ninth development well in the third quarter of 2018 and encountered 230 net feet of oil pay in two Pliocene sands. The well was completed and brought online in the fourth quarter of 2018. Spud-to-first-production cycle time was 71 days, a Company record for a deepwater subsea well.
The Company entered into an agreement with partners to expand the Lucius unit to encompass the adjacent Hadrian North discovery in late 2017. The first Hadrian North expansion well concluded drilling in the third quarter of 2018. The well encountered 200 net feet of oil pay in two Pliocene sands and was completed in the fourth quarter of 2018. A second well, originally drilled by the previous operator, was also completed in the fourth quarter of 2018. First production from the North Hadrian two-well expansion is expected by mid-2019.
K2 Complex (41.8% working interest)
At the K2 Complex, the Company successfully drilled and completed the twelfth development well in the second quarter of 2018. The well encountered 220 net feet of oil pay in three Miocene sands and was brought online in the second quarter of 2018 as a tie-back to the Marco Polo facility.

Exploration and Appraisal
The Company continues to create value through successful working interest farmdowns of existing acreage, while also increasing its position through lease sale participation for additional acreage. The Music City and the Sugar exploration wells were drilled in the first quarter of 2018 and were unsuccessful.

14 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


International

Anadarko’s international operations include oil, natural-gas, and NGL production and development in Algeria and Ghana, along with activities in Mozambique, where the Company continues to make progress toward an FID on an LNG development. The Company also has exploration acreage in Canada, Colombia, Peru, South Africa, and other countries. In 2019, the Company expects to focus its international drilling activity in Ghana and position itself to make a final investment decision on the future LNG development in Mozambique.

2018 INTERNATIONAL OPERATIONS
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Algeria  Anadarko is engaged in production and development operations in Algeria’s Sahara Desert in Blocks 404A 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 and NGLs through the El Merk central processing facility (CPF) in Block 208 and oil through the Hassi Berkine South and Ourhoud CPFs in Block 404A. Gross production through these facilities averaged more than 320 MBbls/d in 2018, inclusive of 29 days of planned downtime for statutory maintenance at the Hassi Berkine South CPF. The Company drilled seven development wells in 2018 and plans to continue drilling operations throughout 2019.

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


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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, utilizes a 120 MBbls/d-capacity FPSO to produce from subsea wells. Gross production averaged 78 MBbls/d of oil in 2018. An average of 75 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. The partnership received Ghanaian government approval for the full-field plan of development in October 2017 and drilling operations commenced in 2018. The operator drilled, completed, and brought online a production well in each of the third and fourth quarters of 2018. Additionally, a previously drilled water injector well was completed and put into service at the end of 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 in 2017. In 2018, the operator completed the necessary work, including two shutdown periods, to effectively stabilize the turret and rotate the FPSO to its permanent heading. Completion of the permanent spread-mooring anchoring system is expected in early 2019, with no further shutdowns anticipated.
The TEN project (19% nonoperated participating interest), located in the Deepwater Tano Block, utilizes an 80 MBbls/d-capacity FPSO to produce from subsea wells. The project achieved first oil in the third quarter of 2016. However additional field development was delayed due to a border dispute between Ghana and Côte d’Ivoire. In September 2017, the International Tribunal for the Law of the Sea issued a ruling 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, did not affect the TEN fields, and the operator resumed development drilling in the first quarter of 2018. The first well was completed and brought online in the third quarter of 2018. Drilling on two additional wells was completed in the fourth quarter of 2018, with completion activities ongoing at year end. The project averaged gross production of 65 MBbls/d of oil in 2018.
In 2019, the operator plans to drill and complete seven new wells to optimize the deliverability from the Jubilee and TEN fields.

16 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


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Mozambique  Anadarko operates Offshore Area 1 (26.5% working interest).

Development  In February 2018, the Government of Mozambique approved the Development Plan for the Anadarko-operated, initial two-train Golfinho/Atum onshore LNG project, marking a major milestone required for an FID. Major infrastructure projects, including roads, camps, an airstrip, and resettlement, are underway and proceeding as planned, preparing the area for onshore LNG facility construction. In the third quarter of 2018, Offshore Area 4, which is owned and operated by third parties, joined the Anadarko-led resettlement and airstrip projects as a 50% participant. The preferred offshore construction and installation contractor was selected in the fourth quarter of 2018, and the contracts with the onshore and offshore construction, installation, and equipment contractors are being finalized. Subsequent to year end, LNG sales and purchase agreements (SPAs) were executed with Tokyo Gas Co., Ltd; Centrica LNG Company Ltd., a subsidiary of Centrica plc; Shell International Trading Middle East Ltd; and CNOOC Gas and Power Singapore Trading & Marketing Pte. Ltd, increasing the contracted volume to more than 7.5 MTPA, inclusive of previously announced SPAs executed with Tohoku Electric Power Company, Inc. and Électricité de France, S.A. Execution of SPAs representing 2.0 MTPA of additional contracted volume is anticipated prior to FID.
With progress on major contracts and marketing SPAs, the Company formally launched project financing in December 2018 with the aim of securing funding for up to two-thirds of the required construction capital. The Company is working to finalize project finance arrangements with lenders and secure all partner and government-related approvals required to position the Company to make a final investment decision in the first half of 2019.

Appraisal  In Offshore Area 1, the Company completed the interpretations of the re-processed 3D seismic data covering the Orca, Tubarao, and Tubarao-Tigre discovery areas, and continues to assess these areas in accordance with the appraisal program submitted to the Government of Mozambique.




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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Proved Reserves

Estimates of proved reserves volume 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 volume is 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 volume. 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, 2018 were $65.56 per Bbl for oil, $3.10 per MMBtu for natural gas, and $37.68 per Bbl for NGLs.
Disclosures by geographic area include the United States and International. For 2018, 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, 2018
 
 
 
 
Developed
 
 
 
 
United States
392

2,564

192

1,011

International
123

24

10

137

Undeveloped
 
 
 
 
United States
137

634

66

309

International
15

8


16

Total proved reserves
667

3,230

268

1,473

December 31, 2017
 
 
 
 
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 reserves
658

3,230

243

1,439

December 31, 2016
 
 
 
 
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 reserves
702

4,424

283

1,722


The Company’s proved-reserves product mix was 63% liquids in 2018, 63% in 2017 and 57% in 2016. The Company’s year-end 2018 proved reserves product mix was 45% oil, 37% natural gas, and 18% NGLs.

18 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Changes to the Company’s proved reserves during 2018 are summarized in the table below:
MMBOE
2018

2017

2016

Proved Reserves
 
 
 
January 1
1,439

1,722

2,057

Reserves additions and revisions
 
 
 
Discoveries and extensions
164

114

40

Infill-drilling additions (1)
181

71

69

Drilling-related reserves additions and revisions
345

185

109

Other non-price-related revisions (1)
(61
)
59

191

Net organic reserves additions
284

244

300

Acquisition of proved reserves in place

3

97

Price-related revisions (1)
29

92

(147
)
Total reserves additions and revisions
313

339

250

Sales in place
(37
)
(379
)
(294
)
Production
(242
)
(243
)
(291
)
December 31
1,473

1,439

1,722

Proved Developed Reserves
 
 
 
January 1
1,127

1,325

1,632

December 31
1,148

1,127

1,325

(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.

The Company’s estimates of proved developed reserves, PUDs, and total proved reserves at December 31, 2018, 2017, and 2016, 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, 2018. Annually, Anadarko reports gross proved reserves for U.S.-operated properties to the U.S. Department of Energy. These reported reserves are derived from the same database used to estimate and report proved reserves in this Form 10-K.


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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Changes in PUDs  Changes to PUDs during 2018 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, 2018
312

Revisions of prior estimates
117

Extensions, discoveries, and other additions
47

Conversions to developed
(144
)
Sales in place
(7
)
PUDs at December 31, 2018
325


Revisions of prior estimates  Revisions of prior estimates reflect Anadarko’s ongoing evaluation of its asset portfolio. In 2018, PUDs were revised upward by 117 MMBOE.
MMBOE
December 31, 2018

Revisions due to changes in year-end prices (price impact to opening balance)

Other revisions of prior estimates
 
Revisions due to performance
18

Revisions due to cost updates
2

Revisions due to successful infill drilling
158

Revisions due to development plan updates
(61
)
Total other revisions of prior estimates
117

Revisions of prior estimates
117


Prior estimates were revised upward by a total of 117 MMBOE and were associated with the following:
Performance  The Company experienced an overall increase in PUDs of 18 MMBOE due to performance improvements. Upward revisions of 26 MMBOE were driven primarily by performance improvements in the DJ basin. Downward revisions of 8 MMBOE were primarily due to minor performance reductions in various areas in the Gulf of Mexico and Ghana.
Infill-drilling activities  The Company added 158 MMBOE of PUDs associated with infill-drilling activities, with 151 MMBOE in the DJ basin, 5 MMBOE in the Lucius area in the Gulf of Mexico, and the remaining in the Ghana TEN field.
Development plan updates  The majority of revisions associated with updates to development plans occurred in the DJ basin due to municipal permit delays in certain areas of the field and ongoing optimization of development activity.
Extensions, discoveries, and other additions  The extension of proved acreage in 2018 resulted in an increase in PUDs of 47 MMBOE, of which 24 MMBOE was in the Hadrian North expansion area of the Gulf of Mexico and 23 MMBOE was in the Delaware basin.

Conversions to developed  In 2018, the Company converted 144 MMBOE of PUDs to developed status, equating to 34% of total year-end 2017 PUDs when adjusted for revisions and sales. Approximately 79% of PUD conversions occurred in U.S. onshore assets, 15% in Gulf of Mexico assets, and the remaining in international assets.
Anadarko spent $1.1 billion to develop PUDs in 2018, of which approximately 71% related to U.S. onshore assets, 25% related to Gulf of Mexico assets, and the remaining related to international assets.

Sales in place  In 2018, PUDs decreased by 7 MMBOE due to the Company’s divestiture activities.
 

20 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


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 deepwater development and international programs may take longer. At December 31, 2018, the Company had no material pre-2014 PUDs that remained undeveloped. However, the Company did have 15 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 are 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 proved reserves additions are based on estimates generated through the integration of relevant geological, engineering, and production data, and may include the use of reliable technologies that have been demonstrated in the field to yield reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation as defined in the SEC regulations. Data used in these integrated assessments may include 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 may also include subsurface information obtained through indirect measurements such as seismic data. Reservoir parameters from analogous reservoirs may be used to increase the quality of and confidence in the reserves estimates when available and necessary. The method or combination of methods used to estimate the reserves of each reservoir is 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 SVP—Corporate Planning. The SVP—Corporate Planning reports to the Company’s Executive Vice President, Finance and Chief Financial Officer, who in turn reports to the Chairman 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 32 years of experience in the oil and gas industry, including over 18 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 32 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.


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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


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, 2018. The purpose of these reviews 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 93% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2018. 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.


22 | APC 2018 FORM 10-K

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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Sales Volume, Prices, and Production Costs

The following provides the Company’s annual sales volume, average sales prices, and average production costs per BOE for each of the last three years:
 
Sales Volume
 
 
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)
 
2018
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
DJ basin
36

225

22

95

 
 
$
63.17

 
$
2.44

 
$
32.80

 
$
1.90

Other United States
71

165

14

113

 
 
64.44

 
2.76

 
34.52

 
6.43

Total United States
107

390

36

208

 
 
64.01

 
2.57

 
33.46

 
4.35

International
33


2

35

 
 
70.38

 
0.66

 
43.25

 
7.09

Total
140

390

38

243

 
 
65.51

 
2.57

 
33.93

 
4.73

2017
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
DJ basin
31

212

21

88

 
 
$
49.73

 
$
2.55

 
$
27.46

 
$
1.67

Other United States
66

266

13

123

 
 
49.57

 
3.03

 
32.24

 
5.22

Total United States
97

478

34

211

 
 
49.62

 
2.82

 
29.24

 
3.75

International
32


2

34

 
 
53.77

 

 
35.64

 
5.84

Total
129

478

36

245

 
 
50.66

 
2.82

 
29.54

 
4.04

2016
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
DJ basin
33

214

20

89

 
 
$
40.27

 
$
2.00

 
$
18.26

 
$
1.26

Other United States
52

552

24

168

 
 
38.29

 
2.06

 
20.21

 
2.97

Total United States
85

766

44

257

 
 
39.06

 
2.04

 
19.32

 
2.37

International
31


2

33

 
 
43.93

 

 
25.63

 
6.28

Total
116

766

46

290

 
 
40.34

 
2.04

 
19.64

 
2.81

(1) 
Excludes the impact of commodity derivatives.
(2) 
Includes oil and gas operating expenses and other taxes and excludes ad valorem and severance taxes. Volume represents produced volume sold during the period.

Additional information on volume, prices, and production costs is contained in Financial Results under Item 7 of this Form 10-K.


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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


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. 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.
The following is a summary of the Company’s delivery commitments at December 31, 2018:
 
Delivery Commitments
 
2019

2020

2021

Thereafter

Total

Oil (MMBbls)
 
 
 
 
 
United States
19

9



28

International
9




9

Natural-Gas (Bcf)
 
 
 
 
 
United States (1)
470

264

224

515

1,473

NGLs (MMBbls)
 
 
 
 
 
United States
4




4

(1) 
Volume committed to various customers through 2033.

Properties and Leases

The following shows the developed lease, undeveloped lease, and fee mineral acres in which Anadarko held interests at December 31, 2018:
 
Developed
Lease
 
Undeveloped
Lease
 
Fee
Mineral (1)
 
Total
thousands
Gross

Net

 
Gross

Net

 
Gross

Net

 
Gross

Net

United States
 
 
 
 
 
 
 
 
 
 
 
Onshore
2,272

1,445

 
545

313

 
9,868

8,154

 
12,685

9,912

Offshore
315

183

 
1,017

822

 


 
1,332

1,005

Total United States
2,587

1,628

 
1,562

1,135

 
9,868

8,154

 
14,017

10,917

International
635

138

 
36,439

30,536

 


 
37,074

30,674

Total
3,222

1,766

 
38,001

31,671

 
9,868

8,154

 
51,091

41,591

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

At December 31, 2018, the Company had approximately 20.2 million net undeveloped lease acres scheduled to expire by December 31, 2019, 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, 2019, if not amended, primarily relate to 20.0 million net acres of international exploration acreage in South Africa (16.0 million net acres) and Colombia (4.0 million 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.


24 | APC 2018 FORM 10-K

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EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Drilling Program

The Company’s 2018 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 2018 consisted of 47 gross completed wells in the U.S. onshore. Development activity in 2018 consisted of 637 gross completed wells, which included 615 U.S. onshore wells, 10 Gulf of Mexico wells, and 12 international wells.

Drilling Statistics
The following shows the number of net 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

2018
 
 
 
 
 
 
 
 
United States
17.0

2.0

19.0

 
393.7

5.4

399.1

418.1

International



 
2.6


2.6

2.6

Total
17.0

2.0

19.0

 
396.3

5.4

401.7

420.7

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


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, 2018:
 
Wells in the process of drilling or in active completion
 
Wells suspended or waiting on completion (1)
 
Exploration

Development

 
Exploration

Development (2)

United States
 
 
 
 
 
Gross
3

45

 
8

489

Net
0.2

35.2

 
4.6

370.5

International
 
 
 
 
 
Gross

1

 
25

8

Net

0.3

 
7.1

1.8

Total
 
 
 
 
 
Gross
3

46

 
33

497

Net
0.2

35.5

 
11.7

372.3

(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 114 MMBOE of PUDs primarily assigned to U.S. onshore development wells suspended or waiting on completion at December 31, 2018. The Company expects to convert 113 MMBOE of these PUDs reserves to developed status within five years of their initial disclosure. The remaining 1 MMBOE is associated with an international well that was spud late in the year and will be converted to developed status in the near future.

APC 2018 FORM 10-K | 25


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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES


Productive Wells

At December 31, 2018, the Company’s ownership interest in productive wells was as follows:
 
Oil Wells (1)

Gas Wells (1)

United States
 
 
Gross
3,976

7,852

Net
2,544.3

6,543.4

International
 
 
Gross
215

9

Net
38.9

2.2

Total
 
 
Gross
4,191

7,861

Net
2,583.2

6,545.6

(1) Includes wells containing multiple completions as follows:
 
 
Gross
364

2,510

Net
311.3

2,263.4




26 | APC 2018 FORM 10-K

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BUSINESS & PROPERTIES
MIDSTREAM PROPERTIES AND ACTIVITIES


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 assets, the Company improves its ability to manage costs, controls the timing of bringing on new production, and enhances the value received for the Company’s production. Anadarko also provides midstream services to a variety of third-party customers and 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, 2018, Anadarko’s ownership interest in WGP consisted of a 77.8% limited partner interest and the entire non-economic general partner interest. At December 31, 2018, WGP’s ownership interest in WES consisted of a 29.6% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At December 31, 2018, Anadarko also owned a 9.7% limited partner interest in WES through other subsidiaries.
At the end of 2018, Anadarko announced the planned contribution and sale of substantially all of its midstream assets not owned by WES, which are largely associated with Anadarko's two premier U.S. onshore oil plays in the Delaware and DJ basins, to WES for approximately $4.0 billion, with approximately $2.0 billion of cash proceeds and the balance to be paid in WES common units. Additionally, at the end of 2018, WES announced that a wholly owned subsidiary of WGP will merge with and into WES, with WES continuing as the surviving entity and a subsidiary of WGP, which will result in a simplified midstream structure. Under the terms of the WES Merger, WGP will acquire all of the outstanding publicly held common units of WES and substantially all of the WES common units owned by Anadarko, including the Class C units that will be converted into WES common units immediately prior to the transaction, in a unit-for-unit, tax-free exchange. WES will survive as a partnership with no publicly traded equity, owned 98% by WGP and 2% by Anadarko. WES will remain the borrower for all existing debt, is expected to remain the borrower for all future debt, and will remain the owner of all operating assets and equity investments. Anadarko will maintain operating control of WGP, with approximately 55.5% pro forma ownership of the combined entity. The WES Merger is expected to close in the first quarter of 2019 concurrently with the asset contribution and sale.

ANADARKO’S MIDSTREAM PROPERTIES AND ACTIVITIES
midstreammap201801a08.jpg

APC 2018 FORM 10-K | 27


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BUSINESS & PROPERTIES
MIDSTREAM PROPERTIES AND ACTIVITIES


WES Midstream

At December 31, 2018, WES Midstream included 19 gathering systems and 46 processing and treating facilities located throughout major onshore producing basins in Wyoming, Colorado, Utah, Pennsylvania, Texas, and New Mexico. In 2018, WES Midstream activity focused on constructing midstream infrastructure in the Delaware basin to prepare for long-term volumetric oil growth, providing additional system expansions in the DJ basin to keep pace with basin activity, and ensuring sufficient access to downstream markets by acquiring options to invest in various transportation assets and long-haul pipelines.

Delaware Basin  In 2018, WES expanded its midstream infrastructure for production in the Delaware basin of West Texas, installing approximately 365 miles of gas and water gathering lines. Within its gas gathering system, eight new central gathering facilities (CGFs) were installed and one existing CGF was expanded to add a total of approximately 325 MMcf/d of natural gas compression capacity. One produced-water disposal facility was placed into service during the first quarter of 2018, with capacity of 30,000 barrels of water per day. Additional gas gathering, compression, and produced-water disposal infrastructure is planned for 2019.
With the completion of the Mentone Train I, a 200 MMcf/d cryogenic facility, in the fourth quarter of 2018, the West Texas Complex now includes 1.1 Bcf/d of cryogenic processing capacity, 2,000 gallons per minute of amine-treating capacity, and 28 MBbls/d of high-pressure condensate stabilization capacity. WES expects to add 200 MMcf/d of additional cryogenic processing capacity to the West Texas Complex when the Mentone Train II is completed in the first quarter of 2019.  
WES exercised options to acquire a 20% interest in the Midland-to-Sealy crude-oil pipeline, which began full service in April 2018, and a 15% interest in the Cactus II crude-oil pipeline, which is expected to come online in the second half of 2019. Both of these pipelines transport oil from gathering systems in West Texas to market centers along the Gulf Coast. Additionally, WES exercised its option to acquire a 30% interest in the Red Bluff Express pipeline, which was placed into service in May 2018, and closed on the investment in January 2019. This pipeline transport provides crude-oil flow assurance by ensuring residue gas takeaway from natural-gas processing plants in West Texas to the WAHA hub in Pecos County, Texas.

DJ Basin  WES continued to optimize its gas gathering system throughout 2018 which resulted in average gathering pipeline pressures believed to be among the lowest in the basin and supportive of stable and consistent production. Management believes that WES is well positioned in the DJ basin with sufficient oil, NGL, and residue gas transportation capacity.
In 2018, WES expanded its midstream infrastructure to support incremental DJ basin production, adding approximately 170 MMcf/d of compression capacity and 35 miles of gas pipeline. In addition, WES completed a bypass at the DJ Basin Complex, which provides for a total of 160 MMcf/d of bypass capacity. In the third quarter of 2018, WES commenced construction of the Latham plant at the DJ Basin Complex, which will consist of two cryogenic gas processing trains that will increase natural-gas processing capacity by 400 MMcf/d. Additional gas gathering and compression system expansions are also planned for 2019.
In 2018, WES participated in the expansion of the Texas/Oklahoma system of the Texas Express Gathering pipeline, which was completed in the second quarter and resulted in total capacity of 100 MBbls/d for the Texas/Oklahoma system. The Texas Express Gathering pipeline ultimately delivers NGLs to the Texas Express Pipeline. In addition, WES elected to participate in the expansion of both the Front Range Pipeline and the Texas Express Pipeline. The expansion of Front Range Pipeline will increase NGL-transport capacity by 100 MBbls/d, and the expansion of Texas Express Pipeline will increase NGL-transport capacity by 90 MBbls/d, with service on the expanded pipelines expected to begin during 2019. These expansions support the ongoing production growth from the DJ basin and provide flow assurance to attractive markets. WES also elected to participate in the conversion of one of the two White Cliffs oil pipelines to a NGL Y-grade pipeline with an initial capacity of 90 MBbls/d. The pipeline will be taken out of service in early 2019 for conversion and is expected to come back online during the fourth quarter of 2019.

Eagleford  In the Eagleford shale, WES continues to operate oil and gas gathering systems, with a 2018 average gross throughput of 65 MBbls/d of oil and 440 MMcf/d of natural gas. The 200 MMcf/d operated Brasada natural-gas cryogenic processing plant continued steady operations at capacity.


28 | APC 2018 FORM 10-K

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BUSINESS & PROPERTIES
MIDSTREAM PROPERTIES AND ACTIVITIES


The following provides information regarding the WES Midstream assets including gathering, processing, treating, transportation, and produced-water disposal by area:
Area
Miles of
Pipelines

Total
Horsepower (1)

2018 Average Net
Throughput (MMcf/d)

2018 Average Net
Throughput (MBbls/d)

DJ basin
4,720

302,200

1,110

55

Delaware basin
2,080

412,700

1,040

160

Wyoming
4,210

160,800

840


Eagleford
880

202,700

445

40

Greater Natural Buttes
40

74,900

360

10

Other
930

9,700

100

95

Total
12,860

1,163,000

3,895

360

(1) 
Excludes horsepower associated with transportation assets.

Other Midstream

At the end of 2018, Anadarko’s Other Midstream assets included 10 gathering systems and 25 processing and treating facilities located throughout major onshore producing basins in Colorado, Utah, Texas, and New Mexico. In 2018, Anadarko’s Other Midstream activity was focused on the build out of its crude-oil gathering and stabilization capacity and produced-water gathering and disposal capacity in the Delaware basin, as well as on expanding its crude-oil gathering and stabilization capacity in the DJ basin.

Delaware Basin  In 2018, the Company expanded its midstream infrastructure to further support Anadarko-operated production in the Delaware basin. Oil-stabilization capacity increased by 120 MBbls/d in 2018, as the Reeves ROTF came online in the second quarter and the Loving ROTF came online in the third quarter. Additionally, over 600 miles of oil and water gathering lines were installed, oil pumping stations with a capacity of 125 MBbls/d were completed, and new produced-water disposal facilities added approximately 340,000 barrels of water per day. Additional oil gathering as well as produced-water gathering and disposal expansions are planned for 2019.

DJ Basin In 2018, the sixth stabilizer train at the COSF was placed into service during the third quarter, increasing the facility’s nameplate capacity by 30 MBbls/d to 155 MBbls/d of total oil-stabilization 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 2018):
Area
Miles of
Pipelines

Total
Horsepower
(1)

2018 Average Net
Throughput (MMcf/d)

2018 Average Net
Throughput (MBbls/d)

DJ basin
1,070

23,300

220

120

Delaware basin
1,140

76,900

150

285

Greater Natural Buttes
1,130

146,800

280


Other
300



15

Total
3,640

247,000

650

420

(1) 
Excludes horsepower associated with transportation assets.

APC 2018 FORM 10-K | 29


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BUSINESS & PROPERTIES
COMPETITION AND EMPLOYEES


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.

EMPLOYEES

The Company had approximately 4,700 employees at December 31, 2018.


30 | APC 2018 FORM 10-K

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BUSINESS & PROPERTIES
REGULATORY AND ENVIRONMENTAL MATTERS


REGULATORY AND ENVIRONMENTAL MATTERS

Environmental and Occupational Health and Safety Regulations

Anadarko’s business operations are subject to numerous environmental and occupational health and safety laws and regulations that may be imposed internationally, domestically at the federal, regional, state, tribal and local levels, or by foreign governments. The more significant of these environmental and occupational health and safety laws and regulations include the following legal standards that currently exist in the United States, as amended from time to time:
the U.S. Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, operational, monitoring, and reporting requirements, and that the EPA has relied upon as authority for adopting climate change regulatory initiatives relating to 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 (which includes Bureau of Land Management (BLM), Bureau of Indian Affairs (BIA), Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE) regulations), which govern operations on federal lands and 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 U.S. 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 (SDWA), 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 U.S. 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 U.S. 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
U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency response preparedness

APC 2018 FORM 10-K | 31


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BUSINESS & PROPERTIES
REGULATORY AND ENVIRONMENTAL MATTERS


Additionally, there exist regional, state, tribal and local jurisdictions in the United States where the Company operates that also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. Outside of the United States, there are foreign countries and provincial, regional, tribal or local jurisdictions therein where the Company is conducting business that also have, or may be developing, regulatory initiatives or analogous controls that regulate Anadarko’s environmental-related activities. While the legal requirements imposed in foreign countries or jurisdictions therein 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, delay or cancel the permitting, development, or expansion of a project or substantially increase the cost of doing business. Moreover, both in the United States and in foreign countries, 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 or to address perceived health or safety-related concerns such as oil and natural-gas development in close proximity to specific occupied structures and/or certain environmentally-sensitive or recreational areas, are expected to continue to have a considerable impact on the Company’s operations.
Anadarko has acquired certain oil and natural-gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances or wastes were not under Anadarko's control. Under environmental laws and regulations, Anadarko could incur liability for remediating hydrocarbons, hazardous substances or wastes disposed of or released by prior owners or operators. Anadarko also could incur costs related to the clean-up of third-party sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.
Furthermore, regulatory bodies at the federal, regional, state, tribal and local levels in the United States as well as internationally, and certain non-governmental organizations have been increasingly focused on GHG emissions and climate change issues. In addition to the EPA's rule applicable to onshore and offshore sources of oil and natural-gas production and requiring annual reporting of GHG emissions, the EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the U.S Clean Air Act. In 2016, the EPA published a final rule requiring operators to reduce methane emissions and emissions of volatile organic compounds from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. The EPA is reconsidering this rule and has proposed to stay its requirements but this proposed rule has not been finalized and, thus, the 2016 final rule remains in effect, subject to amendments issued by the agency in March 2018. Developments in GHG initiatives may affect us and other similarly situated companies operating in the oil and natural-gas industry.
These environmental and occupational health and safety laws and regulations 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 or cancellations 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, there exist environmental laws that 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 regulatory initiatives relating to environmental protection.
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. 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. 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.

32 | APC 2018 FORM 10-K

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BUSINESS & PROPERTIES
REGULATORY AND ENVIRONMENTAL MATTERS


Oil Spill-Response Plan

Domestically, the Company is subject to compliance with the federal 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 with respect 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.
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). 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 is also a member of the Marine Well Containment Company (MWCC) which provides access to subsea intervention, containment, capture, and shut-in capacity for deepwater exploration wells. 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 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.

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.


APC 2018 FORM 10-K | 33


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BUSINESS & PROPERTIES
EXECUTIVE OFFICERS OF THE REGISTRANT


EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Age at
January 31, 2019
Position
R. A. Walker
61
Chairman and Chief Executive Officer
Robert G. Gwin
55
President
Benjamin M. Fink
48
Executive Vice President, Finance and Chief Financial Officer
Daniel E. Brown
43
Executive Vice President, U.S. Onshore Operations
Mitchell W. Ingram
56
Executive Vice President, International, Deepwater and Exploration
Amanda M. McMillian
45
Executive Vice President and General Counsel
Christopher O. Champion
49
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. He also served as President from February 2010 until November 2018. 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 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 President in November 2018. Prior to this position, he served as Executive Vice President, Finance and Chief Financial Officer since May 2013; Senior Vice President, Finance and Chief Financial Officer since March 2009; and Senior Vice President since March 2008. He served as Chairman of the Board of WGH from October 2009 until November 2018 and has served as a director since August 2007. Additionally, Mr. Gwin served as Chairman of the Board of WGEH from September 2012 until November 2018 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 served as Chairman of the Board of LyondellBasell Industries N.V. from August 2013 through September 2018 and as a director from May 2011 through November 2018.
Mr. Fink was named Executive Vice President, Finance and Chief Financial Officer in November 2018. Prior to that, Mr. Fink was named Senior Vice President in February 2017 and previously served as Vice President, Finance and Assistant Treasurer since May 2013, having joined Anadarko in 2007. Mr. Fink also served as President of WGH and WGEH from May 2017 to November 2018 and as Chief Executive Officer of WGH and WGEH from May 2017 to January 2019. In addition, he has served as a director of WGH since February 2017. He previously served as President, Chief Executive Officer, Chief Financial Officer and Treasurer of WGH and WGEH from February 2017 to May 2017, and as Senior Vice President and Chief Financial Officer of WGH from 2009 to February 2017 and of WGEH since its formation in September 2012 to February 2017.
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.

34 | APC 2018 FORM 10-K

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BUSINESS & PROPERTIES
EXECUTIVE OFFICERS OF THE REGISTRANT


Mr. Ingram was named Executive Vice President, International, Deepwater and Exploration in May 2018. Prior to this position, he served as Executive Vice President, International & Deepwater Operations and Project Management since 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. Ingram has served as a director of WGH and WGEH since November 2018.
Ms. McMillian was named Executive Vice President and General Counsel in August 2018. Prior to this position, she served as Senior Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer since September 2015; Vice President, Deputy General Counsel, Corporate Secretary and Chief Compliance Officer since May 2013; and Deputy General Counsel and Corporate Secretary since July 2012. Ms. McMillian joined Anadarko in December 2004 and has held positions of increasing responsibility with Anadarko, including Vice President, General Counsel and Corporate Secretary of WGH from January 2008 to August 2012. Prior to joining Anadarko, she practiced corporate and securities law at the law firm of Akin Gump Strauss Hauer & Feld LLP, where she represented a variety of clients in a wide range of transactional, corporate governance and securities matters.
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 14, 2019, and hold office until their successors are duly elected and qualified. There are no family relationships between any directors or executive officers of Anadarko.


APC 2018 FORM 10-K | 35



Item 1A.  Risk Factors

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 Cautionary Statement About Forward-Looking Statements on page 4 for additional information.

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 NGL 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


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The long-term effect of these and other factors on the prices of oil, natural gas, and NGLs is uncertain. Prolonged or substantial 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, ability to repurchase shares, reduce debt and pay dividends, 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 NGL 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 NGL 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 laws and regulations governing the release of pollutants or otherwise relating to environmental protection that may be imposed internationally, domestically at the federal, regional, state, tribal and local levels, or by foreign governments. These laws and regulations govern, among other things, the following activities and matters:
issuance of permits in connection with exploration, drilling, production, produced water disposal, and other upstream and midstream activities
drilling activities on certain lands lying within wilderness, wetlands, and other protected areas
types, quantities, and concentrations of emissions, discharges, and authorized releases
generation, management, and disposition of waste materials
offshore oil and natural-gas operations and decommissioning of abandoned facilities
reclamation and abandonment of wells and facility sites
remediation of contaminated sites
protection of endangered species
These laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations or any property we’ve acquired, 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 or cancellations 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 adversely impact our operations. Examples of recent proposed and final regulations or other regulatory initiatives include the following:
Ground-Level Ozone Standards. In October 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS 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

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gas and volatile organic compound emissions. These Subpart OOOOa standards 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. In February 2018, the EPA finalized amendments to certain requirements of the 2015 final rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to other requirements, such as fugitive emission monitoring frequency. Notwithstanding the current uncertainty with these rules establishing emission standards for methane and VOCs and BLM’s 2016 final rule to reduce methane emissions from venting, flaring, and leaking from oil and natural-gas operations on public lands, 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.
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 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. Texas has also issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions and reporting requirements on 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 regulations 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 U.S. 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 a large volume 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. Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Climate Agreement, an international climate change agreement in Paris, France, that calls for countries to set their own GHG emissions targets and be transparent about the measures that each country will use to achieve its GHG emissions targets. The Paris Climate Agreement entered into force in November 2016. However, 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 18—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, delays or curtailments, 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 onshore in the U.S. is typically regulated by state oil and natural-gas commissions and similar agencies. However, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation, including by federal agencies. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the SDWA involving the use of diesel fuels and published permitting guidance in 2014 addressing the use of diesel in fracturing operations. Additionally, in 2016, the EPA published a final rule under authority of the Clean Water Act 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 2015 establishing new or more stringent standards for performing hydraulic fracturing on federal and Indian land but the BLM rescinded the 2015 rule in December 2017; however, litigation filed in January 2018 in the federal District Court for the Northern District of California challenging the BLM’s decision to repeal 2015 rule remains pending. 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 certain circumstances.
Certain states in which we operate, including Colorado, Texas, and Wyoming, have adopted, and other states and local communities 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 February 2018, the Colorado Oil & Gas Conservation Commission (COGCC) approved new regulations addressing the operation of flowlines and related infrastructure associated with oil and natural-gas development in the state, including more stringent requirements relating to design, installation, maintenance, testing, tracking, and abandoning of flowlines. The COGCC also approved new regulations in December 2018 enhancing the state’s school setback rules by expanding the definition of a school facility and broadening the boundaries. 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 the time, place and manner of drilling in general and/or hydraulic fracturing in particular.
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 revise either statutory law or the state constitution in a manner that would effectively prohibit or make such exploration and production activities in the state more difficult or expensive in the future. For example, in each of the November 2014, 2016 and 2018 general election cycles, ballot initiatives have been pursued, with the 2018 initiative making the November 2018 ballot, seeking to increase setback distances between new oil and natural-gas development and specific occupied structures and/or certain environmentally sensitive or recreational areas that, if adopted, may have had significant adverse impacts on new oil and natural-gas development in the state. However, in each election cycle, the ballot initiative either did not secure a place on the general ballot or, as was the case in November 2018, was defeated. 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, whether in Colorado or in another state, 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.


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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 consolidated 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 in September 2018 issued a statutory notice of deficiency rejecting the Company’s refund claim. We disagree and filed a petition with the U.S. Tax Court to dispute the disallowance in November 2018. It is possible that we may not ultimately succeed in defending this deduction. 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 14—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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

At December 31, 2018, our total consolidated debt of $16.4 billion consisted of $11.6 billion related to Anadarko and $4.8 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 agreement governing the APC RCF contains 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.


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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 NGL 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 NGL 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 NGL 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.

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

As of December 31, 2018, our long-term debt was rated “BBB” by S&P and Fitch with a stable outlook by S&P and a positive outlook by Fitch. Our long-term debt was rated “Ba1” with a stable outlook by Moody’s, which is below investment grade. Subsequent to year end, Moody’s changed its outlook with respect to its rating from stable to positive. Our commercial paper program was rated “A-2” by S&P, “F2” by Fitch, and “NP” by Moody’s. Although we are not aware of any current plans of S&P, Fitch, or Moody’s to lower their respective credit ratings on our long-term debt, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital and could also adversely affect our ability to effectively execute aspects of our strategy or to raise debt in the public debt markets. In addition, a downgrade could affect the Company’s requirements to provide financial assurance of its performance under certain contractual arrangements and derivative agreements. For additional information, see Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


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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. In addition, government disruptions, such as an extended federal government shutdown resulting from the failure to pass budget appropriations or adopt continuing funding resolutions could delay or halt the granting and renewal of such permits, approvals, and certificates required to conduct our operations. As a result, activity in the affected regions, such as the Gulf of Mexico and on federal and Indian lands in the United States, could be adversely affected or delayed.

Our domestic midstream operations are subject to governmental risks by federal or state regulators that may impact our operations and revenues.

The Federal Energy Regulatory Commission (FERC) has authority to regulate the rates and terms and conditions of service of natural gas, oil, NGL, and other liquids pipelines operating in interstate commerce. The FERC could exercise jurisdiction over our midstream operations to the extent it determines they operate in interstate commerce. Should we fail to comply with laws the FERC administers, we could be subject to substantial monetary penalties. State regulators in the areas where we have midstream operations may likewise have authority to regulate the rates and terms and conditions of service of, and impose monetary penalties on, our natural gas, oil, NGL, and other liquids pipelines operating in intrastate commerce. To the extent a federal or state regulator imposes rate or service limitations on our midstream operations, it may adversely affect our operations and revenues, either directly or through WES’s operations.

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

Historically, concerns about global economic growth, including issues related to tariffs and geopolitical issues, 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.

Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third parties with whom we do business.

The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. A default by any of our counterparties may result in our inability to perform obligations under agreements we have made with third parties or may otherwise adversely affect our business or results of operations. For certain assets where we rely on third-party customers for substantially all of our revenues related to those assets, the loss of all or even a portion of the contracted production volume could result in reduced throughput on those systems causing a decline in revenues and the potential impairment of the impacted assets. Furthermore, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances.


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

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

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 offshore-related developments may have a material adverse effect on our business, financial condition, or results of operations.

The BOEM and the BSEE have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. 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.
Additionally, these governmental agencies are continuing to evaluate and develop and implement new, more restrictive requirements 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 BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and maintenance of blowout preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements. In May 2018, however, the BSEE issued a proposed rule, which has not been finalized, to revise these regulations for well control.
Moreover, in September 2016, the BOEM issued a Notice to Leaseholders (NTL) 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 NTL, the agency has delayed indefinitely, beyond June 30, 2017, the implementation timeline of the NTL for most of those facilities so that BOEM could further assess this financial assurance program, but this delay is expected to be temporary. Following completion of its review, the BOEM may elect to retain the September 2016 NTL in its current form or may make revisions thereto and, thus, until the review is completed and the BOEM determines what additional financial assurance may be required by us, we cannot provide any assurance of the amount of any additional financial assurance, which may be material, that may be ordered by the BOEM and required in any proposed tailored plan that we may submit to the BOEM in the future for approval, or that such additional financial assurance amounts can be obtained.


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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 or any subsequent 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, or a subsequent assignee, 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 natural-gas exploration and development. We cannot predict with any certainty the full impact of any new laws, regulations, or legal initiatives on our drilling operations or on the cost or availability of insurance to cover the risks associated with such operations. The overall costs to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete.
Further, the deepwater Gulf of Mexico (as well as international deepwater locations) lacks the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, despite our oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to potential material deepwater events in the future.
The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.


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

We have operations outside the United States, including in Algeria, Ghana, Mozambique, Colombia, Peru, 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
difficulties enforcing our rights against a governmental agency in the absence of an appropriate and adequate dispute resolution mechanism to address contractual disputes, such as international arbitration
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 or delays in project completions. 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 could be materially impaired.
Our international operations may also be adversely affected, directly or indirectly, by laws, policies, and regulations of the United States affecting foreign trade and taxation, including U.S. trade sanctions.
Realization of any of the factors listed above could materially and adversely affect our financial condition, results of operations, or cash flows.

The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, or qualified personnel. The cost for such items may increase as a result of a variety of factors beyond our control, such as increases in the cost of electricity, steel, and other raw materials that we and our vendors rely upon; increased demand for labor, services, and materials as drilling activity increases; and increased taxes. 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.


APC 2018 FORM 10-K | 45



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.

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 volume
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 NGL 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.

46 | APC 2018 FORM 10-K


Material differences between the estimated and actual timing of critical events may affect the completion, cost and commencement of production from development projects.

We are involved in certain 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. If we are unable to complete such projects at their expected costs and in a timely manner, our financial condition, results of operations, or cash flows could be materially and adversely effected.

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.

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.


APC 2018 FORM 10-K | 47



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, adversely affect the timing of activities, or lead to unexpected future costs, including costs associated with 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.

Our ability to sell and deliver our oil, natural-gas, and NGL 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.

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, 2018. 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.


48 | APC 2018 FORM 10-K


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

Any 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

In addition, from time to time, we may sell or otherwise dispose of certain of our properties as a result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks, including:
possible delays in closing
lower-than-expected sales proceeds for the disposed assets
potential post-closing claims for indemnification

Moreover, the agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations, such as matters of litigation, environmental contingencies, royalty obligations and income taxes, have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts and similar arrangements. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. In addition, one or more of the parties in these transactions could fail to perform its obligations under the agreements as a result of financial distress. In the event that any such counterparty were to become the subject of a case proceeding under Title 11 of the U.S. Bankruptcy Code or any other insolvency law or similar law, the counterparty may not perform its obligations under the agreement and we may be responsible for the cost of the obligations assumed by the counterparties. As a result, after a divestiture, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

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


APC 2018 FORM 10-K | 49



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. In addition, our business has become increasingly dependent on digital technologies and we anticipate expanding our use of technology in our operations, including through data analytics and process automation. Further, we have exposure to cyber incidents and the negative impacts of such incidents related to our critical data and proprietary information housed on third-party information technology systems, including the cloud. Our vendors and other business partners may also separately suffer disruptions or breaches from cyber attacks which could adversely impact our operations and compromise our information. 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. We could incur substantial remediation and other costs or suffer other negative consequences, including litigation risks. 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.

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 2019, our quarterly dividend was $0.30 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 development and operating activities depends, 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.


50 | APC 2018 FORM 10-K


Item 1B.  Unresolved Staff Comments

None.

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 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.
In September 2018, Anadarko E&P Onshore LLC, a subsidiary of the Company, entered into a final consent assessment with the Pennsylvania Department of Environmental Protection resolving issues concerning enforcement over a produced water release in Pennsylvania in 2015 and agreed to pay a penalty of $350,000.
Kerr-McGee Oil and Gas Onshore, LP, a 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 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 in Colorado. 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 18—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.


APC 2018 FORM 10-K | 51



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, 2019, there were approximately 9,074 holders of record of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange under the symbol “APC”.
The amount of future dividends paid to Anadarko common stockholders is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board. In November 2018, the Company announced an increase in the quarterly dividend to $0.30 from $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.

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, 2018:
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
6,356,970

 
$
67.00

20,246,444

Equity compensation plans not approved by security holders

 


Total
6,356,970

 
$
67.00

20,246,444



52 | APC 2018 FORM 10-K


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 2018:
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)(3)
 
October 1-31, 2018
35,626

 
$
64.55


 
$
500,000,003

November 1-30, 2018
56,912

 
$
55.73


 
$
1,500,000,003

December 1-31, 2018
4,792,707

 
$
52.35

4,776,318

 
$
1,250,000,064

Total
4,885,245

 
$
52.48

4,776,318

 


(1) 
During the fourth quarter of 2018, 109 thousand shares were repurchased 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 23—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(2) 
During the fourth quarter of 2018, under the Share Repurchase Program, the Company repurchased 4.8 million shares of common stock in the open market for $250 million. For additional information, see Note 21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(3) 
The Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018 and $4.0 billion in July 2018. In November 2018, the program was further expanded to $5.0 billion and extended through June 30, 2020. For additional information, see Note 21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


APC 2018 FORM 10-K | 53



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
peergraph02.jpg
 
Copyright© 2019 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, 2013, and its relative performance is tracked through December 31, 2018

Fiscal Year Ended December 31
2013

 
2014

 
2015

 
2016

 
2017

 
2018

Anadarko Petroleum Corporation
$
100.00

 
$
105.14

 
$
62.88

 
$
90.58

 
$
69.96

 
$
58.19

S&P 500
100.00

 
113.69

 
115.26

 
129.05

 
157.22

 
150.33

Peer Group
100.00

 
92.09

 
69.98

 
91.31

 
94.42

 
82.93




54 | APC 2018 FORM 10-K


Item 6.  Selected Financial Data
 
Summary Financial Information (1)
millions except per-share and employee amounts
2018

 
2017

 
2016

 
2015

 
2014

Sales Revenues (6)
$
13,070

 
$
10,969

 
$
8,447

 
$
9,486

 
$
16,375

Gains (Losses) on Divestitures and Other, net
312

 
939

 
(578
)
 
(788
)
 
2,095

Total Revenues and Other
13,382

 
11,908

 
7,869

 
8,698

 
18,470

Operating Income (Loss)
2,619

 
(565
)
 
(2,372
)
 
(8,743
)
 
5,438

Net Income (Loss) (2)
752

 
(211
)
 
(2,808
)
 
(6,812
)
 
(1,563
)
Net Income (Loss) Attributable to Common Stockholders
615

 
(456
)
 
(3,071
)
 
(6,692
)
 
(1,750
)
Per Common Share (amounts attributable to common stockholders)
 
 
 
 
 
 
 
 
 
Net Income (Loss)—Basic
$
1.20

 
$
(0.85
)
 
$
(5.90
)
 
$
(13.18
)
 
$
(3.47
)
Net Income (Loss)—Diluted
$
1.20

 
$
(0.85
)
 
$