~~TABLE OF CONTENTS~~



		Table of Contents Index to Financial Statements



TABLE OF CONTENTS		Page
PART I

Items 1 and 2.	Business and Properties	46
	General	46
	Exploration and Production Properties and Activities	67
	United States	79
	International	1215
	Proved Reserves	1418
	Sales ~~Volumes,~~Volume, Prices, and Production Costs	1923
	Delivery Commitments	2024
	Properties and Leases	2024
	Drilling Program	2025
	Drilling Statistics	2125
	Productive Wells	2226
	Midstream Properties and Activities	2327
	WES Midstream	2328
	Other Midstream	2529
	Competition	25
	~~Segment Information~~	2530
	Employees	2530
	Regulatory and Environmental Matters	2631
	Title to Properties	2933
	Executive Officers of the Registrant	2934
Item 1A.	Risk Factors	3136
Item 1B.	Unresolved Staff Comments	4851
Item 3.	Legal Proceedings	4951
Item 4.	Mine Safety Disclosures	4951

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	5052
Item 6.	Selected Financial Data	5355
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5456
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	8486
Item 8.	Financial Statements and Supplementary Data	8587
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	170
Item 9A.	Controls and Procedures	170
Item 9B.	Other Information	170

PART III

Item 10.	Directors, Executive Officers, and Corporate Governance	171
Item 11.	Executive Compensation	171
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	171
Item 13.	Certain Relationships and Related Transactions, and Director Independence	171
Item 14.	Principal Accounting Fees and Services	171

PART IV

Item 15.	Exhibits, Financial Statement Schedules	172
Item 16.	Form 10-K Summary	177



		Table of Contents Index to Financial Statements

COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, the terms ~~“Anadarko”~~“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:

~~$3.0 Billion Share-Repurchase Program~~ - A program approved by the Anadarko Board of Directors, in September 2017, authorizing the repurchase of $2.5 billion of Anadarko’s common stock, which was expanded to $3.0 billion in February 2018. The program extends through the end of 2018.

364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured RCF

3D - Three-dimensional

~~$5.0 Billion Facility~~ ~~- Anadarko’s $5.0 billion senior secured RCF, which was replaced in January 2015 with the APC RCF and a 364-day facility~~

APC RCF - Anadarko’s $3.0 billion senior unsecured RCF

AROs - Asset retirement obligations

ASR Agreement - An accelerated share-repurchase agreement with an investment bank to repurchase the Company’s common stock

ASU - Accounting Standards Update

Bbl - Barrel

Bcf - Billion cubic feet

BOE - Barrels of oil equivalent

CBM - Coalbed methane

COSF - Centralized oil stabilization facility

DBJV - Delaware Basin JV Gathering LLC

DBJV System - A gathering system and related facilities located in the Delaware basin in Loving, Ward, Winkler, and Reeves Counties in West Texas, 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

~~Table of Contents~~

~~Index to Financial Statements~~

Mcf - Thousand cubic feet

MMBbls - Million barrels

2 | APC 2018 FORM 10-K



		Table of Contents Index to Financial Statements

MMBOE - Million barrels of oil equivalent

MMBtu - Million British thermal units

MMBtu/d - Million British thermal units per day

MMcf/d - Million cubic feet per day

Moody’s - Moody’s Investors Service

MTPA - Million tonnes per annum

~~NGLs~~ ~~- Natural gas liquids~~

NMN/A - Not ~~meaningful~~applicable

~~NTSB~~NGL or NGLs - ~~National Transportation Safety Board~~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

~~S&P~~Share-Repurchase Program- ~~Standard and Poor’s~~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 ~~$1.2~~$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 ~~$250~~$35 million ~~three-year~~ senior secured RCF

Zero Coupons - Anadarko’s Zero-Coupon Senior Notes due 2036

APC 2018 FORM 10-K | 3



		Table of Contents Index to Financial Statements

~~PART I~~

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



		Table of Contents Index to Financial Statements


–	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



	BUSINESS AND PROPERTIES ~~Items 1 and 2. Business and Properties~~ GENERAL Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with approximately 1.4 billion BOE of proved reserves at December 31, 2017. Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko’s asset portfolio is positioned to deliver long-term value to stakeholders by combining a large inventory of development opportunities in the U.S. onshore and the Gulf of Mexico with high-potential worldwide exploration and development activities. Anadarko’s portfolio includes assets in the Delaware and DJ basins in the U.S. onshore. The Company is also among the largest independent producers in the deepwater Gulf of Mexico and has exploration and production activities internationally, including activities in Algeria, Ghana, Mozambique, and other countries. Anadarko’s strategy is to explore for, develop and commercialize resources globally; ensure health, safety, and environmental excellence; and focus on financial discipline, flexibility, and value creation, while demonstrating the Company’s core values of integrity and trust, servant leadership, people and passion, commercial focus, and open communication in all business activities. Anadarko previously presented three reportable segments in its quarterly and annual filings: Oil and Gas Exploration and Production, Midstream, and Marketing. In the first half of 2017, Anadarko substantially completed a repositioning of its asset portfolio to focus on higher-margin liquids production. This shift resulted in a substantial decrease in the number of U.S. operating areas. Since the portfolio repositioning, the chief operating decision maker has reviewed operating results for Exploration and Production and Midstream when making operating and capital allocation decisions. Accordingly, Anadarko no longer identifies marketing activities as a separate reportable segment. Also, in prior periods, the Company aggregated its two midstream operating segments, WES Midstream and Other Midstream, into one Midstream reporting segment due to similar financial and operating characteristics. While the aggregation criteria continues to be met, the Company will no longer aggregate these operating segments in order to provide additional information about its midstream operations. Accordingly, Anadarko now has three reporting segments: Exploration and Production, WES Midstream, and Other Midstream, which include their respective marketing results. ~~Exploration and Production—This segment is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing its Mozambique LNG project toward FID.~~ ~~WES Midstream and Other Midstream~~—These two segments engage in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production as well as gathering and disposal of produced water. The WES Midstream segment consists of Western Gas Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko. The Other Midstream segment consists of the Company’s other midstream assets. This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates, and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See ~~Risk Factors~~ ~~under Item 1A of this Form 10-K.~~ 4	Table of Contents Index to Financial Statements

PART I

Items 1 and 2. Business and Properties

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with approximately 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 The Company’s corporate headquarters is located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046, and its telephone number is (832) 636-1000. The Company files or furnishes Annual Reports on Form 10-K; Quarterly Reports on Form 10-Q; Current Reports on Form 8-K; registration statements, or any amendments thereto; and other reports and filings with the SEC. Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its website located at investors.anadarko.com/sec-filings. The Company will also make available to any stockholder, without charge, printed copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this Form 10-K, or any other filing, please contact Anadarko Petroleum Corporation, Investor Relations, P.O. Box 1330, Houston, Texas 77251-1330; call (855) 820-6605; send an email to investor@anadarko.com; or complete an information request on the Company’s website at www.anadarko.com by selecting Investors/Shareholder Resources/Shareholder Services.

The public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Anadarko, that file electronically with the SEC.



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

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



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ~~ACTIVITIES~~ACTIVITES The Company’s Exploration and Production segment actively manages Anadarko’s worldwide oil, natural-gas, and NGLs sales of its equity production, as well as the Company’s anticipated LNG sales. In marketing its production, the Company attempts to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. The Company’s sales of oil, natural gas, and NGLs are generally made at market prices at the time of sale. The Company sells its products under a variety of contract structures, including indexed, fixed-price, and cost-escalation-based agreements. The Company also engages in limited trading activities for the purpose of generating profits from exposure to changes in market prices of oil, natural gas, and NGLs. The Company does not engage in market-making practices and limits its marketing activities to oil, natural-gas, NGLs, and LNG commodity contracts. The Company’s marketing-risk position is typically a net short position (reflecting agreements to sell oil, natural gas, and NGLs in the future for specific prices) that is offset by the Company’s natural long position as a producer (reflecting ownership of underlying oil and natural-gas reserves). See ~~Commodity-Price Risk~~ ~~under Item 7A of this Form 10-K.~~ ~~Oil and NGLs~~ Anadarko’s oil and NGLs revenues are derived from production in the United States, Algeria, and Ghana. Most of the Company’s U.S. oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality, and transportation. Product from Algeria is sold by tanker as Saharan Blend, Algerian condensate, refrigerated propane, and refrigerated butane to customers primarily in the Mediterranean and Western European area. Oil from Ghana is sold by tanker as Jubilee crude oil and TEN Blend crude oil to customers around the world. Saharan Blend, Jubilee, and TEN Blend are high-quality crudes that provide refiners with large quantities of premium products such as gasoline, diesel, and jet fuel. ~~Natural Gas~~ Anadarko markets its U.S. natural-gas production to maximize value and to reduce the inherent risks of physical commodity markets. The Company controls natural-gas firm-transportation capacity that ensures access to downstream markets, which enables the Company to maximize its natural-gas production. This transportation capacity also provides the opportunity to capture incremental value when price differentials between physical locations exist. From time to time, the Company stores natural gas in contracted storage facilities to minimize operational disruptions to its ongoing operations and to take advantage of seasonal price differentials. Normally, the Company will have forward contracts in place (physical delivery or financial derivative instruments) to sell stored natural gas at a fixed price. 6	Table of Contents Index to Financial Statements

~~United States~~

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

~~U.S. Onshore~~Anadarko’s U.S. onshore properties include significant oil and natural-gas plays located in Colorado, Texas, Utah, and Wyoming, where the Company operates approximately 9,250 wells and owns interests in approximately 2,500 nonoperated wells.

~~The map below illustrates the locations of Anadarko’s U.S. onshore oil and natural-gas exploration and production operations:~~

Activities in the U.S. onshore during 2017 primarily focused on adding reserves through horizontal drilling, optimizing wellbore and completion design, improving cost structure, and delivering efficient production. The Company also focused on capturing operatorship within its premier position in the Delaware basin. Process improvements and optimization projects assisted in providing both well performance and cycle-time improvements across all assets. The Company drilled 541 wells and completed 396 wells in the U.S. onshore during 2017. The Company also divested non-core U.S. onshore assets, primarily in South Texas, Southeast Texas, Pennsylvania, Wyoming, and Utah. In 2018, the Company expects to continue its horizontal drilling program, focusing on the Delaware and DJ basins.



ANADARKO’S EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITIES

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



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

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

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

U.S. OnshoreAnadarko’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

APC 2018 FORM 10-K | 9



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

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.



	Delaware BasinAnadarko ~~holds~~operates approximately 750 wells and owns interests in approximately ~~590,000 gross (240,000 net) acres~~450 nonoperated wells in the Delaware ~~basin in West Texas. Anadarko’s 2017~~basin. The Company’s 2018 drilling activity primarily targeted the Wolfcamp shale play, while also testing the liquids-rich Bone Spring tight ~~sands~~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 ~~Avalon shale play.~~integrated infrastructure positions in the region, primarily in Reeves and Loving counties. In ~~2017, Anadarko drilled 192 operated wells and participated in 93 nonoperated wells. The~~2018, the Company ~~was~~ focused on ~~increasing operatorship through the drilling program for the majority of~~securing sufficient oil takeaway capacity, ending the year ~~averaging 14~~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 ~~through the third quarter of 2017~~ and ending 2017 with 10 operated drilling rigs. Prior to the conclusion of a participation agreement in July 2017, Anadarko completed all of the well proposals required to secure operatorship on approximately 70% of its joint venture acreage. Additionally, joint-operating agreements have been established in all areas where operatorship has been defined. The wells associated with operatorship capture are scheduled to be completed and turned to sales throughout 2018. During 2018, the Company plans to average seven operated rigs and sixfive completion ~~crews and grow year-over-year sales volumes by more than 50%.~~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. TheThe Company ~~has identified approximately 5,500 potential mid-lateral-equivalent drilling locations in~~expects the Wolfcamp ~~A formation that are expected~~shale play to provide substantial opportunity for Anadarko’s future activity in the basin. The ~~Company plans~~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 ~~continue to add~~the area. See Midstream Properties and Activities for additional discussion on the significant infrastructure added during 2018 to facilitate ~~future~~ growth from this ~~asset as discussed inMidstream Properties and Activities~~.asset.

10 | APC 2018 FORM 10-K



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements



	DJ BasinAnadarko ~~holds interests in over 400,000 net acres in its core position and~~ operates ~~over 4,600~~approximately 3,400 vertical wells and ~~1,400~~1,700 horizontal wells in ~~the DJ basin in Colorado. The field contains~~ the Niobrara and Codell formations ~~which are naturally fractured formations that hold both liquids and natural gas. During 2017,~~in the ~~Company’s drilling program focused entirely on horizontal development, drilling 348 horizontal wells.~~DJ basin. Horizontal drilling results in the field continue to be strong, with enhanced economics ~~that are enhanced by~~realized through the Company’s ownership of the Land Grant and ~~recent~~ operational efficiencies in drilling and completions. Anadarko continues to drive drilling efficiencies in its DJ basin operations. In ~~2017,~~2018, the Company ~~implemented a new~~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 ~~design, which has resulted~~crews. The sixth COSF train was placed in ~~a 20% improvement in average well recovery. In~~service during the third quarter of ~~2017, the Company sanctioned~~2018, adding 30 MBbls/d of oil-stabilization capacity. Construction activities have commenced at the Latham plant, which ~~is expected to provide an additional~~will deliver 400 MMcf/d of increased natural-gas processing capacity. See Midstream Properties and Activities for additional discussion.



	Powder River Basin In the southern Powder River basin, Anadarko’s acreage is mainly located in ~~cryogenic processing.~~ ~~Drilling spud-to-rig-release cycle time average for~~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 mid-lateral equivalent well improved from 5.7 days in 2016 to 5.1 days in 2017. The full-year 2017 average drilling cost per foot was reduced by approximately 19% and completion capital was reduced by 11% relative to 2016. Operated well capital costs in 2017 decreased to less than $2.9 million from approximately $3.5 million in 2016 for a mid-lateral-equivalent well, driven by continued operational efficiencies and supply-chain savings. The Company had six operated drilling rigs300,000 gross-acre position in the ~~first quarter of 2017 and ended 2017~~southern Powder River basin area, with six operated drilling rigs. Anadarko expects to increase year-over-year oil sales volumes from the DJ Basin by more than 30% and plans to average five operated rigs and three completion crews in the basin during 2018.significant stacked-oil potential.

APC 2018 FORM 10-K | 11



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements



	Greater Natural Buttes The Greater Natural Buttes area in eastern Utah is a tight-gas asset. The Company uses cryogenic and refrigeration processing facilities in this area to extract NGLs from the natural-gas stream. ~~The Company operated the~~There was minimal activity in this field ~~at a reduced activity level for the majority of 2017~~during 2018 due to capital being allocated to higher-margin projects. ~~Focus in the field shifted to increasing operating margins through the reduction of expenses and optimization of base production. The Company operates approximately 2,850 wells in the area.~~ 8

12 | APC 2018 FORM 10-K



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Gulf of MexicoAnadarko 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.Anadarko owns a working interest in 319 blocks in the Gulf of Mexico, operates 10 active floating platforms, and holds interests in 37 fields. The Company continued an active deepwater development and appraisal program in the Gulf of Mexico during 2017 as it continues to take advantage of existing infrastructure to cost-effectively develop known resources.

~~The map below illustrates the locations of Anadarko’s Gulf of Mexico oil and natural-gas exploration and production operations:~~



GULF OF MEXICO OIL AND NATURAL-GAS EXPLORATION AND PRODUCTION OPERATIONS

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.

APC 2018 FORM 10-K | 13



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

~~Development~~

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

~~Marlin~~ At

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

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.

~~Lucius~~

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

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.

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

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

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

~~K2 Complex~~ ~~At the~~

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

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.

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

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

~~Table of Contents~~

~~Index to Financial Statements~~

Exploration and Appraisal

~~Warrior~~ The ~~Warrior exploration well (70%~~Company continues to create value through successful working ~~interest) encountered more than 210 net feet~~interest farmdowns of ~~oil pay in multiple high-quality Miocene-aged reservoirs.~~existing acreage, while also increasing its position through lease sale participation for additional acreage. The first Warrior appraisal well and subsequent side track completed drilling in the northern portion of the field in the third quarter of 2017. The well encountered approximately 109 net feet of dispersed oil pay. Despite finding oil, this northern appraisal well found insufficient quantities of oil pay to justify the development of the northern portion of the field in the current price environment. Evaluation of tie-back opportunities in the southern portion of the field is ongoing.

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

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

~~Phobos~~ ~~The first Phobos appraisal well (100% working interest),~~Sugar exploration wells were drilled in the first quarter of ~~2017, encountered approximately 130 net feet of oil pay from the primary objective Wilcox-aged reservoirs~~2018 and more than 90 net feet of oil pay in the secondary objective Pliocene-aged reservoir. The second appraisal well, drilled in the third quarter of 2017, encountered approximately 136 net feet of oil pay from the primary objective Wilcox-aged reservoirs. These wells found insufficient quantities of oil pay to justify development in the current price environment.

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

were unsuccessful.

1114 | APC 2018 FORM 10-K



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

International

~~Overview~~Anadarko’s international operations include oil, natural-gas, and ~~NGLs~~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, ~~Mozambique,~~Peru, South Africa, and other countries. ~~International locations accounted for 14% of Anadarko’s sales volumes and 20% of sales revenues during 2017 and 12% of proved reserves at year-end 2017.~~ In ~~2018,~~2019, the Company expects to focus its international drilling activity in Ghana and ~~continue preparing the site of~~position itself to make a final investment decision on the future ~~onshore~~ LNG ~~park~~development in Mozambique.



2018 INTERNATIONAL OPERATIONS



	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.

APC 2018 FORM 10-K | 15

~~Algeria~~ Anadarko is engaged in production and development operations in Algeria’s Sahara Desert in Blocks 404 and 208, which are governed by a Production Sharing Agreement (PSA) between Anadarko, Sonatrach, and other partners. Under this PSA, the Company is responsible for 24.5% of the development and production costs. The Company produces oil through the Hassi Berkine South and Ourhoud central processing facilities (CPFs) in Block 404 and oil and NGLs through the El Merk CPF in Block 208. Gross production through these facilities averaged more than 337 MBbls/d in 2017, inclusive of approximately 34 days of planned downtime for statutory maintenance at the El Merk CPF. The Company drilled seven development wells in 2017. Late in 2017, Algeria and other members of OPEC agreed to extend the previously agreed upon reduction in production output through the end of 2018. Anadarko had minimal production impact from this reduction during 2017 and expects minimal impact in 2018.



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements



	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 ~~Anadarko’s production and development activities in Ghana are located offshore in the West Cape Three Points Block and the Deepwater Tano Block.~~| APC 2018 FORM 10-K

The Jubilee field (27% nonoperated participating interest), which spans both the West Cape Three Points Block and the Deepwater Tano Block, averaged gross production of 89 MBbls/d of oil in 2017. An average of 86 MMcf/d of natural gas was exported to an onshore natural-gas processing plant in satisfaction of a commitment established in conjunction with the Jubilee development plan. In October 2017, the partnership received Ghanaian government approval for the full-field plan of development, with drilling operations expected to commence in 2018.



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

In 2016, the operator of the Jubilee field announced that damage to the FPSO turret bearing had occurred. As a result, new production and offtake procedures were implemented, and the partners agreed to a long-term solution to convert the FPSO to a permanently spread-moored facility. Interim spread mooring of the FPSO commenced in the fourth quarter of 2016 and was completed during the first quarter of 2017. In early 2018, the operator will start the first of three shutdown periods that are expected to occur in 2018 to effectively stabilize the turret and rotate the FPSO to its permanent heading. In October, the partnership received Ghanaian Government approval for the full-field plan of development, with drilling operations expected to commence in 2018. Including the impact of the potential facility shutdown, the operator expects the average gross production from the Jubilee field to be more than 75 MBbls/d in 2018.

The TEN project (19% nonoperated participating interest), located in the Deepwater Tano Block, uses an 80 MBbls/d-capacity FPSO for production from subsea wells. After achieving first oil in the third quarter of 2016 and first liftings during the fourth quarter of 2016, the project averaged gross production of 56 MBbls/d of oil in 2017. The International Tribunal for the Law of the Sea issued a ruling in September 2017 regarding the delimitation of the maritime boundary between Ghana and Côte d’Ivoire in the Atlantic Ocean. The new maritime boundary, as determined by the tribunal, does not affect the TEN fields, and the operator now plans to resume development drilling in 2018.



	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.

~~Table of Contents~~

~~Index to Financial Statements~~

~~Mozambique~~APC Anadarko operates Offshore Area 1 (26.5% working interest), which totals approximately 1.2 million gross acres. With the delivery of the legal and contractual framework necessary for the development of LNG in Mozambique, the commencement of resettlement, and progress towards the delivery of project finance and long-term LNG sales contracts, the Company continues to advance the initial two-train Golfinho/Atum project toward FID.2018 FORM 10-K | 17

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

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

~~Colombia~~ ~~Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on six blocks totaling approximately 14 million gross acres.~~ In the Grand Fuerte area, the COL 5 and Purple Angel blocks are operated at a 50% working interest. In 2017, Anadarko withdrew from the Fuerte Norte and Fuerte Sur blocks. In the Grand COL area, the COL 1, COL 2, COL 6, and COL 7 blocks are operated at a 100% working interest.

In Grand Fuerte, the Purple Angel-1 exploration well concluded drilling in the first quarter of 2017. The well encountered approximately 70 to 110 net feet of gas pay and confirmed a gas column greater than 1,700 feet. The well successfully tested objectives establishing pressure connectivity to Anadarko’s 2015 play-opening Kronos discovery. The rig mobilized to the Gorgon prospect, also located in the Purple Angel Block, where it successfully tested an analogous structure along trend to the Kronos discovery. The Gorgon-1 well completed drilling in the second quarter and encountered approximately 260 to 350 net feet of gas pay. Whole cores were obtained at both wells to assess the potential deliverability of the primary reservoirs.

While evaluation of the Kronos and Gorgon discovery areas continue, all of the Company’s suspended exploratory well costs related to wells in the Grand Fuerte area were expensed in 2017 due to insufficient progress on contractual and fiscal reforms needed for deepwater gas development. See ~~Note 6—Suspended Exploratory Well Costs~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Item 8 of this Form 10-K.~~

In Grand COL, interpretations of the Esmeralda 3D seismic survey are ongoing. A sea floor sampling campaign was completed in the third quarter of 2017, which supports the potential presence of liquid hydrocarbons in Grand COL.

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

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



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Proved Reserves

Estimates of proved reserves ~~volumes~~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 ~~volumes are~~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 ~~volumes.~~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 ~~2017,~~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~~SUMMARY OF PROVED RESERVES


	Oil (MMBbls)	Natural Gas (Bcf)	NGLs (MMBbls)	Total (MMBOE)	Oil (MMBbls)	Natural Gas (Bcf)	NGLs (MMBbls)	Total (MMBOE)
December 31, 2017
Proved
December 31, 2018
Developed
United States	361	2,640	176	977	392	2,564	192	1,011
International	136	24	10	150	123	24	10	137
Undeveloped
United States	140	553	56	288	137	634	66	309
International	21	13	1	24	15	8	—	16
Total proved	658	3,230	243	1,439

December 31, 2016
Proved
Total proved reserves					667	3,230	268	1,473
December 31, 2017
Developed
United States	360	3,637	193	1,159	361	2,640	176	977
International	147	25	15	166	136	24	10	150
Undeveloped
United States	181	762	75	383	140	553	56	288
International	14	—	—	14	21	13	1	24
Total proved	702	4,424	283	1,722

December 31, 2015
Proved
Total proved reserves					658	3,230	243	1,439
December 31, 2016
Developed
United States	332	5,184	257	1,453	360	3,637	193	1,159
International	159	30	15	179	147	25	15	166
Undeveloped
United States	193	807	68	396	181	762	75	383
International	29	—	—	29	14	—	—	14
Total proved	713	6,021	340	2,057
Total proved reserves					702	4,424	283	1,722

The Company’s ~~proved reserves~~proved-reserves product mix ~~increased to~~was 63% liquids in 2018, 63% in 2017 ~~compared to~~and 57% in ~~2016 and 52% in 2015.~~2016. The Company’s year-end ~~2017~~2018 proved reserves product mix was ~~46%~~45% oil, 37% natural gas, and ~~17%~~18% NGLs. ~~This shift to liquids and the reduction in proved reserves was largely a result of divesting the Company’s lower-margin, non-core assets throughout the last three years.~~

1418 | APC 2018 FORM 10-K



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Changes to the Company’s proved reserves during ~~2017~~2018 are summarized in the table below:


MMBOE	2017		2016		2015		2018		2017		2016
Proved Reserves
January 1	1,722		2,057		2,858		1,439		1,722		2,057
Reserves additions and revisions
Discoveries and extensions	114		40		29		164		114		40
Infill-drilling additions ⁽¹⁾	71		69		89		181		71		69
Drilling-related reserves additions and revisions	185		109		118		345		185		109
Other non-price-related revisions ⁽¹⁾	59		191		289		(61	)	59		191
Net organic reserves additions	244		300		407		284		244		300
Acquisition of proved reserves in place	3		97		1		—		3		97
Price-related revisions ⁽¹⁾	92		(147	)	(624	)	29		92		(147	)
Total reserves additions and revisions	339		250		(216	)	313		339		250
Sales in place	(379	)	(294	)	(279	)	(37	)	(379	)	(294	)
Production	(243	)	(291	)	(306	)	(242	)	(243	)	(291	)
December 31	1,439		1,722		2,057		1,473		1,439		1,722
Proved Developed Reserves
January 1	1,325		1,632		1,969		1,127		1,325		1,632
December 31	1,127		1,325		1,632		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.

Proved reserves are estimated based on the average beginning-of-month prices during the 12-month period for the respective year. The average prices used to compute proved reserves at December 31, 2017 were $51.34 per Bbl for oil, $2.98 per MMBtu for natural gas, and $31.83 per Bbl for NGLs.

The Company’s estimates of proved developed reserves, PUDs, and total proved reserves at December 31, 2018, 2017,, ~~2016~~, and ~~2015~~,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, ~~2017~~.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.

15APC 2018 FORM 10-K | 19



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Changes in PUDs Changes to PUDs during ~~2017~~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, ~~2017~~2018	~~397~~312
Revisions of prior estimates	~~103~~117
Extensions, discoveries, and other additions	2247
Conversions to developed	(~~132~~144	)
~~Purchases~~	1
Sales in place	(797	)
PUDs at December 31, ~~2017~~2018	~~312~~325

Revisions of prior estimates Revisions of prior estimates reflect Anadarko’s ongoing evaluation of its asset portfolio. In ~~2017,~~2018, PUDs were revised upward by ~~103~~117 MMBOE.



MMBOE	December 31, ~~2017~~2018
Revisions due to changes in year-end prices (price impact to opening balance)	—
Other revisions of prior estimates
Revisions due to performance	3218
Revisions due to cost updates	—2
Revisions due to successful infill drilling	64158
Revisions due to development plan updates	7(61
~~Other revisions~~	—	)
Total other revisions of prior estimates	~~103~~117
Revisions of prior estimates	~~103~~117

Prior estimates were revised upward by a total of ~~103~~117 MMBOE and were associated with the following:

~~Performance~~

–

PerformanceThe 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.The Company experienced an overall increase in PUDs of 32 MMBOE due to performance. Upward revisions of 39 MMBOE were driven primarily by performance improvements in the DJ and Delaware basin areas. Downward revisions of 7 MMBOE were primarily due to performance based reductions in various areas in the Gulf of Mexico.

~~Infill-drilling activities~~ The Company added 64 MMBOE of PUDs associated with infill-drilling activities, of which 46 MMBOE was in the DJ basin, 13 MMBOE in the Lucius and Holstein areas in the Gulf of Mexico and the remaining in the Ghana Jubilee field.

~~Development plan updates~~ ~~The majority of revisions associated with updates to development plans occurred in the DJ basin due to ongoing optimization of development activity.~~


–	Infill-drilling activitiesThe 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 updatesThe 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 ~~During 2017, PUDs increased by 22 MMBOE primarily through the~~The extension of proved ~~acreage. Projects~~acreage in 2018 resulted in an increase in PUDs of 47 MMBOE, of which 24 MMBOE was in the ~~Delaware basin, Alaska,~~Hadrian North expansion area of the Gulf of Mexico and ~~Ghana contributed to~~23 MMBOE was in the ~~increase.~~Delaware basin.

Conversions to developed In ~~2017,~~2018, the Company converted ~~132~~144 MMBOE of PUDs to developed status, equating to ~~31%~~34% of total year-end ~~2016~~2017 PUDs when adjusted for revisions and sales. Approximately ~~81%~~79% of PUD conversions occurred in U.S. onshore assets, ~~including Alaska; 17%~~15% in Gulf of Mexico assets, and the remaining in international assets.

Anadarko spent ~~$1.0~~$1.1 billion to develop PUDs in ~~2017,~~2018, of which approximately ~~72%~~71% related to U.S. onshore assets, ~~including Alaska; 26%~~25% related to Gulf of Mexico ~~assets;~~assets, and the remaining related to international assets.

Sales in place In ~~2017,~~2018, PUDs decreased by 797 MMBOE due to the Company’s divestiture ~~activities in the Eagleford and Marcellus areas.~~activities.

1620 | APC 2018 FORM 10-K



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Development Plans The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Typically, U.S. onshore PUDs are converted to developed reserves within five years of the initial proved reserves booking, but projects associated with ~~arctic development,~~ deepwater development and international programs may take longer. At December 31, ~~2017,~~2018, the Company had no material ~~pre-2013~~pre-2014 PUDs that remained undeveloped. However, the Company did have 1915 MMBOE of PUDs scheduled to be developed more than five years from their initial date of booking. Approximately 12 MMBOE of these PUDs are associated with recompletion projects in the Gulf of Mexico, where project timing is dependent upon the current producing horizon achieving its economic limit. The remaining ~~7 MMBOE~~ are ~~primarily~~ associated with international drilling projects, which are being developed according to ~~government approved~~government-approved development plans. The Company did not have any U.S. onshore PUDs scheduled for development more than five years from initial booking.

Technologies Used in Proved Reserves Estimation The Company’s ~~2017~~proved reserves additions ~~were~~are based on estimates generated through the integration of relevant geological, engineering, and production data, ~~using~~and may include the use of reliable technologies that have been demonstrated in the field to yield ~~repeatable~~reasonably certain results with consistency and ~~consistent results~~repeatability in the formation being evaluated or in an analogous formation as defined in the SEC regulations. Data used in these integrated assessments ~~included~~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 ~~included~~include subsurface information obtained through indirect measurements such as seismic data. ~~The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software.~~ Reservoir parameters from analogous reservoirs ~~were~~may be used to increase the quality of and confidence in the reserves estimates when ~~available.~~available and necessary. The method or combination of methods used to estimate the reserves of each reservoir ~~was~~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 ~~VP—~~SVP—Corporate Planning. The ~~VP—~~SVP—Corporate Planning reports to the Company’s Executive Vice President, Finance and Chief Financial Officer, who in turn reports to the Chairman ~~President,~~ and Chief Executive Officer. The Governance and Risk Committee of the Company’s Board meets with management, members of the CRG, and the Company’s independent petroleum consultants, Miller and Lents, Ltd. (M&L), to discuss the results of procedures and methods reviews as discussed below as well as other matters and policies related to reserves.

The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserves estimates, has over 3132 years of experience in the oil and gas industry, including over 1718 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 3132 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.

17APC 2018 FORM 10-K | 21



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Third-Party Procedures and Methods Reviews M&L reviewed the procedures and methods used by Anadarko’s staff in preparing the Company’s estimates of proved reserves and future net cash flows at December 31, ~~2017~~.2018. The purpose of ~~the review~~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 ~~92%~~93% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, ~~2017~~.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.

1822 | APC 2018 FORM 10-K



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

~~Sales Volumes,~~

Sales Volume, Prices, and Production Costs

The following provides the Company’s annual sales ~~volumes,~~volume, average sales prices, and average production costs per BOE for each of the last three years:

Sales Volumes
Average Sales Prices ⁽¹⁾

Average
Production Costs ⁽²⁾
(Per BOE)

Oil
(MMBbls)

Natural Gas
(Bcf)

NGLs
(MMBbls)

Barrels of Oil
Equivalent
(MMBOE)

Oil
(Per Bbl)

Natural Gas
(Per Mcf)

NGLs
(Per Bbl)

2017

United States
DJ basin 31
212
21
88
49.73
2.55
27.46
10.23
Other United States 66
266
13
123
49.57
3.03
32.24
9.38
Total United States 97
478
34
211
49.62
2.82
29.24
9.73
International 32
—
2
34
53.77
—
35.64
7.01
Total 129
478
36
245
50.66
2.82
29.54
9.34
2016
United States
DJ basin 33
214
20
89
40.27
2.00
18.26
8.41
Other United States 52
552
24
168
38.29
2.06
20.21
6.80
Total United States 85
766
44
257
39.06
2.04
19.32
7.36
International 31
—
2
33
43.93
—
25.63
7.93
Total 116
766
46
290
40.34
2.04
19.64
7.42
2015
United States
DJ basin 35
176
16
81
44.88
2.31
15.65
8.21
Other United States 50
676
29
191
45.08
2.37
17.83
8.55
Total United States 85
852
45
272
45.00
2.36
17.03
8.45
International 31
—
2
33
51.68
—
29.85
7.22
Total 116
852
47
305
46.79
2.36
17.61
8.31

~~_______________________________________________________________________________~~



	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)			Average Production Costs ⁽²⁾ (Per BOE)
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⁾	~~Excludes~~Includes oil and gas operating expenses and other taxes and excludes ad valorem and severance taxes. Volume represents produced volume sold during the period.

Production costs are costs to operate and maintain the Company’s wells, related equipment, and supporting facilities, including the cost of labor, well service and repair, location maintenance, power and fuel, gathering, processing, transportation, other taxes, and production-related G&A costs. Additional information on ~~volumes,~~volume, prices, and production costs is contained in Financial Results under Item 7 of this Form 10-K. ~~Additional detail regarding production costs is contained in the~~ ~~Supplemental Information~~ ~~under Item 8 of this Form 10-K.~~

19APC 2018 FORM 10-K | 23



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Delivery Commitments

The Company sells oil and natural gas under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. At December 31, 2017, Anadarko was contractually committed to deliver approximately 1,488 Bcf of natural gas to various customers in the United States through 2032. These contracts have various expiration dates, with approximately 21% of the Company’s current commitment to be delivered in 2018 and 76% by 2022. At December 31, 2017, Anadarko was also contractually committed to deliver approximately 22 MMBbls of oil to a customer in the United States through 2020. These contracts have various expiration dates, with approximately 45% of the Company’s current commitment to be delivered in 2018 and 100% by 2020. At December 31, 2017, Anadarko also was contractually committed to deliver approximately 8 MMBbls of oil to ports in Algeria and Ghana through 2018. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves, which the Company regularly monitors to ensure sufficient availability to meet its commitments. If production is not sufficient to meet contractual delivery commitments, the Company may purchase commodities in the market to satisfy its delivery commitments. In areas where Anadarko no longer has production due to asset divestitures, the Company has entered into long-term purchase commitments to satisfy its existing delivery commitments.

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, ~~2017:~~2018:

Developed
Lease

Undeveloped
Lease

Fee
Mineral ⁽¹⁾
Total
thousands of acres Gross Net Gross Net Gross Net Gross Net
United States
Onshore 2,417
1,486
1,797
681
9,891
8,192
14,105
10,359
Offshore 352
198
1,483
1,098
—
—
1,835
1,296
Total United States 2,769
1,684
3,280
1,779
9,891
8,192
15,940
11,655
International 636
138
39,440
31,690
—
—
40,076
31,828
Total 3,405
1,822
42,720
33,469
9,891
8,192
56,016
43,483

~~_______________________________________________________________________________~~



	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, ~~2017,~~2018, the Company had approximately 2120.2 million net undeveloped lease acres scheduled to expire by December 31, ~~2018,~~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, ~~2018,~~2019, if not amended, primarily relate to ~~20.5~~20.0 million net acres of international exploration acreage in South Africa (16.0 million net acres) and Colombia ~~(4.5~~(4.0 million ~~net~~ acres) where proved reserves have not yet been assigned. The Company plans to continue the terms of many of these licenses and concession areas through operational or administrative ~~actions and does not expect a significant portion of its total net acreage position to expire in 2018.~~actions.

24 | APC 2018 FORM 10-K

~~Drilling Program~~



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Drilling Program

The Company’s ~~2017~~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 ~~2017~~2018 consisted of 1047 gross completed wells in the U.S. onshore. Development activity in 2018 consisted of 637 gross completed wells, which included 8615 U.S. onshore wells, ~~and 2~~10 Gulf of Mexico ~~wells. Development activity in 2017 consisted of 554 gross completed wells, which included 548 U.S. onshore~~ wells, and ~~6 Gulf of Mexico~~12 international wells.

~~Table of Contents~~

~~Index to Financial Statements~~

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	Net Exploratory			Net Development			Total
	Productive	Dry Holes	Total	Productive	Dry Holes	Total	Total	Productive	Dry Holes	Total	Productive	Dry Holes	Total	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	6.6	3.6	10.2	359.1	2.4	361.5	371.7
International	—	7.3	7.3	—	—	—	7.3	—	7.3	7.3	—	—	—	7.3
Total	6.6	10.9	17.5	359.1	2.4	361.5	379.0	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	3.7	1.2	4.9	322.1	—	322.1	327.0
International	—	1.8	1.8	2.9	—	2.9	4.7	—	1.8	1.8	2.9	—	2.9	4.7
Total	3.7	3.0	6.7	325.0	—	325.0	331.7	3.7	3.0	6.7	325.0	—	325.0	331.7
2015
United States	16.0	—	16.0	573.1	13.8	586.9	602.9
International	2.4	0.4	2.8	1.8	—	1.8	4.6
Total	18.4	0.4	18.8	574.9	13.8	588.7	607.5

The following shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion at December 31, ~~2017:~~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 —
23
14
543
Net —
20.4
8.6
396.2
International
Gross —
—
28
15
Net —
—
7.8
3.5
Total
Gross —
23
42
558
Net —
20.4
16.4
399.7

~~_______________________________________________________________________________~~



	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 ~~107~~114 MMBOE of PUDs primarily assigned to U.S. onshore development wells suspended or waiting on completion at December 31, ~~2017.~~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



	BUSINESS AND PROPERTIES EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES	Table of Contents Index to Financial Statements

Productive Wells

At December 31, ~~2017~~,2018, the Company’s ownership interest in productive wells was as follows:

Oil Wells ⁽¹⁾

Gas Wells ⁽¹⁾
United States
Gross 3,571
8,574
Net 2,309.2
7,182.0
International
Gross 208
9
Net 37.3
2.2
Total
Gross 3,779
8,583
Net 2,346.5
7,184.2


⁽¹⁾	~~Includes wells containing multiple completions as follows:~~



	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

Gross 411
2,997
Net 355.1
2,697.1

2226 | APC 2018 FORM 10-K



	BUSINESS & PROPERTIES MIDSTREAM PROPERTIES AND ACTIVITIES	Table of Contents Index to Financial Statements

~~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 ~~facilities,~~assets, the Company improves its ability to manage costs, controls the timing of bringing on new production, and enhances the value received for ~~gathering, processing, treating, and transporting~~ the Company’s production. ~~Anadarko’s midstream business~~Anadarko also provides midstream services to a variety of third-party customers ~~including major~~ and ~~independent producers. Anadarko~~ generates revenues from its midstream activities through a variety of contract structures, including fixed-fee, percent-of-proceeds, ~~wellhead purchase,~~wellhead-purchase, and keep-whole agreements. Anadarko’s midstream activities include those of WES, which acquires, owns, develops, and operates midstream assets.

At December 31, ~~2017,~~2018, Anadarko’s ownership interest in WGP consisted of ~~an 81.6%~~a 77.8% limited partner interest and the entire non-economic general partner interest. At December 31, ~~2017,~~2018, WGP’s ownership interest in WES consisted of a ~~29.8%~~29.6% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At December 31, ~~2017,~~2018, Anadarko also owned a ~~9.1%~~9.7% limited partner interest in WES through other subsidiaries.

~~WES Midstream~~

At the end of ~~2017,~~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

APC 2018 FORM 10-K | 27



	BUSINESS & PROPERTIES MIDSTREAM PROPERTIES AND ACTIVITIES	Table of Contents Index to Financial Statements

WES Midstream

At December 31, 2018, WES Midstream included 2019 gathering systems and 5146 processing and treating facilities located throughout major onshore producing basins in Wyoming, Colorado, Utah, Pennsylvania, Texas, and New Mexico. In ~~2017, the~~2018, WES Midstream activity ~~was concentrated~~focused on constructing midstream infrastructure in the Delaware basin to ~~build infrastructure~~prepare for ~~present~~long-term volumetric oil growth, providing additional system expansions in the DJ basin to keep pace with basin activity, and ~~future Wolfcamp development. In 2018, the Company expects~~ensuring sufficient access to ~~continue~~downstream markets by acquiring options to ~~focus its midstream investment on the Delaware~~invest in various transportation assets and ~~DJ basins.~~long-haul pipelines.

Delaware Basin In ~~2017, the Company~~2018, WES expanded its midstream infrastructure for ~~Bone Spring, Wolfcamp, and Avalon~~ production in the Delaware basin of West Texas, installing ~~over 150~~approximately 365 miles of gas and water gathering lines. ~~Four~~Within its gas gathering system, eight new central gathering facilities (CGFs) were installed and ~~seven~~one existing ~~CGFs were~~CGF was expanded to add a total of approximately ~~495~~325 MMcf/d of natural gas compression capacity. ~~Two~~One produced-water disposal ~~systems were~~facility was placed into service during the ~~second~~first quarter of ~~2017,~~2018, with ~~combined~~ capacity of ~~90,000~~30,000 barrels of water per day. Additional ~~compressor station expansions within the field are~~gas gathering, compression, and produced-water disposal infrastructure is planned for ~~2018.~~2019.

In the first quarter of 2017, Anadarko completed the divestiture of its Marcellus operated and nonoperated oil and natural-gas assets and related operated midstream assets to a third party. The midstream assets owned by WES were excluded from the divestiture; however, during the first quarter of 2017, WES entered into a property exchange whereby it exchanged its 33.75% nonoperated interest in certain Marcellus assets, commonly referred to as the Liberty and Rome systems, plus $155 million in cash for a third party’s 50% nonoperated interest in the DBJV System. The property exchange increased WES’s interest in the DBJV System to 100%.

With the completion of the Mentone Train ~~VI,~~I, a 200 MMcf/d cryogenic facility, atin the ~~end~~fourth quarter of ~~2017,~~2018, the ~~DBM~~West Texas Complex now includes ~~900 MMcf/~~1.1 Bcf/d of cryogenic processing capacity, ~~1,400~~2,000 gallons per minute of amine-treating capacity, 18and 28 MBbls/d of high-pressure condensate stabilization ~~and a rich-gas gathering system, with over 400 miles of high-pressure and low-pressure segments. Construction has begun on the Mentone plant, which will~~capacity. WES expects to add ~~400~~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 ~~2018.~~

~~In December 2015, there~~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 an initial fire and secondary explosion at the processing facility within the DBM Complex. The majority of damage was to the liquid-handling facilities and the amine-treating units at the inlet of the processing facility. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returned to service in December 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returnedto~~full~~placed into service in May ~~2016. There was no damage to Trains~~IV2018, and V~~(each with a capacity of200 MMcf/d), which were under construction at~~closed on the ~~time of the incident. Train IV came online~~investment in ~~May 2016 and Train V came online~~January 2019. This pipeline transport provides crude-oil flow assurance by ensuring residue gas takeaway from natural-gas processing plants in ~~October 2016.~~

~~During the second quarter of 2017, the Company reached a settlement with insurers and final proceeds were received related~~West Texas to the ~~December 2015 incident at the DBM Complex. As of December 31, 2017, the Company had received a total of $86.7 million~~WAHA hub in ~~cash proceeds from insurers related to the incident, including $46.2 million in proceeds from business interruption insurance claims and $40.5 million in proceeds from property insurance claims.~~

~~Table of Contents~~

~~Index to Financial Statements~~

Pecos County, Texas.

DJ Basin ~~The Company~~WES continued to optimize ~~gathering and compression in 2017, which reduced~~its gas gathering system throughout 2018 which resulted in average gathering pipeline pressures believed to be among the lowest in the ~~field, enhancing system efficiency~~basin and ~~improving the base production profile.~~supportive of stable and consistent production. Management believes that ~~the Company~~WES is ~~well-positioned~~well positioned in the DJ basin with ~~its~~sufficient oil, NGL, and ~~NGLs~~residue gas transportation ~~capacity, which includes transport by pipeline, rail, and truck.~~capacity.

In ~~2017, the Company~~2018, WES expanded its midstream infrastructure to support incremental DJ basin production, adding ~~a total of~~ approximately ~~100~~170 MMcf/d of compression capacity ~~to three~~and 35 miles of ~~its compressor stations.~~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 ~~2017, the Company sanctioned the~~2018, WES commenced construction of the Latham plant ~~consisting~~at the DJ Basin Complex, which will consist of two cryogenic gas processing trains ~~which~~that will increase natural-gas processing capacity by 400 MMcf/d. ~~Construction is expected to start in 2018,~~Additional gas gathering and ~~the plant is expected to be online in 2019. Additional compressor stations and~~compression system expansions ~~to existing compressor stations~~ are also planned for ~~2018.~~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 ~~Company~~Texas Express Gathering pipeline ultimately delivers NGLs to the Texas Express Pipeline. In addition, WES elected to participate in anthe 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 ~~which was completed~~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 ~~2017, increasing total capacity from 150 MBbls/d to approximately 180 MBbls/d.~~the fourth quarter of 2019.

Eagleford In the Eagleford shale, ~~the Company~~WES continues to operate oil and gas gathering systems, with a ~~2017~~2018 average gross throughput of 5565 MBbls/d of oil and ~~450~~440 MMcf/d of natural gas. The 200 MMcf/d operated Brasada natural-gas cryogenic processing plant continued steady operations at capacity. ~~In the first quarter of 2017, Anadarko completed the divestiture of its oil and natural-gas assets to a third party; the midstream assets owned by WES were not divested.~~

28 | APC 2018 FORM 10-K



	BUSINESS & PROPERTIES MIDSTREAM PROPERTIES AND ACTIVITIES	Table of Contents Index to Financial Statements

The following provides information regarding the WES Midstream assets including gathering, processing, treating, transportation, and produced-water disposal by ~~area (excluding divestitures closed in 2017):~~area:


Area	Miles of Pipelines	Total Horsepower	2017 Average Net Throughput (MMcf/d)	2017 Average Net Throughput (MBbls/d)	Miles of Pipelines	Total Horsepower ⁽¹⁾	2018 Average Net Throughput (MMcf/d)	2018 Average Net Throughput (MBbls/d)
DJ basin	4,680	319,200	950	50	4,720	302,200	1,110	55
Delaware basin	1,300	316,100	810	30	2,080	412,700	1,040	160
Greater Natural Buttes	40	74,900	420	10
Wyoming	4,750	173,300	800	—	4,210	160,800	840	—
Eagleford	870	200,100	450	30	880	202,700	445	40
Greater Natural Buttes					40	74,900	360	10
Other	870	34,600	80	80	930	9,700	100	95
Total	12,510	1,118,200	3,510	200	12,860	1,163,000	3,895	360


⁽¹⁾	Excludes horsepower associated with transportation assets.

~~Table of Contents~~

~~Index to Financial Statements~~

Other Midstream

At the end of ~~2017,~~2018, Anadarko’s Other Midstream assets included 810 gathering systems and 2025 processing and treating facilities located throughout major onshore producing basins in Colorado, Utah, Texas, and New Mexico. In ~~2017,~~2018, Anadarko’s Other Midstream activity was ~~concentrated~~focused on the build out of its crude-oil gathering and stabilization capacity and produced-water gathering and disposal capacity in the Delaware basin, ~~to build infrastructure for present~~as well as on expanding its crude-oil gathering and ~~future Wolfcamp development. In 2018,~~stabilization capacity in the ~~Company expects to continue to focus its midstream investment on the Delaware and~~ DJ ~~basins.~~basin.

Delaware BasinIn ~~2017,~~2018, the Company expanded its midstream infrastructure ~~for Bone Spring, Wolfcamp, and Avalon~~to further support Anadarko-operated production in the Delaware ~~basin of West Texas, installing~~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 60600 miles of oil and water gathering lines. In addition, oil processing capacity increased by 20 MBbls/d in 2017 with the expansion of the Avalon central production facility in Loving County, and capacity is expected to increase significantly in 2018 with two ROTFs, each with capacity of 60 MBbls/d, expected to come online. Several newlines 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 ~~also~~ planned for ~~2018.~~2019.

~~In the first quarter of 2017, Anadarko purchased an additional interest in the Bone Spring Plant from a third party, increasing its ownership in the plant from 33% to 50%.~~

DJ Basin In ~~2017,~~2018, the ~~Company completed certain projects at its COSF, increasing the facility’s capacity from 100 MBbls/d to 125 MBbls/d. Construction has begun on a~~ sixth stabilizer train at the COSF ~~which will add 25~~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 ~~2017)~~2018):


Area	Miles of Pipelines	Total Horsepower	2017 Average Net Throughput (MMcf/d)	2017 Average Net Throughput (MBbls/d)	Miles of Pipelines	Total Horsepower ⁽¹⁾	2018 Average Net Throughput (MMcf/d)	2018 Average Net Throughput (MBbls/d)
DJ basin	1,050	50,200	190	110	1,070	23,300	220	120
Delaware basin	540	44,500	130	80	1,140	76,900	150	285
Greater Natural Buttes	1,180	152,100	330	—	1,130	146,800	280	—
Other	300	7,000	—	10	300	—	—	15
Total	3,070	253,800	650	200	3,640	247,000	650	420


⁽¹⁾	Excludes horsepower associated with transportation assets.

APC 2018 FORM 10-K | 29



	BUSINESS & PROPERTIES COMPETITION AND EMPLOYEES	Table of Contents Index to Financial Statements

COMPETITION

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

~~SEGMENT INFORMATION~~

EMPLOYEES

~~For additional information on operations by segment, see~~ ~~Note 26—Segment Information~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Item 8 of this Form 10-K, and for additional information on risk associated with international operations, see~~ ~~Risk Factors~~ ~~under Item 1A of this Form 10-K.~~

~~EMPLOYEES~~

The Company had approximately ~~4,400~~4,700 employees at December 31, ~~2017~~.2018.

2530 | APC 2018 FORM 10-K



	BUSINESS & PROPERTIES REGULATORY AND ENVIRONMENTAL MATTERS	Table of Contents Index to Financial Statements

REGULATORY AND ENVIRONMENTAL MATTERS

Environmental and Occupational Health and Safety Regulations

Anadarko’s business operations are subject to numerous ~~international, provincial, federal, regional, state, tribal, local, and foreign~~ environmental and occupational health and safety laws and ~~regulations.~~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 ~~existing~~ environmental and occupational health and safety laws and regulations include the following ~~U.S. laws and regulations,~~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, imposes various pre-construction, monitoring, and reporting requirements, which the EPA has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (GHG) emissions


–	the U.S. 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



	BUSINESS & PROPERTIES REGULATORY AND ENVIRONMENTAL MATTERS	Table of Contents Index to Financial Statements

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 ~~U.S. Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees~~Company is conducting business that also have, or ~~permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States~~

U.S. Department of the Interior regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages

the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur

~~the U.S. Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes~~

the U.S. Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and control over the injection of waste fluids into below-ground formations that may adversely affect drinking water sources

the U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories

the U.S. Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures

the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas

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

developing, regulatory initiatives or analogous controls that regulate Anadarko’s environmental-related activities. While the ~~U.S. Department of Transportation regulations, which relate~~legal requirements imposed in foreign countries or jurisdictions therein may be similar in form to ~~advancing the safe transportation of energy and hazardous materials and emergency response preparedness~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~These~~ 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 ~~state counterparts,~~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, ~~multiple~~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 ~~regulations~~regulatory initiatives relating to environmental protection. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.

Many states where the Company operates also have, or are developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. In addition, many foreign countries where the Company is conducting business also have, or may be developing, regulatory initiatives or analogous controls that regulate Anadarko’s environmental-related activities. While the legal requirements imposed under state or foreign law may be similar in form to U.S. laws and regulations, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the permitting, development, or expansion of a project or substantially increase the cost of doing business. In addition, environmental and occupational health and safety laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental concerns such as air and water impacts, are expected to continue to have a considerable impact on the Company’s operations.

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

2732 | APC 2018 FORM 10-K



	BUSINESS & PROPERTIES REGULATORY AND ENVIRONMENTAL MATTERS	Table of Contents Index to Financial Statements

Oil Spill-Response Plan

Domestically, the Company is subject to compliance with the federal ~~Bureau of Safety and Environmental Enforcement (BSEE)~~BSEE regulations, which, among other standards, require every owner or operator of a U.S. offshore lease to prepare and submit for approval an oil spill-response plan prior to conducting any offshore operations. The submitted plan is required to provide a detailed description of actions to be taken in the event of a spill; identify contracted spill-response equipment, materials, and trained personnel; and stipulate the time necessary to deploy identified resources in the event of a spill. The BSEE regulations may be amended, resulting in more stringent requirements ~~as changes~~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. The Plans are reviewed by the Company at least annually and updated as necessary. Drills are conducted by the Company at least annually to test the effectiveness of the Plans and includes the participation of spill-response contractors and other third parties. The Plans and any revisions to the Plans must be approved by the BSEE.

As part of the Company’s oil spill-response preparedness, and as set forth in the Plans, Anadarko maintains membership in Clean Gulf Associates (CGA) ~~and has an employee representative on the executive committee of CGA.~~. CGA was created to provide a means of effectively staging response equipment and to provide effective spill-response capability for its member companies operating in the Gulf of Mexico. Anadarko is also a member of the Marine Preservation Association, which provides full access to the Marine Spill Response Corporation (MSRC) cooperative. In the event of a spill, MSRC stands ready to mobilize all of its equipment and materials. MSRC has a fleet of dedicated Responder Class Oil Spill Response Vessels (OSRVs), designed and built to recover spilled oil.

The Company ~~has~~is also ~~entered into~~ a ~~contractual commitment~~member of the Marine Well Containment Company (MWCC) which provides access to ~~access~~ subsea intervention, containment, capture, and shut-in capacity for deepwater exploration wells. ~~Marine Well Containment Company (MWCC)~~MWCC is open to oil and gas operators in the U.S. Gulf of Mexico and provides members access to oil spill-response equipment and services on a per-well fee basis. Anadarko has an employee representative on the executive committee of MWCC. MWCC members have access to a containment system that is planned for use in deepwater depths of up to 10,000 feet, with containment capacity of 100 MBbls/d of liquids and flare capability for 200 MMcf/d of natural gas.

Anadarko has emergency and oil spill-response plans in place for each of its exploration and operational activities around the globe. Each plan is intended to satisfy the requirements of relevant local or national authorities, describes the actions the Company is expected to take in the event of an incident, includes drills conducted by the Company at least annually, and includes reference to external resources that may become necessary in the event of an incident. Included in these external resources is the Company’s contract with Oil Spill Response Limited (OSRL), a global emergency and oil spill-response organization headquartered in London.

In addition to Anadarko’s membership in or access to CGA, MSRC, OSRL, and MWCC, the Company participates in industry-wide task forces, which are currently studying improvements in both gaining access to and controlling blowouts in subsea environments. Two such task forces are the Subsea Well Control and Containment Task Force and the Oil Spill Task Force.

~~Table of Contents~~

~~Index to Financial Statements~~

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



	BUSINESS & PROPERTIES EXECUTIVE OFFICERS OF THE REGISTRANT	Table of Contents Index to Financial Statements

EXECUTIVE OFFICERS OF THE REGISTRANT



Name		Age at January 31, ~~2018~~2019		Position
R. A. Walker		60	61	Chairman ~~President~~ and Chief Executive Officer
Robert G. Gwin	55	54President
Benjamin M. Fink	48	Executive Vice President, Finance and Chief Financial Officer
Daniel E. Brown		42	43	Executive Vice President, U.S. Onshore Operations
Mitchell W. Ingram		55	56	Executive Vice President, International, & Deepwater ~~Operations~~ and ~~Project Management~~Exploration
~~Ernest A. Leyendecker~~Amanda M. McMillian		57	45	Executive Vice President ~~Exploration~~
~~Robert K. Reeves~~		60		~~Executive Vice President, Law~~ and ~~Chief Administrative Officer~~General Counsel
Christopher O. Champion		48	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, and the role of~~2012. He also served as President ~~which he assumed in~~from February ~~2010.~~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 ~~Temple-Inland Inc. from November 2008 to February 2012 and a director of~~ CenterPoint Energy, Inc. from April 2010 to April 2015 and has served as a director of BOK Financial Corporation since April 2013, where he is the Chairman of the Risk Committee.

Mr. Gwin was named President in November 2018. Prior to this position, he served as Executive Vice President, Finance and Chief Financial Officer insince May ~~2013 and previously served as~~2013; Senior Vice President, Finance and Chief Financial Officer since March ~~2009~~2009; and Senior Vice President since March 2008. He ~~also has~~ served as Chairman of the Board of WGH ~~since~~from October 2009 until November 2018 and has served as a director since August 2007. Additionally, Mr. Gwin ~~has~~ served as Chairman of the Board of WGEH ~~since~~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 ~~has~~ served as Chairman of the Board of LyondellBasell Industries N.V. ~~since~~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 ~~2011.~~

~~Table~~2013, having joined Anadarko in 2007. Mr. Fink also served as President of ~~Contents~~

~~Index~~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 ~~Statements~~

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



	BUSINESS & PROPERTIES EXECUTIVE OFFICERS OF THE REGISTRANT	Table of Contents Index to Financial Statements

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 insince 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~~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.

~~Mr. Leyendecker~~Ms. McMillian was named Executive Vice President ~~Exploration~~and General Counsel in ~~October 2017.~~August 2018. Prior to this position, heshe served as ~~Executive Vice President, International and Deepwater Exploration since August 2016;~~ Senior Vice President, ~~International Exploration~~General Counsel, Corporate Secretary and Chief Compliance Officer since ~~April~~September 2015; ~~and Senior~~ Vice President, ~~Gulf of Mexico Exploration since February 2014. Prior to that, he served as Vice President, Gulf of Mexico Exploration~~Deputy General Counsel, Corporate Secretary and Chief Compliance Officer since May ~~2011~~2013; and ~~as Vice President of~~Deputy General Counsel and Corporate ~~Planning and Gulf of Mexico Exploration~~Secretary since ~~October 2010. Mr. Leyendecker~~July 2012. Ms. McMillian joined Anadarko ~~upon the acquisition of Kerr-McGee Corporation~~ in ~~August 2006. He~~December 2004 and has held positions of increasing responsibility with Anadarko, ~~and Kerr-McGee Corporation,~~ including Exploration Manager for the Gulf of Mexico and General Manager for Worldwide Exploration, Engineering and Planning. Mr. Leyendecker began his career with Marathon Oil Company prior to pursuing a leadership role with Enterprise Oil Gulf of Mexico, which was acquired by Shell Oil in 2002.

~~Mr. Reeves was named Executive Vice President, Law and Chief Administrative Officer in September 2015 and previously served as Executive~~ Vice President, General Counsel and Chief Administrative Officer since May 2013 and as Senior Vice President, General Counsel and Chief Administrative Officer since February 2007. He also served as Chief Compliance Officer from July 2012 to May 2013. He served as Corporate Secretary of WGH from ~~February 2007~~January 2008 to August ~~2008. He previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer since 2004.~~2012. Prior to joining Anadarko, ~~he served as Executive Vice President, Administration~~she practiced corporate and ~~General Counsel~~securities law at the law firm of ~~North Sea New Ventures from 2003 to 2004~~Akin Gump Strauss Hauer & Feld LLP, where she represented a variety of clients in a wide range of transactional, corporate governance and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. He served as a director of Key Energy Services, Inc., a publicly traded oilfield services company, from October 2007 to December 2016 and has served as a director of WGH since August 2007 and as a director of WGEH since September 2012.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 ~~15, 2018,~~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.

30APC 2018 FORM 10-K | 35



	RISK FACTORS	Table of Contents Index to Financial Statements

Item 1A. Risk Factors

~~CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS~~

~~Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this~~This Annual Report on Form 10-K and ~~may from time to time make in other public filings, press releases, and management discussions,~~the documents incorporated herein by reference contain forward-looking statements ~~within the meaning of Section 27A~~based on expectations, estimates, and projections as of the ~~Securities Act~~date of ~~1933, as amended,~~this filing. These statements by their nature are subject to risks, uncertainties, and ~~Section 21E of the Securities Exchange Act of 1934, as amended, concerning the Company’s operations, economic performance,~~assumptions 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 precededare influenced 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 asvarious factors. As a ~~result of new information, future events, or otherwise.~~

~~These forward-looking statements involve risk and uncertainties. Important factors that could cause~~consequence, actual results tomay differ materially from ~~the Company’s expectations include, but are not limited to, the following risks and uncertainties:~~

~~the Company’s assumptions about energy markets~~

~~production and sales volume levels~~

~~levels of oil, natural-gas, and NGLs reserves~~

~~operating results~~

~~competitive conditions~~

~~technology~~

~~availability of capital resources, levels of capital expenditures, and other contractual obligations~~

~~supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services~~

~~volatility~~those expressed in the ~~commodity-futures market~~

~~weather~~

~~inflation~~

~~availability of goods and services, including unexpected changes in costs~~

~~drilling and other operational risks~~

~~processing volumes, pipeline throughput, and produced water disposal~~

~~general economic conditions, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, doing business~~

~~the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary~~forward-looking statements. See Cautionary Statement About Forward-Looking Statements on page 4 for ~~drilling and/or development projects~~

legislative or regulatory changes, including changes relating to hydraulic fracturing; retroactive royalty or production tax regimes; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, tribal, local, and foreign environmental laws and regulations

additional information.

~~Table of Contents~~

~~Index to Financial Statements~~

~~civil or political unrest or acts of terrorism in a region or country~~

~~the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties~~

~~volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk~~

~~the Company’s ability to successfully monetize select assets, repay or refinance its debt, and the impact of changes in the Company’s credit ratings~~

~~the Company’s ability to successfully complete its share-repurchase program~~

~~uncertainties associated with acquired properties and businesses~~

~~disruptions in international oil and NGLs cargo shipping activities~~

~~physical, digital, cyber, internal, and external security breaches~~

~~supply and demand, technological, political, governmental, and commercial conditions associated with long-term development and production projects in domestic and international locations~~

the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the NTSB related to the Company’s operations in Colorado, and continued or additional disruptions in operations that may occur as the Company complies with regulatory orders or other state or local changes in laws or regulations in Colorado

~~other factors discussed below and elsewhere in this Form 10-K, and in the Company’s other public filings, press releases, and discussions with Company management~~

~~Table of Contents~~

~~Index to Financial Statements~~

RISK FACTORS

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

Oil, natural-gas, and ~~NGLs~~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~~


–	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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	RISK FACTORS	Table of Contents Index to Financial Statements

The long-term effect of these and other factors on the prices of oil, natural gas, and NGLs is uncertain. Prolonged or substantial decline in these commodity prices may have the following effects on our business:

~~adversely affect our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations~~

~~reduce the amount of oil, natural gas, and NGLs that we can produce economically~~

~~cause us to delay or postpone some of our capital projects~~

~~reduce our revenues, operating income, or cash flows~~

~~reduce the amounts of our estimated proved oil, natural-gas, and NGLs reserves~~

reduce the carrying value of our oil, natural-gas, and midstream properties due to recognizing additional impairments of proved properties, unproved properties, exploration assets, and midstream facilities

~~reduce the standardized measure of discounted future net cash flows relating to oil, natural-gas, and NGLs reserves~~

~~limit our access to, or increasing the cost of, sources of capital such as equity and long-term debt~~

~~adversely affect the ability of our partners to fund their working interest capital requirements~~


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

~~issuance of permits in connection with exploration, drilling, production, produced water disposal,~~activities and ~~other midstream activities~~matters:

~~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~~

~~Table of Contents~~

~~Index to Financial Statements~~


–	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 ~~negatively~~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 for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA did not meet the October 1, 2017 deadline for designating non-attainment areas but, on November 6, 2017, issued final designations for areas in the United States that are in attainment with the 70 parts per billion standard, representing approximately 85% of the U.S. counties that became effective on January 18, 2018. For the remaining areas of the United States, the EPA has not yet prepared final designations, but is expected to do so in a separate future action in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified facilities in new designated non-attainment areas. Also, states that are designated as non-attainment are expected to implement more stringent regulations, which

–

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

~~Reduction of Methane Emissions by the Oil and Gas Industry.~~APC 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 2018 FORM 10-K | 37



	RISK FACTORS	Table of Contents Index to Financial Statements

gas and volatile organic compound emissions. These Subpart OOOOa standards ~~would~~ expand previously issued New Source Performance Standards, Subpart OOOO, published by the EPA in 2012 by using certain equipment-specific emissions control practices with respect to, among other things, hydraulically fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. ~~However, in June 2017,~~In February 2018, the EPA ~~published a proposed rule~~finalized amendments to ~~stay~~ certain ~~portions~~requirements of the ~~June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a~~2015 final rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to other requirements, such as ~~a result,~~fugitive emission monitoring frequency. Notwithstanding the ~~June~~current uncertainty with these rules establishing emission standards for methane and VOCs and BLM’s 2016 ~~standards remain in effect, but future implementation of the standards are uncertain at this time. Furthermore, in June 2017, the Bureau of Land Management (BLM) stayed a~~final rule ~~published in November 2016 imposing requirements~~ to reduce methane emissions from venting, flaring, and leaking from oil and natural-gas operations on public lands. On October 4, 2017, the U.S. District Court for the Northern District of California struck down the June 2017 stay. However, on December 8, 2017, the BLM published a final rule that will temporarily suspend certain requirements contained in the November 2016 final rule until January 17, 2019. The December 2017 compliance extension was challenged by non-governmental organizations and several states on December 19, 2017. Notwithstanding the current uncertainty,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.

~~Table of Contents~~

~~Index to Financial Statements~~

~~Induced Seismic Activity Associated with Oilfield Disposal Wells.~~ We dispose of wastewater generated from oil and natural-gas production operations directly or through the use of third parties. The legal requirements related to the disposal of wastewater in underground injections wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near injection wells used for the disposal of produced water resulting from oil and natural-gas activities. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Colorado developed and follows guidance when issuing underground injection control permits to limit the maximum injection pressure, rate, and volume of water. Oklahoma has issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has also adopted similar permitting, operating, and reporting rules for disposal wells. In addition, ongoing class action lawsuits, to which we are not currently a party, allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.

•–

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~~"best available control ~~technology”~~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 ~~volumes~~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. ~~In December 2015,~~Additionally, the United States ~~joined~~is one of almost 200 nations that, in December 2015, agreed to the Paris Climate Agreement, an international ~~community at the 21~~^st ~~Conference of the Parties of the United Nations Framework Convention on Climate Change~~climate change agreement in Paris, France, that ~~prepared an agreement requiring member~~calls for countries to ~~review and “represent a progression” in~~set their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this international agreement does not create any binding obligations for nations to limit theirown GHG emissions ~~it does include pledges~~targets and be transparent about the measures that each country will use to ~~voluntarily limit or reduce future emissions. In~~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 ~~17—~~18—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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	RISK FACTORS	Table of Contents Index to Financial Statements

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 ~~delays,~~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, ~~several~~the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation, including by federal ~~agencies have also~~agencies. For example, the EPA has asserted federal regulatory authority over certain ~~aspects~~hydraulic-fracturing activities under the SDWA involving the use of diesel fuels and published permitting guidance in 2014 addressing the ~~process. For example,~~use of diesel in ~~June~~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 ~~March~~ 2015 ~~that establishes~~establishing new or more stringent standards for performing hydraulic fracturing on federal and Indian ~~land. This rule was struck down by a Wyoming federal judge,~~land but ~~in June 2016, the decision was appealed by~~ the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit. However, in July 2017, the BLM published a proposed rule to rescind the 2015 final rule. In September 2017, the Tenth Circuit Court issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challengingrescinded the 2015 rule in ~~light~~December 2017; however, litigation filed in January 2018 in the federal District Court for the Northern District of California challenging the BLM’s ~~proposed rulemaking. The timing of a final rulemaking~~decision to ~~rescind the~~repeal 2015 rule ~~is uncertain and, as a result of these developments, future implementation of the 2015 rule is uncertain at this time.~~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 some circumstances”.~~under certain circumstances.

Certain states in which we operate, including Colorado, ~~Pennsylvania, Louisiana,~~ 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 ~~May 2017,~~February 2018, the Colorado Oil & Gas Conservation Commission (COGCC) issued a two-phase Notice to Operators (NTO) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and inspect and complete abandonment of all inactive flowlines regardless of distance to a building unit. Furthermore, in August 2017, following a three month review of oil and gas operations, the Governor of Colorado announced several policy initiatives designed to enhance public safety, which are to be implemented through rulemaking or legislation. As part of these policy initiatives, on February 13, 2017, the COGCC approved new regulations addressing the operation of flowlines and related infrastructure associated with oil and natural-gas development 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. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective city limits beginning in 2012 but, since that time, local district courts have struck down the ordinances for certain of those Colorado cities, which decisions were upheld by the Colorado Supreme Court in 2016. Notwithstanding attempts at the local level to prohibit hydraulic fracturing, the opportunity exists for cities to adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions while regulating the time, place, and manner of those activities.

~~Table of Contents~~

~~Index to Financial Statements~~

Additionally, certain interest groups in Colorado opposed to oil and natural-gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if approved, would ~~allow revisions to~~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. However, an amendment on the Colorado 2016 ballot was approved by voters, making it more difficult to place an initiative to amend the constitution on the state ballot by requiring signatures from 2% of registered voters fromFor example, in each of the ~~state’s 35 Senate districts~~November 2014, 2016 and ~~approval by 55% of~~2018 general election cycles, ballot initiatives have been pursued, with the ~~voters.~~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.

APC 2018 FORM 10-K | 39



	RISK FACTORS	Table of Contents Index to Financial Statements

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 ~~draft~~statutory notice of ~~proposed adjustment denying our deduction in its entirety.~~deficiency rejecting the Company’s refund claim. We disagree and ~~plan~~filed a petition with the U.S. Tax Court to ~~defend our tax position.~~dispute the disallowance in November 2018. It is possible that we may not ultimately succeed in defending this deduction. We could be required to repay all or a portion of the tentative refund received, with interest, prior to determining the final outcome of our tax position either upon IRS request or litigation of the matter in District or Federal Claims Court. If the payment is ultimately determined not to be deductible, we would be required to repay the tentative refund received plus interest and reverse the net benefit of $346 million previously recognized in our consolidated financial statements, which could have a material adverse effect on our results of operations, liquidity, and financial condition. For additional information on income taxes, see Note ~~13—~~14—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

~~Table of Contents~~

~~Index to Financial Statements~~

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

At December 31, ~~2017,~~2018, our total consolidated debt of ~~$15.7~~$16.4 billion consisted of ~~$12.2~~$11.6 billion related to Anadarko and ~~$3.5~~$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~~


–	increasing our vulnerability to general adverse economic and industry conditions


–	limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flows from operations to payments on our debt or to comply with any restrictive terms of our debt


–	limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate


–	placing us at a competitive disadvantage compared to our competitors that have less debt and/or fewer financial commitments

Additionally, the credit ~~agreements~~agreement governing the APC RCF ~~and our 364-Day Facility contain~~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.

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

As of December 31, 2017, our long-term debt was rated “BBB” with a stable outlook by S&P and Fitch. Our long-term debt was rated “Ba1” with a stable outlook by Moody’s, which is below investment grade. As of the time of filing this Form 10-K, no additional changes in our credit rating have occurred and we are not aware of any current plans of S&P, Fitch, or Moody’s to revise their respective credit ratings on our long-term debt; however, we cannot be assured that our credit ratings will not be further downgraded. Any further downgrade in our credit ratings could negatively impact our cost of capital and could also adversely affect our ability to effectively execute aspects of our strategy or to raise debt in the public debt markets.

As a result of Moody’s below-investment-grade rating of our long-term debt in February 2016, we are more likely to be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements such as pipeline transportation contracts and oil and gas sales contracts. The amount of letters of credit or cash provided as assurance of our performance under these types of contractual arrangements with respect to credit-risk-related contingent features was $263 million at December 31, 2017, and $274 million at December 31, 2016. Additionally, certain of these arrangements contain financial-assurances language that may, under certain circumstances, permit our counterparties to request additional collateral.

Furthermore, as a result of Moody’s rating, the credit thresholds with certain derivative counterparties were reduced and in some cases eliminated, which required us to increase the amount of collateral posted with derivative counterparties when our net trading position is a liability in excess of the contractual threshold. We may be required to post additional collateral with respect to our derivative instruments if our credit ratings decline below current levels. For example, based on year-end derivative positions, if Anadarko’s credit rating were to be downgraded one level by either S&P or Moody’s, we would be required to post additional collateral of up to approximately $50 million. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.4 billion (net of $170 million of collateral) at December 31, 2017, and $1.4 billion (net of $117 million of collateral) at December 31, 2016. For additional information, see ~~Note 10—Derivative Instruments~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Item 8 of this Form 10-K.~~

~~Additionally, in February 2016, Moody’s downgraded our commercial paper program credit rating, which eliminated our access to the commercial paper market.~~

3940 | APC 2018 FORM 10-K



	RISK FACTORS	Table of Contents Index to Financial Statements

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

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated or understated. The reserves information included or incorporated by reference in this Form 10-K represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants; however, no reserves audit was conducted by these consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil, natural-gas, and ~~NGLs~~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 NGLs prices, future operating costs, and capital expenditures~~

~~estimates of future severance and excise taxes, workover costs, and remedial costs~~


–	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 ~~NGLs~~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.

APC 2018 FORM 10-K | 41



	RISK FACTORS	Table of Contents Index to Financial Statements

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.

~~Table~~The Federal Energy Regulatory Commission (FERC) has authority to regulate the rates and terms and conditions of ~~Contents~~

~~Index~~service of natural gas, oil, NGL, and other liquids pipelines operating in interstate commerce. The FERC could exercise jurisdiction over our midstream operations to ~~Financial Statements~~

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.

~~During the last few years,~~Historically, concerns over inflation, potential default on U.S. debt, energy costs, geopolitical issues, the availability and cost of credit, and uncertainties with regard to European sovereign debt, have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic growth, 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.

42 | APC 2018 FORM 10-K



	RISK FACTORS	Table of Contents Index to Financial Statements

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~~


–	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.

~~Table of Contents~~

~~Index to Financial Statements~~

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

~~In recent years, the Bureau of Ocean Energy Management (BOEM)~~The BOEM and the BSEE ~~agencies of the U.S. Department of the Interior,~~ have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. For example, in 2016, BSEE finalized rule-making entitled “Oil and Sulfur Operations on the Outer Continental Shelf — Blowout Prevention Systems and Well Control,” which focuses on well blowout preventer systems and well control with respect to operations on the OCS. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.

~~In addition,~~Additionally, these governmental agencies are continuing to evaluate and develop and implement new, ~~regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future~~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 ~~BOEM~~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, ~~that would update existing air-emissions requirements relating~~which has not been finalized, to ~~offshore oil and natural-gas activity on federal OCS waters including in the Central Gulf of Mexico. In addition,~~revise these regulations for well control.

Moreover, in September 2016, the BOEM issued a Notice to ~~Lessees and Operators~~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 ~~Notice to Lessees,~~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.

APC 2018 FORM 10-K | 43



	RISK FACTORS	Table of Contents Index to Financial Statements

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 ~~gas~~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.

~~Table of Contents~~

~~Index to Financial Statements~~

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.

44 | APC 2018 FORM 10-K



	RISK FACTORS	Table of Contents Index to Financial Statements

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~~

~~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~~


–	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.~~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 ~~in such countries~~ could be materially impaired.

Our international operations may also be adversely affected, directly or indirectly, by laws, policies, and regulations of the United States affecting foreign trade and taxation, including U.S. trade sanctions.

Realization of any of the factors listed above could materially and adversely affect our financial condition, results of operations, or cash flows.

~~Table of Contents~~

~~Index to Financial Statements~~

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

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, or qualified personnel. The cost for such items may increase as a result of a variety of factors beyond our control, such as increases in the cost of electricity, steel, and other raw materials that we and our vendors rely upon; increased demand for labor, services, and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling rigs, equipment, supplies, or qualified personnel. However, if commodity prices rise, such costs may rise faster than increases in our revenue and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

APC 2018 FORM 10-K | 45



	RISK FACTORS	Table of Contents Index to Financial Statements

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.

~~Table of Contents~~

~~Index to Financial Statements~~

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

To the extent that we engage in commodity-price risk-management activities to protect our cash flows from commodity-price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our commodity-price risk-management and trading activities may expose us to the risk of financial loss in certain circumstances, including instances in which the following occur:

~~our production is less than the notional volumes~~

~~a widening of price basis differentials occurs between delivery points for our production and the delivery point assumed in the derivative arrangement~~

~~the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements~~

~~a sudden unexpected event materially impacts oil, natural-gas, or NGLs prices~~


–	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



	RISK FACTORS	Table of Contents Index to Financial Statements

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

We are involved in ~~several~~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~~


–	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 ~~could have~~in a ~~material adverse effect on~~timely manner, our financial condition, results of ~~operations.~~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.

~~Table of Contents~~

~~Index to Financial Statements~~

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~~


–	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



	RISK FACTORS	Table of Contents Index to Financial Statements

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 ~~adversely affect the timing of activities.~~other hazardous substances.

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

~~Table of Contents~~

~~Index to Financial Statements~~

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

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



	RISK FACTORS	Table of Contents Index to Financial Statements

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

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

~~the validity of our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses, and costs~~

~~the assumption of environmental, decommissioning, and other liabilities, and losses or costs for which we are not indemnified or for which our indemnity is inadequate~~


–	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



	RISK FACTORS	Table of Contents Index to Financial Statements

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.

~~Table of Contents~~

~~Index to Financial Statements~~

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

Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the nomination and removal of directors, the prohibition of stockholder action by written consent and regulation of stockholders’ ability to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.

In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

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

We can provide no assurance that we will continue to pay dividends at the current rate or at all. As of February ~~2018,~~2019, our quarterly dividend was ~~$0.25~~$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 ~~integral to our operations will depend,~~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



	OTHER INFORMATION	Table of Contents Index to Financial Statements

Item 1B. Unresolved Staff Comments

None.

~~Table of Contents~~

~~Index to Financial Statements~~

Item 3. Legal Proceedings

The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including personal injury and death claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, development, production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, tribal, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.

WGR Operating, LP, a ~~wholly owned~~ subsidiary of the Company, is currently in negotiations with the EPA with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

In September 2018, Anadarko E&P Onshore LLC, a ~~wholly owned~~ subsidiary of the Company, ~~is currently in negotiations~~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. Although management cannot predict the outcome~~2015 and agreed to pay a penalty of ~~settlement discussions, it is likely a resolution of these matters will result in a fine or penalty in excess of $100,000.~~$350,000.

Kerr-McGee Oil and Gas Onshore, LP, a ~~wholly owned~~ subsidiary of the Company, is currently in negotiations with the State of Colorado’s Department of Public Health and Environment with respect to alleged noncompliance with the Colorado Air Quality Control Commission’s Regulations. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

Kerr-McGee Gathering, LLC, a ~~wholly owned~~ subsidiary of the Company, is currently in negotiations with the EPA and the Department of Justice with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Fort Lupton ~~complex. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result~~complex in ~~a fine or penalty in excess of $100,000.~~

In December 2017, the Company entered into a consent agreement and final order with the EPA with respect to alleged violations of the U.S. Resource Conservation and Recovery Act at certain facilities associated with the Gulf of Mexico and agreed to pay a penalty of approximately $1.4 million. There were no allegations that waste was improperly disposed of or released into the environment.

Delaware Basin Midstream, LLC, a subsidiary of the Company, is currently in negotiations with the EPA with respect to alleged noncompliance with certain Risk Management Plan regulations under the Clean Air Act at its Ramsey Gas Plant.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 ~~17—~~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.

49APC 2018 FORM 10-K | 51



	OTHER INFORMATION	Table of Contents Index to Financial Statements

PART II

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


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

MARKET INFORMATION, HOLDERS, AND DIVIDENDS

At January 31, ~~2018,~~2019, there were approximately ~~9,680~~9,074 holders of record of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock ~~Exchange. The following shows information regarding~~Exchange under the ~~market price of, and dividends declared and paid on, the Company’s common stock by quarter for 2017 and 2016:~~

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter
2017
Market Price
High $ 72.32
$ 64.15
$ 50.16
$ 54.45
Low $ 59.34
$ 43.45
$ 39.96
$ 46.75
Dividends $ 0.05
$ 0.05
$ 0.05
$ 0.05
2016
Market Price
High $ 50.39
$ 57.00
$ 63.84
$ 73.33
Low $ 28.16
$ 43.52
$ 50.23
$ 58.59
Dividends $ 0.05
$ 0.05
$ 0.05
$ 0.05

symbol “APC”.

The amount of future dividends paid to Anadarko common ~~stock dividends will depend~~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 ~~and will be determined~~deemed relevant by the ~~Board of Directors on a quarterly basis.~~Board. In ~~February~~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.

~~Table of Contents~~

~~Index to Financial Statements~~

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the Company at December 31, ~~2017:~~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))	(a) Number of securities to be issued upon exercise of outstanding options, warrants, and rights	(b) Weighted-average exercise price of outstanding options, warrants, and rights			(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column(a))
Equity compensation plans approved by security holders	6,567,944	$	71.44	27,094,327	6,356,970		$	67.00	20,246,444
Equity compensation plans not approved by security holders	—	—		—	—		—		—
Total	6,567,944	$	71.44	27,094,327	6,356,970		$	67.00	20,246,444

~~PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS~~

52 | APC 2018 FORM 10-K



	OTHER INFORMATION	Table of Contents Index to Financial Statements

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

The following sets forth information with respect to repurchases made by the Company of its shares of common stock during the fourth quarter of ~~2017~~: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⁾
October 1-31, 2017⁽³⁾
15,698,241
$ 48.13
15,679,096
$ 1,745,327,838
November 1-30, 2017 44,950
$ 51.09
—
$ 1,745,327,838
December 1-31, 2017 ⁽³⁾
6,239,532
$ 48.84
6,236,398
$ 1,440,745,052
Total 21,982,723
$ 48.34
21,915,494

~~_______________________________________________________________________________~~



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 ~~2017, (i) 21.9 million shares were purchased under the $3.0 Billion Share-Repurchase Program and (ii) 67~~2018, 109 thousand shares were ~~purchased~~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 ~~22—~~23—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

⁽²⁾

~~At December 31, 2017,~~During the fourth quarter of 2018, under the Share Repurchase Program, the Company ~~had~~ repurchased ~~through open-market and private transactions, approximately $1.1 billion~~4.8 million shares of common stock ~~under its share-repurchase program~~ in ~~place at year end, which was expanded by $500 million in February 2018 under~~ the ~~$3.0 Billion Share-Repurchase Program. In February 2018, the Company completed the repurchase of an additional 8.5 million shares as part of an ASR Agreement.~~open market for $250 million. For additional information, see Note ~~20—~~21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

⁽³⁾

~~In October 2017, the~~The Company ~~entered into an ASR Agreement to complete $1.0~~announced a $2.5 billion ~~of the $3.0 Billion~~ Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018 and ~~received an initial delivery of 15.7 million shares. The transaction~~$4.0 billion in July 2018. In November 2018, the program was ~~completed in December 2017, at which time the Company received an additional 5.1 million shares~~further expanded to settle the agreement. The settlement price was determined by the volume-weighted average price of the shares during the term less a negotiated settlement price adjustment. During the fourth quarter of 2017, the Company repurchased an additional 1.1 million shares for $59 million$5.0 billion and extended through ~~open-market purchases.~~June 30, 2020. For additional information, see Note ~~20—~~21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

51APC 2018 FORM 10-K | 53



	OTHER INFORMATION	Table of Contents Index to Financial Statements

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

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the S&P 500 Index, and in the peer group on December 31, ~~2012,~~2013, and its relative performance is tracked through December 31, ~~2017.~~ 2018.


Fiscal Year Ended December 31	2012		2013		2014		2015		2016		2017		2013		2014		2015		2016		2017		2018
Anadarko Petroleum Corporation	$	100.00	$	107.39	$	112.91	$	67.53	$	97.28	$	75.14	$	100.00	$	105.14	$	62.88	$	90.58	$	69.96	$	58.19
S&P 500	100.00		132.39		150.51		152.59		170.84		208.14		100.00		113.69		115.26		129.05		157.22		150.33
Peer Group	100.00		126.49		116.48		88.51		115.49		119.42		100.00		92.09		69.98		91.31		94.42		82.93

5254 | APC 2018 FORM 10-K



	OTHER INFORMATION	Table of Contents Index to Financial Statements

Item 6. Selected Financial Data


	Summary Financial Information ⁽¹⁾															Summary Financial Information ⁽¹⁾
millions except per-share amounts	2017			2016			2015			2014			2013
millions except per-share and employee amounts																2018			2017			2016			2015			2014
Sales Revenues(6)	$	10,969		$	8,447		$	9,486		$	16,375		$	14,867		$	13,070		$	10,969		$	8,447		$	9,486		$	16,375
Gains (Losses) on Divestitures and Other, net	939			(578		)	(788		)	2,095			(286		)	312			939			(578		)	(788		)	2,095
Total Revenues and Other	11,908			7,869			8,698			18,470			14,581			13,382			11,908			7,869			8,698			18,470
Operating Income (Loss)	(672		)	(2,599		)	(8,809		)	5,403			3,333			2,619			(565		)	(2,372		)	(8,743		)	5,438
Tronox-related Contingent Loss	—			—			5			4,360			850
Net Income (Loss) ⁽²⁾	(211		)	(2,808		)	(6,812		)	(1,563		)	941			752			(211		)	(2,808		)	(6,812		)	(1,563		)
Net Income (Loss) Attributable to Common Stockholders	(456		)	(3,071		)	(6,692		)	(1,750		)	801			615			(456		)	(3,071		)	(6,692		)	(1,750		)
Per Common Share (amounts attributable to common stockholders)
Net Income (Loss)—Basic	$	(0.85	)	$	(5.90	)	$	(13.18	)	$	(3.47	)	$	1.58		$	1.20		$	(0.85	)	$	(5.90	)	$	(13.18	)	$	(3.47	)
Net Income (Loss)—Diluted	$	(0.85	)	$	(5.90	)	$	(13.18	)	$	(3.47	)	$	1.58		$	1.20		$	(0.85	)	$	(5.90	)	$	(13.18	)	$	(3.47	)
Dividends	$	0.20		$	0.20		$	1.08		$	0.99		$	0.54		$	1.05		$	0.20		$	0.20		$	1.08		$	0.99
Average Number of Common Shares Outstanding—Basic	548			522			508			506			502			504			548			522			508			506
Average Number of Common Shares Outstanding—Diluted	548			522			508			506			505			504			548			522			508			506
Cash Provided by (Used in) Operating Activities ⁽³⁾	4,009			3,000			(1,877		)	8,466			8,888
Net Cash Provided by (Used in) Operating Activities ⁽³⁾																$	5,929		$	4,009		$	3,000		$	(1,877	)	$	8,466
Net Cash Provided by (Used in) Investing Activities																(5,982		)	(1,030		)	(2,742		)	(4,771		)	(6,472		)
Net Cash Provided by (Used in) Financing Activities																(3,177		)	(1,613		)	2,008			220			1,675
Capital Expenditures	$	5,300		$	3,314		$	5,888		$	9,256		$	8,523		$	6,185		$	5,300		$	3,314		$	5,888		$	9,256
Short-term Debt - Anadarko ⁽⁴⁾	$	142		$	42		$	32		$	—		$	500
Long-term Debt - Anadarko ⁽⁴⁾	12,054			12,162			12,945			12,595			11,576
Long-term Debt - WES and WGP	3,493			3,119			2,691			2,409			1,408
Total Debt	$	15,689		$	15,323		$	15,668		$	15,004		$	13,484
Long-term debt - Anadarko⁽⁴⁾																$	10,683		$	12,054		$	12,162		$	12,945		$	12,595
Long-term debt - WES and WGP																4,787			3,493			3,119			2,691			2,409
Total Stockholders’ Equity	10,696			12,212			12,819			19,725			21,857			8,496			10,696			12,212			12,819			19,725
Total Assets	$	42,086		$	45,564		$	46,331		$	60,879		$	55,340		$	40,376		$	42,086		$	45,564		$	46,331		$	60,879
Annual Sales Volumes
Annual Sales Volume
Oil (MMBbls)	129			116			116			106			91			141			129			116			116			106
Natural Gas (Bcf)	478			766			852			945			968			390			478			766			852			945
Natural Gas Liquids (MMBbls)	36			46			47			44			33
Natural-Gas Liquids (MMBbls)																37			36			46			47			44
Total (MMBOE) ⁽⁵⁾	245			290			305			308			285			243			245			290			305			308
Average Daily Sales Volumes
Average Daily Sales Volume
Oil (MBbls/d)	355			316			317			292			248			385			355			316			317			292
Natural Gas (MMcf/d)	1,309			2,093			2,334			2,589			2,652			1,069			1,309			2,093			2,334			2,589
Natural Gas Liquids (MBbls/d)	99			128			130			119			91
Total (MBOE/d)	672			793			836			843			781
Natural-Gas Liquids (MBbls/d)																103			99			128			130			119
Total (MBOE/d) ⁽⁵⁾																666			672			793			836			843
Proved Reserves
Oil Reserves (MMBbls)	658			702			713			929			851			667			658			702			713			929
Natural-gas Reserves (Tcf)	3.2			4.4			6.0			8.7			9.2			3.2			3.2			4.4			6.0			8.7
Natural-gas Liquids Reserves (MMBbls)	243			283			340			479			407			268			243			283			340			479
Total Proved Reserves (MMBOE)	1,439			1,722			2,057			2,858			2,792
Total Proved Reserves (MMBOE) ⁽⁵⁾																1,473			1,439			1,722			2,057			2,858
Number of Employees	4,400			4,500			5,800			6,100			5,700			4,700			4,400			4,500			5,800			6,100


⁽¹⁾	Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.


⁽²⁾	Includes a $1.2 billion one-time deferred tax benefit ~~of $1.2 billion~~ in 2017 related to Tax Reform ~~Legislation.~~Legislation and a $4.4 billion Tronox-related contingent loss in 2014.


⁽³⁾	Includes Tronox settlement payment of $5.2 billion in 2015.


⁽⁴⁾	Excludes WES and WGP.


⁽⁵⁾	Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.


⁽⁶⁾	2018 includes impact of adopting ASU 2014-09. See Note 2—Revenue from Contracts with Customers.

53APC 2018 FORM 10-K | 55

~~Table of Contents~~



	MANAGEMENT’S DISCUSSION AND ANALYSIS Index	Table of Contents Index to Financial Statements

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

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.



Index	Page

Management Overview	5457

Financial Results	5861

Liquidity and Capital Resources	7073

Critical Accounting Estimates	7882

Recent Accounting Developments	8385

56 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW	Table of Contents Index to Financial Statements

MANAGEMENT OVERVIEW

Anadarko’s ~~strategy is~~strategic objectives are to explore for, develop, and commercialize resources globally; ensure health, safety, and environmental excellence; focus on financial discipline, flexibility, and value creation; and demonstrate the Company’s core values in all its business activities. The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on commodity prices, which affect the value the Company receives from its sales of oil, natural gas, and NGLs.

~~Over the last several years,~~The Company continues to efficiently allocate capital in order to generate attractive returns on, and of, capital while investing within cash flow. Anadarko also continues to focus on cash-margin improvement and has actively managed its portfolio to focus on higher-return, oil-levered opportunities, namely in the Delaware and DJ basins in the U.S. onshore and the deepwater Gulf of Mexico. Anadarko has divested non-core gas-focused assets while also completing the GOM Acquisition in late 2016, which doubled the Company’s production in the Gulf of Mexico and strengthened its infrastructure and tie-back inventory. As a result of this portfolio transformation, the Company’s overall sales-volume product mix increased to 53% oil in 2017, compared to 40% in 2016, which significantly improved margins and returns.

~~Table of Contents~~

~~Index to Financial Statements~~

~~2018 Outlook~~ The Company’s 2018 capital program is designed to enhance shareholder value by delivering an attractive cash return on invested capital in a $50 oil (for both WTI and Brent) and $3 natural gas (Henry Hub) price environment while advancing the development of the Company’s core assets. If realized commodity prices are above investment assumptions, Anadarko plans to focus on returning value directly to the stockholders versus material increases to activity, capital expenditures, and greater production volume. The Company demonstrated this focus in February 2018, by announcing a 400% increase in the quarterly cash dividend to $0.25 per share, a $500 million expansion of its share-repurchase program, and its intent to reduce outstanding indebtedness by more than $1.0 billion by retiring 2018 and 2019 Anadarko debt maturities.

Anadarko currently estimates a 2018 initial capital spending range of $4.1 billion to $4.5 billion, excluding WES capital spending of approximately $1.0 billion to $1.1 billion. The Company has currently allocated approximately 86% of its 2018 capital spending budget to the U.S. onshore upstream and midstream and deepwater Gulf of Mexico; 8% to future value areas, which includes 5% to exploration and 3% to global LNG; 3% to international cash generation assets, such as oil projects in Algeria and Ghana; and 3% to corporate activities. The Company’s repositioned asset footprint and strong balance sheet are built to deliver through future commodity cycles.

~~Delaware Basin~~ Anadarko plans to allocate approximately $1.0 billion toward upstream and an additional $500 million toward Anadarko midstream investments. This program supports the continuation of the Company's efforts to build out one of the most expansive and integrated infrastructure positions in the region. The Company also is advancing its efforts to capture operatorship on 70% of its acreage position, primarily in Reeves and Loving counties. Additionally, Anadarko continues to progress the construction of three ROTFs to support its more cost-effective and environmentally beneficial tankless battery design field-wide, while also securing necessary gathering, processing, and takeaway capacity. This comprehensive build-out plan and phased development approach in the basin is expected to deliver incremental oil sales volumes during the second half of 2018, with total-year Delaware basin oil sales volumes expected to increase more than 50% relative to 2017. During 2018, the Company plans to average seven operated rigs and six completion crews.

~~DJ Basin~~ Anadarko expects to invest approximately $950 million on upstream activities and an additional $50 million toward Anadarko midstream investments. The Company has implemented a new completion design in the field, which has ~~resulted in a 20% improvement in average well recovery. Anadarko expects to increase year-over-year oil sales volumes from the DJ basin by more than 30% and plans to average five operated rigs and three completions crews in the basin during the year.~~

~~Deepwater Gulf of Mexico~~ Anadarko expects to allocate approximately $1.0 billion toward its deepwater Gulf of Mexico operations. The majority of these investments are expected to be directed toward high-return oil development opportunities near operated infrastructure at Lucius, Horn Mountain, Marlin, Holstein, and Marco Polo. The Company plans to operate two floating drillships and one platform rig and spud approximately nine development wells in the Gulf of Mexico during the year.

~~International~~ Anadarko plans to allocate approximately $150 million toward its international cash-generating operations in Algeria and Ghana. These investments will support further drilling in the TEN development area, which is expected to commence in early 2018, as well as additional drilling operations in the Jubilee field following the Ghanaian government's recent approval of the full-field plan of development.

~~Exploration~~ The Company's exploration investments in 2018 are expected to total approximately $200 million. Exploration spending will primarily be focused on the Gulf of Mexico, where the Company plans to drill identified prospects near existing operated infrastructure with one floating drillship. The Company plans to allocate additional exploration investment to the U.S. onshore as it continues to identify future areas that could make a material and scalable addition to its portfolio.

~~LNG~~ ~~The Company expects to invest approximately $150 million to advance the Mozambique LNG project toward FID. This includes funding Anadarko's portion~~ ~~of the costs associated with preparing the site of the future onshore LNG park.~~

~~Table of Contents~~

~~Index to Financial Statements~~

The Company announced a $2.5 billion share-repurchase program in September 2017, which was expanded to $3.0 billion in February 2018. The program is authorized through the end of 2018. During the fourth quarter of 2017, the Company repurchased 21.9 million shares for approximately $1.1 billion (average price of $48.33 per share) under an ASR Agreement and through open-market purchases. In February 2018, Anadarko completed a repurchase of 8.5 million shares for $500 million (average price of $58.82 per share) under an additional ASR Agreement. The Company plans to execute the remainder of the $3.0 Billion Share-Repurchase Program by the end of 2018.

In the fourth quarter of 2017, in order to reduce commodity-price risk and increase the predictability of 2018 cash flows, the Company entered into strategic derivative positions covering approximately 50% of its anticipated oil sales volumes for 2018. The Company entered into two-way collars for 108 MBbls/d, consisting of a sold call at $60.48 and a purchased put at $50.00 as well as fixed price swaps for 84 MBbls/d at an average price of $61.45. In January 2018, the Company entered into additional fixed-price swaps consisting of 280 MMBtu/d at an average price of $3.02, increasing its coverage to slightly more than 50% of its anticipated 2018 natural-gas sales volumes. See ~~Note 10—Derivative Instruments~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Item 8 of this Form 10-K.~~

~~Subsequent to year end, the Company divested its nonoperated interest in Alaska for net proceeds of $383 million. The transaction is subject to regulatory approval.~~

~~2017 Overview~~ ~~To effectively manage the influence of potential commodity-price volatility, Anadarko continued to optimize and further concentrate its portfolio~~ on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely in the Delaware and DJ basins in the U.S. onshore and in the deepwater Gulf of Mexico. ~~Much~~The Company plans to deploy a portion of its cash flow generated from its Gulf of Mexico, Algeria, Ghana, and DJ basin assets to fund investments in other assets that generate attractive cash returns, thereby improving the Company’s overall long-term cash-flow profile and ability to continue returning cash to investors.

2019 Outlook

The Company plans to continue focusing on returning capital directly to its investors. The Company demonstrated this focus in 2018 by increasing its quarterly cash dividend from $0.05 to $0.30 per share, expanding its authorized Share-Repurchase Program to $5 billion, and increasing its debt-reduction program to $2 billion. As of December 31, 2018, the Company had repurchased 65 million shares of its common stock for an average price of $57.69 per share. The Company expects to complete the remaining $1.25 billion of authorized share repurchases by mid-year 2020. As of December 31, 2018, Anadarko had retired more than $600 million of debt and plans to repay $900 million of debt maturing in the first half of 2019. An additional $500 million of debt reduction is anticipated through mid-year 2020. These actions demonstrate the cash-flow-generating strength of the ~~2017 operational~~Company’s asset portfolio and ~~investment focus was preparing~~the Company’s ongoing commitment to capital efficiency and returns.

At the end of 2018, the Company 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 ~~basin~~and DJ basins, to WES for ~~development~~approximately $4.0 billion, with ~~increased operatorship~~approximately $2.0 billion of cash proceeds and ~~infrastructure~~the balance to ~~facilitate long-term growth and value.~~

On December 22, 2017, the Tax Reform Legislation was signed into law. The Company recognized a one-time deferred tax benefit of $1.2 billion, inclusive of a $236 million increase to the Company’s valuation allowance on its foreign tax credit carryforwards, due to the remeasurement of its U.S. deferred tax assets and liabilities based on the 21% corporate tax rate. The Company did not recognize U.S. income tax expense related to the deemed repatriation of its foreign income as required by the new legislation as any U.S. taxes will be ~~offset with foreign tax credits. In a $60 WTI price environment, the Tax Reform Legislation~~paid in WES common units. This transaction is expected to increase WES’s cash distributions paid to Anadarko in 2019 and reduce Anadarko’s future midstream capital funding requirements associated with the divested assets. Additionally, WES announced that a wholly owned subsidiary of WGP will merge with and into WES to simplify its structure and lower the weighted-average cost of capital for the midstream entity via the elimination of incentive distribution rights. These transactions are expected to close in the first quarter of 2019 and should result in enhanced liquidity of Anadarko’s residual ownership of WGP securities.

APC 2018 FORM 10-K | 57



	MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW	Table of Contents Index to Financial Statements

The Company’s 2019 capital program is consistent with the Company’s ~~2018~~focus on enhancing shareholder value by delivering attractive cash ~~taxes by~~returns on invested capital in a $50 oil (for both WTI and Brent) and $3 natural-gas (Henry Hub) price environment while advancing the development of the Company’s core assets. Anadarko currently estimates a 2019 capital spending range of $4.3 billion to $4.7 billion, excluding WES. Anadarko expects to allocate approximately 70% of this 2019 capital investment to the U.S. onshore upstream and midstream resource plays; 16% to conventional oil plays in the deepwater Gulf of Mexico, Algeria, and Ghana; 10% to future value areas, which includes 6% to exploration and 4% to Mozambique LNG activities, excluding post-FID incremental spend; and 4% to corporate activities. The Company’s asset footprint and strong balance sheet are intended to perform through commodity cycles.


–	Delaware Basin Anadarko plans to allocate approximately $1.4 billion toward upstream activities. The successful expansion of the Company’s infrastructure footprint, including oil gathering and treating facilities throughout West Texas, is paving the way to transition to multi-well pad development. This phased development approach is expected to deliver incremental oil sales volume in 2019.


–	DJ Basin Anadarko expects to invest approximately $1.3 billion on upstream activities, with continued development of its minerals-interest ownership and infrastructure-advantaged position in the Wattenberg field. Anadarko expects to deliver incremental oil sales volume from the DJ basin in 2019.


–	Powder River Basin Anadarko expects to invest approximately $250 million toward upstream activities, including appraisal and delineation of its 300,000 gross acre position in the southern Powder River basin primarily targeting the Turner formation.

–

Gulf of Mexico Anadarko expects to allocate approximately $500 million toward its deepwater Gulf of Mexico operations. Although the capital allocation is lower than in 2018, the Company plans to deliver a similar number of wells in 2019 and maintain production levels around 140 MBOE/d. The majority of these investments are expected to be directed toward high-return oil development opportunities near operated infrastructure at Constellation, Holstein, Horn Mountain, K2, Lucius, and North Hadrian.


–	International Anadarko plans to allocate approximately $200 million toward its international operations in Algeria and Ghana. The investment in Ghana will be focused on adding incremental wells to optimize capacity at the Jubilee and TEN FPSO vessels.


–	Exploration The Company's exploration investments in 2019 are expected to total approximately $250 million. Exploration spending will primarily be focused on identifying material and scalable opportunities in the U.S. onshore and tie-back opportunities near existing operated facilities in the deepwater Gulf of Mexico.

–

LNG The Company expects to invest approximately $200 million in the Mozambique LNG project in 2019 on pre-FID activities. This includes Anadarko’s portion of the cost associated with ongoing site preparation for the shared onshore facilities. The Company remains on track for making a final investment decision in the first half of 2019, and anticipates adjusting its capital investment expectations associated with the Mozambique LNG project if the project is sanctioned.

~~Following~~WES currently estimates a ~~home explosion in Firestone, Colorado in April 2017, the Company took precautionary measures~~2019 total capital spending range of $1.3 to ~~shut in all operated vertical wells~~$1.4 billion. WES capital investment will be primarily focused in the DJ ~~basin to conduct additional inspections. It subsequently tested~~ and ~~permanently plugged, abandoned, and capped all one-inch return lines associated~~Delaware basins, with these wells. In May 2017, the Colorado Oil & Gas Conservation Commission issued a two-phase Notice to Operators (NTO) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and abandon all inactive flowlines in such areas. During the third quarter, the Company substantially completed the requirementsover 90% of the ~~NTO. In August 2017, following a three-month review of oil and gas operations, the Governor of Colorado announced several policy initiatives designed~~estimated 2019 total capital expenditures allocated to enhance public safety, which are to be implemented through rulemaking or legislation. The Company continues to work cooperatively with state regulators and others and is also cooperating with the NTSB in its investigation related to the accident.these two basins.

5658 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW	Table of Contents Index to Financial Statements

~~Significant 2017 operating and financial activities include the following:~~

Significant 2018 Operating and Financial Activities

Total Company

The Company’s oil sales volumes averaged 355 MBbls/d, representing a 12% increase from 2016, primarily due to increased volumes from the Gulf of Mexico, partially offset by the divestiture of certain U.S. onshore assets in 2017 and 2016.

~~The Company’s overall sales-volume product mix increased to 53% oil in 2017, compared to 40% in 2016, which significantly improved margins and returns.~~


–	The Company’s oil sales volume averaged 385 MBbls/d, representing a 9% increase from 2017, primarily due to increased volume from the DJ and Delaware basins, partially offset by the divestiture of certain U.S. onshore assets in 2017.


–	The Company’s overall oil sales-volume product mix increased to 58% in 2018, compared to 53% in 2017. The overall liquids sales-volume product mix increased to 73% in 2018, compared to 67% in 2017.

U.S. Onshore

Total sales volumes in the Delaware basin averaged 63 MBOE/d, representing a 41% increase from 2016, and oil sales volumes in the Delaware basin increased 13 MBbls/d, representing a 52% increase from 2016, primarily due to continued drilling and completion activities.

~~WES acquired a third party’s 50% nonoperated interest in the DBJV System in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash.~~

~~The Company received net proceeds of approximately $4.0 billion from divestitures of certain U.S. onshore assets during 2017.~~


–	Total sales volume in the Delaware basin averaged 109 MBOE/d, representing a 68% increase from 2017, and oil sales volume in the Delaware basin increased 27 MBbls/d, representing a 71% increase from 2017, primarily due to continued drilling and completion activities.


–	In the Delaware basin, the Reeves and Loving County ROTFs were completed, with 138 total wells flowing into the facilities by the end of 2018. In addition, the first train at the WES-owned Mentone natural-gas processing plant was placed in service during the fourth quarter, adding 200 MMcf/d of natural-gas processing capacity.


–	Oil sales volume in the DJ basin increased 14 MBbls/d, representing a 17% increase from 2017, primarily due to continued drilling and completion activities.


–	In the DJ basin, the sixth COSF train was placed in service, adding 30 MBbls/d of oil-stabilization capacity.


–	The Company received net proceeds of approximately $370 million from the divestiture of its nonoperated interest in Alaska.

Gulf of Mexico


–	Oil sales volume averaged 121 MBbls/d, remaining relatively flat compared to 2017, primarily due to natural production declines and planned downtime at various platforms, partially offset by new wells coming online at Horn Mountain, Holstein, Marlin, and Caesar Tonga.

Oil sales volumes averaged 121 MBbls/d, representing an 85% increase from 2016, primarily due to the GOM Acquisition and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017.Ghana


–	In the TEN field, the operator resumed drilling operations in early 2018, with one well brought online in 2018. Two additional wells were drilled in 2018, with completion activities ongoing at year end.


–	In the Jubilee field, the operator drilled two production wells during the second quarter of 2018, with the first of these wells brought online in the third quarter. The second well was brought online in the fourth quarter. Additionally, a previously drilled water injector well was brought online during the fourth quarter of 2018.


–	The operator of the Jubilee FPSO completed two shutdowns to effectively stabilize the turret and rotate the FPSO to its permanent heading. Completion of the spread-mooring anchoring system is expected in early 2019, with no further shutdowns anticipated.

~~International~~

APC 2018 FORM 10-K | 59

The International Tribunal for the Law of the Sea issued a ruling in September 2017 regarding the delimitation of the maritime boundary between Ghana and Côte d’Ivoire in the Atlantic Ocean. The new maritime boundary as determined by the tribunal does not affect the TEN fields, and the operator now plans to resume development drilling in early 2018.



	MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW	Table of Contents Index to Financial Statements

Interim spread mooring of the FPSO at the Jubilee field in Ghana commenced in the fourth quarter of 2016 and was completed during the first quarter of 2017. In early 2018, the operator will start the first of three shutdown periods that are expected to occur in 2018 to effectively stabilize the turret and rotate the FPSO to its permanent heading. In October, the partnership received Ghanaian Government approval for the full-field plan of development, with drilling operations expected to commence in 2018.

During the third quarter of 2017, the foundational legal and contractual framework was completed for the Company’s onshore LNG project in Mozambique. Anadarko commenced resettlement and site preparation activities, which will position the onshore area for construction of the LNG facilities.

~~Anadarko and its co-venturers in Offshore Area 1 in~~ Mozambique ~~reached agreement on the project’s first long-term sale and purchase agreement for 2.6 MTPA with Thailand’s national oil and gas company, subject to the approval of the Government of Thailand.~~


–	During 2018 and subsequent to year end, additional LNG sales and purchase agreements were executed, increasing contracted volumes to more than 7.5 MTPA, with an additional 2.0 MTPA of contracted volume anticipated prior to FID.


–	The Government of Mozambique approved the Development Plan for the Anadarko-operated, initial two-train Golfinho/Atum project.


–	The preferred offshore construction and installation contractor was selected in the fourth quarter of 2018, and the contracts with the onshore and offshore construction and installation contractors are being finalized ahead of making a final investment decision in the first half of 2019.


–	Site preparation activities are fully underway at the Afungi onshore site, as major infrastructure and resettlement projects are proceeding as planned, positioning the area for construction of the LNG facilities.


–	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.

Financial

~~The Company generated $4.0 billion of cash flow from operations and ended 2017 with $4.6 billion of cash.~~

~~Prior to the end of 2017, the Company completed $1.1 billion of the share repurchases. In February 2018, the Company completed an additional $500 million of share repurchases.~~

~~The Company recognized a one-time deferred tax benefit of $1.2 billion as a result of the Tax Reform Legislation.~~


–	The Company generated $5.9 billion of cash flow from operations and ended 2018 with $1.3 billion of cash.


–	The Company completed $2.7 billion of share repurchases and retired more than $600 million of debt.

5760 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

FINANCIAL RESULTS


millions except per-share amounts	2017			2016			2015			2018		2017			2016
Oil, natural-gas, and NGLs sales	$	8,969		$	7,153		$	8,260
Oil, natural-gas, and NGL sales										$	11,482	$	8,969		$	7,153
Gathering, processing, and marketing sales	2,000			1,294			1,226			1,588		2,000			1,294
Gains (losses) on divestitures and other, net	939			(578		)	(788		)	312		939			(578		)
Revenues and other	$	11,908		$	7,869		$	8,698		$	13,382	$	11,908		$	7,869
Costs and expenses	12,580			10,468			17,507			10,763		12,473			10,241
Other (income) expense	1,016			1,230			880			1,134		1,123			1,457
Income tax expense (benefit)	(1,477		)	(1,021		)	(2,877		)	733		(1,477		)	(1,021		)
Net income (loss) attributable to common stockholders	$	(456	)	$	(3,071	)	$	(6,692	)	$	615	$	(456	)	$	(3,071	)
Net income (loss) per common share attributable to common stockholders—diluted	$	(0.85	)	$	(5.90	)	$	(13.18	)	$	1.20	$	(0.85	)	$	(5.90	)
Average number of common shares outstanding—diluted	548			522			508			504		548			522

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the year ended December 31, 2018,” refer to the comparison of the year ended December 31, 2018, to the year ended December 31, 2017. Similarly, any increases or decreases “for the year ended December 31, 2017,” refer to the comparison of the year ended December 31, 2017, to the year ended December 31, 2016. ~~Similarly, any increases or decreases “for the year ended December 31, 2016,” refer to the comparison of the year ended December 31, 2016, to the year ended December 31, 2015.~~ The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales ~~volumes;~~volume; the cost of finding and developing such reserves; and operating costs.

58APC 2018 FORM 10-K | 61



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

REVENUES AND SALES VOLUME

~~Revenues and Sales Volumes~~

millions Oil Natural Gas NGLs Total
2016 sales revenues $ 4,668
$ 1,564
$ 921
$ 7,153
Changes associated with prices 1,334
373
358
2,065
Changes associated with sales volumes 550
(589 ) (210 ) (249 )
2017 sales revenues $ 6,552
$ 1,348
$ 1,069
$ 8,969
Increase/(decrease) vs. 2016 40 % (14 )% 16 % 25 %

2015 sales revenues $ 5,420
$ 2,007
$ 833
$ 8,260
Changes associated with prices (745 ) (241 ) 95
(891 )
Changes associated with sales volumes (7 ) (202 ) (7 ) (216 )
2016 sales revenues $ 4,668
$ 1,564
$ 921
$ 7,153
Increase/(decrease) vs. 2015 (14 )% (22 )% 11 % (13 )%

For ~~2017,~~2018, the ~~above~~ table below illustrates the effect of increases in commodity prices and changes associated with sales ~~volumes.~~volume. Sales volume changes during ~~2017~~2018 included increases ~~related to assets acquired~~associated with continued drilling and completion activities in the ~~Gulf of Mexico in December 2016 (primarily oil)~~Delaware and DJ basins and decreases associated with U.S. onshore asset divestitures ~~(primarily natural gas). For 2016, decreases~~ in ~~commodity prices were the main driver for the decrease in revenues.~~2017 and 2018.

The following provides Anadarko’s sales ~~volumes~~volume for the years ended December 31:

2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
Barrels of Oil Equivalent
(MMBOE except percentages)
United States 211
(18 )% 257
(5 )% 272
International 34
3
33
(1 ) 33
Total barrels of oil equivalent 245
(16 ) 290
(5 ) 305

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States 579
(18 )% 704
(5 )% 745
International 93
4
89
(1 ) 91
Total barrels of oil equivalent per day 672
(15 ) 793
(5 ) 836



	Barrels of Oil Equivalent (MMBOE)			Barrels of Oil Equivalent per Day (MBOE/d)
	2018	2017	2016	2018	2017	2016
United States	208	211	257	570	579	704
International	35	34	33	96	93	89
Total	243	245	290	666	672	793

Sales ~~volumes represent~~volume represents actual production ~~volumes~~volume adjusted for changes in commodity inventories as well as natural-gas production ~~volumes~~volume provided to satisfy a commitment under the Jubilee development plan in Ghana. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note ~~10—~~11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.

5962 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

~~Oil Sales Revenues, Average Prices, and Volumes~~

Oil Sales Revenues, Average Prices, and Volume

2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
Oil sales revenues (millions) $ 6,552
40 % $ 4,668
(14 )% $ 5,420

United States
Sales volumes—MMBbls 97
14 % 85
1 % 85
MBbls/d 266
14
233
1
232
Price per barrel $ 49.62
27
$ 39.06
(13 ) $ 45.00

International
Sales volumes—MMBbls 32
6 % 31
(2 )% 31
MBbls/d 89
6
83
(2 ) 85
Price per barrel $ 53.77
22
$ 43.93
(15 ) $ 51.68

Total
Sales volumes—MMBbls 129
12 % 116
— % 116
MBbls/d 355
12
316
—
317
Price per barrel $ 50.66
26
$ 40.34
(14 ) $ 46.79

~~The following summarizes primary drivers for the change in oil sales revenues:~~

millions Change in Revenues
Due to Change
in Prices

Due to Change
in Volumes
2017 vs. 2016 $ 1,884
$ 1,334
$ 550
2016 vs. 2015 (752 ) (745 ) (7 )



	2018		2017		2016
Oil sales revenues (millions)	$	9,206	$	6,552	$	4,668

Price per barrel
United States	$	64.01	$	49.62	$	39.06
International	70.38		53.77		43.93
Total	$	65.51	$	50.66	$	40.34

Sales volume (MMBbls)
United States	108		97		85
International	33		32		31
Total	141		129		116

Sales volume per day (MBbls/d)
United States	294		266		233
International	91		89		83
Total	385		355		316

Oil Prices

~~The average~~Anadarko’s realized oil price ~~Anadarko received decreased from 2015 through late 2016, primarily due to continued high petroleum inventories globally and stronger supply growth from OPEC. Oil prices~~ increased in late 2016 through 2017, primarily due to the expectation of decreasing global oversupply as a result of OPEC’s agreement to reduce production through the end of 2018. Oil prices continued to increase during most of 2018, primarily due to concerns of a supply shortfall as a result of reductions in output from Iran as the U.S. reimposed sanctions, as well as decreased production from Venezuela. Oil prices declined in the fourth quarter of 2018 due to concerns of oil demand weakness from a slowing global economy.

60APC 2018 FORM 10-K | 63



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

Oil Sales ~~Volumes~~Volume

2018 vs. 2017 The Company’s oil sales volume increased by 30 MBbls/d, primarily due to the following:

U.S. Onshore


–	Sales volume for the Delaware basin increased by 27 MBbls/d, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018.


–	Sales volume for the DJ basin increased by 14 MBbls/d, primarily due to continued drilling and completion activities in 2018.


–	Divestitures resulted in decreased sales volume of 16 MBbls/d, primarily related to the sale of the Alaska nonoperated assets in the first quarter of 2018 and the Eagleford and West Chalk assets in the first half of 2017.

Gulf of Mexico


–	Sales volume for the Gulf of Mexico remained flat, primarily due to natural production declines and planned downtime at various platforms, partially offset by new wells coming online at Horn Mountain, Holstein, Marlin, and Caesar Tonga throughout 2018.

2017 vs. 2016 The Company’s oil sales ~~volumes~~volume increased by 39 MBbls/d, primarily due to the following:

U.S. Onshore

~~Sales volumes for the Delaware basin increased by 13 MBbls/d, primarily due to continued drilling and completion activities in 2017.~~

~~Divestitures resulted in a decrease in sales volumes of 29 MBbls/d, primarily related to the sale of the Eagleford assets in the first half of 2017.~~


–	Sales volume for the Delaware basin increased by 13 MBbls/d, primarily due to continued drilling and completion activities in 2017.


–	Divestitures resulted in a decrease in sales volume of 29 MBbls/d, primarily related to the sale of the Eagleford assets in the first half of 2017.

Gulf of Mexico

Sales volumes increased by 56 MBbls/d, primarily due to the GOM Acquisition in December 2016 and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017.


–	Sales volume increased by 56 MBbls/d, primarily due to the GOM Acquisition in December 2016 and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017.

International

Sales volumes for Ghana increased by 9 MBbls/d, primarily due to a full year of liftings from the TEN development project, which came online late in the third quarter of 2016, and downtime in 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing. Shuttle tankers are conducting offtakes until the facility is permanently moored.

~~2016 vs. 2015~~ ~~The Company’s oil sales volumes remained relatively flat.~~

~~U.S. Onshore~~

~~Sales volumes for the Delaware basin increased by 8 MBbls/d, primarily due to continued field development.~~

~~Sales volumes for the DJ basin decreased by 6 MBbls/d, primarily due to reduced capital activity.~~

~~Sales volumes decreased by 7 MBbls/d, primarily due to the sale of EOR assets in the first half of 2015 and the East Chalk and Wamsutter assets in the first half of 2016.~~

~~Gulf of Mexico~~

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

~~International~~

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


–	Sales volume for Ghana increased by 9 MBbls/d, primarily due to a full year of liftings from the TEN development, which came online late in the third quarter of 2016, and downtime in 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing.

6164 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

~~Natural-Gas Sales Revenues, Volumes,~~

Natural-Gas Sales Revenues, Volume, and Average Prices

2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
Natural-gas sales revenues (millions) $ 1,348
(14 )% $ 1,564
(22 )% $ 2,007

United States
Sales volumes—Bcf 478
(38 )% 766
(10 )% 852
MMcf/d 1,309
(37 ) 2,093
(10 ) 2,334
Price per Mcf $ 2.82
38
$ 2.04
(14 ) $ 2.36



	2018		2017		2016
Natural-gas sales revenues (millions)	$	1,005	$	1,348	$	1,564

Price per Mcf	$	2.57	$	2.82	$	2.04

Sales volume (Bcf) ⁽¹⁾	390		478		766
Sales volume per day (MMcf/d) ⁽¹⁾	1,069		1,309		2,093

~~The following summarizes primary drivers for the change in natural-gas sales revenues:~~

millions Change in Revenues
Due to Change
in Prices

Due to Change
in Volumes
2017 vs. 2016 $ (216 ) $ 373
$ (589 )
2016 vs. 2015 (443 ) (241 ) (202 )


⁽¹⁾	All natural-gas sales volume originates in the United States.

Natural-Gas Prices

~~The average~~Anadarko’s realized natural-gas price Anadarko received decreased from 2015 through late 2016, primarily due to high gas storage levels in 2016. The increase in storage levels was a result of strong production growth in 2015 coupled with lower weather-driven residential and commercial demand in late 2015 and early 2016. This decrease was slightly offset by an increase in exports to Mexico throughout 2015 and 2016. The price increased ~~year-over-year~~ from 2016 to 2017, primarily due to a reduction of U.S. natural-gas storage ~~industry-wide~~ resulting from production declines across the industry from mid-2016 through early 2017 and stable exports to Mexico throughout 2017. In 2018, NYMEX prices were higher due to strong demand growth and low U.S. natural-gas storage. However, Anadarko’s realized natural-gas price decreased in 2018 due to wider regional differentials in its operated basins as strong production growth in the Delaware and DJ basins required higher utilization of gas pipeline takeaway capacity.

Natural-Gas Sales ~~Volumes~~Volume

2018 vs. 2017 The Company’s natural-gas sales volume decreased by 240 MMcf/d, primarily due to the sale of the Marcellus, Eagleford, and Utah CBM assets in the first half of 2017 and the Moxa assets in the second half of 2017.

2017 vs. 2016 The Company’s natural-gas sales ~~volumes~~volume decreased by 784 MMcf/d, primarily due to the sale of the Marcellus and Eagleford assets in the first half of 2017, the Carthage and Elm Grove assets in the second half of 2016, and the Wamsutter assets in the first half of 2016.

~~2016 vs. 2015~~APC ~~The Company’s natural-gas sales volumes decreased by 241 MMcf/d primarily due to the following:~~2018 FORM 10-K | 65

~~U.S. Onshore~~

~~Sales volumes for the DJ basin increased by 98 MMcf/d, primarily due to improved performance.~~



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

~~Sales volumes for the Delaware basin increased by 18 MMcf/d, primarily due to continued field development.~~

Sales volumes decreased by 290 MMcf/d, primarily due to the sale of the Powder River Basin CBM assets and the Freestone assets in the second half of 2015, the Carthage assets in the second half of 2016, and the Wamsutter assets in the first half of 2016.

~~Gulf of Mexico~~

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

~~Table of Contents~~

~~Index to Financial Statements~~

~~Natural-Gas Liquids Sales Revenues, Volumes,~~

Natural-Gas Liquids Sales Revenues, Volume, and Average Prices

2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
Natural-gas liquids sales revenues (millions) $ 1,069
16 % $ 921
11 % $ 833

Total
Sales volumes—MMBbls ⁽¹⁾
36
(23 )% 46
(1 )% 47
MBbls/d ⁽²⁾
99
(23 ) 128
(1 ) 130
Price per barrel $ 29.54
50
$ 19.64
12
$ 17.61

~~_______________________________________________________________________________~~



	2018		2017		2016
Natural-gas liquids sales revenues (millions)	$	1,271	$	1,069	$	921

Price per barrel	$	33.93	$	29.54	$	19.64

Sales volume (MMBbls) ⁽¹⁾	37		36		46
Sales volume per day (MBbls/d) ⁽¹⁾	103		99		128


⁽¹⁾	~~The percentage~~Approximately 95% of ~~NGLs~~NGL sales ~~volumes~~volume was from the ~~U.S. was 94%~~United States.

NGL Prices

Anadarko’s realized NGL price increased from 2016 to 2017, primarily due to increased domestic demand and higher exports. The average NGL price continued to increase during most of 2018, primarily due to increased demand for ethane to supply newly-constructed ethane cracker facilities. NGL prices declined in the fourth quarter of 2018 due to higher gas plant production of NGLs and loosening of infrastructure constraints.

NGL Sales Volume

2018 vs. 2017 The Company’s NGL sales volume increased by 4 MBbls/d, primarily due to the following:

U.S. Onshore


–	Sales volume for the Delaware basin increased by 9 MBbls/d, primarily due to continued drilling and completion activities and midstream infrastructure additions in ~~2017 and 96% in 2016 and 2015.~~2018.


⁽²⁾ –	~~The percentage~~Sales volume for other U.S. onshore assets decreased by 5 MBbls/d, primarily due to the sale of ~~daily NGLs sales volumes from~~ the ~~U.S. was 96%~~Eagleford and West Chalk assets in the first half of 2017 and ~~95%~~the Moxa assets in ~~2016 and 2015.~~the second half of 2017.

~~The following summarizes primary drivers for the change in NGLs sales revenues:~~

millions Change in Revenues
Due to Change
in Prices

Due to Change
in Volumes
2017 vs. 2016 $ 148
$ 358
$ (210 )
2016 vs. 2015 88
95
(7 )

~~NGLs Prices~~

~~The average NGLs price Anadarko received increased from 2015 to 2017, primarily due to increased ethane and propane prices stemming from higher exports and increased domestic demand.~~

~~NGLs Sales Volumes~~

2017 vs. 2016 The Company’s ~~NGLs~~NGL sales ~~volumes~~volume decreased by 29 MBbls/d, primarily due to the sale of the Eagleford assets in the first half of 2017 and the Carthage assets in the second half of 2016.

~~2016 vs. 2015~~ ~~The Company’s NGLs sales volumes were relatively flat.~~

6366 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

~~Gathering, Processing, and Marketing~~

millions except percentages 2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
Gathering, processing, and marketing sales $ 2,000
55 % $ 1,294
6 % $ 1,226
Gathering, processing, and marketing expense 1,560
44
1,087
3
1,054
Total gathering, processing, and marketing, net $ 440
113
$ 207
20
$ 172

Gathering, Processing, and Marketing



millions	2018		2017		2016
Gathering, processing, and marketing sales ⁽¹⁾	$	1,588	$	2,000	$	1,294
Gathering, processing, and marketing expense ⁽¹⁾	1,047		1,552		1,083
Gathering, processing, and marketing, net	$	541	$	448	$	211

⁽¹⁾

As a result of adopting ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as of January 1, 2018, gathering, processing, and marketing sales decreased by $1.0 billion for the year ended December 31, 2018, and gathering, processing, and marketing expenses decreased by $1.0 billion for the year ended December 31, 2018. Refer to Note 2—Revenue from Contracts with Customersin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information.

Gathering and processing sales include fee revenue earned by providing gathering, processing, compression, and treating services to third parties as well as revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko. The net margin from the sale of NGLs and residue gas for service customers when Anadarko is acting as ~~well as fee revenue earned by providing gathering, processing, compression, and treating services to third parties.~~an agent is also included. Gathering and processing expense includes the cost of third-party natural gas purchased and processed by Anadarko as well as transportation and other operating ~~and transportation~~ expenses related to the Company’s costs to perform gathering and processing ~~activities. Beginning in 2018, gathering and processing sales and expenses are expected to be impacted by ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606).~~ ~~See~~ ~~Note 1—Summary of Significant Accounting Policies~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Item 8 of this Form 10-K~~activities for ~~further information.~~third parties.

Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Marketing expense includes transportation and other operating expenses related to the Company’s costs to perform third-party marketing activities.

~~2017~~2018 vs. ~~2016~~ 2017Gathering, processing, and marketing, net increased by ~~$233~~$93 million. This increase primarily related to higher third-party throughput ~~volumes~~volume at the West Texas Complex, which were partially due to increased capacity from the 200 MMcf/d cryogenic train that commenced service in December 2017, and increased third-party throughput volume and rates at the DJ Basin Complex. These increases were partially offset by decreased marketing margins related to pricing on NGL inventory.

2017 vs. 2016Gathering, processing, and marketing, net increased by $237 million. This increase primarily related to higher third-party throughput volume and prices at the DBM Complex due to increased processing capacity from the start-up of newly constructed facilities in May and October 2016 and previously existing facilities returning to service after the 2016 outage at the DBM Complex.

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

~~Gains (Losses) on Divestitures and Other, net~~

millions except percentages 2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
Gains (losses) on divestitures, net $ 674
189 % $ (757 ) 26 % $ (1,022 )
Other 265
48
179
(24 ) 234
Total gains (losses) on divestitures and other, net $ 939
NM
$ (578 ) 27
$ (788 )

Gains (Losses) on Divestitures and Other, net



millions	2018		2017		2016
Gains (losses) on divestitures, net	$	20	$	674	$	(757	)
Other	292		265		179
Total gains (losses) on divestitures and other, net	$	312	$	939	$	(578	)

Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues, including ~~hard-minerals royalties,~~ earnings (losses) from equity investments, hard-minerals royalties, and other revenues.

During the years presented, Anadarko divested of certain non-core U.S. onshore and Gulf of Mexico assets. See Note ~~3—Acquisitions,~~ 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.

64APC 2018 FORM 10-K | 67



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

~~Costs and Expenses~~COSTS AND EXPENSES

The following provides Anadarko’s total costs and expenses for the years ended December 31:


millions	2017		2016		2015		2018		2017		2016
Oil and gas operating	$	1,000	$	811	$	1,014	$	1,153	$	988	$	807
Oil and gas transportation	914		1,002		1,117		878		914		1,002
Exploration	2,541		946		2,644		459		2,535		944
Gathering, processing, and marketing	1,560		1,087		1,054		1,047		1,552		1,083
G&A	1,075		1,440		1,176		1,084		994		1,223
DD&A	4,279		4,301		4,603		4,254		4,279		4,301
Production, property, and other taxes	582		536		553		826		582		536
Impairments	408		227		5,075		800		408		227
Other operating expense	221		118		271		262		221		118
Total	$	12,580	$	10,468	$	17,507	$	10,763	$	12,473	$	10,241

~~Oil and Gas Operating and Transportation Expenses~~

2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
Oil and gas operating (millions) $ 1,000
23 % $ 811
(20 )% $ 1,014
Oil and gas operating—per BOE 4.08
46
2.79
(16 ) 3.32
Oil and gas transportation (millions) 914
(9 ) 1,002
(10 ) 1,117
Oil and gas transportation—per BOE 3.73
8
3.46
(5 ) 3.66

Oil and Gas Operating Expenses



	2018		2017		2016
Oil and gas operating (millions)	$	1,153	$	988	$	807
Oil and gas operating—per BOE	4.74		4.03		2.78

~~Oil and Gas Operating Expenses~~

~~2017~~2018 vs. ~~2016~~ 2017Oil and gas operating expenses increased by ~~$189~~$165 million, primarily due to the following:


–	higher U.S. onshore costs of $140 million, primarily related to increased operating and nonoperating activity in the DJ and Delaware basins, partially offset by lower expenses of $74 million as a result of U.S. onshore asset divestitures


–	higher non-operating costs of $54 million in Ghana, primarily due to the Jubilee FPSO turret repair and additional wells coming online in 2018


–	higher operating costs of $32 million, primarily related to maintenance at various platforms in GOM

~~higher~~

2017 vs. 2016Oil and gas operating ~~costs of $212~~expenses increased by $181 million, primarily ~~related~~due to the ~~GOM Acquisition~~following:

~~higher operating costs of $88 million related to increased activity in the DJ and Delaware basins and costs related to the Company’s response efforts in Colorado in 2017~~

lower nonoperating costs of $12 million in Ghana primarily related to FPSO maintenance costs in 2016, partially offset by higher costs in 2017 due to increased production from the TEN development, which came online late in the third quarter of 2016

~~lower expenses of $89 million as a result of U.S. onshore asset divestitures~~


–	higher operating costs of $212 million, primarily related to the GOM Acquisition


–	higher operating costs of $84 million related to increased activity in the DJ and Delaware basins and costs related to the Company’s response efforts in Colorado in 2017


–	lower nonoperating costs of $12 million in Ghana, primarily related to FPSO maintenance costs in 2016, partially offset by higher costs in 2017 due to increased production from the TEN development, which came online late in the third quarter of 2016


–	lower expenses of $89 million as a result of U.S. onshore asset divestitures

The related costs per BOE increased ~~by $1.29~~from 2016 to 2018, primarily due to increased costs as a result of shifting to a higher-return, oil-levered portfolio that includes the Gulf of Mexico and Delaware basin, which operate at a higher cost compared to the lower-return, gas-levered divested assets.

~~2016~~68 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

Oil and Gas Transportation Expenses



	2018		2017		2016
Oil and gas transportation (millions)	$	878	$	914	$	1,002
Oil and gas transportation—per BOE	3.61		3.73		3.46

2018 vs. ~~2015~~ 2017Oil and gas ~~operating~~transportation expenses decreased by ~~$203~~$36 million, primarily due to ~~the following:~~

~~lower workover~~U.S. onshore divestitures and increased transportation costs ~~of $28 million~~related to sales from storage in 2017, partially offset by increased oil sales volume in the ~~Gulf of Mexico and the U.S. onshore~~

~~lower surface maintenance costs of $16 million~~Delaware basin in ~~the U.S. onshore and the Gulf of Mexico~~

~~lower expenses of $112 million as a result of divestitures~~

~~Table of Contents~~

~~Index to Financial Statements~~

2018. Oil and ~~Gas Transportation Expenses~~gas transportation expenses per BOE remained relatively flat.

2017 vs. 2016Oil and gas transportation expenses decreased by $88 million, primarily due to 2017 and 2016 U.S. onshore divestitures, partially offset by increased oil and gas sales ~~volumes~~volume in the Gulf of Mexico and increased rates atin the DJ basin. Oil and gas transportation expenses per BOE increased by $0.27 primarily due to increased oil and natural-gas transportation rates atin the DJ basin.

~~2016 vs. 2015~~ Oil and gas transportation expenses decreased by $115 million due to overall lower natural-gas sales volumes attributable to divestitures. Oil and gas transportation expenses per BOE decreased by $0.20 primarily due to lower costs as a result of lower natural-gas sales volumes.

Exploration Expense


millions	2017		2016		2015		2018		2017		2016
Dry hole expense	$	1,433	$	397	$	1,052	$	87	$	1,433	$	397
Impairments of unproved properties	788		216		1,215		159		788		216
Geological and geophysical, exploration overhead, and other expense	320		333		377		213		314		331
Total exploration expense	$	2,541	$	946	$	2,644	$	459	$	2,535	$	944

Dry Hole Expense

~~2017~~ 2018


–	$87 million related to unsuccessful drilling activities, primarily in the Gulf of Mexico

$437 million related to the Shenandoah project, $215 million related to the Phobos project, and $108 million related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development2017

~~$329 million related to all remaining wells in Côte d’Ivoire, where the Company relinquished its interest in its Cote d'Ivoire blocks~~

~~$243 million related to certain wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater natural-gas development~~


–	$437 million related to the Shenandoah project, $215 million related to the Phobos project, and $108 million related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development


–	$329 million related to all remaining wells in Côte d’Ivoire, where the Company relinquished its interest in all of its exploration blocks


–	$243 million related to certain wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater natural-gas development

2016

~~$231 million related to certain wells in the Gulf of Mexico and $92 million related to certain wells in Mozambique~~

~~$39 million for a well in Côte d’Ivoire that finished drilling in the third quarter of 2016 and encountered noncommercial quantities of hydrocarbons~~

~~2015~~

~~$746 million primarily related to Brazil where the Company did not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment~~

~~$306 million due to unsuccessful drilling activities in 2015 primarily in Colombia and the Gulf of Mexico~~


–	$231 million related to certain wells in the Gulf of Mexico and $92 million related to certain wells in Mozambique


–	$39 million for a well in Côte d’Ivoire that finished drilling in the third quarter of 2016 and encountered noncommercial quantities of hydrocarbons

See Note 6—7—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

~~Table of Contents~~

~~Index to Financial Statements~~

Impairments of Unproved Properties

~~2017~~ For discussion related to impairments of unproved properties, see Note 6—Impairmentsin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-K.

APC 2018 FORM 10-K | 69



•	~~The Company recognized a $610 million impairment~~MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of ~~unproved Gulf of Mexico properties, of which $463 million related~~Contents Index to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr McGee Corporation in 2006. For additional details on the Shenandoah project, see ~~Note 6—Suspended Exploratory Well Costs~~ ~~in the~~ ~~Notes to Consolidated~~ Financial Statements ~~under Item 8 of this Form 10-K.~~

~~The Company recognized $88 million of impairments of unproved international properties.~~

~~2016~~

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

~~2015~~

The Company recognized a $935 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unproved Gulf of Mexico property as a result of lower commodity prices.

~~The Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.~~

~~G&A~~

millions except percentages 2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
G&A $ 1,075
(25 )% $ 1,440
22 % $ 1,176

G&A



millions	2018		2017		2016
G&A	$	1,084	$	994	$	1,223

2018 vs. 2017G&A increased by $90 million, primarily due to an increase in employee-related expenses of $31 million, higher legal and consulting fees of $23 million and higher contract labor costs of $13 million.

2017 vs. 2016G&A decreased by ~~$365~~$229 million for the year ended December 31, 2017. Excluding ~~$389~~$192 million of charges recorded in 2016 associated with the workforce reduction program, G&A remained relatively flat. See Note ~~18—~~19—Restructuring Charges in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

DD&A



millions	2018		2017		2016
DD&A	$	4,254	$	4,279	$	4,301

~~2016~~2018 vs. ~~2015~~ 2017GDD&A ~~for the year ended December 31, 2016, included $389 million of charges associated with a workforce reduction program initiated in March 2016. Excluding the workforce reduction expenses, G&A~~expense decreased by ~~$125~~$25 million, primarily due to ~~lower employee-related expenses resulting from~~ the ~~workforce reduction.~~following:


–	$140 million decrease, primarily related to divestitures associated with U.S. onshore properties in 2018 and 2017 and a lower DD&A rate in 2018 driven by increased proved developed reserves in Ghana

These decreases were offset by the following:

~~Table of Contents~~

~~Index to Financial Statements~~

~~DD&A~~

millions except percentages 2017 Inc (Dec)
vs. 2016 2016 Inc (Dec)
vs. 2015 2015
DD&A $ 4,279
(1 )% $ 4,301
(7 )% $ 4,603


–	$62 million increase in ARO accretion expense due to increased ARO estimates in the Gulf of Mexico


–	$53 million increase in straight line depreciation related to newly constructed pipelines and salt water disposal facilities in the Delaware basin

2017 vs. 2016DD&A expense decreased by $22 million, primarily due to the following:

~~$717 million related to lower 2017 sales volumes and asset property balances associated with U.S. onshore properties as a result of divestitures in 2016 and 2017~~


–	$717 million related to lower 2017 sales volume and asset property balances associated with U.S. onshore properties as a result of divestitures in 2016 and 2017

These decreases were offset by the following:

~~$457 million related to higher sales volumes in the Gulf of Mexico primarily due to the GOM Acquisition~~

~~$240 million related to international production DD&A primarily due to higher sales volumes~~


–	$457 million related to higher sales volume in the Gulf of Mexico, primarily due to the GOM Acquisition


–	$240 million related to international production DD&A, primarily due to higher sales volume from the Ghana TEN project, which came online late in the third quarter of 2016

Production, Property, and Other Taxes



millions	2018		2017		2016
U.S. production and severance taxes	$	164	$	90	$	80
Algeria exceptional profits taxes	405		289		280
Ad valorem taxes	254		196		163
Other	3		7		13
Total production, property, and other taxes	$	826	$	582	$	536

~~2016~~2018 vs. ~~2015~~ 2017~~DD&A expense decreased~~Production, property and other taxes increased by ~~$302~~$244 million, primarily due to an increase in ad valorem and U.S. production and severance taxes driven by higher sales volume and commodity prices in the ~~following:~~

~~lower carrying value for U.S. onshore~~Delaware and ~~midstream properties as a result of 2015 asset impairments and divestitures in 2015 and 2016~~

~~lower 2016 sales volumes associated with U.S. onshore properties~~DJ basins. Additionally, Algeria exceptional profits taxes increased due to higher commodity prices.

2017 vs. 2016Production, property and other taxes increased by $46 million, primarily due to an increase in commodity prices.

70 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

Impairments

The Company recognized the following impairments for the years ended December 31:


millions	2017		2016		2015		2018		2017		2016
Exploration and Production
U.S. onshore properties	$	2	$	28	$	3,684	$	347	$	2	$	28
Gulf of Mexico properties	227		27		349		27		227		27
Cost-method investment	—		59		3		—		—		59
WES Midstream	176		16		515		228		176		16
Other Midstream	2		57		524		53		2		57
Other	1		40		—		145		1		40
Total impairments ⁽¹⁾	$	408	$	227	$	5,075	$	800	$	408	$	227


⁽¹⁾	~~In 2015, $3.0 billion of Exploration and Production impairments and $482 million of Other Midstream impairments related to Greater Natural Buttes.~~

See Note 5—6—Impairments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on impairments and Risk Factors under Item 1A of this Form 10-K for further discussion on the risks associated with oil, natural-gas, and ~~NGLs~~NGL prices.

~~Table of Contents~~

~~Index to Financial Statements~~

Other (Income) Expense

The following provides Anadarko’s other (income) expense for the years ended December 31:


millions	2017			2016			2015			2018			2017		2016
Interest expense ⁽¹⁾	$	932		$	890		$	825		$	947		$	932	$	890
Loss on early extinguishment of debt ⁽²⁾	2			155			—
(Gains) losses on early extinguishment of debt ⁽²⁾										(2		)	2		155
(Gains) losses on derivatives, net ⁽³⁾	135			286			(99		)	130			135		286
Other (income) expense, net	(53		)	(101		)	154			59			54		126
Total	$	1,016		$	1,230		$	880		$	1,134		$	1,123	$	1,457


⁽¹⁾	~~The increase in interest~~Interest expense increased from 2016 to 2017 is primarily due to lower capitalized interest in 2017. See Note ~~12—~~13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


⁽²⁾	See ~~Note 12—Debt and Interest Expense~~Financing Activities in ~~the~~ ~~Notes to Consolidated Financial Statements~~Liquidity and Capital Resources ~~under Item 8 of this Form 10-K~~ for ~~information on early extinguishment of debt.~~additional information.


⁽³⁾	See Note ~~10—~~11—Derivative Instruments intheNotes toConsolidatedFinancialStatementsunderItem 8ofthisForm10-K.

APC 2018 FORM 10-K | 71



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents Index to Financial Statements

Income Tax Expense (Benefit)

Total income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate to income (loss) before income taxes. The following summarizes the sources of these differences for the years ended December 31:


millions except percentages	2017			2016			2015			2018			2017			2016
Income tax expense (benefit)	$	(1,477	)	$	(1,021	)	$	(2,877	)	$	733		$	(1,477	)	$	(1,021	)
Income (loss) before income taxes	$	(1,688	)	$	(3,829	)	$	(9,689	)	$	1,485		$	(1,688	)	$	(3,829	)
Effective tax rate	88		%	27		%	30		%	49		%	88		%	27		%

In 2017, as a result of the Tax Reform Legislation, the Company recognized a one-time deferred tax benefit of $1.2 billion primarily due to the remeasurement of its U.S. deferred tax assets and liabilities, resulting in an 88% effective tax rate. Excluding this one-time benefit, the Company’s effective tax rate would have been 18%. The Company remeasured its U.S. deferred tax assets and liabilities based on the reduction of the U.S. corporate tax rate from 35% to 21%. After completing the accounting for income tax effects related to the adoption of the Tax Reform Legislation in 2018, the Company revised the provisional amount and recognized an additional current tax benefit of $26 million offset by deferred tax expense of $121 million. Excluding the impact from the Tax Reform Legislation, the Company’s 2018 effective tax rate would have been 43%.

The Company’s effective tax rate is impacted each year by the relative ~~pretax~~pre-tax income (loss) earned by the Company’s operations in the U.S., Algeria, and the rest of the world. The Company is subject to statutory tax rates of 38% in Algeria and 35% in Ghana. These higher-taxed foreign operations as well as non-deductible Algerian exceptional profits tax for Algerian income tax purposes generally cause the Company’s effective tax rate to vary significantly from the U.S. corporate tax rate. Additionally, the Company’s effective tax rate is typically impacted by net changes in uncertain tax positions, income attributable to noncontrolling interests, state income taxes (net of federal benefit), ~~non-deductible Algerian exceptional profits tax for Algerian income tax purposes, net changes in uncertain tax positions,~~ and dispositions of non-deductible goodwill. Excluding the ~~one-time benefit~~impact related to the Tax Reform Legislation in 2017 and 2018, the Company’s effective tax rate increased from 18% in 2017 to 43% in 2018 primarily due to higher-taxed income earned in Algeria relative to the Company’s pretax income in the United States. The Company’s effective tax rate decreased from 27% in 2016 to 18% in 2017, primarily due to the higher-taxed income earned in Algeria relative to the Company’s pretax losses in the U.S. and Ghana as well as the impact of international exploration pretax losses with no associated tax benefit. ~~The Company’s effective tax rate decreased from 30% in 2015 to 27% in 2016 primarily due to the reversal of non-deductible goodwill due to asset divestitures in 2016.~~

~~The Company generated a net operating loss in 2016 and filed a carryback claim for a tax refund of $159 million, which was received in December 2017.~~

The Company received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. ~~The~~In April 2018, the IRS ~~has~~ issued a ~~draft~~final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s refund claim. As a result, the Company filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018, and pursuant to standard U.S. Tax Court procedures, is not required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the Tax Court, the court will issue an opinion and then enter a decision. If the ~~payment is ultimately determined to~~Company does not ~~be deductible,~~prevail on the issue, the earliest potential date the Company ~~would~~might be required to repay the ~~tentative~~ refund ~~previously~~ received, plus interest, ~~and~~would be 91 days after entry of the decision. At such time, the Company would ~~be required to~~ reverse the portion of the $346 million net benefit ~~of $346 million~~ previously recognized in its consolidated financial ~~statements.~~statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company asserts its position in the Tax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not anticipate a decision to be entered within the next three years.

For additional information on income taxes, see Note ~~13—~~14—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

6972 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

LIQUIDITY AND CAPITAL RESOURCES


millions	2017			2016			2015			2018			2017			2016
Net cash provided by (used in) operating activities	$	4,009		$	3,000		$	(1,877	)	$	5,929		$	4,009		$	3,000
Net cash provided by (used in) investing activities	(1,028		)	(2,762		)	(4,771		)	(5,982		)	(1,030		)	(2,742		)
Net cash provided by (used in) financing activities	(1,613		)	2,008			220			(3,177		)	(1,613		)	2,008

~~Overview~~

Overview

The Company has a variety of funding sources available, including cash, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through asset divestitures and joint-venture arrangements that reduce future capital expenditures, the Company’s credit ~~facilities,~~facility, and access to both debt and equity capital markets. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units.

During ~~2017,~~2018, Anadarko repurchased $2.7 billion of shares under the Share-Repurchase Program, retired more than $600 million of debt, and received net proceeds of ~~$4.0 billion~~$417 million from divestitures, primarily related to the sale of the Company’s ~~Eagleford, Marcellus, Eaglebine, Utah CBM, and Moxa assets. As of December 31, 2017,~~nonoperated interests in Alaska. Anadarko had ~~$4.6~~$1.3 billion of cash ~~plus $5.0~~at December 31, 2018. Following the expiration of the 364-Day Facility in January 2019, the Company has $3.0 billion of borrowing capacity under ~~its RCFs. In January 2018,~~ the ~~Company received net proceeds of $383 million from the divestiture of its nonoperated interest in Alaska.~~APC RCF. Anadarko believes that its current available cash, anticipated proceeds from the sale of midstream assets to WES, and ~~anticipated~~future operating cash flows will be sufficient to fund the Company’s projected long-term operational and capital programs, ~~as well as to~~ fund the ~~increase in~~increased dividends, ~~to $0.25 per share, to repurchase~~and complete both the ~~remaining shares under the $3.0 Billion~~ Share-Repurchase Program byand the end of 2018, and to retire Anadarko’s debt maturing in 2018 and 2019. In a $60 WTI price environment, the Tax Reform Legislation is expected to reduce the Company’s 2018 cash taxes by approximately $200 million.debt-reduction program. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions.

In order to reduce commodity-price risk and increase the predictability of 2019 cash flows, the Company entered into strategic derivative positions covering approximately 21% of its anticipated oil sales volume for 2019. The Company entered into three-way collars for 87 MBbls/d, consisting of a sold call at $72.98, a purchased put at $56.72, and a sold put at $46.72. See Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Credit Rating

~~Credit Rating~~As of December 31, ~~2017,~~2018, the Company’s long-term debt was rated investment grade (BBB) by both S&P and Fitch and below investment grade (Ba1) by Moody’s. Subsequent to year end, Moody’s changed its outlook with respect to its rating from stable to positive. As a result of Moody’s Ba1 rating, Anadarko is more likely to be required to post collateral in the form of letters of credit or cash under certain contractual arrangements, such as derivative instruments, pipeline transportation contracts, and oil and gas sales contracts. Collateral related to credit-risk-related contingent features for which a net liability position existed was $66 million at December 31, 2018, and $170 million at December 31, ~~2017, and $117 million at December 31, 2016.~~2017. For more information on credit-risk considerations, see Note ~~10—~~11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. The amount of letters of credit or cash provided as assurance of the Company’s performance under pipeline transportation contracts and oil and gas sales contracts with respect to credit-risk-related contingent features was $260 million at December 31, 2018, and $263 million at December 31, ~~2017, and $274 million at December 31, 2016.~~2017.

70APC 2018 FORM 10-K | 73



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

~~Operating Activities~~

Operating Activities

One of the primary sources of variability in the Company’s cash flows from operating activities is the fluctuation in commodity prices, the impact of which Anadarko partially mitigates by periodically entering into commodity derivatives. ~~Sales volume~~Sales-volume changes also impact cash flow but historically have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are also impacted by the costs related to operations and interest payments related to the Company’s outstanding debt.

Cash flows from operating activities were $5.9 billion for 2018, $1.9 billion higher compared to 2017, primarily due to higher sales revenues resulting from higher oil prices.

Cash flows from operating activities were $4.0 billion for 2017, $1.0 billion higher compared to 2016, primarily due to higher sales revenues resulting from higher commodity prices. Additional significant items impacting operating activities for 2016 were ~~impacted by several significant items, including~~ the $159.5 million payment of the Clean Water Act (CWA) penalty, $247 million related to severance costs and retirement benefits paid in connection with the workforce reduction program, and the receipt of an $881 million tax refund related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback. Excluding these 2016 items, cash flows from operating activities for 2017 were $1.5 billion higher compared to 2016, primarily as a result of higher sales revenues due to the impact of higher commodity prices.

Cash flows from operating activities for 2015 were impacted by the $5.2 billion Tronox settlement payment. Excluding the Tronox settlement payment in 2015 and the significant 2016 items mentioned above, cash flows from operating activities for 2016 were $813 million lower compared to 2015, primarily as a result of lower sales revenues due to the impact of lower commodity prices.

See Note ~~13—~~14—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion related to the potential repayment of the 2016 tax refund.

Pension and Other Postretirement Contributions Contributions to the pension and other postretirement plans were $244 million in 2018, $276 million in 2017, and $120 million in ~~2016, and $58 million in 2015.~~2016. The Company expects to contribute ~~$152~~$155 million in ~~2018~~2019 to its pension and other postretirement plans.

74 | APC 2018 FORM 10-K

~~Investing Activities~~



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

Investing Activities

Capital Expenditures The following presents the Company’s capital expenditures:


millions	2017			2016			2015			2018			2017			2016
Cash Flows from Investing Activities
Additions to properties and equipment ⁽¹⁾	$	5,031		$	3,505		$	6,067		$	6,183		$	5,031		$	3,505
Adjustments for capital expenditures
Changes in capital accruals	275			(205		)	(226		)	(3		)	275			(205		)
Other	(6		)	14			47			5			(6		)	14
Total capital expenditures ⁽²⁾	$	5,300		$	3,314		$	5,888		$	6,185		$	5,300		$	3,314

Exploration and Production and other capital expenditures	$	3,886		$	2,764		$	5,118		$	4,264		$	3,884		$	2,763
WES Midstream capital expenditures	956			491			525			1,178			956			491
Other Midstream capital expenditures	458			59			245			743			460			60


⁽¹⁾	Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells, whether or not they were deemed to have a commercially sufficient quantity of proved reserves.


⁽²⁾	Capital expenditures exclude the FPSO capital lease asset; see Financing Activities—Capital Lease Obligations below.

~~Table~~2018 vs. 2017 The Company’s capital expenditures increased by $885 million for the year ended December 31, 2018. Exploration and Production capital expenditures increased primarily due to higher development costs of ~~Contents~~

~~Index~~$809 million driven by increased drilling and completion activities primarily in the DJ and Delaware basins and the Gulf of Mexico. Exploration costs decreased by $485 million primarily related to ~~Financial Statements~~

decreased exploration drilling in the Gulf of Mexico, Côte d’Ivoire, and Colombia. Other Midstream capital expenditures increased $283 million due to infrastructure build-out primarily in the Delaware basin. WES Midstream capital expenditures increased $222 million primarily related to infrastructure build-out in the Delaware and DJ basins.

2017 vs. 2016 The Company’s capital expenditures increased by $2.0 billion for the year ended December 31, 2017. Exploration and Production capital expenditures increased primarily due to higher development costs of ~~$917~~$925 million driven by increased U.S. onshore drilling activity primarily in the DJ basin and operatorship capture in the Delaware basin as well as higher exploration costs of ~~$363~~$356 million primarily driven by U.S. onshore acreage acquisitions and $172 million primarily due to exploration drilling in the Gulf of Mexico. These increases were partially offset by decreased development costs of $227 million driven by the TEN development ~~project~~ in Ghana, which achieved first oil in the third quarter of 2016. WES Midstream capital expenditures increased primarily due to $465 million related to the development of assets primarily in the Delaware and DJ basins. Other Midstream capital expenditures increased ~~$399~~$400 million due to asset development primarily in the Delaware basin.

~~2016 vs. 2015~~ The Company’s capital expenditures decreased by $2.6 billion for the year ended December 31, 2016. Exploration and Production capital expenditures decreased primarily due to reduced development and exploration activity, resulting in decreased development costs of $2.1 billion primarily in the U.S. onshore and decreased exploration costs of $432 million primarily in the U.S. onshore, Colombia, and Mozambique. These decreases were partially offset by increased exploration costs of $251 million primarily due to exploration drilling in the Gulf of Mexico and Côte d’Ivoire. Other Midstream capital expenditures decreased by $186 million and WES Midstream capital expenditures decreased by $34 million primarily due to reduced development activity.

Property Exchange On March 17, 2017, WES acquired a third party’s 50% nonoperated interest in the DBJV System, now part of the West Texas Complex, in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash. WES funded the cash considerationwithcashonhandandrecognized a gainof ~~$126~~$126 million as a result of this transaction. After the acquisition, the DBJV System iswas 100% owned by WES and consolidated by Anadarko. See Note ~~3—Acquisitions,~~ 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

AcquisitionsIn December 2016, the Company closed the GOM Acquisition for $1.8 billion.

Investments The Company made capital contributions for equity investments of $303 million in 2018, $29 million in 2017, and $62 million in 2016, which are presented as cash flows from investing activities as a component of Other, net. These contributions were primarily associated with joint ventures for the Midland-to-Sealy and Cactus II pipelines in West Texas in 2018, the Ranch Westex natural-gas processing plant in West Texas in 2017, and the Saddlehorn-Grand Mesa pipeline in Colorado in 2016.

Divestitures Anadarko received net proceeds from property divestitures of $417 million in 2018, $4.0 billion in 2017, and $2.4 billion in 2016. See Note ~~3—Acquisitions,~~ 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

~~Divestitures~~APC 2018 FORM 10-K | 75



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

Financing Activities



	December 31,
millions except percentages	2018			2017
Anadarko	$	11,602		$	12,196
WES	4,787			3,465
WGP	28			28
Total debt	$	16,417		$	15,689
Total equity	10,943			13,790
Consolidated debt to total capitalization ratio	60.0		%	53.2		%

Debt-reduction Program The Company has commenced a $2.0 billion debt-reduction program. As of December 31, 2018, Anadarko had retired more than $600 million of debt and plans to repay $900 million of debt maturing in the first half of 2019. An additional $500 million of debt reduction is anticipated through mid-year 2020.

Credit Facilities

APC RCFs The Company has a $3.0 billion senior unsecured RCF that matures in January 2023. The Company’s $2.0 billion 364-day senior unsecured RCF expired in January 2019. At December 31, 2018, Anadarko ~~received net proceeds~~had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

WES RCF WES has a $1.5 billion senior unsecured RCF which is expandable to a maximum of $2.0 billion that matures in February 2023. At December 31, 2018, WES had outstanding borrowings under its RCF of $220 million, outstanding letters of credit of $5 million, available borrowing capacity of $1.3 billion, and was in compliance with all covenants.

In December 2018, WES entered into an amendment to extend the maturity date of the WES RCF from ~~property divestitures~~February 2023 to February 2024 effective on February 15, 2019 and to expand the borrowing capacity to $2.0 billion, while leaving the $500 million accordion feature unexercised. Expansion of ~~$4.0 billion~~the borrowing capacity is subject to the completion of the WES Merger anticipated in ~~2017, $2.4 billion in 2016, and $1.4 billion in 2015.~~the first quarter of 2019. See Note ~~3—Acquisitions, Divestitures, and Assets Held for Sale~~24—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form ~~10-K.~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~Financing Activities~~

millions except percentages 2017 2016
Anadarko $ 12,196
$ 12,204
WES 3,465
3,091
WGP 28
28
Total debt $ 15,689
$ 15,323
Total equity 13,790
15,497
Debt to total capitalization ratio 53.2 % 49.7 %

~~Debt Activity~~ ~~The following summarizes the Company’s borrowing activity:~~

millions 2017 2016 2015 Description
Issuances $ —
$ 800
$ —

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

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

6.600% Senior Notes due 2046 ⁽¹⁾
—
500
—
WES 4.650% Senior Notes due 2026
—
—
500
WES 3.950% Senior Notes due 2025
—
—
101
TEUs - senior amortizing notes
—
200
—
WES 5.450% Senior Notes due 2044
Borrowings —
1,750
1,800
364-Day Facility
—
—
1,500
$5.0 Billion Facility
370
600
400
WES RCF
—
28
—
WGP RCF
—
—
250

Commercial paper notes, net ⁽²⁾
Repayments (6 ) —
—
7.000% Debentures due 2027
(3 ) —
—
6.625% Debentures due 2028
(1 ) —
—
7.950% Debentures due 2029
—
(1,750 ) —
5.950% Senior Notes due 2016
—
(2,000 ) —
6.375% Senior Notes due 2017
—
(1,750 ) (1,800 ) 364-Day Facility
—
—
(1,500 ) $5.0 Billion Facility
—
(900 ) (610 ) WES RCF
—
(250 ) —
Commercial paper notes, net
(34 ) (34 ) (16 ) TEUs - senior amortizing notes


⁽¹⁾	~~Represent senior notes issued in March 2016.~~


⁽²⁾	~~Includes repayments of $(106) million~~10-K for additional information related to ~~commercial paper notes with maturities greater than 90 days.~~

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

In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion of the amount outstanding under the WES RCF. In October 2016, WES completed a public offering of $200 million aggregate principal amount of 5.450% Senior Notes due April 2044. Net proceeds were primarily used to repay amounts outstanding under the WES RCF and the remaining proceeds were used for general partnership purposes, including capital expenditures. In 2015, net proceeds from the WES 3.950% Senior Notes were used to repay WES RCF borrowings.

~~Table of Contents~~

~~Index to Financial Statements~~

~~Anadarko RCFs~~ At December 31, 2017, Anadarko had no outstanding borrowings under its $3.0 billion senior unsecured RCF (APC RCF) or its $2.0 billion 364-day senior unsecured RCF (364-Day Facility). In January 2018, the Company amended the APC RCF to extend the maturity date to January 2022 and amended the 364-Day Facility to extend the maturity date to January 2019.Merger.

WGP RCF WGP has a $35 million senior secured RCF that matures the earlier of June 2019 or three business days following the completion of the WES ~~and WGP RCFs~~Merger. At December 31, 2017, WES had a $1.2 billion RCF that matures in February 2020 and is expandable to $1.5 billion. During 2017, WES borrowed $370 million under its RCF, which was used for general partnership purposes. At December 31, 2017, WES had $370 million outstanding borrowings under its RCF at an interest rate of 2.87%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $825 million. In February 2018, ~~the WES RCF was amended to extend the maturity date from February 2020 to February 2023 and expand the borrowing capacity to $1.5 billion.~~

During 2017, WGP had a $250 million RCF that matures in March 2019 and is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. At December 31, 2017, WGP had outstanding borrowings under its RCF of $28 million ~~at an interest rate of 3.57% and had~~classified as short-term debt on the Company’s Consolidated Balance Sheet, available borrowing capacity of ~~$222 million. In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under the WGP RCF to $35 million.~~

~~For additional information on the Company’s RCFs, such as years of maturity, interest rates,~~$7 million, and ~~covenants, see~~was in compliance with all covenants. See Note ~~12—Debt and Interest Expense~~24—Noncontrolling Interests in the NotestoConsolidatedFinancialStatements under Item 8 of this Form ~~10‑K.~~10-K for additional information related to the WES Merger.

Commercial Paper Program The Company has a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper ~~notes and is supported by the APC RCF.~~notes. As a result of Moody’s credit rating on Anadarko, the Company’s access to the commercial paper market has been ~~eliminated. The Company repaid $250 million of commercial paper notes during the first quarter of 2016, and there~~limited. There were no outstanding borrowings under the commercial paper program at December 31, ~~2017.~~ 2018.

76 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

Debt Activity Amounts in the table below do not include capital lease activity and are presented at face value.



millions	Company	2018			2017			2016			Description
Issuances	Anadarko	$	—		$	—		$	800		4.850% Senior Notes due 2021 ⁽¹⁾
	Anadarko	—			—			1,100			5.550% Senior Notes due 2026 ⁽¹⁾
	Anadarko	—			—			1,100			6.600% Senior Notes due 2046 ⁽¹⁾
	WES	400			—			—			WES 4.500% Senior Notes due 2028 ⁽²⁾
	WES	700			—			—			WES 5.300% Senior Notes due 2048 ⁽²⁾
	WES	400			—			—			WES 4.750% Senior Notes due 2028 ⁽³⁾
	WES	350			—			—			WES 5.500% Senior Notes due 2048 ⁽³⁾
	WES	—			—			500			WES 4.650% Senior Notes due 2026 ⁽⁴⁾
	WES	—			—			200			WES 5.450% Senior Notes due 2044 ⁽²⁾
Borrowings	Anadarko	—			—			1,750			364-Day Facility ⁽⁵⁾
	WES	540			370			600			WES RCF ⁽⁶⁾
	WGP	—			—			28			WGP RCF
Repayments	Anadarko	(114		)	—			—			7.050% Debentures due 2018
	Anadarko	(123		)	—			—			4.850% Senior Notes due 2021 ⁽⁷⁾
	Anadarko	(377		)	—			—			3.450% Senior Notes due 2024 ⁽⁷⁾
	Anadarko	(90		)	—			—			Zero Coupon Notes due 2036
	Anadarko	—			(6		)	—			7.000% Debentures due 2027
	Anadarko	—			(3		)	—			6.625% Debentures due 2028
	Anadarko	—			(1		)	—			7.950% Debentures due 2029
	Anadarko	—			—			(1,750		)	5.950% Senior Notes due 2016 ⁽⁸⁾
	Anadarko	—			—			(2,000		)	6.375% Senior Notes due 2017 ⁽⁸⁾
	Anadarko	—			—			(1,750		)	364-Day Facility
	Anadarko	—			—			(250		)	Commercial paper notes, net
	Anadarko	(17		)	(34		)	(34		)	TEUs - senior amortizing notes
	WES	(350		)	—			—			WES 2.600% Senior Notes due 2018
	WES	(690		)	—			(900		)	WES RCF


⁽¹⁾	Proceeds were used to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016.


⁽²⁾	Proceeds were used to repay amounts outstanding under the WES RCF, with remaining proceeds used for general partnership purposes, including capital expenditures.


⁽³⁾	Proceeds were used to repay the maturing $350 million 2.600% Senior Notes due August 2018 and amounts outstanding under the WES RCF, with remaining proceeds used for general partnership purposes, including capital expenditures.


⁽⁴⁾	Proceeds were used to repay a portion of the amount outstanding under the WES RCF.


⁽⁵⁾	Proceeds were primarily used for general short-term working capital needs.


⁽⁶⁾	Borrowings in 2018 and 2017 were used for general partnership purposes, including capital expenditures. In 2016, borrowings were used to fund a portion of an acquisition and for general partnership purposes, including capital expenditures.


⁽⁷⁾	The Company purchased and retired $377 million of its $625 million 3.450% Senior Notes due 2024 and $123 million of its $800 million 4.850% Senior Notes due 2021 pursuant to a tender offer.


⁽⁸⁾	The Company recognized losses of $155 million for the early retirement and redemption of these senior notes, which included $144 million of premiums paid.

See Note ~~12—~~13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.

APC 2018 FORM 10-K | 77



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

Debt Maturities At December 31, ~~2017, Anadarko’s scheduled debt maturities during~~ 2018, ~~consisted~~Anadarko had outstanding borrowings of ~~$17~~$600 million of ~~senior amortizing notes associated with the TEUs and $114 million of 7.05% Debentures due May 2018. In addition, WES has a scheduled debt maturity during 2018 of $350 million of 2.600%~~8.700% Senior Notes due ~~August 2018. WES’s $350~~March 2019 and $300 million ~~2.600%~~of 6.950% Senior Notes due ~~August 2018 were~~June 2019 classified as ~~long-term~~short-term debt on the Company’s Consolidated Balance ~~Sheet~~Sheet. The Company plans to retire this debt at maturity.

In December ~~31, 2017, as WES has~~2018, the ~~ability~~Company purchased and ~~intent~~retired $36 million of the accreted value of its Zero Coupons due 2036, which resulted in a reduction of $90 million of the $2.4 billion originally due at maturity in 2036. The principal payments related to ~~refinance these obligations using long-term debt.~~the Zero Coupons are reported in financing activities and interest accretion payments related to the Zero Coupons are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons were put to the Company in October ~~2017.~~2018. The Zero Coupons can next be put to the Company in October ~~2018,~~2019, which, if put in whole, ~~or in part, for~~would be $942 million. Anadarko’s Zero Coupons were classified as long-term debt on the ~~then-accreted value of $930 million.~~Company’s Consolidated Balance Sheet at December 31, 2018, as the Company has the ability and intent to refinance these obligations using long-term debt, should a put be exercised.

For additional information on the Company’s debt instruments, ~~and capital lease obligations,~~ such as transactions during the period, years of maturity, and interest rates, see Note ~~12—~~13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Capital Lease Obligations Construction of the FPSO for the Company’s TEN field operations in Ghana commenced in 2013. The Company recognized an asset and related obligation during the construction period for its pro-rata share. Upon completion of the construction during the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s share of the fair value of the FPSO based on the operator’s lease agreement. The Company made capital lease payments of $46 million in 2018 and $44 million in 2017. Anadarko’s scheduled payments for ~~2018~~2019 associated with capital lease obligations are ~~$53~~$58 million. Principal payments related to capital lease obligations are reported in financing activities and interest payments related to capital lease obligations are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. See Note ~~12—~~13—Debt and Interest Expense intheNotestoConsolidatedFinancialStatementsunderItem8ofthisForm 10-K for additional information.

~~Table of Contents~~

~~Index to Financial Statements~~

Equity Transactions During 2018, as part of the ~~fourth quarter~~Share-Repurchase Program, the Company completed the repurchase of 43.1 million shares of its common stock for $2.7 billion under two ASR Agreements and through open-market repurchases. During 2017, the Company completed ~~approximately~~ ~~$1.1 billion~~the repurchase of ~~the $3.0 Billion Share-Repurchase Program by repurchasing~~ 21.9 million shares ~~(average price~~ of ~~$48.33 per share)~~its common stock for $1.1 billion under an ASR Agreement and through open-market purchases. In February 2018, Anadarko completed a repurchase of 8.5 million shares for $500 million (average price of $58.82 per share) under an additional ASR Agreement. The Company expects to execute the remainder of the program by the end of 2018.repurchases. For additional information, see Note ~~20—~~21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10‑K.

In September 2016, Anadarko completed a public offering of 40.5 million shares of its common stock for net proceeds of $2.16 billion. Net proceeds were primarily used to fund the GOM Acquisition, with the remainder used for general corporate purposes.

Anadarko sold 12.5 million of its WGP common units to the public for net proceeds of $476 million in ~~2016 and 2.3 million WGP common units to the public for net proceeds of $130 million in 2015.~~2016. The proceeds ~~for all periods~~ were used for general corporate purposes. At December 31, ~~2017,~~2018, Anadarko owned ~~179~~170 million WGP common units, which represents ~~an 81.6%~~a 77.8% interest in WGP.

During 2016, WES issued 22 million Series A Preferred units to private investors for net proceeds of $687 million. In July 2017, WES filed a registration statement with the SEC for the issuance of up to an aggregate of $500 million of WES common units under a continuous offering program that has not yet been initiated. Pursuant to WES’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500 million of WES common units, WES issued approximately 874 thousand common units to the public and raised net proceeds of $57 million during 2015. The proceeds were used for general partnership purposes, including capital expenditures.

During the second quarter of 2015, Anadarko issued 9.2 million 7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for WGP common units, subject to Anadarko’s right to elect to issue and deliver shares of Anadarko’s common stock in lieu of WGP common units, and a senior amortizing note due in June 2018. See ~~Note 11—Tangible Equity Unitsin the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Item 8 of this Form 10-K for additional information.~~

Derivative InstrumentsInterest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates. Net cash payments related to settlements and amendments of interest-rate swap agreements were $92 million in 2018, $112 million in 2017, and $274 million in 2016. For information on derivative instruments, including cash flow treatment, see Note ~~10—~~11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Conveyance of Future Hard-Minerals Royalty RevenuesDuring the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. The Company made payments for royalties of $50 million in both 2018 and 2017, and $25 million in 2016. For additional information on the cash flow treatment, expected timing, and scheduled payments of the conveyed royalties, see Note ~~15—~~16—Conveyance of Future Hard-Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

78 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

Common Stock DividendsAnadarko paid dividends to its common stockholders of $528 million in 2018, $111 million in 2017, and $105 million in ~~2016, and $553 million in 2015.~~2016. In response to ~~the commodity-price environment,~~a sustained decline in commodity prices, the Company decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016. In February 2018, the Company ~~announced an increase in~~increased the quarterly dividend to $0.25 per share. As part of the Company’s focus on increasing shareholder returns, the quarterly dividend was increased again in November 2018 to $0.30 per share. Anadarko has paid a dividend to its common stockholders quarterly since becoming a public company in 1986.

The amount of future dividends paid to Anadarko common stockholders 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.

~~Table of Contents~~

~~Index to Financial Statements~~

Distributions to Noncontrolling Interest OwnersDistributions to noncontrolling interest owners primarily relate to the following:


millions	2017		2016		2015		2018		2017		2016
WES distributions to unitholders (excluding Anadarko and WGP) ⁽¹⁾	$	326	$	258	$	231	$	379	$	326	$	258
WES distributions to Series A Preferred unitholders ⁽²⁾	22		31		—		—		22		31
WES distributions to Chipeta noncontrolling interest owners							14		14		14
WGP distributions to unitholders (excluding Anadarko) ⁽³⁾	81		59		37		102		81		59


⁽¹⁾	WES has made quarterly distributions to its unitholders since its IPO in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to ~~$0.92~~$0.98 per common unit for the fourth quarter of ~~2017~~2018 (paid in February ~~2018)~~2019).


⁽²⁾	WES made distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April 2016. As of June 30, 2017, all Series A Preferred units had converted into WES common units. See Note ~~23—~~24—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


⁽³⁾	WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to ~~$0.54875~~$0.6025 per unit for the fourth quarter of ~~2017~~2018 (to be paid in February ~~2018)~~2019).

APC 2018 FORM 10-K | 79

~~Insurance Coverage and Other Indemnities~~



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

Insurance Coverage and Other Indemnities

Anadarko maintains property and casualty insurance that includes coverage for physical damage to the Company’s properties, blowout/control of a well, restoration and redrill, sudden and accidental pollution, third-party liability, workers’ compensation and employers’ liability, and other risks. Anadarko’s insurance coverage includes deductibles that must be met prior to recovery. Additionally, the Company’s insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect the Company against liability or loss from all potential consequences and damages.

The Company’s current insurance coverage includes (a) $400 million per occurrence from Oil Insurance Limited (OIL) for physical damage to Anadarko’s properties on a replacement cost basis, blowout/control of well, restoration and redrill, and sudden and accidental pollution; (b) $1.2 billion per occurrence from the commercial markets for the items described in item (a) above, which is in excess of the OIL coverage and which follows the form of OIL coverage with certain exceptions; (c) $500 million from the commercial markets, which scales to Anadarko’s working interest, for third-party liabilities, including sudden and accidental pollution and aviation liability; and (d) $275 million for aircraft liability (in addition to the third-party liability limits described in item (c) above). Anadarko does not carry significant coverage for loss of production income from any of the Company’s facilities or for any losses that result from the effects of a named windstorm.

The Company’s service agreements, including drilling contracts, generally indemnify Anadarko for injuries and death to employees of the service provider and subcontractors hired by the service provider as well as for property damage suffered by the service provider and its contractors. Also, these service agreements generally indemnify Anadarko for pollution originating from the equipment of any contractors or subcontractors hired by the service provider.

7680 | APC 2018 FORM 10-K



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents Index to Financial Statements

~~Off-Balance-Sheet Arrangements~~

Off-Balance-Sheet Arrangements

Anadarko may enter into off-balance-sheet arrangements and transactions that can give rise to material off-balance-sheet obligations. The Company’s material off-balance-sheet arrangements and transactions include operating lease arrangements and undrawn letters of credit. In addition, the Company enters into other contractual agreements in the normal course of business for processing, treating, transportation, and storage of oil, natural gas, and NGLs, as well as for other oil and gas activities as discussed below in Obligations. Other than the items discussed above, there are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Anadarko’s liquidity or availability of, or requirements for, capital resources.

Obligations

The following is a summary of the Company’s obligations at December 31, ~~2017:~~2018:

Obligations by Period
millions
Note Reference ⁽¹⁾
2018 2019-2020 2021-2022 2023 and Beyond Total
Total debt
Principal—total borrowings ⁽²⁾
Note 12
$ 481
$ 1,298
$ 1,970
$ 13,283
$ 17,032
Interest on borrowings
Note 12

826
1,597
1,431
8,631
12,485
Capital lease obligation and interest
Note 12

53
85
84
365
587
Investee entities’ debt and interest ⁽³⁾
Note 8
82
183
191
2,073
2,529
Operating leases
Note 16
465
353
64
52
934
Oil and gas activities ⁽⁴⁾
Note 16
408
280
101
127
916
Midstream and marketing activities
Note 16
859
1,757
1,260
1,310
5,186
AROs
Note 14
298
100
644
1,752
2,794
Derivative liabilities ⁽⁵⁾
Note 10
344
486
397
183
1,410
Uncertain tax positions ⁽⁶⁾
Note 13
21
53
72
1,171
1,317
Other ⁽⁷⁾
37
192
58
84
371
Total ⁽⁸⁾
$ 3,874
$ 6,384
$ 6,272
$ 29,031
$ 45,561

~~_______________________________________________________________________________~~



			Obligations by Period
millions	Note Reference ⁽¹⁾	2019			2020-2021			2022-2023			Thereafter			Total
Total debt
Principal—total borrowings ⁽²⁾	Note 13		$	928		$	1,177		$	890		$	14,666		$	17,661
Interest on borrowings	Note 13		834			1,655			1,530			9,515			13,534
Capital lease obligation and interest	Note 13		58			98			88			323			567
Investee entities’ debt and interest ⁽³⁾	Note 9		108			206			204			2,115			2,633
Operating leases	Note 17		264			196			59			135			654
Oil and gas activities ⁽⁴⁾	Note 17		272			332			109			89			802
Midstream and marketing activities	Note 17		875			1,816			1,323			1,409			5,423
AROs	Note 15		254			345			699			1,801			3,099
Derivative liabilities ⁽⁵⁾	Note 11		72			655			448			—			1,175
Uncertain tax positions ⁽⁶⁾	Note 14		70			74			1,143			—			1,287
Environmental liabilities	Note 18		22			35			10			42			109
Other			20			200			31			57			308
Total ⁽⁷⁾			$	3,777		$	6,789		$	6,534		$	30,152		$	47,252


⁽¹⁾	For additional information, see the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

⁽²⁾

Includes the fully accreted principal amount of the Zero Coupons of approximately ~~$2.4~~$2.3 billion as coming due after ~~2022.~~2023. While the Zero Coupons do not mature until 2036, the outstanding Zero Coupons can be put to the Company each October, in whole or in part, for the then-accreted value. The Company could be required to repurchase the outstanding Zero Coupons ~~at $930~~for $942 million, if put in whole, in October ~~2018~~2019 (the next potential put date).


⁽³⁾	The obligations and related investments are presented net on the Company’s Consolidated Balance Sheets in other assets or other long-term liabilities-other. Future interest payments are estimated using the relevant forward LIBOR rate curve. The preferred return that Anadarko receives on its investment in these entities is not included.


⁽⁴⁾	Includes long-term drilling and work-related commitments of ~~$916~~$802 million, comprised of approximately ~~$815~~$670 million related to the United States and ~~$101~~$132 million related to international locations. Amounts are undiscounted and do not include purchase commitments for jointly owned fields and facilities where the Company is not the operator.


⁽⁵⁾	Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties.


⁽⁶⁾	Timing of conclusion of the uncertain tax positions cannot be determined with certainty.


⁽⁷⁾	~~Includes environmental liabilities; for additional information, see~~ ~~Note 17—Contingencies~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Item 8 of this Form 10-K.~~

⁽⁸⁾

Excludes litigation-related contingent liabilities, the Company’s pension and postretirement benefit obligations, or payments related to the conveyance of future hard-minerals royalty revenues. See Note ~~17—~~18—Contingencies, Note ~~19—~~20—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans, and Note ~~15—~~16—Conveyance of Future Hard-Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

77APC 2018 FORM 10-K | 81

~~Table of Contents~~

~~Index to Financial Statements~~



	MANAGEMENT’S DISCUSSION AND ANALYSIS CRITICAL ACCOUNTING ESTIMATES	Table of Contents Index to Financial Statements



Delaware		76-0146568
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



Title of each class		Name of each exchange on which registered
Common Stock, par value $0.10 per share		~~New York Stock Exchange~~
~~7.50% Tangible Equity Units~~		New York Stock Exchange



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		~~532,487,194~~499,575,992



þ[ X ]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



1201 Lake Robbins Drive, The Woodlands, Texas		77380-1046
(Address of principal executive offices)		(Zip Code)



	Sales Volumes				Average Sales Prices ⁽¹⁾			Average Production Costs ⁽²⁾ (Per BOE)
	Oil (MMBbls)	Natural Gas (Bcf)	NGLs (MMBbls)	Barrels of Oil Equivalent (MMBOE)	Oil (Per Bbl)	Natural Gas (Per Mcf)	NGLs (Per Bbl)	Average Production Costs ⁽²⁾ (Per BOE)
2017
United States
DJ basin	31	212	21	88	49.73	2.55	27.46	10.23
Other United States	66	266	13	123	49.57	3.03	32.24	9.38
Total United States	97	478	34	211	49.62	2.82	29.24	9.73
International	32	—	2	34	53.77	—	35.64	7.01
Total	129	478	36	245	50.66	2.82	29.54	9.34
2016
United States
DJ basin	33	214	20	89	40.27	2.00	18.26	8.41
Other United States	52	552	24	168	38.29	2.06	20.21	6.80
Total United States	85	766	44	257	39.06	2.04	19.32	7.36
International	31	—	2	33	43.93	—	25.63	7.93
Total	116	766	46	290	40.34	2.04	19.64	7.42
2015
United States
DJ basin	35	176	16	81	44.88	2.31	15.65	8.21
Other United States	50	676	29	191	45.08	2.37	17.83	8.55
Total United States	85	852	45	272	45.00	2.36	17.03	8.45
International	31	—	2	33	51.68	—	29.85	7.22
Total	116	852	47	305	46.79	2.36	17.61	8.31



	Wells in the process of drilling or in active completion		Wells suspended or waiting on completion ⁽¹⁾
	Exploration	Development	Exploration	Development ⁽²⁾
United States
Gross	—	23	14	543
Net	—	20.4	8.6	396.2
International
Gross	—	—	28	15
Net	—	—	7.8	3.5
Total
Gross	—	23	42	558
Net	—	20.4	16.4	399.7



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2017
Market Price
High	$	72.32	$	64.15	$	50.16	$	54.45
Low	$	59.34	$	43.45	$	39.96	$	46.75
Dividends	$	0.05	$	0.05	$	0.05	$	0.05
2016
Market Price
High	$	50.39	$	57.00	$	63.84	$	73.33
Low	$	28.16	$	43.52	$	50.23	$	58.59
Dividends	$	0.05	$	0.05	$	0.05	$	0.05



millions	Oil			Natural Gas			NGLs			Total
2016 sales revenues	$	4,668		$	1,564		$	921		$	7,153
Changes associated with prices	1,334			373			358			2,065
Changes associated with sales volumes	550			(589		)	(210		)	(249		)
2017 sales revenues	$	6,552		$	1,348		$	1,069		$	8,969
Increase/(decrease) vs. 2016	40		%	(14		)%	16		%	25		%

2015 sales revenues	$	5,420		$	2,007		$	833		$	8,260
Changes associated with prices	(745		)	(241		)	95			(891		)
Changes associated with sales volumes	(7		)	(202		)	(7		)	(216		)
2016 sales revenues	$	4,668		$	1,564		$	921		$	7,153
Increase/(decrease) vs. 2015	(14		)%	(22		)%	11		%	(13		)%



	2017	Inc (Dec) vs. 2016		2016	Inc (Dec) vs. 2015		2015
Barrels of Oil Equivalent
(MMBOE except percentages)
United States	211	(18	)%	257	(5	)%	272
International	34	3		33	(1	)	33
Total barrels of oil equivalent	245	(16	)	290	(5	)	305

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States	579	(18	)%	704	(5	)%	745
International	93	4		89	(1	)	91
Total barrels of oil equivalent per day	672	(15	)	793	(5	)	836



millions	Change in Revenues			Due to Change in Prices			Due to Change in Volumes
2017 vs. 2016	$	1,884		$	1,334		$	550
2016 vs. 2015	(752		)	(745		)	(7		)



	MARKET RISK QUANTITATIVE AND QUALITATIVE DISCLOSURES	Table of Contents Index to Financial Statements



	FINANCIAL STATEMENTS INDEX	Table of Contents Index to Financial Statements



INDEX TO CONSOLIDATED FINANCIAL STATEMENTS	Page

Report of Management	8688

Management’s Assessment of Internal Control Over Financial Reporting	8688

Reports of Independent Registered Public Accounting Firm	8789

Consolidated Statements of Income for the Three Years Ended December 31, ~~2017~~2018	8991

Consolidated Statements of Comprehensive Income for the Three Years Ended December 31, ~~2017~~2018	9092

Consolidated Balance Sheets at December 31, ~~2017~~2018 and ~~2016~~2017	9193

Consolidated Statements of Equity for the Three Years Ended December 31, ~~2017~~2018	9294

Consolidated Statements of Cash Flows for the Three Years Ended December 31, ~~2017~~2018	9395

Notes to Consolidated Financial Statements	9496

Note 1 - Summary of Significant Accounting Policies	9496

Note 2 - ~~Inventories~~	~~102~~

~~Note 3 - Acquisitions, Divestitures, and Assets Held for Sale~~	~~103~~

~~Note 4 - Properties and Equipment~~Revenue from Contracts with Customers	105

Note 53 - ~~Impairments~~	~~106~~

~~Note 6 - Suspended Exploratory Well Costs~~Commodity Inventories	108

Note 74 - ~~Goodwill~~Divestitures and ~~Other Intangible~~ Assets Held for Sale	~~111~~108

Note 85 - ~~Equity-Method Investments~~Properties and Equipment	~~111~~109

Note 96 - ~~Current Liabilities~~Impairments	110

Note 7 - Suspended Exploratory Well Costs	112

Note 108 - ~~Derivative Instruments~~Goodwill and Other Intangible Assets	~~112~~115

Note 9 - Equity-Method Investments	115

Note 10 - Current Liabilities	116

Note 11 - ~~Tangible Equity Units~~Derivative Instruments	~~118~~116

Note 12 - ~~Debt and Interest Expense~~Tangible Equity Units	~~120~~121

Note 13 - ~~Income Taxes~~Debt and Interest Expense	~~126~~122

Note 14 - ~~Asset Retirement Obligations~~Income Taxes	~~130~~129

Note 15 - ~~Conveyance of Future Hard-Minerals Royalty Revenues~~	~~131~~

~~Note 16 - Commitments~~	~~132~~

~~Note 17 - Contingencies~~Asset Retirement Obligations	133

Note 1816 - ~~Restructuring Charges~~Conveyance of Future Hard-Minerals Royalty Revenues	134

Note 1917 - ~~Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans~~Commitments	135

Note 2018 - ~~Stockholders’ Equity~~Contingencies	~~141~~136

Note 19 - Restructuring Charges	136

Note 20 - Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans	137

Note 21 - ~~Accumulated Other Comprehensive Income (Loss)~~Stockholders’ Equity	143

Note 22 - ~~Share-Based Compensation~~Accumulated Other Comprehensive Income (Loss)	~~144~~145

Note 23 - ~~Noncontrolling Interests~~Share-Based Compensation	~~147~~146

Note 24 - ~~Variable Interest Entities~~Noncontrolling Interests	148

Note 25 - ~~Supplemental Cash Flow Information~~Variable Interest Entities	~~150~~149

Note 26 - Supplemental Cash Flow Information	151

Note 27 - Segment Information	~~151~~152

Supplemental Quarterly Information	156

Supplemental Information on Oil and Gas Exploration and Production Activities	157

~~Supplemental Quarterly Information~~	~~156~~



	FINANCIAL STATEMENTS REPORTS	Table of Contents Index to Financial Statements



	FINANCIAL STATEMENTS	Table of Contents Index to Financial Statements


	Years Ended December 31,									Years Ended December 31,
millions except per-share amounts	2017			2016			2015			2018			2017			2016
Revenues and Other
Oil sales	$	6,552		$	4,668		$	5,420		$	9,206		$	6,552		$	4,668
Natural-gas sales	1,348			1,564			2,007			1,005			1,348			1,564
Natural-gas liquids sales	1,069			921			833			1,271			1,069			921
Gathering, processing, and marketing sales	2,000			1,294			1,226			1,588			2,000			1,294
Gains (losses) on divestitures and other, net	939			(578		)	(788		)	312			939			(578		)
Total	11,908			7,869			8,698			13,382			11,908			7,869
Costs and Expenses
Oil and gas operating	1,000			811			1,014			1,153			988			807
Oil and gas transportation	914			1,002			1,117			878			914			1,002
Exploration	2,541			946			2,644			459			2,535			944
Gathering, processing, and marketing	1,560			1,087			1,054			1,047			1,552			1,083
General and administrative	1,075			1,440			1,176			1,084			994			1,223
Depreciation, depletion, and amortization	4,279			4,301			4,603			4,254			4,279			4,301
Production, property, and other taxes	582			536			553			826			582			536
Impairments	408			227			5,075			800			408			227
Other operating expense	221			118			271			262			221			118
Total	12,580			10,468			17,507			10,763			12,473			10,241
Operating Income (Loss)	(672		)	(2,599		)	(8,809		)	2,619			(565		)	(2,372		)
Other (Income) Expense
Interest expense	932			890			825			947			932			890
Loss on early extinguishment of debt	2			155			—
(Gains) losses on early extinguishment of debt										(2		)	2			155
(Gains) losses on derivatives, net	135			286			(99		)	130			135			286
Other (income) expense, net	(53		)	(101		)	154			59			54			126
Total	1,016			1,230			880			1,134			1,123			1,457
Income (Loss) Before Income Taxes	(1,688		)	(3,829		)	(9,689		)	1,485			(1,688		)	(3,829		)
Income tax expense (benefit)	(1,477		)	(1,021		)	(2,877		)	733			(1,477		)	(1,021		)
Net Income (Loss)	(211		)	(2,808		)	(6,812		)	752			(211		)	(2,808		)
Net income (loss) attributable to noncontrolling interests	245			263			(120		)	137			245			263
Net Income (Loss) Attributable to Common Stockholders	$	(456	)	$	(3,071	)	$	(6,692	)	$	615		$	(456	)	$	(3,071	)

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	(0.85	)	$	(5.90	)	$	(13.18	)	$	1.20		$	(0.85	)	$	(5.90	)
Net income (loss) attributable to common stockholders—diluted	$	(0.85	)	$	(5.90	)	$	(13.18	)	$	1.20		$	(0.85	)	$	(5.90	)
Average Number of Common Shares Outstanding—Basic	548			522			508			504			548			522
Average Number of Common Shares Outstanding—Diluted	548			522			508			504			548			522
Dividends (per Common Share)	$	0.20		$	0.20		$	1.08


⁽¹⁾	Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents Index to Financial Statements



CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606			Effect of Change Increase/(Decrease)
December 31, 2018
Assets
Other current assets	$	474		$	472		$	2
Net properties and equipment	28,615			28,548			67
Other assets	2,336			2,326			10
Liabilities
Other current liabilities	1,295			1,290			5
Deferred income taxes	2,437			2,441			(4		)
Other	4,021			3,914			107
Equity
Total equity	10,943			10,972			(29		)



CONSOLIDATED STATEMENT OF INCOME	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606			Effect of Change Increase/(Decrease)
Year Ended December 31, 2018
Revenues
Gathering, processing, and marketing sales	$	1,588		$	2,592		$	(1,004	)
Gains (losses) on divestitures and other, net	312			316			(4		)
Expenses
Gathering, processing, and marketing	1,047			2,075			(1,028		)
Income tax expense (benefit)	733			731			2
Net income (loss) attributable to noncontrolling interests	137			127			10
Net Income (Loss) Attributable to Common Stockholders	$	615		$	607		$	8



millions	Exploration & Production				WES Midstream				Other Midstream			Other and Intersegment Eliminations				Total
Year Ended December 31, 2018
Oil sales		$	9,206			$	—			$	—		$	—		$	9,206
Natural-gas sales		1,005				—				—			—			1,005
Natural-gas liquids sales		1,271				—				—			—			1,271
Gathering, processing, and marketing sales⁽¹⁾		—				1,997				416			21			2,434
Other, net		30				—				1			97			128
Total Revenue from Customers		$	11,512			$	1,997			$	417		$	118		$	14,044
Gathering, processing, and marketing sales⁽²⁾		—				(8		)		8			(846		)	(846		)
Gains (losses) on divestitures, net		20				1				10			(11		)	20
Other, net		(34		)		173				40			(15		)	164
Total Revenue from Other than Customers		$	(14	)		$	166			$	58		$	(872	)	$	(662	)
Total Revenue and Other		$	11,498			$	2,163			$	475		$	(754	)	$	13,382


⁽¹⁾	The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $957 million and intersegment eliminations of $(876) million for the year ended December 31, 2018.



millions
Balance at December 31, 2017	$	37
Increase due to cumulative effect of adopting Topic 606	98
Increase due to cash received, excluding revenues recognized in the period	66
Increase due to assets received from customer	13
Decrease due to revenue recognized	(42		)
Decrease due to change in estimated consideration	(22		)
Balance at December 31, 2018	$	150

Contract liabilities at December 31, 2018
Other current liabilities	$	31
Other long-term liabilities - other	119
Total contract liabilities from contracts with customers	$	150



millions
Current assets	$	8
Properties and equipment	2,492
Other assets	145
AROs	(816		)
Net assets acquired	$	1,829
Accounts payable	(5		)
Other long-term liabilities	(109		)
Cash paid	$	1,715


⁽¹⁾	Includes goodwill allocated to divestitures of $209 million in 2017 and $397 million in ~~2016, and $184 million in 2015.~~2016.


⁽²⁾	Includes ~~the~~gain of $126 million ~~gain~~ related to the 2017 property exchange discussed ~~above.~~below.


–	Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $370 million and net losses of $33 million in 2018 and $154 million in the fourth quarter of 2017


–	Ram Powell nonoperated assets in the Gulf of Mexico, included in the Exploration and Production reporting segment, resulting in a net gain of $67 million


–	Eaglebine assets in Southeast Texas, included in the Exploration and Production reporting segment, for net proceeds of $533 million and a net gain of $282 million


–	Utah CBM assets, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $69 million and a net loss of $52 million


–	Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $951 million and net losses of $55 million in 2017 and $129 million in 2016