10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[ X ]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

or

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

EXCHANGE ACT OF 1934

For the transition period fromto

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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

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

Registrant’s telephone number, including area code (832) 636-1000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  þ    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨ Emerging growth company  ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ

The number of shares outstanding of the Company’s common stock at October 18, 2018, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	504,280,902

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2018 and 2017	4
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2018 and 2017	5
	Consolidated Balance Sheets at September 30, 2018, and December 31, 2017	6
	Consolidated Statement of Equity for the Nine Months Ended September 30, 2018	7
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017	8
	Notes to Consolidated Financial Statements	9
	Note 1—Summary of Significant Accounting Policies	9
	Note 2—Revenue from Contracts with Customers	12
	Note 3—Commodity Inventories	16
	Note 4—Divestitures	16
	Note 5—Impairments	17
	Note 6—Suspended Exploratory Well Costs	17
	Note 7—Current Liabilities	18
	Note 8—Derivative Instruments	18
	Note 9—Tangible Equity Units	24
	Note 10—Debt	24
	Note 11—Income Taxes	27
	Note 12—Contingencies	28
	Note 13—Pension Plans and Other Postretirement Benefits	29
	Note 14—Stockholders’ Equity	30
	Note 15—Noncontrolling Interests	32
	Note 16—Variable Interest Entities	33
	Note 17—Supplemental Cash Flow Information	35
	Note 18—Segment Information	36
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
	Cautionary Statement About Forward-Looking Statements	39
	Management Overview	41
	Financial Results	43
	Liquidity and Capital Resources	54
	Recent Accounting Developments	57
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	59
PART II
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 6.	Exhibits	63

COMMONLY USED TERMS AND DEFINITIONS

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

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

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

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

ASU - Accounting Standards Update

Bcf - Billion cubic feet

BOE - Barrels of oil equivalent

CBM - Coalbed methane

DBJV - Delaware Basin JV Gathering LLC

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

DBM Complex - The processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving, and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico

DD&A - Depreciation, depletion, and amortization

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

FID - Final investment decision

Fitch - Fitch Ratings

FPSO - Floating production, storage, and offloading unit

G&A - General and administrative expenses

IRS - Internal Revenue Service

IPO - Initial public offering

LIBOR - London Interbank Offered Rate

LNG - Liquefied natural gas

MBbls/d - Thousand barrels per day

MBOE/d - Thousand barrels of oil equivalent per day

Mcf - Thousand cubic feet

MMBbls - Million barrels

MMBOE - Million barrels of oil equivalent

MMBtu - Million British thermal units

MMBtu/d - Million British thermal units per day

MMcf/d - Million cubic feet per day

Moody’s - Moody’s Investors Service

N/A - Not applicable

NGLs - Natural gas liquids

NM - Not meaningful

NTSB - National Transportation Safety Board

NYMEX - New York Mercantile Exchange

Oil - Includes crude oil and condensate

RCF - Revolving credit facility

ROTF - Regional oil treating facility

2

S&P - Standard and Poor’s

Share-Repurchase Program - A program authorizing the repurchase of Anadarko’s common stock

Tax Reform Legislation - The U.S. Tax Cuts and Jobs Act signed into law on December 22, 2017

TEN - Tweneboa/Enyenra/Ntomme

TEUs - Tangible equity units

VIE or VIEs - Variable interest entity

WES - Western Gas Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko

WES RCF - WES’s $1.5 billion senior unsecured RCF

WGP - Western Gas Equity Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko

WGP RCF - WGP’s $35 million senior secured RCF

WTI - West Texas Intermediate

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

3

PART I. FINANCIAL INFORMATION

Item 1.  Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
millions except per-share amounts	2018		2017			2018		2017
Revenues and Other
Oil sales	$	2,572	$	1,567		$	6,964	$	4,652
Natural-gas sales	232		269			682		1,090
Natural-gas liquids sales	382		265			992		768
Gathering, processing, and marketing sales	421		509			1,163		1,417
Gains (losses) on divestitures and other, net	90		(114		)	232		1,052
Total	3,697		2,496			10,033		8,979
Costs and Expenses
Oil and gas operating	294		253			845		738
Oil and gas transportation	228		220			633		698
Exploration	118		750			380		2,366
Gathering, processing, and marketing	256		396			745		1,101
General and administrative	248		261			814		768
Depreciation, depletion, and amortization	1,130		1,083			3,123		3,235
Production, property, and other taxes	246		159			637		449
Impairments	172		—			319		383
Other operating expense	26		123			188		157
Total	2,718		3,245			7,684		9,895
Operating Income (Loss)	979		(749		)	2,349		(916		)
Other (Income) Expense
Interest expense	240		230			705		682
(Gains) losses on derivatives, net	32		82			503		(33		)
Other (income) expense, net	24		5			16		51
Total	296		317			1,224		700
Income (Loss) Before Income Taxes	683		(1,066		)	1,125		(1,616		)
Income tax expense (benefit)	256		(425		)	507		(366		)
Net Income (Loss)	427		(641		)	618		(1,250		)
Net income (loss) attributable to noncontrolling interests	64		58			105		182
Net Income (Loss) Attributable to Common Stockholders	$	363	$	(699	)	$	513	$	(1,432	)
Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.72	$	(1.27	)	$	0.99	$	(2.60	)
Net income (loss) attributable to common stockholders—diluted	$	0.72	$	(1.27	)	$	0.99	$	(2.61	)
Average Number of Common Shares Outstanding—Basic	499		553			507		552
Average Number of Common Shares Outstanding—Diluted	500		553			508		552
Dividends (per common share)	$	0.25	$	0.05		$	0.75	$	0.15

See accompanying Notes to Consolidated Financial Statements.

4

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions	2018			2017			2018			2017
Net Income (Loss)	$	427		$	(641	)	$	618		$	(1,250	)
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	1			1			2			3
Income taxes on reclassification of previously deferred derivative losses	—			—			—			(1		)
Total adjustments for derivative instruments, net of taxes	1			1			2			2
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	25			(14		)	25			1
Income taxes on net gain (loss) incurred during period	(6		)	5			(6		)	—
Amortization of net actuarial (gain) loss to other (income) expense, net	15			29			28			100
Income taxes on amortization of net actuarial (gain) loss	(4		)	(11		)	(7		)	(37		)
Amortization of net prior service (credit) cost to other (income) expense, net	(6		)	(7		)	(18		)	(19		)
Income taxes on amortization of net prior service (credit) cost	2			3			4			7
Total adjustments for pension and other postretirement plans, net of taxes	26			5			26			52
Total	27			6			28			54
Comprehensive Income (Loss)	454			(635		)	646			(1,196		)
Comprehensive income (loss) attributable to noncontrolling interests	64			58			105			182
Comprehensive Income (Loss) Attributable to Common Stockholders	$	390		$	(693	)	$	541		$	(1,378	)

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,			December 31,
millions except per-share amounts	2018			2017
ASSETS
Current Assets
Cash and cash equivalents ($133 and $80 related to VIEs)	$	1,883		$	4,553
Accounts receivable (net of allowance of $11 and $14)
Customers ($159 and $106 related to VIEs)	1,644			1,222
Others ($15 and $19 related to VIEs)	547			607
Other current assets	397			380
Total	4,471			6,762
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $36,375 and $34,107) ($6,419 and $5,731 related to VIEs)	28,744			27,451
Other Assets ($801 and $579 related to VIEs)	2,292			2,211
Goodwill and Other Intangible Assets ($1,170 and $1,191 related to VIEs)	5,638			5,662
Total Assets	$	41,145		$	42,086
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade ($337 and $305 related to VIEs)	$	2,144		$	1,894
Other ($16 and $1 related to VIEs)	201			266
Short-term debt - Anadarko (1)	910			142
Short-term debt - WGP/WES	28			—
Current asset retirement obligations	332			294
Other current liabilities	1,502			1,310
Total	5,117			3,906
Long-term Debt
Long-term debt - Anadarko (1)	11,189			12,054
Long-term debt - WGP/WES	4,566			3,493
Total	15,755			15,547
Other Long-term Liabilities
Deferred income taxes	2,455			2,234
Asset retirement obligations ($158 and $143 related to VIEs)	2,538			2,500
Other	4,043			4,109
Total	9,036			8,843
Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.2 million and 574.2 million shares issued)	57			57
Paid-in capital	12,344			12,000
Retained earnings	1,291			1,109
Treasury stock (82.3 million and 43.4 million shares)	(4,608		)	(2,132		)
Accumulated other comprehensive income (loss)	(383		)	(338		)
Total Stockholders’ Equity	8,701			10,696
Noncontrolling interests	2,536			3,094
Total Equity	11,237			13,790
Total Liabilities and Equity	$	41,145		$	42,086

__________________________________________________________________

Parenthetical references reflect amounts as of September 30, 2018, and December 31, 2017.

VIE amounts relate to WGP and WES. See Note 16—Variable Interest Entities.

⁽¹⁾  Excludes WES and WGP.

See accompanying Notes to Consolidated Financial Statements.

6

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Total Stockholders’ Equity
millions	Common Stock		Paid-in Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity
Balance at December 31, 2017	$	57	$	12,000		$	1,109		$	(2,132	)	$	(338	)	$	3,094		$	13,790
Net income (loss)	—		—			513			—			—			105			618
Common stock issued	—		6			—			—			—			—			6
Share-based compensation expense	—		125			—			—			—			—			125
Dividends—common stock	—		—			(380		)	—			—			—			(380		)
Repurchases of common stock	—		—			—			(2,476		)	—			—			(2,476		)
Subsidiary equity transactions	—		(17		)	—			—			—			25			8
Settlement of tangible equity units	—		230			—			—			—			(300		)	(70		)
Distributions to noncontrolling interest owners	—		—			—			—			—			(365		)	(365		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—			—			—			2			—			2
Adjustments for pension and other postretirement plans	—		—			—			—			26			—			26
Cumulative effect of accounting change (1)	—		—			49			—			(73		)	(23		)	(47		)
Balance at September 30, 2018	$	57	$	12,344		$	1,291		$	(4,608	)	$	(383	)	$	2,536		$	11,237

 __________________________________________________________________

⁽¹⁾  Beginning January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and 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.

See accompanying Notes to Consolidated Financial Statements.

7

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
millions	2018			2017
Cash Flows from Operating Activities
Net income (loss)	$	618		$	(1,250	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	3,123			3,235
Deferred income taxes	141			(1,026		)
Dry hole expense and impairments of unproved properties	212			2,144
Impairments	319			383
(Gains) losses on divestitures, net	(31		)	(815		)
Total (gains) losses on derivatives, net	506			(33		)
Operating portion of net cash received (paid) in settlement of derivative instruments	(433		)	21
Other	224			227
Changes in assets and liabilities
(Increase) decrease in accounts receivable	(344		)	(32		)
Increase (decrease) in accounts payable and other current liabilities	230			(95		)
Other items, net	(263		)	(140		)
Net cash provided by (used in) operating activities	4,302			2,619
Cash Flows from Investing Activities
Additions to properties and equipment	(4,891		)	(3,538		)
Divestitures of properties and equipment and other assets	393			3,480
Other, net	(161		)	30
Net cash provided by (used in) investing activities	(4,659		)	(28		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	2,131			249
Repayments of debt	(1,176		)	(42		)
Financing portion of net cash received (paid) for derivative instruments	19			(160		)
Increase (decrease) in outstanding checks	(13		)	(58		)
Dividends paid	(380		)	(84		)
Repurchases of common stock	(2,476		)	(37		)
Issuances of common stock	6			—
Distributions to noncontrolling interest owners	(365		)	(327		)
Payments of future hard-minerals royalty revenues conveyed	(50		)	(50		)
Other financing activities	(2		)	(18		)
Net cash provided by (used in) financing activities	(2,306		)	(527		)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents	(18		)	4
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	(2,681		)	2,068
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period	4,674			3,308
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period	$	1,993		$	5,376

See accompanying Notes to Consolidated Financial Statements.

8

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing its Mozambique LNG project toward FID. In addition, the Company engages in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. The Company also participates in the hard-minerals business through royalty arrangements.

Basis of Presentation  The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain notes and other information have been condensed or omitted. The accompanying interim financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation. These interim financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

The consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. The Company has determined that WGP and WES are VIEs. Anadarko is considered the primary beneficiary and consolidates WGP and WES. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in noncontrolled entities that Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Investments are included in other assets.

Recently Adopted Accounting Standards  ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The Company adopted this ASU on January 1, 2018, with retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. Upon adoption, non-service cost components of net periodic benefit costs of $107 million for 2017, including $94 million for the nine months ended September 30, 2017, were reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense.

ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Company adopted this ASU using a retrospective approach on January 1, 2018. Adoption did not have a material impact on the Company’s consolidated financial statements. See Consolidated Statements of Cash Flows and Note 17—Supplemental Cash Flow Informationfor additional information.

9

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior-period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included a reduction to total equity of $47 million. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. See Note 2—Revenue from Contracts with Customers for additional information. The Company’s revenue recognition accounting policy effective January 1, 2018, is detailed below.

• Exploration and Production—The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. For natural gas and NGLs sold on our behalf by a processor, revenue is typically measured based on the price the processor receives for the sale, less certain costs withheld by the processor.

Revenues are recognized for the sale of Anadarko’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee to move oil from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income.

10

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

• WES Midstream and Other Midstream—Anadarko provides gathering, compressing, treating, processing, stabilizing, transporting, and disposal services pursuant to a variety of contracts. Under these arrangements, the Company receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Revenue is recognized for fee-based gathering and processing services in the month of service based on the volumes delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period.

The Company’s midstream business also purchases natural-gas volumes from producers at the wellhead or production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. These fees are treated as a reduction of the purchase cost when the fees relate to services performed after control of the product has transferred to Anadarko. Revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to a third party.

Revenue from percentage of proceeds gathering and processing contracts is recognized net of the cost of product for purchases from service customers when the Company is acting as their agent in the product sale, and any fees charged on these percentage of proceeds contracts are recognized in service revenues.

ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, provides entities the option to reclassify stranded tax effects resulting from the Tax Reform Legislation from accumulated other comprehensive income (AOCI) to retained earnings. In accordance with its accounting policy, the Company releases stranded income tax effects from AOCI in the period the underlying portfolio is liquidated. This ASU allows for the reclassification of stranded tax effects as a result of the change in tax rates from Tax Reform Legislation to be recorded upon adoption of the ASU, rather than at the actual portfolio liquidation date. The Company adopted this ASU on January 1, 2018, electing to reclassify $73 million from AOCI to retained earnings, including a $2 million federal benefit of state tax impact related to the Tax Reform Legislation.

New Accounting Standards Issued But Not Yet Adopted  ASU 2016-02, Leases (Topic 842), requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Company plans to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases. Anadarko continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU. The Company expects the adoption of this ASU to primarily impact other assets and other long-term liabilities and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko expects to implement new accounting software and complete the evaluation of its systems, processes, and internal controls by the end of 2018. Anadarko will adopt this ASU on January 1, 2019, using a modified retrospective approach. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements and will recognize a cumulative effect adjustment in the opening balance of retained earnings in the period of adoption.

11

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Revenue from Contracts with Customers

Change in Accounting Policy  The Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. See Note 1—Summary of Significant Accounting Policies for additional information.

Impacts on Financial Statements

Exploration and Production There were no significant changes to the timing or valuation of revenue recognized for sales of production by the Exploration and Production segment.

WES Midstream and Other Midstream Gathering and processing revenues decreased for contracts where the Company is acting as an agent for its processing customer in the sale of processed volumes and increased for contracts with noncash consideration, with an offset to gathering and processing expense upon product sale. The magnitude of these presentation changes in subsequent periods is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes. These presentation changes do not impact net earnings.

The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements:

CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
September 30, 2018
Assets
Other current assets	$	397	$	395	$	2
Net properties and equipment	28,744		28,697		47
Other assets	2,292		2,282		10
Liabilities
Other current liabilities	1,502		1,494		8
Deferred income taxes	2,455		2,461		(6		)
Other	4,043		3,932		111
Equity
Total equity	11,237		11,291		(54		)

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Revenue from Contracts with Customers (Continued)

CONSOLIDATED STATEMENT OF INCOME	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
Three Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	421	$	717	$	(296	)
Gains (losses) on divestitures and other, net	90		89		1
Expenses
Gathering, processing, and marketing	256		551		(295		)
Income tax expense (benefit)	256		254		2
Net income (loss) attributable to noncontrolling interests	64		71		(7		)
Net Income (Loss) Attributable to Common Stockholders	$	363	$	358	$	5
Nine Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	1,163	$	1,944	$	(781	)
Gains (losses) on divestitures and other, net	232		233		(1		)
Expenses
Gathering, processing, and marketing	745		1,520		(775		)
Income tax expense (benefit)	507		507		—
Net income (loss) attributable to noncontrolling interests	105		111		(6		)
Net Income (Loss) Attributable to Common Stockholders	$	513	$	514	$	(1	)

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Revenue from Contracts with Customers(Continued)

Disaggregation of Revenue from Contracts with CustomersThe following table disaggregates revenue by significant product type and segment:

millions	Exploration & Production			WES Midstream			Other Midstream		Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2018
Oil sales	$	2,572		$	—		$	—	$	—		$	2,572
Natural-gas sales	232			—			—		—			232
Natural-gas liquids sales	382			—			—		—			382
Gathering, processing, and marketing sales (1)	—			511			113		1			625
Other, net	9			—			—		31			40
Total Revenue from Customers	$	3,195		$	511		$	113	$	32		$	3,851
Gathering, processing, and marketing sales(2)	—			(3		)	3		(204		)	(204		)
Gains (losses) on divestitures, net	5			—			1		(3		)	3
Other, net	(8		)	52			12		(9		)	47
Total Revenue from Other than Customers	$	(3	)	$	49		$	16	$	(216	)	$	(154	)
Total Revenue and Other	$	3,192		$	560		$	129	$	(184	)	$	3,697
Nine Months Ended September 30, 2018
Oil sales	$	6,964		$	—		$	—	$	—		$	6,964
Natural-gas sales	682			—			—		—			682
Natural-gas liquids sales	992			—			—		—			992
Gathering, processing, and marketing sales(1)	—			1,438			255		83			1,776
Other, net	16			—			—		71			87
Total Revenue from Customers	$	8,654		$	1,438		$	255	$	154		$	10,501
Gathering, processing, and marketing sales(2)	—			(6		)	6		(613		)	(613		)
Gains (losses) on divestitures, net	24			—			10		(3		)	31
Other, net	(21		)	113			30		(8		)	114
Total Revenue from Other than Customers	$	3		$	107		$	46	$	(624	)	$	(468	)
Total Revenue and Other	$	8,657		$	1,545		$	301	$	(470	)	$	10,033

 __________________________________________________________________

⁽¹⁾  The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $328 million and intercompany eliminations of $(312) million for the three months ended September 30, 2018, and sales of third-party natural gas and NGLs of $813 million and intercompany eliminations of $(715) million for the nine months ended September 30, 2018.

⁽²⁾  The amount in Other and Intersegment Eliminations represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table, as the purchases are not considered revenue from customers.

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Revenue from Contracts with Customers(Continued)

Contract Liabilities Contract liabilities primarily relate to midstream fees and capital reimbursements that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of benefit, fixed and variable fees that are received from customers but revenue recognition is deferred under midstream cost of service contracts, and hard-minerals bonus payments received from customers that must be recognized as revenue over the expected period of benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:

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 (1)	46
Decrease due to revenue recognized (2)	(30		)
Balance at September 30, 2018	$	151
Contract liabilities at September 30, 2018
Other current liabilities	$	23
Other long-term liabilities - other	128
Total contract liabilities from contracts with customers	$	151

 __________________________________________________________________

⁽¹⁾  Includes $(6) million for the three months ended September 30, 2018.

⁽²⁾  Includes $(9) million for the three months ended September 30, 2018.

Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of September 30, 2018, is reflected in the table below. The Company applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. Therefore, the following table represents only a small portion of Anadarko’s expected future consolidated revenues as future revenue from the sale of most products and services is dependent on future production or variable customer volumes and variable commodity prices for those volumes.

millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Remainder of 2018	$	27	$	124	$	31	$	(96	)	$	86
2019	104		480		204		(441		)	347
2020	103		545		293		(606		)	335
2021	103		525		361		(672		)	317
2022	7		529		417		(739		)	214
Thereafter	65		2,192		3,107		(4,662		)	702
Total	$	409	$	4,395	$	4,413	$	(7,216	)	$	2,001

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3. Commodity Inventories

The following summarizes the major classes of commodity inventories included in other current assets:

	September 30,		December 31,
millions	2018		2017
Oil	$	168	$	165
Natural gas	19		29
NGLs	131		122
Total commodity inventories	$	318	$	316

4. Divestitures

Divestitures  The following summarizes the proceeds received and gains (losses) recognized on divestitures:

	Nine Months Ended
	September 30,
millions	2018		2017
Proceeds received, net of closing adjustments	$	393	$	3,480
Gains (losses) on divestitures, net (1)	31		815

__________________________________________________________________

⁽¹⁾  Includes the $126 million gain related to the 2017 property exchange discussed below.

2018During the nine months ended September 30, 2018, the Company divested of the following U.S. onshore and Gulf of Mexico assets:

• 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.

2017During the nine months ended September 30, 2017, the Company divested of the following U.S. onshore assets:

• Eagleford assets in South Texas, included in the Exploration and Production reporting segment, for net proceeds of $2.1 billion and a net gain of $730 million

• Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $758 million and net losses of $56 million in 2017 and $129 million in the fourth quarter of 2016

• 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

Property Exchange On March 17, 2017, 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. WES recognized a gain of $126 million as a result of this transaction. Following the acquisition, the DBJV System is 100% owned by WES and consolidated by Anadarko.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. Impairments

Impairments of Long-Lived Assets

2018During the nine months ended September 30, 2018, the Company expensed $319 million primarily related to the following:

• $145 million in the third quarter of 2018 related to hard-minerals properties due to the Company’s primary consumer of coal stating its intent to retire its existing coal-fired power generation plant earlier than expected, coupled with the outlook for limited new markets for the Company’s coal in the Rockies region. These coal assets had a post-impairment fair value of $15 million.

• $126 million related to a gathering system in the DJ basin, included in the WES Midstream reporting segment that was permanently taken out of service in the second quarter of 2018.

2017During the nine months ended September 30, 2017, the Company expensed $383 million primarily related to the following:

• $211 million related to oil and gas properties in the Gulf of Mexico, included in the Exploration and Production reporting segment, due to lower forecasted commodity prices at that time. The assets had a post-impairment fair value of $231 million.

• $168 million related to U.S. onshore midstream properties, included in the WES Midstream reporting segment, primarily due to a reduced throughput fee as a result of a producer’s bankruptcy. The assets had a post-impairment fair value of $58 million.

Fair values were measured as of the impairment date using the income approach and Level 3 inputs. The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs.

Impairments of Unproved PropertiesImpairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. During the nine months ended September 30, 2018, the Company recognized $158 million of impairments of unproved Gulf of Mexico properties primarily related to blocks where the Company determined it would no longer pursue activities. The Company recognized $586 million of impairments of unproved Gulf of Mexico properties during the nine months ended September 30, 2017, of which $463 million related 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.

It is reasonably possible that significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional impairments.

6. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $510 million at September 30, 2018, and $525 million at December 31, 2017. For exploratory wells, drilling costs are capitalized, or “suspended,” on the balance sheet when the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. During the nine months ended September 30, 2018, there was no exploration expense recorded for suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017.

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $205 million at September 30, 2018, and $219 million atDecember 31, 2017, representing the amount by which checks issued but not presented to the Company’s banks for collection exceeded balances in applicable bank accounts. Changes in these liabilities are classified as cash flows from financing activities.

Other Current Liabilities The following summarizes the Company’s other current liabilities:

	September 30,		December 31,
millions	2018		2017
Accrued income taxes	$	79	$	71
Interest payable	169		246
Production, property, and other taxes payable	344		216
Accrued employee benefits	270		210
Derivatives	491		384
Other	149		183
Total other current liabilities	$	1,502	$	1,310

8. Derivative Instruments

Objective and Strategy  The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities.

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates.

The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings.

18

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The oil prices listed below are a combination of NYMEX WTI and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, 2018:

	2018 Settlement		2019 Settlement
Oil
Two-Way Collars (MBbls/d)	108		—
Average price per barrel (WTI)
Ceiling sold price (call)	$	60.48	$	—
Floor purchased price (put)	$	50.00	$	—
Three-Way Collars (MBbls/d)	—		87
Average price per barrel (WTI and Brent)
Ceiling sold price (call)	$	—	$	72.98
Floor purchased price (put)	$	—	$	56.72
Floor sold price (put)	$	—	$	46.72
Fixed-Price Contracts (MBbls/d)	84		—
Average price per barrel (Brent)	$	61.45	$	—
Natural Gas
Three-Way Collars (thousand MMBtu/d)	250		—
Average price per MMBtu (Henry Hub)
Ceiling sold price (call)	$	3.54	$	—
Floor purchased price (put)	$	2.75	$	—
Floor sold price (put)	$	2.00	$	—
Fixed-Price Contracts (thousand MMBtu/d)	280		—
Average price per MMBtu (Henry Hub)	$	3.02	$	—

A two-way collar is a combination of two options: a sold call and a purchased put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes.

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

19

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Derivative Instruments (Continued)

Interest-Rate Derivatives  Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR.

In August 2018, the Company amended an interest-rate swap with a notional principal amount of $200 million, extending the mandatory termination date from 2018 to 2023 in exchange for a cash payment of approximately $10 million.

At September 30, 2018, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or in September 2023 that manage interest-rate risk associated with potential future debt issuances. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at September 30, 2018: 

millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418%
$	250	September 2016 - 2046	September 2022	6.809%
$	100	September 2017 - 2047	September 2020	6.891%
$	250	September 2017 - 2047	September 2021	6.570%
$	450	September 2017 - 2047	September 2023	6.445%

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or cash payments for amendments related to these extended interest-rate derivatives are classified as cash flows from financing activities. Net cash payments related to settlements and amendments of interest-rate swap agreements were $101 million during the nine months ended September 30, 2018, and $118 million during the nine months ended September 30, 2017.

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Derivative Instruments (Continued)

Effect of Derivative Instruments—Balance Sheet  The following summarizes the fair value of the Company’s derivative instruments:

	Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2018		2017		2018			2017
Commodity derivatives
Other current assets	$	2	$	7	$	—		$	(1	)
Other assets	—		2		—			—
Other current liabilities	20		45		(440		)	(206		)
Other liabilities	15		—		(56		)	(2		)
	37		54		(496		)	(209		)
Interest-rate derivatives
Other current assets	21		14		—			—
Other assets	54		40		—			—
Other current liabilities	—		—		(80		)	(236		)
Other liabilities	—		—		(1,028		)	(1,183		)
	75		54		(1,108		)	(1,419		)
Total derivatives	$	112	$	108	$	(1,604	)	$	(1,628	)

Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:

	Three Months Ended					Nine Months Ended
millions	September 30,					September 30,
Classification of (Gain) Loss Recognized	2018			2017		2018			2017
Commodity derivatives
Gathering, processing, and marketing sales	$	1		$	—	$	3		$	—
(Gains) losses on derivatives, net	104			43		734			(164		)
Interest-rate derivatives
(Gains) losses on derivatives, net	(72		)	39		(231		)	131
Total (gains) losses on derivatives, net	$	33		$	82	$	506		$	(33	)

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Derivative Instruments (Continued)

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types.

The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s portfolio valuation versus negotiated credit thresholds. These credit thresholds generally require full or partial collateralization of the Company’s obligations depending on certain credit-risk-related provisions, such as the Company’s credit rating from S&P and Moody’s. As of September 30, 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. The Company may be required to post additional collateral with respect to its derivative instruments if its credit ratings decline below current levels or if the liability associated with any such derivative instrument increases substantially. For example, based on the derivative positions as of September 30, 2018, if Anadarko’s credit rating were to be downgraded one level by either S&P or Moody’s, the Company could be required to post additional collateral of up to approximately $124 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 $49 million of collateral) at September 30, 2018, and $1.4 billion (net of $170 million of collateral) at December 31, 2017.

22

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Derivative Instruments (Continued)

Fair Value  Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.

The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:

millions	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
September 30, 2018
Assets
Commodity derivatives	$	—		$	37		$	—	$	(35	)	$	—		$	2
Interest-rate derivatives	—			75			—		—			—			75
Total derivative assets	$	—		$	112		$	—	$	(35	)	$	—		$	77
Liabilities
Commodity derivatives	$	—		$	(496	)	$	—	$	35		$	6		$	(455	)
Interest-rate derivatives	—			(1,108		)	—		—			49			(1,059		)
Total derivative liabilities	$	—		$	(1,604	)	$	—	$	35		$	55		$	(1,514	)
December 31, 2017
Assets
Commodity derivatives	$	1		$	53		$	—	$	(46	)	$	(1	)	$	7
Interest-rate derivatives	—			54			—		—			—			54
Total derivative assets	$	1		$	107		$	—	$	(46	)	$	(1	)	$	61
Liabilities
Commodity derivatives	$	(1	)	$	(208	)	$	—	$	46		$	3		$	(160	)
Interest-rate derivatives	—			(1,419		)	—		—			170			(1,249		)
Total derivative liabilities	$	(1	)	$	(1,627	)	$	—	$	46		$	173		$	(1,409	)

 __________________________________________________________________

⁽¹⁾  Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

23

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Tangible Equity Units

In June 2015, the Company issued 9.2 million7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU was comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. The prepaid equity purchase contract was considered a freestanding financial instrument, indexed to WGP common units, and met the conditions for equity classification.

Equity ComponentOn June 7, 2018, the mandatory settlement date, Anadarko settled 9.2 million outstanding TEUs in exchange for approximately 8.2 million WGP common units based on the determined final settlement rate of 0.8921 WGP common units per outstanding TEU. See settlement of tangible equity units in the Company’s Consolidated Statement of Equity.

Debt Component Each senior amortizing note had an initial principal amount of $10.95 and bore interest at 1.50% per year. The final installment payment of $9 million was made on June 7, 2018. For activity related to the senior amortizing notes, see Note 10—Debt.

10. Debt

Debt Activity  The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the nine months ended September 30, 2018:

	Carrying Value
millions	WES			WGP (1)		Anadarko (2)			Anadarko Consolidated			Description
Balance at December 31, 2017	$	3,465		$	28	$	11,965		$	15,458
Issuances
	394			—		—			394			WES 4.500% Senior Notes due 2028
	687			—		—			687			WES 5.300% Senior Notes due 2048
	396			—		—			396			WES 4.750% Senior Notes due 2028
	342			—		—			342			WES 5.500% Senior Notes due 2048
Borrowings
	320			—		—			320			WES RCF
Repayments
	(690		)	—		—			(690		)	WES RCF
	—			—		(114		)	(114		)	7.050% Debentures due 2018
	(350		)	—		—			(350		)	WES 2.600% Senior Notes due 2018
	—			—		(17		)	(17		)	TEUs - senior amortizing notes
Other, net	2			—		39			41			Amortization of discounts, premiums, and debt issuance costs
Balance at September 30, 2018	$	4,566		$	28	$	11,873		$	16,467

__________________________________________________________________

⁽¹⁾  Excludes WES.

⁽²⁾  Excludes WES and WGP.

24

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Debt (Continued)

Debt  The following summarizes the Company’s outstanding debt, including capital lease obligations, after eliminating the effect of intercompany transactions:

millions	WES			WGP (1)		Anadarko (2)			Consolidated
September 30, 2018
Total borrowings at face value	$	4,620		$	28	$	13,383		$	18,031
Net unamortized discounts, premiums, and debt issuance costs (3)	(54		)	—		(1,510		)	(1,564		)
Total borrowings (4)	4,566			28		11,873			16,467
Capital lease obligations	—			—		226			226
Less short-term debt	—			28		910			938
Total long-term debt	$	4,566		$	—	$	11,189		$	15,755
December 31, 2017
Total borrowings at face value	$	3,490		$	28	$	13,514		$	17,032
Net unamortized discounts, premiums, and debt issuance costs (3)	(25		)	—		(1,549		)	(1,574		)
Total borrowings (4)	3,465			28		11,965			15,458
Capital lease obligations	—			—		231			231
Less short-term debt	—			—		142			142
Total long-term debt	$	3,465		$	28	$	12,054		$	15,547

__________________________________________________________________

⁽¹⁾  Excludes WES.

⁽²⁾  Excludes WES and WGP.

⁽³⁾  Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

⁽⁴⁾  The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.8 billion at September 30, 2018, and $17.7 billion at December 31, 2017.

25

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Debt (Continued)

Anadarko BorrowingsIn January 2018, the Company amended its $3.0 billion senior unsecured RCF to extend the maturity date to January 2022 (APC RCF) and amended its $2.0 billion364-day senior unsecured RCF to extend the maturity date to January 2019 (364-Day Facility). At September 30, 2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

At September 30, 2018, Anadarko had outstanding borrowings of $600 million of 8.700% Senior Notes due March 2019 and $300 million of 6.950% Senior Notes due June 2019 classified as short-term debt on the Company’s Consolidated Balance Sheet. Short-term debt also included the current portion of the Company’s capital lease obligations.

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 2018. The Zero Coupons can next be put to the Company in October 2019, which, if put in whole, would be $980 million.

The Company also has notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. See Note 8—Equity-Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

WES and WGP Borrowings  In February 2018, WES amended its RCF to extend the maturity date from February 2020 to February 2023 and expanded the borrowing capacity to $1.5 billion (WES RCF). As part of the amendment, the WES RCF is expandable to a maximum of $2.0 billion. During the nine months ended September 30, 2018, WES borrowed $320 million under its RCF, which was used for general partnership purposes, and made repayments of $690 million. At September 30, 2018, WES had no outstanding borrowings under its RCF, outstanding letters of credit of $5 million, available borrowing capacity of $1.495 billion, and was in compliance with all covenants.

In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from the public offerings were used to repay the maturing WES $350 million of 2.600% Senior Notes due August 2018, and amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.

In March 2018, WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the public offerings were used to repay amounts outstanding under the WES RCF and for general partnership purposes, including to fund capital expenditures.

In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under its senior secured RCF maturing in March 2019 from $250 million to $35 million (WGP RCF). Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES) as well as all equity interests owned by WGP. At September 30, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.25%, classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $7 million. At September 30, 2018, WGP was in compliance with all covenants.

26

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Income Taxes

Upon enactment of the Tax Reform Legislation on December 22, 2017, 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%. During the third quarter of 2018, the Company recognized an additional net tax benefit of $5 million related to the adoption of the Tax Reform Legislation under Staff Accounting Bulletin 118. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation, including its accounting policy related to Global Intangible Low Taxed Income, and record any remaining adjustments to provisional tax amounts, which could be material to income tax expense, before the end of the measurement period on December 21, 2018. See Note 13—Income Taxes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

The following summarizes income tax expense (benefit) and effective tax rates:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2018			2017			2018			2017
Current income tax expense (benefit)	$	146		$	430		$	383		$	670
Deferred income tax expense (benefit)	110			(855		)	124			(1,036		)
Total income tax expense (benefit)	$	256		$	(425	)	$	507		$	(366	)
Income (loss) before income taxes	683			(1,066		)	1,125			(1,616		)
Effective tax rate	37		%	40		%	45		%	23		%

The Company’s tax provision for interim periods is determined using an estimate of its annual current and deferred effective tax rates, adjusted for discrete items. Each quarter, the Company updates these rates and records a cumulative adjustment to current and deferred tax expense by applying the rates to the year-to-date pre-tax income excluding discrete items. The Company’s quarterly estimate of its annual current and deferred effective tax rates can vary significantly based on various forecasted items, including future commodity prices, capital expenditures, expenses for which tax benefits are not recognized, and the geographic mix of pre-tax income and losses.

The variance from the U.S. federal statutory rate of 21% for the three and nine months ended September 30, 2018, was primarily attributable to the following items:

• tax impact from foreign operations

• non-deductible Algerian exceptional profits tax for Algerian income tax purposes

The Company reported a loss before income taxes for the three and nine months ended September 30, 2017. As a result, items that ordinarily increase or decrease the Company’s tax rate will have the opposite effect. The variance from the U.S. federal statutory rate of 35% for the three and nine months ended September 30, 2017 was primarily attributable to the following items:

• tax impact from foreign operations

• non-deductible Algerian exceptional profits tax for Algerian income tax purposes

• net changes in uncertain tax positions

• income attributable to noncontrolling interests

27

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Income Taxes (Continued)

The Company recognized a net tax benefit of $346 million as of September 30, 2018 and December 31, 2017, related to the deduction of its 2015 settlement payment for the Tronox Adversary Proceeding. This benefit is net of uncertain tax positions of $1.2 billion as of September 30, 2018 and December 31, 2017, due to uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment, the Company had a net operating loss carryback for 2015, which resulted in a tentative tax refund of $881 million in 2016. The IRS has audited this position and, in April 2018, issued a 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 intends to file a petition with the U.S. Tax Court to dispute the disallowances, and pursuant to standard U.S. Tax Court procedures, the Company 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 Company does not prevail on the issue, the earliest potential date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial 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. 

12. Contingencies

Litigation  There are no material developments in previously reported contingencies nor are there any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

28

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree and, in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:

	Pension Benefits						Other Benefits
millions	2018			2017			2018			2017
Three Months Ended September 30
Service cost	$	23		$	22		$	—		$	—
Interest cost	19			21			3			3
Expected (return) loss on plan assets	(20		)	(21		)	—			—
Amortization of net actuarial loss (gain)	6			7			—			—
Amortization of net prior service cost (credit)	—			(1		)	(6		)	(6		)
Settlement expense	9			22			—			—
Termination benefits expense	7			—			—			—
Net periodic benefit cost (1)	$	44		$	50		$	(3	)	$	(3	)
Nine Months Ended September 30
Service cost	$	68		$	64		$	1		$	1
Interest cost	57			63			8			9
Expected (return) loss on plan assets	(61		)	(63		)	—			—
Amortization of net actuarial loss (gain)	19			20			—			—
Amortization of net prior service cost (credit)	—			(1		)	(18		)	(18		)
Settlement expense	9			80			—			—
Termination benefits expense	7			4			—			—
Net periodic benefit cost (1)	$	99		$	167		$	(9	)	$	(8	)

__________________________________________________________________

⁽¹⁾  The service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and all other components of net periodic benefit cost are included in other (income) expense on the Company’s Consolidated Statements of Income.

The Company contributed $161 million to funded pension plans and $36 million to unfunded pension plans during the nine months ended September 30, 2018. The Company expects to contribute an additional $1 million to funded pension plans and $26 million to unfunded pension plans during 2018.

29

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Stockholders’ Equity

Earnings Per Share  The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and TEUs, if the inclusion of these items is dilutive. All outstanding TEUs were settled in June 2018. See Note 9—Tangible Equity Units for additional information.

The following provides a reconciliation between basic and diluted EPS attributable to common stockholders:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
millions except per-share amounts	2018		2017			2018			2017
Net income (loss)
Net income (loss) attributable to common stockholders	$	363	$	(699	)	$	513		$	(1,432	)
Income (loss) effect of TEUs	—		(2		)	(4		)	(6		)
Less distributions on participating securities	2		—			4			—
Less undistributed income allocated to participating securities	2		—			1			—
Basic	$	359	$	(701	)	$	504		$	(1,438	)
Income (loss) effect of TEUs	—		—			—			(1		)
Diluted	$	359	$	(701	)	$	504		$	(1,439	)
Shares
Average number of common shares outstanding—basic	499		553			507			552
Dilutive effect of stock options	1		—			1			—
Average number of common shares outstanding—diluted	500		553			508			552
Excluded due to anti-dilutive effect	8		11			9			11
Net income (loss) per common share
Basic	$	0.72	$	(1.27	)	$	0.99		$	(2.60	)
Diluted	$	0.72	$	(1.27	)	$	0.99		$	(2.61	)

30

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Stockholders’ Equity (Continued)

Common Stock  The Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018. In July 2018, the program was further expanded to $4.0 billion and extended through June 30, 2019. The Share-Repurchase Program authorizes the repurchase of the Company’s common stock in the open market or through private transactions. As of the end of the third quarter of 2018, the Company had completed $3.5 billion of the Share-Repurchase Program through ASR Agreements and open-market repurchases. These transactions were accounted for as equity transactions, with all of the repurchased shares classified as treasury stock. Additionally, the receipt of these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS.

During the nine months ended September 30, 2018, the Company entered into and completed two ASR Agreements and open-market repurchases as presented below:

millions except per-share amounts
Agreement Date	Settlement Date	Amount		Average Price per Share		Initial Shares Delivered	Additional Shares Delivered	Total Shares Delivered
ASR Agreements
January 2018	February 2018	$	500	$	58.82	7.0	1.5	8.5
March 2018	June 2018	1,441		65.28		19.1	3.0	22.1
Total ASR Agreements		1,941				26.1	4.5	30.6
Open-market repurchases
August 2018	August 2018	250		66.14		N/A	N/A	3.8
September 2018	September 2018	250		63.11		N/A	N/A	3.9
Total open-market repurchases		500						7.7
Total		$	2,441					38.3

Under each ASR Agreement, the Company paid a specific amount in cash and received an initial delivery of shares of the Company’s common stock. The initial delivery of shares represented the minimum number of shares to be repurchased under the agreement. The final number of shares delivered upon settlement of each ASR Agreement was determined with reference to the volume-weighted average price of the shares during the term of the agreement less a negotiated settlement price adjustment.

31

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Noncontrolling Interests

WES is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During 2016, WES issued 22 million Series A Preferred units to private investors. Pursuant to an agreement between WES and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units were converted on May 2, 2017.

WES Class C units issued to Anadarko will convert into WES common units on a one-for-one basis on the conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The Class C units receive quarterly distributions in the form of additional Class C units until the March 1, 2020 conversion date, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 802 thousand Class C units to Anadarko during the nine months ended September 30, 2018, and 886 thousand Class C units to Anadarko during 2017.

WGP is a limited partnership formed by Anadarko to own interests in WES. In June 2018, Anadarko settled 9.2 million outstanding TEUs, originally issued in 2015, in exchange for approximately 8.2 million WGP common units. See Note 9—Tangible Equity Unitsfor additional information. At September 30, 2018, Anadarko’s ownership interest in WGP consisted of a 77.8% limited partner interest and the entire non-economic general partner interest. The remaining 22.2% limited partner interest in WGP was owned by the public.

At September 30, 2018, WGP’s ownership interest in WES consisted of a 29.6% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At September 30, 2018, Anadarko also owned a 9.5% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.4% limited partner interest in WES was owned by the public.

32

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. Variable Interest Entities

Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES; therefore, Anadarko is considered the primary beneficiary and consolidates WGP, WES, and all of their consolidated subsidiaries. For additional information on WGP and WES, see Note 15—Noncontrolling Interests.

The following tables present selected financial data from the consolidated financial statements of WGP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2018		2017		2018		2017
Statement of Operations Data
Total revenues and other	$	508	$	575	$	1,432	$	1,616
Operating income (loss)	200		179		461		523
Net income (loss)	155		147		340		424

	Nine Months Ended
	September 30,
millions	2018			2017
Statement of Cash Flows Data
Net cash provided by (used in) operating activities	$	749		$	642
Net cash provided by (used in) investing activities	(1,161		)	(515		)
Net cash provided by (used in) financing activities	465			(334		)

	September 30,		December 31,
millions	2018		2017
Balance Sheet Data
Cash and cash equivalents	$	133	$	80
Net property, plant, and equipment	6,419		5,731
Total assets	9,034		8,016
Long-term debt	4,566		3,493
Total liabilities	5,417		4,071
Total equity and partners’ capital	3,617		3,945

Assets and Liabilities of VIEsThe assets of WGP, WES, and their subsidiaries cannot be used by Anadarko for general corporate purposes and are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP, WES, and their subsidiaries for which the creditors do not have recourse to other assets of the Company are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.

All outstanding debt for WES at September 30, 2018, and December 31, 2017, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at September 30, 2018, and December 31, 2017, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note 10—Debt for additional information on WGP and WES short-term and long-term debt balances.

33

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. Variable Interest Entities (Continued)

VIE Financing WGP’s sources of liquidity include borrowings under its RCF and distributions from WES. WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under its RCF, the issuance of additional partnership units, and debt offerings. See Note 10—DebtandNote 15—Noncontrolling Interestsfor additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $13 million for the nine months ended September 30, 2018 and 2017. The note receivable and related interest income are eliminated in consolidation.

To reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of its contracts, Anadarko has commodity price swap agreements in place with WES expiring on December 31, 2018. WES recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price, minus (ii) the amount by which the swap price for product purchases exceeds the market price. WES recorded a capital contribution from Anadarko of $41 million for the nine months ended September 30, 2018, and $47 million for the nine months ended September 30, 2017.

34

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

17. Supplemental Cash Flow Information

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

The following summarizes cash paid (received) for interest and income taxes as well as non-cash investing and financing activities:

	Nine Months Ended
	September 30,
millions	2018			2017
Cash paid (received)
Interest, net of amounts capitalized	$	813		$	764
Income taxes, net of refunds	48			169
Non-cash investing activities
Fair value of properties and equipment acquired	$	8		$	619
Asset retirement cost additions	261			228
Accruals of property, plant, and equipment	886			786
Net liabilities assumed (divested) in acquisitions and divestitures	(97		)	(115		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	14
Non-cash financing activities
Settlement of tangible equity units	$	300		$	—

The following table provides a reconciliation of Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents as reported in the Consolidated Statement of Cash Flows to the line items within the Consolidated Balance Sheets:

	September 30,		December 31,
millions	2018		2017
Cash and cash equivalents	$	1,883	$	4,553
Restricted cash and restricted cash equivalents included in Other Assets	110		121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	1,993	$	4,674

Included in cash and cash equivalents is restricted cash and restricted cash equivalents of $134 million at September 30, 2018, and $255 million at December 31, 2017. Total restricted cash and restricted cash equivalents are primarily associated with certain international joint venture operations, payments of future hard-minerals royalty revenues conveyed, like-kind exchanges of property, and a judicially-controlled account related to a Brazilian tax dispute. See Note 17—Contingencies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

35

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

18. Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences. Anadarko has three reporting segments: Exploration and Production, WES Midstream, and Other Midstream, which include their respective marketing results. The Company has reclassified prior-period amounts to conform to the current-period presentation.

The Exploration and Production reporting 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. The WES Midstream and Other Midstream reporting segments engage in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. The WES Midstream segment consists of WES midstream assets, and the Other Midstream segment consists of the Company’s other midstream assets.

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; DD&A; exploration expense; gains (losses) on divestitures, net; impairments; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; restructuring charges; and less net income (loss) attributable to noncontrolling interests.

The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.

Management believes Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial performance across periods. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions	2018			2017			2018			2017
Income (loss) before income taxes	$	683		$	(1,066	)	$	1,125		$	(1,616	)
Interest expense	240			230			705			682
DD&A	1,130			1,083			3,123			3,235
Exploration expense (1)	118			750			380			2,366
(Gains) losses on divestitures, net	(3		)	194			(31		)	(815		)
Impairments	172			—			319			383
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(167		)	98			73			(12		)
Restructuring charges	13			3			13			20
Less net income (loss) attributable to noncontrolling interests	64			58			105			182
Consolidated Adjusted EBITDAX	$	2,122		$	1,234		$	5,602		$	4,061

 __________________________________________________________________

⁽¹⁾  Includes restructuring charges of $20 million for the three and nine months ended September 30, 2018.

36

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

18. Segment Information (Continued)

Information presented below as “Other and Intersegment Eliminations” includes corporate costs, margin on sales of third-party commodity purchases, deficiency fee expenses, results from hard-minerals royalties, net cash from settlement of commodity derivatives, and net income (loss) attributable to noncontrolling interests. The following summarizes selected financial information for Anadarko’s reporting segments:

millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2018
Sales revenues	$	3,161	$	394	$	39	$	13		$	3,607
Intersegment revenues	25		114		78		(217		)	—
Other	1		52		11		23			87
Total revenues and other (1)	3,187		560		128		(181		)	3,694
Operating costs and expenses (2)	1,059		245		55		(67		)	1,292
Net cash from settlement of commodity derivatives	—		—		—		199			199
Other (income) expense, net (3)	—		—		—		17			17
Net income (loss) attributable to noncontrolling interests	—		—		—		64			64
Total expenses and other	1,059		245		55		213			1,572
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		—		—			—
Adjusted EBITDAX	$	2,128	$	315	$	73	$	(394	)	$	2,122
Three Months Ended September 30, 2017
Sales revenues	$	2,097	$	445	$	53	$	15		$	2,610
Intersegment revenues	4		119		43		(166		)	—
Other	6		39		7		28			80
Total revenues and other (1)	2,107		603		103		(123		)	2,690
Operating costs and expenses (2)	956		345		62		49			1,412
Net cash from settlement of commodity derivatives	—		—		—		(16		)	(16		)
Other (income) expense, net	—		—		—		2			2
Net income (loss) attributable to noncontrolling interests	—		—		—		58			58
Total expenses and other	956		345		62		93			1,456
Adjusted EBITDAX	$	1,151	$	258	$	41	$	(216	)	$	1,234

 __________________________________________________________________

⁽¹⁾  Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

⁽²⁾  Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

⁽³⁾  Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.

37

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

18. Segment Information (Continued)

millions	Exploration & Production			WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Nine Months Ended September 30, 2018
Sales revenues	$	8,589		$	1,063	$	73	$	76		$	9,801
Intersegment revenues	49			369		188		(606		)	—
Other	(5		)	113		30		63			201
Total revenues and other (1)	8,633			1,545		291		(467		)	10,002
Operating costs and expenses (2)	2,840			687		134		195			3,856
Net cash from settlement of commodity derivatives	—			—		—		437			437
Other (income) expense, net (3)	—			—		—		9			9
Net income (loss) attributable to noncontrolling interests	—			—		—		105			105
Total expenses and other	2,840			687		134		746			4,407
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		7			7
Adjusted EBITDAX	$	5,793		$	858	$	157	$	(1,206	)	$	5,602
Nine Months Ended September 30, 2017
Sales revenues	$	6,500		$	1,213	$	134	$	80		$	7,927
Intersegment revenues	10			387		125		(522		)	—
Other	16			124		20		77			237
Total revenues and other (1)	6,526			1,724		279		(365		)	8,164
Operating costs and expenses (2)	2,679			936		168		135			3,918
Net cash from settlement of commodity derivatives	—			—		—		(23		)	(23		)
Other (income) expense, net	—			—		—		24			24
Net income (loss) attributable to noncontrolling interests	—			—		—		182			182
Total expenses and other	2,679			936		168		318			4,101
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		(2		)	(2		)
Adjusted EBITDAX	$	3,847		$	788	$	111	$	(685	)	$	4,061

 __________________________________________________________________

⁽¹⁾  Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

⁽²⁾  Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

⁽³⁾  Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

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-Q, and may from time to time make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include, among other things, information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will be realized. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

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

• the Company’s assumptions about energy markets

• production and sales volume levels

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

• operating results

• competitive conditions

• technology

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

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

• volatility in the commodity-futures market

• weather

• inflation

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

• drilling and other operational risks

• processing volumes, pipeline throughput, and produced water disposal

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

• the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects

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

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

39

• 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, meet its debt-reduction expectations, 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 approvals, enter into additional long-term sales contracts, take FID 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 NGLs cargo shipping activities

• physical, digital, internal, and external security breaches

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

• 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 “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

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-Q in Part I, Item 1; the information set forth in the Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017; and the information set forth in the Risk Factors under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

40

MANAGEMENT OVERVIEW

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 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 determine the value the Company receives from its sales of oil, natural gas, and NGLs.

The Company continues to leverage its foundational principle of efficient capital allocation 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 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. The Company expects to use excess cash generated from its Gulf of Mexico, Algeria, Ghana, and DJ basin assets to fund the growth of its other unconventional assets in the U.S. onshore and improve returns to shareholders.

In the third quarter of 2018, the Company expanded the Share-Repurchase Program from $3.0 billion to $4.0 billion and completed the repurchase of $500 million of the Company’s common stock, bringing the total repurchases to $3.5 billion. The Company also announced a $500 million increase to its debt-reduction expectations, bringing the total planned debt reduction to $1.5 billion. As of September 30, 2018, the Company had repaid $114 million of debt at maturity and plans to retire $900 million of fixed-rate debt maturing in the first half of 2019. These actions demonstrate the strength of the Company’s portfolio and commitment to capital efficiency.

In the Delaware basin, located in Texas, the Company continues to build out one of the most expansive and integrated infrastructure positions in the region and is transitioning to multi-well pad development, primarily in Reeves and Loving counties. The first ROTF in Reeves County was completed and brought online during the second quarter of 2018. During the third quarter of 2018, final commissioning activities were completed for the second ROTF in Loving County. New wells in the area were brought online and flowed into these ROTFs during the third quarter of 2018. Additionally, the WES-operated Mentone I processing train at the DBM Complex is expected to commence operations in the fourth quarter of 2018, which will facilitate incremental production growth of the asset. As of the end of the third quarter of 2018, Anadarko had secured sufficient takeaway capacity with approximately 50% of its Delaware basin operated oil volumes being sold at Gulf Coast markets via the Enterprise pipeline to Houston. This capacity is expected to increase to approximately 100% in 2019, when the Plains Cactus II pipeline to Corpus Christi is brought online. The Company ended the third quarter of 2018 with 7 operated drilling rigs and 5 completion crews in the Delaware basin, which compares to 13 operated drilling rigs and 6 completion crews at the end of the third quarter of 2017.

In the DJ basin, located in Colorado, the Company continues to leverage its minerals-interest ownership and extensive infrastructure position to deliver development wells with attractive rates of return. The Company ended the third quarter of 2018 with four operated drilling rigs and two completion crews in the DJ basin, which compares to six operated drilling rigs and four completion crews at the end of the third quarter of 2017. The Colorado general election ballot in November 2018 will include Proposition 112, which, if passed, would amend the Colorado Revised Statutes to require that new oil and gas development on non-federal lands take place a minimum distance of 2,500 feet from occupied buildings such as homes, schools, and hospitals, and other areas designated as vulnerable. Such setbacks would effectively ban new oil and gas drilling and hydraulic fracturing on a substantial portion of Colorado’s non-federal lands. If Proposition 112 passes, and is not amended or repealed by the state legislature, resulting in more stringent limitations on the production and development of oil and natural gas in Colorado, the Company will be limited or precluded in the drilling of wells or in the volumes that are ultimately able to be produced from assets in Colorado. Given the depth and quality of the Company’s portfolio, if this occurs, the Company would expect to reallocate capital in order to continue to focus on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely in the Delaware basin and in the deepwater Gulf of Mexico, and accelerate investments in the emerging oil play in Wyoming’s Powder River basin.

In the deepwater Gulf of Mexico, Anadarko has two floating drillships and one platform rig available to conduct operations that are focused toward high-return oil development opportunities near the Company’s expansive infrastructure. Internationally, drilling continues in offshore Ghana with new development activities at the TEN and Jubilee fields.

In order to reduce commodity-price risk and increase the predictability of 2018 cash flows, the Company has strategic derivative positions covering approximately 50% of its anticipated oil sales volumes and approximately 55% of its anticipated natural-gas sales volumes for the remainder of 2018. See Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

41

Significant operating and financial activities for the third quarter of 2018 include the following:

Total Company

• The Company’s overall sales-volume product mix increased to 58% oil in the third quarter of 2018, compared to 56% in the third quarter of 2017.

• The Company’s third-quarter oil sales volumes averaged 397 MBbls/d, representing a 13% increase over the third quarter of 2017.

U.S. Onshore

• U.S. onshore oil sales volumes increased by 35 MBbls/d, representing a 26%increase from the third quarter of 2017.

• Sales volumes for the Delaware basin increased by 32 MBbls/d, representing an 83%increase from the third quarter of 2017, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018.

• In the Delaware basin, the second ROTF was completed in Loving County, with 47 wells flowing into the facility by the end of the third quarter. Additionally, 23 new wells were brought online at the Reeves County ROTF during the quarter.

International

Ghana

• In the TEN fields of Ghana, the operator resumed drilling operations in early 2018, with one well completed and brought online in the third quarter. Subsequent to quarter end, drilling began on a second well.

• In the Jubilee field of Ghana, the operator drilled two wells during the second quarter of 2018, with the first of these wells completed and brought online in the third quarter.

• At the end of the third quarter, a second drillship was mobilized for drilling operations in the TEN and Jubilee fields.

Mozambique

• The Company continues to make progress converting non-binding commitments to fully termed Sales and Purchase Agreements as required to support project financing arrangements and progress to FID.

• Recommendations for award of the offshore contractor and equipment providers are awaiting Government of Mozambique approval.

• 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, Offshore Area 4, which is owned and operated by third parties, joined the Anadarko-led resettlement and airstrip projects as a 50% participant.

• The Company remains on track for FID consideration in the first half of 2019.

Financial

• The Company generated $1.6 billion of cash flows from operations and ended the third quarter with $1.9 billion of cash.

• In the third quarter, the Company completed the repurchase of an additional $500 million of the Company’s common stock under the Share-Repurchase Program.

42

FINANCIAL RESULTS

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
millions except per-share amounts	2018		2017			2018		2017
Oil, natural-gas, and NGLs sales	$	3,186	$	2,101		$	8,638	$	6,510
Gathering, processing, and marketing sales	421		509			1,163		1,417
Gains (losses) on divestitures and other, net	90		(114		)	232		1,052
Revenues and other	$	3,697	$	2,496		$	10,033	$	8,979
Costs and expenses	2,718		3,245			7,684		9,895
Other (income) expense	296		317			1,224		700
Income tax expense (benefit)	256		(425		)	507		(366		)
Net income (loss) attributable to common stockholders	$	363	$	(699	)	$	513	$	(1,432	)
Net income (loss) per common share attributable to common stockholders—diluted	$	0.72	$	(1.27	)	$	0.99	$	(2.61	)
Average number of common shares outstanding—diluted	500		553			508		552

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended September 30, 2018,” refer to the comparison of the three months ended September 30, 2018, to the three months ended September 30, 2017, and any increases or decreases “for the nine months ended September 30, 2018,” refer to the comparison of the nine months ended September 30, 2018, to the nine months ended September 30, 2017. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales volumes; the cost of finding and developing such reserves; and operating costs.

43

Revenues and Sales Volumes

	Three Months Ended
	September 30,
millions except percentages	Oil			Natural Gas			NGLs			Total
2017 sales revenues	$	1,567		$	269		$	265		$	2,101
Changes associated with prices	806			(33		)	78			851
Changes associated with sales volumes	199			(4		)	39			234
2018 sales revenues	$	2,572		$	232		$	382		$	3,186
Increase (decrease) vs. 2017	64		%	(14		)%	44		%	52		%
	Nine Months Ended
	September 30,
millions except percentages	Oil			Natural Gas			NGLs			Total
2017 sales revenues	$	4,652		$	1,090		$	768		$	6,510
Changes associated with prices	1,949			(143		)	227			2,033
Changes associated with sales volumes	363			(265		)	(3		)	95
2018 sales revenues	$	6,964		$	682		$	992		$	8,638
Increase (decrease) vs. 2017	50		%	(37		)%	29		%	33		%

The above table illustrates the effects of changes in prices and sales volumes. The changes in sales volumes primarily include increases associated with continued drilling and completion activities in the Delaware and DJ basins and decreases associated with U.S. onshore asset divestitures in 2017 and 2018.

The following provides Anadarko’s sales volumes for the three and nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018	Inc (Dec) vs. 2017		2017	2018	Inc (Dec) vs. 2017		2017
Barrels of Oil Equivalent
(MMBOE except percentages)
United States	53	7	%	50	153	(5	)%	161
International	10	18		8	26	(3	)	26
Total barrels of oil equivalent	63	9		58	179	(4	)	187
Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States	575	7	%	535	560	(5	)%	587
International	107	18		91	94	(3	)	96
Total barrels of oil equivalent per day	682	9		626	654	(4	)	683

Sales volumes represent actual production volumes adjusted for changes in commodity inventories as well as natural-gas production volumes provided to satisfy a commitment under the Jubilee development plan in Ghana. The Company has derivative instruments in place to reduce the price risk associated with future production. For additional information, see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.

44

Oil Sales Revenues, Average Prices, and Volumes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Oil sales revenues (millions)	$	2,572	64	%	$	1,567	$	6,964	50	%	$	4,652
United States
Sales volumes—MMBbls	26		12	%	25		78		12	%	71
MBbls/d	296		12		266		288		12		259
Price per barrel	$	68.25	46		$	46.89	$	65.96	38		$	47.63
International
Sales volumes—MMBbls	10		16	%	8		25		(3	)%	25
MBbls/d	101		16		87		89		(3	)	91
Price per barrel	$	76.55	46		$	52.61	$	72.85	41		$	51.59
Total
Sales volumes—MMBbls	36		13	%	33		103		8	%	96
MBbls/d	397		13		353		377		8		350
Price per barrel	$	70.37	46		$	48.31	$	67.57	39		$	48.66

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
Three months ended September 30, 2018 vs. 2017	$	1,005	$	806	$	199
Nine months ended September 30, 2018 vs. 2017	2,312		1,949		363

Oil Prices

The average oil price received increased for the three and nine months ended September 30, 2018, primarily due to concerns of a supply shortfall as a result of reductions in output from Iran as the U.S. reimposes sanctions as well as decreased production from Venezuela.

45

Oil Sales Volumes

2018 vs. 2017  The Company’s oil sales volumes increased by 44 MBbls/d for the three months ended September 30, 2018, and 27 MBbls/d for the nine months ended September 30, 2018, primarily due to the following:

U.S. Onshore

• Sales volumes for the Delaware basin increased by 32 MBbls/d for the three months ended September 30, 2018, and 27 MBbls/d for the nine months ended September 30, 2018, due to continued drilling and completion activities and midstream infrastructure additions in 2018.

• Sales volumes for the DJ basin increased by 13 MBbls/d for the three months ended September 30, 2018, and 19 MBbls/d for the nine months ended September 30, 2018, primarily due to continued drilling and completion activities in 2018.

• Divestitures resulted in decreased sales volumes of 12 MBbls/d for the three months ended September 30, 2018, and 18 MBbls/d for the nine months ended September 30, 2018, 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 volumes for the Gulf of Mexico decreased by 5 MBbls/d for the three months ended September 30, 2018, and remained flat for the nine months ended September 30, 2018, primarily due to natural production declines and planned downtime at various platforms, partially offset by continued tie-back activity at Horn Mountain and Marlin.

International

• Sales volumes for Algeria increased by 6 MBbls/d for the three months ended September 30, 2018, primarily due to the timing of liftings. Sales volumes decreased by 5 MBbls/d for the nine months ended September 30, 2018, primarily due to the timing of liftings and a decrease in production driven by facility downtime for statutory maintenance in early 2018.

• SalesvolumesforGhanaincreasedby8MBbls/dfor the three months ended September 30, 2018, and3 MBbls/d for the nine months ended September 30, 2018, primarily due to increased field performance at the TEN field, which resulted in an additional lifting in the third quarter of 2018.

46

Natural-Gas Sales Revenues, Average Prices, and Volumes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Natural-gas sales revenues (millions)	$	232	(14	)%	$	269	$	682	(37	)%	$	1,090
United States
Sales volumes—Bcf	98		(1	)%	100		287		(24	)%	380
MMcf/d	1,071		(1	)	1,086		1,053		(24	)	1,392
Price per Mcf	$	2.35	(13	)	$	2.69	$	2.37	(17	)	$	2.87

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
Three months ended September 30, 2018 vs. 2017	$	(37	)	$	(33	)	$	(4	)
Nine months ended September 30, 2018 vs. 2017	(408		)	(143		)	(265		)

Natural-Gas Prices

The average natural-gas price received decreased for the three and nine months ended September 30, 2018, primarily due to increased U.S. natural-gas production, partially offset by increased weather-driven consumer demand coupled with an increase in natural-gas exports to Mexico and LNG exports.

Natural-Gas Sales Volumes

2018 vs. 2017The Company’s natural-gas sales volumes remained relatively flat for the three months ended September 30, 2018. Natural-gas sales volumes decreased by 339 MMcf/d for the nine months ended September 30, 2018, 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.

47

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Natural-gas liquids sales revenues (millions)	$	382	44	%	$	265	$	992	29	%	$	768
Total
Sales volumes—MMBbls (1)	10		15	%	9		28		—	%	28
MBbls/d (1)	106		15		92		101		—		101
Price per barrel	$	39.16	26		$	31.15	$	36.00	30		$	27.77

 _______________________________________________________________________________

⁽¹⁾  The percentage of total and daily NGLs sales volumes from the U.S. was approximately 95% for three and nine months ended September 30, 2018, and 2017.

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. 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
Three months ended September 30, 2018 vs. 2017	$	117	$	78	$	39
Nine months ended September 30, 2018 vs. 2017	224		227		(3		)

NGLs Prices

The average NGLs price received increased for the three and nine months ended September 30, 2018, primarily due to increased demand for ethane to supply newly-constructed ethane cracker facilities as well as higher propane exports.

NGLs Sales Volumes

2018 vs. 2017The Company’s NGLs sales volumes increased by 14 MBbls/d for the three months ended September 30, 2018, and remained flat for the nine months ended September 30, 2018, primarily due to the following:

U.S. Onshore

• Sales volumes for the Delaware basin increased by 14 MBbls/d for the three months ended September 30, 2018, and 9 MBbls/d for the nine months ended September 30, 2018, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018.

• Sales volumes for other U.S. onshore assets decreased by 8 MBbls/d for the nine months ended September 30, 2018, primarily due to the sale of the Eagleford and West Chalk assets in the first half of 2017 and the Moxa assets in the second half of 2017.

48

Gathering, Processing, and Marketing

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Gathering, processing, and marketing sales (1)	$	421	(17	)%	$	509	$	1,163	(18	)%	$	1,417
Gathering, processing, and marketing expense (1)	256		(35	)	396		745		(32	)	1,101
Gathering, processing, and marketing, net	$	165	46		$	113	$	418	32		$	316

 __________________________________________________________________

⁽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 $296 million for the three months ended September 30, 2018, and $781 million for the nine months ended September 30, 2018, and gathering, processing, and marketing expenses decreased by $295 million for the three months ended September 30, 2018, and $775 million for the nine months ended September 30, 2018. Refer to Note 2—Revenue from Contracts with Customersin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q 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 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 expenses related to the Company’s costs to perform gathering and processing activities.

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.

Total gathering, processing, and marketing, net increased by $52 million for the three months ended September 30, 2018, and by $102 million for the nine months ended September 30, 2018, primarily due to increased throughput volumes at the DBM Complex, which were partially due to increased capacity from the 200 MMcf/d cryogenic train that commenced service in December 2017, and increased throughput volumes at the DJ Basin Complex.

Gains (Losses) on Divestitures and Other, net

	Three Months Ended							Nine Months Ended
	September 30,							September 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017			2018		Inc (Dec) vs. 2017		2017
Gains (losses) on divestitures, net	$	3	102	%	$	(194	)	$	31	(96	)%	$	815
Other	87		9		80			201		(15	)	237
Gains (losses) on divestitures and other, net	$	90	179		$	(114	)	$	232	(78	)	$	1,052

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

During the nine months ended September 30, 2018 and 2017, Anadarko divested certain non-core U.S. onshore and Gulf of Mexico assets. See Note 4—Divestituresin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

49

Costs and Expenses

The following provides Anadarko’s total costs and expenses for the three and nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2018		2017		2018		2017
Oil and gas operating	$	294	$	253	$	845	$	738
Oil and gas transportation	228		220		633		698
Exploration	118		750		380		2,366
Gathering, processing, and marketing (1)	256		396		745		1,101
G&A	248		261		814		768
DD&A	1,130		1,083		3,123		3,235
Production, property, and other taxes	246		159		637		449
Impairments	172		—		319		383
Other operating expense	26		123		188		157
Total	$	2,718	$	3,245	$	7,684	$	9,895

__________________________________________________________________

⁽¹⁾  See above explanation of gathering, processing, and marketing.

Oil and Gas Operating and Transportation Expenses

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Oil and gas operating (millions)	$	294	16	%	$	253	$	845	14	%	$	738
Oil and gas operating—per BOE	4.69		7		4.40		4.73		20		3.95
Oil and gas transportation (millions)	228		4		220		633		(9	)	698
Oil and gas transportation—per BOE	3.63		(5	)	3.82		3.54		(5	)	3.74

Oil and Gas Operating Expense

Oil and gas operating expense increased by $107 million for the nine months ended September 30, 2018, primarily due to the following:

• higher operating costs of $97 million, primarily related to increased activity in the DJ and Delaware basins, partially offset by lower expenses of $63 million as a result of U.S. onshore asset divestitures

• higher non-operating costs of $55 million in Ghana, primarily due to the Jubilee turret repair in 2018 and cost adjustment credits received from the operator in 2017

The related costs per BOE increased by $0.78 for the nine months ended September 30, 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 the DJ and Delaware basins, which operate at a higher cost compared to the divested lower-return, gas-levered assets.

Oil and Gas Transportation Expense

Oil and gas transportation expense decreased by $65 million for the nine months ended September 30, 2018, primarily due to U.S. onshore divestitures. Oil and gas transportation expense per BOE decreased by $0.20 for the nine months ended September 30, 2018, primarily due to divestitures and lower transportation expense per BOE in the DJ basin. After significant investment in its midstream infrastructure, the Company has increased the use of its midstream facilities resulting in lower transportation costs for its DJ sales volumes. These decreases are partially offset by higher third-party transportation costs in the Delaware basin.

50

Exploration Expense

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2018		2017		2018		2017
Dry hole expense	$	—	$	565	$	55	$	1,408
Impairments of unproved properties	64		113		158		736
Geological and geophysical, exploration overhead, and other expense	54		72		167		222
Total	$	118	$	750	$	380	$	2,366

Dry Hole Expense

Dry hole expense for the nine months ended September 30, 2018, primarily related to the following:

• $49 million related to unsuccessful drilling activities in the Gulf of Mexico during the first quarter of 2018

Dry hole expense for the nine months ended September 30, 2017, primarily related to the following:

• $438 million related to the Shenandoah project, $221 million related to the Phobos project, and $110 million related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development

• $325 million related to certain wells in Côte d’Ivoire, where the Company relinquished its interest in its Côte 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

Impairments of Unproved Properties

For discussion related to impairments of unproved properties, see Note 5—Impairmentsin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

G&A

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
G&A	$	248	(5	)%	$	261	$	814	6	%	$	768

G&A increased by $46 million for the nine months ended September 30, 2018, primarily due to an increase in the fair value of performance-based unit awards. The fair value of the performance-based unit awards is calculated using a Monte Carlo simulation that incorporates several variables, including Anadarko’s historical share price and share prices of a predetermined group of peer companies to estimate the future total shareholder returns of each. Accordingly, future G&A could be higher or lower based on the outputs from the Monte Carlo simulation for the performance-based unit awards.

51

Impairments

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2018		2017		2018		2017
Impairments	$	172	$	—	$	319	$	383

During the nine months ended September 30, 2018, the Company recorded asset impairments related to its hard-minerals properties and a gathering system in the DJ basin. During the nine months ended September 30, 2017, the Company recorded asset impairments related to various oil and gas properties in the Gulf of Mexico and a U.S. onshore midstream property. For additional information, see Note 5—Impairments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Other Operating Expense

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Other operating expense	$	26	(79	)%	$	123	$	188	20	%	$	157

Other operating expense includes adjustments to contingency accruals, charges for drilling rig idle time, adjustments to drilling rig termination fees, and surface owner payments.

Other (Income) Expense

The following provides Anadarko’s other (income) expense for the three and nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2018		2017		2018		2017
Interest expense	$	240	$	230	$	705	$	682
(Gains) losses on derivatives, net (1)	32		82		503		(33		)
Other (income) expense, net	24		5		16		51
Total	$	296	$	317	$	1,224	$	700

__________________________________________________________________

⁽¹⁾  (Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments as a result of changes in commodity prices and interest rates, contract modifications, and settlements. See Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

52

Income Tax Expense (Benefit)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2018			2017			2018			2017
Income tax expense (benefit)	$	256		$	(425	)	$	507		$	(366	)
Income (loss) before income taxes	683			(1,066		)	1,125			(1,616		)
Effective tax rate	37		%	40		%	45		%	23		%

Upon enactment of the Tax Reform Legislation on December 22, 2017, 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%. During the third quarter of 2018, the Company recognized an additional net tax benefit of $5 million related to the adoption of the Tax Reform Legislation. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation and record any remaining adjustments to provisional tax amounts, which could be material to income tax expense, before the end of the measurement period on December 21, 2018.

The Company’s effective tax rate is impacted each year by the relative 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), and dispositions of non-deductible goodwill.

The Company received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. In April 2018, the IRS issued a 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 intends to file a petition with the U.S. Tax Court to dispute the disallowances, 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 Company does not prevail on the issue, the earliest potential date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial 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 11—Income Taxesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

53

LIQUIDITY AND CAPITAL RESOURCES

	Nine Months Ended
	September 30,
millions	2018			2017
Net cash provided by (used in) operating activities	$	4,302		$	2,619
Net cash provided by (used in) investing activities	(4,659		)	(28		)
Net cash provided by (used in) financing activities	(2,306		)	(527		)

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 divestitures and joint-venture arrangements that reduce future capital expenditures, the Company’s credit facilities, 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 the nine months ended September 30, 2018, Anadarko paid $2.4 billion to repurchase shares under the Share-Repurchase Program and received net proceeds of $393 million from divestitures, primarily related to the sale of the Company’s nonoperated interest in Alaska. As of September 30, 2018, Anadarko had $1.9 billion of cash plus $5.0 billion of borrowing capacity under its APC RCF and 364-Day Facility. Anadarko believes that its current available cash and future operating cash flows will be sufficient to fund the Company’s projected long-term operational and capital programs, its quarterly dividends, the planned debt retirements, and the repurchase of $500 million of the Company’s common stock remaining under the Share-Repurchase Program. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions.

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 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 $4.3 billion for the nine months ended September 30, 2018, $1.7 billion higher than the same period in 2017, primarily due to higher sales revenues resulting from higher commodity prices and a higher oil composition of sales volumes.

54

Investing Activities

Capital ExpendituresThe following presents the Company’s capital expenditures:

	Nine Months Ended
	September 30,
millions	2018			2017
Cash Flows from Investing Activities
Additions to properties and equipment (1)	$	4,891		$	3,538
Adjustments for capital expenditures
Changes in capital accruals	61			237
Other	(7		)	21
Total capital expenditures	$	4,945		$	3,796
Exploration and Production and other capital expenditures	$	3,367		$	2,876
WES Midstream capital expenditures	920			662
Other Midstream capital expenditures	658			258

 ________________________________________________________________________________________

⁽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.

The Company’s capital expenditures increased by $1.1 billion for the nine months ended September 30, 2018. Exploration and Production capital expenditures increased primarily due to higher development costs of $850 million driven by increased drilling and completion activities primarily in the DJ and Delaware basins and the Gulf of Mexico. Exploration costs decreased by $396 million primarily related to decreased exploration drilling in the Gulf of Mexico, Côte d’Ivoire, and Colombia partially offset by higher exploration drilling in the U.S. onshore. Other Midstream capital expenditures increased $400 million due to asset development primarily in the Delaware basin. WES Midstream capital expenditures increased $258 million primarily related to the development of assets in the Delaware and DJ basins.

Investments  During the nine months ended September 30, 2018, the Company made capital contributions of $235 million for equity investments, 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.

Divestitures  During the nine months ended September 30, 2018, Anadarko received net proceeds of $393 million from divestitures, primarily related to the sale of the Company’s nonoperated interest in Alaska. See Note 4—Divestituresin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

55

Financing Activities

	September 30,			December 31,
millions except percentages	2018			2017
Anadarko	$	12,099		$	12,196
WES	4,566			3,465
WGP	28			28
Total debt	$	16,693		$	15,689
Total equity	11,237			13,790
Consolidated debt to total capitalization ratio	59.8		%	53.2		%

Debt Activity

Anadarko Debentures  The Company repaid $114 million of 7.050% Debentures at maturity in May 2018.

Anadarko RCFs  In January 2018, the Company amended its $3.0 billion senior unsecured RCF to extend the maturity date to January 2022 (APC RCF) and amended its $2.0 billion364-day senior unsecured RCF to extend the maturity date to January 2019 (364-Day Facility). At September 30, 2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

WES Senior Notes  In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from the public offerings were used to repay the maturing $350 million of 2.600% Senior Notes due August 2018 and amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.

In March 2018, WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the public offerings were used to repay amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.

WES and WGP RCFs  In February 2018, WES amended its RCF to extend the maturity date from February 2020 to February 2023 and expanded the borrowing capacity to $1.5 billion (WES RCF). As part of the amendment, the WES RCF is expandable to a maximum of $2.0 billion. During the nine months ended September 30, 2018, WES borrowed $320 million under its RCF, which was used for general partnership purposes, and made repayments of $690 million. At September 30, 2018, WES had no outstanding borrowings under its RCF, outstanding letters of credit of $5 million, available borrowing capacity of $1.495 billion, and was in compliance with all covenants.

In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under its senior secured RCF maturing in March 2019 from $250 million to $35 million (WGP RCF). At September 30, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.25% classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $7 million.

For additional information on the Company’s debt instruments, see Note 10—Debtin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Debt Maturities  At September 30, 2018, Anadarko had outstanding borrowings of $600 million of 8.700% Senior Notes due March 2019 and $300 million of 6.950% Senior Notes due June 2019 classified as short-term debt on the Company’s Consolidated Balance Sheet.

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 2018. The Zero Coupons can next be put to the Company in October 2019, which, if put in whole, would be $980 million.

For additional information on the Company’s debt instruments, see Note 10—Debt in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

56

Equity Transactions  In February 2018, as part of the Share-Repurchase Program, the Company completed the repurchase of 8.5 million shares of its common stock for $500 million (average price of $58.82 per share) under an ASR Agreement. In March 2018, the Company entered into an additional ASR Agreement, which was completed in June 2018 and resulted in the repurchase of 22.1 million shares of its common stock for $1.4 billion (average price of $65.28 per share). In July 2018, the Share-Repurchase Program was expanded to $4.0 billion and extended through June 30, 2019. In the third quarter of 2018, the Company completed the repurchase of 7.7 million shares of its common stock for $500 million through open-market repurchases. For additional information, see Note 14—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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 pursuant to a continuous offering program that has not yet been initiated.

Derivative Instruments  For information on derivative instruments, including cash flow treatment, see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Common Stock Dividends  Anadarko paid dividends to its common stockholders of $380 million during the nine months ended September 30, 2018, and $84 million during the nine months ended September 30, 2017. In February 2018, the Company announced an increase to the quarterly dividend to $0.25 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.

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

	Nine Months Ended
	September 30,
millions	2018		2017
WES distributions to unitholders (excluding Anadarko and WGP) (1)	$	282	$	235
WES distributions to Series A Preferred unitholders (2)	—		22
WGP distributions to unitholders (excluding Anadarko) (3)	73		60

__________________________________________________________________

⁽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 $0.965 per common unit for the third quarter of 2018 (to be paid in November 2018).

⁽²⁾  WES made quarterly 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 15—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.

⁽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 $0.59500 per unit for the third quarter of 2018 (to be paid in November 2018).

RECENT ACCOUNTING DEVELOPMENTS 

See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion of recent accounting developments affecting the Company.

57

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. These risks can affect revenues and cash flows, and the Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

COMMODITY-PRICE RISK  The Company’s most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes  The Company had derivative instruments in place to reduce the price risk associated with future production of 49 MMBbls of oil and 49 Bcf of natural gas at September 30, 2018, with a net derivative liability position of $458 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would increase the net derivative liability by $308 million, while a 10% decrease in underlying commodity prices would decrease the net derivative liability by $270 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

INTEREST-RATE RISK  Borrowings, if any, under each of the 364-Day Facility, the APC RCF, the WES RCF, and the WGP RCF are subject to variable interest rates. The remaining balance of the Company’s short-term and long-term borrowings has fixed interest rates. The Company has $2.9 billion of LIBOR-based obligations that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two noncontrolled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in the applicable benchmark interest rate would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.

At September 30, 2018, the Company had a net derivative liability position of $1.0 billion related to interest-rate swaps. A 10% increase (decrease) in the LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by $103 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

58

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the third quarter of 2018 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

59

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

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

WGR Operating, LP, a subsidiary of the Company, is currently in negotiations with the U.S. Environmental Protection Agency (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 these matters will result in a fine or penalty in excess of $100,000.

In September 2018, Anadarko E&P Onshore LLC, a subsidiary of the Company, entered into a final consent assessment with the Pennsylvania Department of Environmental Protection resolving issues concerning a produced water release in Pennsylvania in 2015 and agreed to pay a penalty of $350,000.

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

Kerr-McGee Gathering, LLC, a subsidiary of the Company, is currently in negotiations with the EPA and the Department of Justice with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Fort Lupton complex. 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 May 2018, Delaware Basin Midstream, LLC, a subsidiary of the Company, entered into a consent agreement and final order with the EPA with respect to alleged noncompliance with certain Risk Management Plan regulations under the Clean Air Act at its Ramsey Gas Plant and agreed to pay a penalty of $226,000.

The Company continues to work cooperatively with Colorado state regulators and others following a home explosion that occurred in Firestone, Colorado in April 2017. The Company also is cooperating with the NTSB at the federal level in its investigation related to the accident.

See Note 12—Contingencies intheNotestoConsolidatedFinancialStatementsunderPartI,Item1ofthisForm10-Q, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.

60

Item 1A.  Risk Factors

Consider carefully the risk factors included below, as well as those included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

Our operations in Colorado involve risks that could increase our costs of doing business, result in additional operating restrictions or delays, limit the areas in which we can operate, and adversely affect our production.

We have significant operations in the DJ basin located in the state of Colorado. 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 passed, would make exploration and production activities in the state more difficult in the future. For example, Colorado Proposition 112 qualified for inclusion on the Colorado general election ballot in November 2018. The proposition, which requires a majority vote to become law, would amend the Colorado Revised Statutes to require that new oil and gas developments, including hydraulic fracturing, take place a minimum distance of 2,500 feet from occupied buildings such as homes, schools and hospitals, and other areas designated as vulnerable. Although an exemption is made for federal lands, such setbacks would effectively ban new oil and gas drilling on a substantial portion of Colorado’s non-federal lands. According to an analysis prepared at the request of the Colorado Oil & Gas Conservation Commission (COGCC), Proposition 112 could preclude oil and gas development on more than 54% of the total land surface area of Colorado. If only non-federal land is considered, the COGCC has stated that Proposition 112 could preclude development on more than 85% of the land surface. In addition, according to the COGCC, in Colorado’s top five oil and gas producing counties combined, 61% of the surface acreage (94% of non-federal land) would be unavailable. In the event that Proposition 112 or other ballot initiatives, local or state restrictions, or other 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, or in the future plan to conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities and possibly be limited or precluded in the drilling of wells or in the volumes that we are ultimately able to produce from our assets in Colorado. 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.

61

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The following sets forth information with respect to repurchases by the Company of its shares of common stock during the third quarter of 2018:

Period	Total number of shares purchased (1)	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (2)	Approximate dollar value of shares that may yet be purchased under the plans or programs (2)(3)
July 1 - 31, 2018	2,591	$	72.92	—	$	1,000,000,000
August 1 - 31, 2018 (2)	3,782,348	$	66.14	3,781,259	$	749,924,384
September 1 - 30, 2018 (2)	4,002,869	$	63.11	3,960,089	$	500,000,003
Total	7,787,808	$	64.58	7,741,348

 ____________________________________________________________

⁽¹⁾  During the third quarter of 2018, (i) 7.7 million shares were repurchased under the Share-Repurchase Program and (ii) 46 thousand shares were repurchased related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans. For additional information, see Note 14—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.

⁽²⁾  During the third quarter of 2018, the Company repurchased 7.7 million shares of common stock for $500 million through open-market repurchases. For additional information, see Note 14—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.

⁽³⁾  The Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018.In July 2018, the Share-Repurchase Program was further expanded to $4.0 billion and extended through June 30, 2019.

62

Item 6.  Exhibits

Exhibits designated by an asterisk (*) are filed herewith or double asterisk (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated.

Exhibit Number			Description
	3	(i)	Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009
		(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of November 14, 2017, filed as Exhibit 3.1 to Form 8-K filed on November 16, 2017
*	31	(i)	Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*	31	(ii)	Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**	32		Section 1350 Certifications
*	101	.INS	XBRL Instance Document
*	101	.SCH	XBRL Schema Document
*	101	.CAL	XBRL Calculation Linkbase Document
*	101	.DEF	XBRL Definition Linkbase Document
*	101	.LAB	XBRL Label Linkbase Document
*	101	.PRE	XBRL Presentation Linkbase Document

63

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ANADARKO PETROLEUM CORPORATION
		(Registrant)
October 30, 2018	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

64

EX-31.I

EXHIBIT 31(i)

CERTIFICATIONS

I, R. A. Walker, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

October 30, 2018

/s/ R. A. WALKER

R. A. Walker

Chairman, President and Chief Executive Officer

EX-31.II

EXHIBIT 31(ii)

CERTIFICATIONS

I, Robert G. Gwin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

October 30, 2018

/s/ ROBERT G. GWIN

Robert G. Gwin

Executive Vice President, Finance and Chief Financial Officer

EX-32

EXHIBIT 32

SECTION 1350 CERTIFICATION OF PERIODIC REPORT

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, R. A. Walker, Chairman, President and Chief Executive Officer of Anadarko Petroleum Corporation (Company), and Robert G. Gwin, Executive Vice President, Finance and Chief Financial Officer of the Company, certify to the best of our knowledge that:

(1) the Quarterly Report on Form 10-Q of the Company for the period ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

October 30, 2018
	/s/ R. A. WALKER
	R. A. Walker
	Chairman, President and Chief Executive Officer
October 30, 2018
	/s/ ROBERT G. GWIN
	Robert G. Gwin
	Executive Vice President, Finance and Chief Financial Officer

This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose. A signed original of this written statement required by Section 906 will be retained by Anadarko and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 18, 2018
Document And Entity Information [Abstract]
Trading Symbol	APC
Entity Registrant Name	ANADARKO PETROLEUM CORP
Entity Central Index Key	0000773910
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		504,280,902

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Revenues and Other
Revenues from Customers	$ 3,851			$ 10,501
Gains (losses) on divestitures and other, net	90		$ (114)	232		$ 1,052
Total	3,697		2,496	10,033		8,979
Costs and Expenses
Oil and gas operating	294		253	845		738
Oil and gas transportation	228		220	633		698
Exploration	118	[1]	750	380	[1]	2,366
General and administrative	248		261	814		768
Depreciation, depletion, and amortization	1,130		1,083	3,123		3,235
Production, property, and other taxes	246		159	637		449
Impairments	172		0	319		383
Other operating expense	26		123	188		157
Total	2,718		3,245	7,684		9,895
Operating Income (Loss)	979		(749)	2,349		(916)
Other (Income) Expense
Interest expense	240		230	705		682
(Gains) losses on derivatives, net	33		82	506		(33)
Other (income) expense, net	24		5	16		51
Total	296		317	1,224		700
Income (Loss) Before Income Taxes	683		(1,066)	1,125		(1,616)
Income tax expense (benefit)	256		(425)	507		(366)
Net Income (Loss)	427		(641)	618		(1,250)
Net income (loss) attributable to noncontrolling interests	64		58	105		182
Net Income (Loss) Attributable to Common Stockholders	$ 363		$ (699)	$ 513		$ (1,432)
Per Common Share
Net income (loss) attributable to common stockholders—basic (in usd per share)	$ 0.72		$ (1.27)	$ 0.99		$ (2.60)
Net income (loss) attributable to common stockholders—diluted (in usd per share)	$ 0.72		$ (1.27)	$ 0.99		$ (2.61)
Average Number of Common Shares Outstanding—Basic	499		553	507		552
Average Number of Common Shares Outstanding—Diluted	500		553	508		552
Dividends (in usd per share)	$ 0.25		$ 0.05	$ 0.75		$ 0.15
Commodity Contract and Interest Rate Swap [Member]
Other (Income) Expense
(Gains) losses on derivatives, net	$ 32		$ 82	$ 503		$ (33)
Oil sales [Member]
Revenues and Other
Revenues from Customers	2,572		1,567	6,964		4,652
Natural gas sales [Member]
Revenues and Other
Revenues from Customers	232		269	682		1,090
Natural-gas liquids sales [Member]
Revenues and Other
Revenues from Customers	382		265	992		768
Gathering, processing, and marketing [Member]
Revenues and Other
Revenues from Customers	421		509	1,163		1,417
Costs and Expenses
Gathering, processing, and marketing	$ 256		$ 396	$ 745		$ 1,101

[1] Includes restructuring charges of $20 million for the three and nine months ended September 30, 2018.

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 427	$ (641)	$ 618	$ (1,250)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	1	1	2	3
Income taxes on reclassification of previously deferred derivative losses	0	0	0	(1)
Total adjustments for derivative instruments, net of taxes	1	1	2	2
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	25	(14)	25	1
Income taxes on net gain (loss) incurred during period	(6)	5	(6)	0
Amortization of net actuarial (gain) loss to other (income) expense, net	15	29	28	100
Income taxes on amortization of net actuarial (gain) loss	(4)	(11)	(7)	(37)
Amortization of net prior service (credit) cost to other (income) expense, net	(6)	(7)	(18)	(19)
Income taxes on amortization of net prior service (credit) cost	2	3	4	7
Total adjustments for pension and other postretirement plans, net of taxes	26	5	26	52
Total	27	6	28	54
Comprehensive Income (Loss)	454	(635)	646	(1,196)
Comprehensive income (loss) attributable to noncontrolling interests	64	58	105	182
Comprehensive Income (Loss) Attributable to Common Stockholders	$ 390	$ (693)	$ 541	$ (1,378)

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents ($133 and $80 related to VIEs)		$ 1,883	$ 4,553
Accounts receivable (net of allowance of $11 and $14)
Customers ($159 and $106 related to VIEs)		1,644	1,222
Others ($15 and $19 related to VIEs)		547	607
Other current assets		397	380
Total		4,471	6,762
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $36,375 and $34,107) ($6,419 and $5,731 related to VIEs)		28,744	27,451
Other Assets ($801 and $579 related to VIEs)		2,292	2,211
Goodwill and Other Intangible Assets ($1,170 and $1,191 related to VIEs)		5,638	5,662
Total Assets		41,145	42,086
Accounts payable
Trade ($337 and $305 related to VIEs)		2,144	1,894
Other ($16 and $1 related to VIEs)		201	266
Short-term debt		938	142
Current asset retirement obligations		332	294
Other current liabilities		1,502	1,310
Total		5,117	3,906
Long-term Debt		15,755	15,547
Other Long-term Liabilities
Deferred income taxes		2,455	2,234
Asset retirement obligations ($158 and $143 related to VIEs)		2,538	2,500
Other		4,043	4,109
Total		9,036	8,843
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.2 million and 574.2 million shares issued)		57	57
Paid-in capital		12,344	12,000
Retained earnings		1,291	1,109
Treasury stock (82.3 million and 43.4 million shares)		(4,608)	(2,132)
Accumulated other comprehensive income (loss)		(383)	(338)
Total Stockholders’ Equity		8,701	10,696
Noncontrolling interests		2,536	3,094
Total Equity		11,237	13,790
Total Liabilities and Equity		41,145	42,086
Anadarko [Member]
Accounts payable
Short-term debt	[1]	910	142
Long-term Debt		11,189	12,054
WES and WGP [Member]
Accounts payable
Short-term debt		28	0
Long-term Debt		$ 4,566	$ 3,493

[1] Excludes WES and WGP.

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 1,883	$ 4,553
Accounts receivable
Allowance for uncollectible accounts	11	14
Customers	1,644	1,222
Others	547	607
Property, Plant and Equipment, Net [Abstract]
Net properties and equipment related to VIEs	28,744	27,451
Accumulated depreciation, depletion and amortization	36,375	34,107
Other Assets	2,292	2,211
Goodwill and Other Intangible Assets	5,638	5,662
Accounts payable
Trade	2,144	1,894
Other	201	266
Other Long-term Liabilities
Asset retirement obligations	$ 2,538	$ 2,500
Stockholders’ equity
Common stock, par value per share (in usd per share)	$ 0.1	$ 0.10
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	576,200,000	574,200,000
Treasury stock, shares	82,300,000	43,400,000
Variable Interest Entity, Primary Beneficiary [Member]
Current Assets
Cash and cash equivalents	$ 133	$ 80
Accounts receivable
Customers	159	106
Others	15	19
Property, Plant and Equipment, Net [Abstract]
Net properties and equipment related to VIEs	6,419	5,731
Other Assets	801	579
Goodwill and Other Intangible Assets	1,170	1,191
Accounts payable
Trade	337	305
Other	16	1
Other Long-term Liabilities
Asset retirement obligations	$ 158	$ 143

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CONSOLIDATED STATEMENT OF EQUITY - 9 months ended Sep. 30, 2018 - USD ($) $ in Millions		Total	Subsidiary Equity Transactions [Member]	Equity Component of 7.50% Tangible Equity Units [Member]	Common Stock [Member]	Paid-in Capital [Member]	Paid-in Capital [Member] Subsidiary Equity Transactions [Member]	Paid-in Capital [Member] Equity Component of 7.50% Tangible Equity Units [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member] Subsidiary Equity Transactions [Member]	Noncontrolling Interests [Member] Equity Component of 7.50% Tangible Equity Units [Member]
Balance at Dec. 31, 2017		$ 13,790			$ 57	$ 12,000			$ 1,109	$ (2,132)	$ (338)	$ 3,094
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		618							513			105
Common stock issued		6				6
Share-based compensation expense		125				125
Dividends—common stock		(380)							(380)
Repurchases of common stock		(2,476)								(2,476)
Subsidiary equity transactions			$ 8				$ (17)						$ 25
Settlement of tangible equity units				$ (70)				$ 230						$ (300)
Distributions to noncontrolling interest owners		(365)										(365)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net		2									2
Adjustments for pension and other postretirement plans		(26)									(26)
Balance at Sep. 30, 2018		11,237			$ 57	$ 12,344			1,291	$ (4,608)	(383)	2,536
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect of accounting change	[1]	$ (47)							$ 49		$ (73)	$ (23)

[1] Beginning January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and 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.

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash Flows from Operating Activities
Net income (loss)	$ 618	$ (1,250)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	3,123	3,235
Deferred income taxes	141	(1,026)
Dry hole expense and impairments of unproved properties	212	2,144
Impairments	319	383
(Gains) losses on divestitures, net	(31)	(815)
Total (gains) losses on derivatives, net	506	(33)
Operating portion of net cash received (paid) in settlement of derivative instruments	(433)	21
Other	224	227
Changes in assets and liabilities
(Increase) decrease in accounts receivable	(344)	(32)
Increase (decrease) in accounts payable and other current liabilities	230	(95)
Other items, net	(263)	(140)
Net cash provided by (used in) operating activities	4,302	2,619
Cash Flows from Investing Activities
Additions to properties and equipment	(4,891)	(3,538)
Divestitures of properties and equipment and other assets	393	3,480
Other, net	(161)	30
Net cash provided by (used in) investing activities	(4,659)	(28)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	2,131	249
Repayments of debt	(1,176)	(42)
Financing portion of net cash received (paid) for derivative instruments	19	(160)
Increase (decrease) in outstanding checks	(13)	(58)
Dividends paid	(380)	(84)
Repurchases of common stock	(2,476)	(37)
Issuances of common stock	6	0
Distributions to noncontrolling interest owners	(365)	(327)
Payments of future hard-minerals royalty revenues conveyed	(50)	(50)
Other financing activities	(2)	(18)
Net cash provided by (used in) financing activities	(2,306)	(527)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents	(18)	4
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	(2,681)	2,068
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period	4,674	3,308
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period	$ 1,993	$ 5,376

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing its Mozambique LNG project toward FID. In addition, the Company engages in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. The Company also participates in the hard-minerals business through royalty arrangements.

Basis of Presentation  The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain notes and other information have been condensed or omitted. The accompanying interim financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation. These interim financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

The consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. The Company has determined that WGP and WES are VIEs. Anadarko is considered the primary beneficiary and consolidates WGP and WES. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in noncontrolled entities that Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Investments are included in other assets.

Recently Adopted Accounting Standards  ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The Company adopted this ASU on January 1, 2018, with retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. Upon adoption, non-service cost components of net periodic benefit costs of $107 million for 2017, including $94 million for the nine months ended September 30, 2017, were reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense.

ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Company adopted this ASU using a retrospective approach on January 1, 2018. Adoption did not have a material impact on the Company’s consolidated financial statements. See Consolidated Statements of Cash Flows and Note 17—Supplemental Cash Flow Informationfor additional information.

1. Summary of Significant Accounting Policies (Continued)

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior-period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included a reduction to total equity of $47 million. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. See Note 2—Revenue from Contracts with Customers for additional information. The Company’s revenue recognition accounting policy effective January 1, 2018, is detailed below.

• Exploration and Production—The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. For natural gas and NGLs sold on our behalf by a processor, revenue is typically measured based on the price the processor receives for the sale, less certain costs withheld by the processor.

Revenues are recognized for the sale of Anadarko’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee to move oil from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income.

1. Summary of Significant Accounting Policies (Continued)

• WES Midstream and Other Midstream—Anadarko provides gathering, compressing, treating, processing, stabilizing, transporting, and disposal services pursuant to a variety of contracts. Under these arrangements, the Company receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Revenue is recognized for fee-based gathering and processing services in the month of service based on the volumes delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period.

The Company’s midstream business also purchases natural-gas volumes from producers at the wellhead or production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. These fees are treated as a reduction of the purchase cost when the fees relate to services performed after control of the product has transferred to Anadarko. Revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to a third party.

Revenue from percentage of proceeds gathering and processing contracts is recognized net of the cost of product for purchases from service customers when the Company is acting as their agent in the product sale, and any fees charged on these percentage of proceeds contracts are recognized in service revenues.

ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, provides entities the option to reclassify stranded tax effects resulting from the Tax Reform Legislation from accumulated other comprehensive income (AOCI) to retained earnings. In accordance with its accounting policy, the Company releases stranded income tax effects from AOCI in the period the underlying portfolio is liquidated. This ASU allows for the reclassification of stranded tax effects as a result of the change in tax rates from Tax Reform Legislation to be recorded upon adoption of the ASU, rather than at the actual portfolio liquidation date. The Company adopted this ASU on January 1, 2018, electing to reclassify $73 million from AOCI to retained earnings, including a $2 million federal benefit of state tax impact related to the Tax Reform Legislation.

New Accounting Standards Issued But Not Yet Adopted  ASU 2016-02, Leases (Topic 842), requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Company plans to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases. Anadarko continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU. The Company expects the adoption of this ASU to primarily impact other assets and other long-term liabilities and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko expects to implement new accounting software and complete the evaluation of its systems, processes, and internal controls by the end of 2018. Anadarko will adopt this ASU on January 1, 2019, using a modified retrospective approach. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements and will recognize a cumulative effect adjustment in the opening balance of retained earnings in the period of adoption.

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Revenue from Contracts with Customers

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers

2. Revenue from Contracts with Customers

Change in Accounting Policy  The Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. See Note 1—Summary of Significant Accounting Policies for additional information.

Impacts on Financial Statements

Exploration and Production There were no significant changes to the timing or valuation of revenue recognized for sales of production by the Exploration and Production segment.

WES Midstream and Other Midstream Gathering and processing revenues decreased for contracts where the Company is acting as an agent for its processing customer in the sale of processed volumes and increased for contracts with noncash consideration, with an offset to gathering and processing expense upon product sale. The magnitude of these presentation changes in subsequent periods is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes. These presentation changes do not impact net earnings.

The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements:

CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
September 30, 2018
Assets
Other current assets	$	397	$	395	$	2
Net properties and equipment	28,744		28,697		47
Other assets	2,292		2,282		10
Liabilities
Other current liabilities	1,502		1,494		8
Deferred income taxes	2,455		2,461		(6		)
Other	4,043		3,932		111
Equity
Total equity	11,237		11,291		(54		)

2. Revenue from Contracts with Customers (Continued)

CONSOLIDATED STATEMENT OF INCOME	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
Three Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	421	$	717	$	(296	)
Gains (losses) on divestitures and other, net	90		89		1
Expenses
Gathering, processing, and marketing	256		551		(295		)
Income tax expense (benefit)	256		254		2
Net income (loss) attributable to noncontrolling interests	64		71		(7		)
Net Income (Loss) Attributable to Common Stockholders	$	363	$	358	$	5
Nine Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	1,163	$	1,944	$	(781	)
Gains (losses) on divestitures and other, net	232		233		(1		)
Expenses
Gathering, processing, and marketing	745		1,520		(775		)
Income tax expense (benefit)	507		507		—
Net income (loss) attributable to noncontrolling interests	105		111		(6		)
Net Income (Loss) Attributable to Common Stockholders	$	513	$	514	$	(1	)

2. Revenue from Contracts with Customers(Continued)

Disaggregation of Revenue from Contracts with CustomersThe following table disaggregates revenue by significant product type and segment:

millions	Exploration & Production			WES Midstream			Other Midstream		Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2018
Oil sales	$	2,572		$	—		$	—	$	—		$	2,572
Natural-gas sales	232			—			—		—			232
Natural-gas liquids sales	382			—			—		—			382
Gathering, processing, and marketing sales (1)	—			511			113		1			625
Other, net	9			—			—		31			40
Total Revenue from Customers	$	3,195		$	511		$	113	$	32		$	3,851
Gathering, processing, and marketing sales(2)	—			(3		)	3		(204		)	(204		)
Gains (losses) on divestitures, net	5			—			1		(3		)	3
Other, net	(8		)	52			12		(9		)	47
Total Revenue from Other than Customers	$	(3	)	$	49		$	16	$	(216	)	$	(154	)
Total Revenue and Other	$	3,192		$	560		$	129	$	(184	)	$	3,697
Nine Months Ended September 30, 2018
Oil sales	$	6,964		$	—		$	—	$	—		$	6,964
Natural-gas sales	682			—			—		—			682
Natural-gas liquids sales	992			—			—		—			992
Gathering, processing, and marketing sales(1)	—			1,438			255		83			1,776
Other, net	16			—			—		71			87
Total Revenue from Customers	$	8,654		$	1,438		$	255	$	154		$	10,501
Gathering, processing, and marketing sales(2)	—			(6		)	6		(613		)	(613		)
Gains (losses) on divestitures, net	24			—			10		(3		)	31
Other, net	(21		)	113			30		(8		)	114
Total Revenue from Other than Customers	$	3		$	107		$	46	$	(624	)	$	(468	)
Total Revenue and Other	$	8,657		$	1,545		$	301	$	(470	)	$	10,033

 __________________________________________________________________

⁽¹⁾  The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $328 million and intercompany eliminations of $(312) million for the three months ended September 30, 2018, and sales of third-party natural gas and NGLs of $813 million and intercompany eliminations of $(715) million for the nine months ended September 30, 2018.

⁽²⁾  The amount in Other and Intersegment Eliminations represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table, as the purchases are not considered revenue from customers.

2. Revenue from Contracts with Customers(Continued)

Contract Liabilities Contract liabilities primarily relate to midstream fees and capital reimbursements that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of benefit, fixed and variable fees that are received from customers but revenue recognition is deferred under midstream cost of service contracts, and hard-minerals bonus payments received from customers that must be recognized as revenue over the expected period of benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:

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 (1)	46
Decrease due to revenue recognized (2)	(30		)
Balance at September 30, 2018	$	151
Contract liabilities at September 30, 2018
Other current liabilities	$	23
Other long-term liabilities - other	128
Total contract liabilities from contracts with customers	$	151

 __________________________________________________________________

⁽¹⁾  Includes $(6) million for the three months ended September 30, 2018.

⁽²⁾  Includes $(9) million for the three months ended September 30, 2018.

Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of September 30, 2018, is reflected in the table below. The Company applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. Therefore, the following table represents only a small portion of Anadarko’s expected future consolidated revenues as future revenue from the sale of most products and services is dependent on future production or variable customer volumes and variable commodity prices for those volumes.

millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Remainder of 2018	$	27	$	124	$	31	$	(96	)	$	86
2019	104		480		204		(441		)	347
2020	103		545		293		(606		)	335
2021	103		525		361		(672		)	317
2022	7		529		417		(739		)	214
Thereafter	65		2,192		3,107		(4,662		)	702
Total	$	409	$	4,395	$	4,413	$	(7,216	)	$	2,001

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Commodity Inventories

9 Months Ended

Sep. 30, 2018

Energy Related Inventory [Abstract]

Inventories

3. Commodity Inventories

The following summarizes the major classes of commodity inventories included in other current assets:

	September 30,		December 31,
millions	2018		2017
Oil	$	168	$	165
Natural gas	19		29
NGLs	131		122
Total commodity inventories	$	318	$	316

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Divestitures

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Divestitures

4. Divestitures

Divestitures  The following summarizes the proceeds received and gains (losses) recognized on divestitures:

	Nine Months Ended
	September 30,
millions	2018		2017
Proceeds received, net of closing adjustments	$	393	$	3,480
Gains (losses) on divestitures, net (1)	31		815

__________________________________________________________________

⁽¹⁾  Includes the $126 million gain related to the 2017 property exchange discussed below.

2018During the nine months ended September 30, 2018, the Company divested of the following U.S. onshore and Gulf of Mexico assets:

• 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.

2017During the nine months ended September 30, 2017, the Company divested of the following U.S. onshore assets:

• Eagleford assets in South Texas, included in the Exploration and Production reporting segment, for net proceeds of $2.1 billion and a net gain of $730 million

• Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $758 million and net losses of $56 million in 2017 and $129 million in the fourth quarter of 2016

• 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

Property Exchange On March 17, 2017, 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. WES recognized a gain of $126 million as a result of this transaction. Following the acquisition, the DBJV System is 100% owned by WES and consolidated by Anadarko.

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Impairments

9 Months Ended

Sep. 30, 2018

Asset Impairment Charges [Abstract]

Impairments

5. Impairments

Impairments of Long-Lived Assets

2018During the nine months ended September 30, 2018, the Company expensed $319 million primarily related to the following:

• $145 million in the third quarter of 2018 related to hard-minerals properties due to the Company’s primary consumer of coal stating its intent to retire its existing coal-fired power generation plant earlier than expected, coupled with the outlook for limited new markets for the Company’s coal in the Rockies region. These coal assets had a post-impairment fair value of $15 million.

• $126 million related to a gathering system in the DJ basin, included in the WES Midstream reporting segment that was permanently taken out of service in the second quarter of 2018.

2017During the nine months ended September 30, 2017, the Company expensed $383 million primarily related to the following:

• $211 million related to oil and gas properties in the Gulf of Mexico, included in the Exploration and Production reporting segment, due to lower forecasted commodity prices at that time. The assets had a post-impairment fair value of $231 million.

• $168 million related to U.S. onshore midstream properties, included in the WES Midstream reporting segment, primarily due to a reduced throughput fee as a result of a producer’s bankruptcy. The assets had a post-impairment fair value of $58 million.

Fair values were measured as of the impairment date using the income approach and Level 3 inputs. The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs.

Impairments of Unproved PropertiesImpairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. During the nine months ended September 30, 2018, the Company recognized $158 million of impairments of unproved Gulf of Mexico properties primarily related to blocks where the Company determined it would no longer pursue activities. The Company recognized $586 million of impairments of unproved Gulf of Mexico properties during the nine months ended September 30, 2017, of which $463 million related 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.

It is reasonably possible that significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional impairments.

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Exploratory Well Costs

9 Months Ended

Sep. 30, 2018

Capitalized Exploratory Well Costs [Abstract]

Exploratory Well Costs

6. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $510 million at September 30, 2018, and $525 million at December 31, 2017. For exploratory wells, drilling costs are capitalized, or “suspended,” on the balance sheet when the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. During the nine months ended September 30, 2018, there was no exploration expense recorded for suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017.

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Current Liabilities

9 Months Ended

Sep. 30, 2018

Payables and Accruals [Abstract]

Current Liabilities

7. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $205 million at September 30, 2018, and $219 million atDecember 31, 2017, representing the amount by which checks issued but not presented to the Company’s banks for collection exceeded balances in applicable bank accounts. Changes in these liabilities are classified as cash flows from financing activities.

Other Current Liabilities The following summarizes the Company’s other current liabilities:

	September 30,		December 31,
millions	2018		2017
Accrued income taxes	$	79	$	71
Interest payable	169		246
Production, property, and other taxes payable	344		216
Accrued employee benefits	270		210
Derivatives	491		384
Other	149		183
Total other current liabilities	$	1,502	$	1,310

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Derivative Instruments

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

8. Derivative Instruments

Objective and Strategy  The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities.

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates.

The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings.

8. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The oil prices listed below are a combination of NYMEX WTI and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, 2018:

	2018 Settlement		2019 Settlement
Oil
Two-Way Collars (MBbls/d)	108		—
Average price per barrel (WTI)
Ceiling sold price (call)	$	60.48	$	—
Floor purchased price (put)	$	50.00	$	—
Three-Way Collars (MBbls/d)	—		87
Average price per barrel (WTI and Brent)
Ceiling sold price (call)	$	—	$	72.98
Floor purchased price (put)	$	—	$	56.72
Floor sold price (put)	$	—	$	46.72
Fixed-Price Contracts (MBbls/d)	84		—
Average price per barrel (Brent)	$	61.45	$	—
Natural Gas
Three-Way Collars (thousand MMBtu/d)	250		—
Average price per MMBtu (Henry Hub)
Ceiling sold price (call)	$	3.54	$	—
Floor purchased price (put)	$	2.75	$	—
Floor sold price (put)	$	2.00	$	—
Fixed-Price Contracts (thousand MMBtu/d)	280		—
Average price per MMBtu (Henry Hub)	$	3.02	$	—

A two-way collar is a combination of two options: a sold call and a purchased put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes.

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

8. Derivative Instruments (Continued)

Interest-Rate Derivatives  Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR.

In August 2018, the Company amended an interest-rate swap with a notional principal amount of $200 million, extending the mandatory termination date from 2018 to 2023 in exchange for a cash payment of approximately $10 million.

At September 30, 2018, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or in September 2023 that manage interest-rate risk associated with potential future debt issuances. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at September 30, 2018: 

millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418%
$	250	September 2016 - 2046	September 2022	6.809%
$	100	September 2017 - 2047	September 2020	6.891%
$	250	September 2017 - 2047	September 2021	6.570%
$	450	September 2017 - 2047	September 2023	6.445%

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or cash payments for amendments related to these extended interest-rate derivatives are classified as cash flows from financing activities. Net cash payments related to settlements and amendments of interest-rate swap agreements were $101 million during the nine months ended September 30, 2018, and $118 million during the nine months ended September 30, 2017.

8. Derivative Instruments (Continued)

Effect of Derivative Instruments—Balance Sheet  The following summarizes the fair value of the Company’s derivative instruments:

	Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2018		2017		2018			2017
Commodity derivatives
Other current assets	$	2	$	7	$	—		$	(1	)
Other assets	—		2		—			—
Other current liabilities	20		45		(440		)	(206		)
Other liabilities	15		—		(56		)	(2		)
	37		54		(496		)	(209		)
Interest-rate derivatives
Other current assets	21		14		—			—
Other assets	54		40		—			—
Other current liabilities	—		—		(80		)	(236		)
Other liabilities	—		—		(1,028		)	(1,183		)
	75		54		(1,108		)	(1,419		)
Total derivatives	$	112	$	108	$	(1,604	)	$	(1,628	)

Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:

	Three Months Ended					Nine Months Ended
millions	September 30,					September 30,
Classification of (Gain) Loss Recognized	2018			2017		2018			2017
Commodity derivatives
Gathering, processing, and marketing sales	$	1		$	—	$	3		$	—
(Gains) losses on derivatives, net	104			43		734			(164		)
Interest-rate derivatives
(Gains) losses on derivatives, net	(72		)	39		(231		)	131
Total (gains) losses on derivatives, net	$	33		$	82	$	506		$	(33	)

8. Derivative Instruments (Continued)

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types.

The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s portfolio valuation versus negotiated credit thresholds. These credit thresholds generally require full or partial collateralization of the Company’s obligations depending on certain credit-risk-related provisions, such as the Company’s credit rating from S&P and Moody’s. As of September 30, 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. The Company may be required to post additional collateral with respect to its derivative instruments if its credit ratings decline below current levels or if the liability associated with any such derivative instrument increases substantially. For example, based on the derivative positions as of September 30, 2018, if Anadarko’s credit rating were to be downgraded one level by either S&P or Moody’s, the Company could be required to post additional collateral of up to approximately $124 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 $49 million of collateral) at September 30, 2018, and $1.4 billion (net of $170 million of collateral) at December 31, 2017.

8. Derivative Instruments (Continued)

Fair Value  Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.

The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:

millions	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
September 30, 2018
Assets
Commodity derivatives	$	—		$	37		$	—	$	(35	)	$	—		$	2
Interest-rate derivatives	—			75			—		—			—			75
Total derivative assets	$	—		$	112		$	—	$	(35	)	$	—		$	77
Liabilities
Commodity derivatives	$	—		$	(496	)	$	—	$	35		$	6		$	(455	)
Interest-rate derivatives	—			(1,108		)	—		—			49			(1,059		)
Total derivative liabilities	$	—		$	(1,604	)	$	—	$	35		$	55		$	(1,514	)
December 31, 2017
Assets
Commodity derivatives	$	1		$	53		$	—	$	(46	)	$	(1	)	$	7
Interest-rate derivatives	—			54			—		—			—			54
Total derivative assets	$	1		$	107		$	—	$	(46	)	$	(1	)	$	61
Liabilities
Commodity derivatives	$	(1	)	$	(208	)	$	—	$	46		$	3		$	(160	)
Interest-rate derivatives	—			(1,419		)	—		—			170			(1,249		)
Total derivative liabilities	$	(1	)	$	(1,627	)	$	—	$	46		$	173		$	(1,409	)

 __________________________________________________________________

⁽¹⁾  Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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Tangible Equity Units

9 Months Ended

Sep. 30, 2018

Tangible Equity Units [Abstract]

Tangible Equity Units

9. Tangible Equity Units

In June 2015, the Company issued 9.2 million7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU was comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. The prepaid equity purchase contract was considered a freestanding financial instrument, indexed to WGP common units, and met the conditions for equity classification.

Equity ComponentOn June 7, 2018, the mandatory settlement date, Anadarko settled 9.2 million outstanding TEUs in exchange for approximately 8.2 million WGP common units based on the determined final settlement rate of 0.8921 WGP common units per outstanding TEU. See settlement of tangible equity units in the Company’s Consolidated Statement of Equity.

Debt Component Each senior amortizing note had an initial principal amount of $10.95 and bore interest at 1.50% per year. The final installment payment of $9 million was made on June 7, 2018. For activity related to the senior amortizing notes, see Note 10—Debt.

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Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Debt

10. Debt

Debt Activity  The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the nine months ended September 30, 2018:

	Carrying Value
millions	WES			WGP (1)		Anadarko (2)			Anadarko Consolidated			Description
Balance at December 31, 2017	$	3,465		$	28	$	11,965		$	15,458
Issuances
	394			—		—			394			WES 4.500% Senior Notes due 2028
	687			—		—			687			WES 5.300% Senior Notes due 2048
	396			—		—			396			WES 4.750% Senior Notes due 2028
	342			—		—			342			WES 5.500% Senior Notes due 2048
Borrowings
	320			—		—			320			WES RCF
Repayments
	(690		)	—		—			(690		)	WES RCF
	—			—		(114		)	(114		)	7.050% Debentures due 2018
	(350		)	—		—			(350		)	WES 2.600% Senior Notes due 2018
	—			—		(17		)	(17		)	TEUs - senior amortizing notes
Other, net	2			—		39			41			Amortization of discounts, premiums, and debt issuance costs
Balance at September 30, 2018	$	4,566		$	28	$	11,873		$	16,467

__________________________________________________________________

⁽¹⁾  Excludes WES.

⁽²⁾  Excludes WES and WGP.

10. Debt (Continued)

Debt  The following summarizes the Company’s outstanding debt, including capital lease obligations, after eliminating the effect of intercompany transactions:

millions	WES			WGP (1)		Anadarko (2)			Consolidated
September 30, 2018
Total borrowings at face value	$	4,620		$	28	$	13,383		$	18,031
Net unamortized discounts, premiums, and debt issuance costs (3)	(54		)	—		(1,510		)	(1,564		)
Total borrowings (4)	4,566			28		11,873			16,467
Capital lease obligations	—			—		226			226
Less short-term debt	—			28		910			938
Total long-term debt	$	4,566		$	—	$	11,189		$	15,755
December 31, 2017
Total borrowings at face value	$	3,490		$	28	$	13,514		$	17,032
Net unamortized discounts, premiums, and debt issuance costs (3)	(25		)	—		(1,549		)	(1,574		)
Total borrowings (4)	3,465			28		11,965			15,458
Capital lease obligations	—			—		231			231
Less short-term debt	—			—		142			142
Total long-term debt	$	3,465		$	28	$	12,054		$	15,547

__________________________________________________________________

⁽¹⁾  Excludes WES.

⁽²⁾  Excludes WES and WGP.

⁽³⁾  Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

⁽⁴⁾  The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.8 billion at September 30, 2018, and $17.7 billion at December 31, 2017.

10. Debt (Continued)

Anadarko BorrowingsIn January 2018, the Company amended its $3.0 billion senior unsecured RCF to extend the maturity date to January 2022 (APC RCF) and amended its $2.0 billion364-day senior unsecured RCF to extend the maturity date to January 2019 (364-Day Facility). At September 30, 2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

At September 30, 2018, Anadarko had outstanding borrowings of $600 million of 8.700% Senior Notes due March 2019 and $300 million of 6.950% Senior Notes due June 2019 classified as short-term debt on the Company’s Consolidated Balance Sheet. Short-term debt also included the current portion of the Company’s capital lease obligations.

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 2018. The Zero Coupons can next be put to the Company in October 2019, which, if put in whole, would be $980 million.

The Company also has notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. See Note 8—Equity-Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

WES and WGP Borrowings  In February 2018, WES amended its RCF to extend the maturity date from February 2020 to February 2023 and expanded the borrowing capacity to $1.5 billion (WES RCF). As part of the amendment, the WES RCF is expandable to a maximum of $2.0 billion. During the nine months ended September 30, 2018, WES borrowed $320 million under its RCF, which was used for general partnership purposes, and made repayments of $690 million. At September 30, 2018, WES had no outstanding borrowings under its RCF, outstanding letters of credit of $5 million, available borrowing capacity of $1.495 billion, and was in compliance with all covenants.

In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from the public offerings were used to repay the maturing WES $350 million of 2.600% Senior Notes due August 2018, and amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.

In March 2018, WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the public offerings were used to repay amounts outstanding under the WES RCF and for general partnership purposes, including to fund capital expenditures.

In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under its senior secured RCF maturing in March 2019 from $250 million to $35 million (WGP RCF). Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES) as well as all equity interests owned by WGP. At September 30, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.25%, classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $7 million. At September 30, 2018, WGP was in compliance with all covenants.

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

11. Income Taxes

Upon enactment of the Tax Reform Legislation on December 22, 2017, 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%. During the third quarter of 2018, the Company recognized an additional net tax benefit of $5 million related to the adoption of the Tax Reform Legislation under Staff Accounting Bulletin 118. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation, including its accounting policy related to Global Intangible Low Taxed Income, and record any remaining adjustments to provisional tax amounts, which could be material to income tax expense, before the end of the measurement period on December 21, 2018. See Note 13—Income Taxes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

The following summarizes income tax expense (benefit) and effective tax rates:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2018			2017			2018			2017
Current income tax expense (benefit)	$	146		$	430		$	383		$	670
Deferred income tax expense (benefit)	110			(855		)	124			(1,036		)
Total income tax expense (benefit)	$	256		$	(425	)	$	507		$	(366	)
Income (loss) before income taxes	683			(1,066		)	1,125			(1,616		)
Effective tax rate	37		%	40		%	45		%	23		%

The Company’s tax provision for interim periods is determined using an estimate of its annual current and deferred effective tax rates, adjusted for discrete items. Each quarter, the Company updates these rates and records a cumulative adjustment to current and deferred tax expense by applying the rates to the year-to-date pre-tax income excluding discrete items. The Company’s quarterly estimate of its annual current and deferred effective tax rates can vary significantly based on various forecasted items, including future commodity prices, capital expenditures, expenses for which tax benefits are not recognized, and the geographic mix of pre-tax income and losses.

The variance from the U.S. federal statutory rate of 21% for the three and nine months ended September 30, 2018, was primarily attributable to the following items:

• tax impact from foreign operations

• non-deductible Algerian exceptional profits tax for Algerian income tax purposes

The Company reported a loss before income taxes for the three and nine months ended September 30, 2017. As a result, items that ordinarily increase or decrease the Company’s tax rate will have the opposite effect. The variance from the U.S. federal statutory rate of 35% for the three and nine months ended September 30, 2017 was primarily attributable to the following items:

• tax impact from foreign operations

• non-deductible Algerian exceptional profits tax for Algerian income tax purposes

• net changes in uncertain tax positions

• income attributable to noncontrolling interests

11. Income Taxes (Continued)

The Company recognized a net tax benefit of $346 million as of September 30, 2018 and December 31, 2017, related to the deduction of its 2015 settlement payment for the Tronox Adversary Proceeding. This benefit is net of uncertain tax positions of $1.2 billion as of September 30, 2018 and December 31, 2017, due to uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment, the Company had a net operating loss carryback for 2015, which resulted in a tentative tax refund of $881 million in 2016. The IRS has audited this position and, in April 2018, issued a 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 intends to file a petition with the U.S. Tax Court to dispute the disallowances, and pursuant to standard U.S. Tax Court procedures, the Company 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 Company does not prevail on the issue, the earliest potential date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial 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.

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Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Contingencies

12. Contingencies

Litigation  There are no material developments in previously reported contingencies nor are there any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

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Pension Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Pension Plans and Other Postretirement Benefits

13. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree and, in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:

	Pension Benefits						Other Benefits
millions	2018			2017			2018			2017
Three Months Ended September 30
Service cost	$	23		$	22		$	—		$	—
Interest cost	19			21			3			3
Expected (return) loss on plan assets	(20		)	(21		)	—			—
Amortization of net actuarial loss (gain)	6			7			—			—
Amortization of net prior service cost (credit)	—			(1		)	(6		)	(6		)
Settlement expense	9			22			—			—
Termination benefits expense	7			—			—			—
Net periodic benefit cost (1)	$	44		$	50		$	(3	)	$	(3	)
Nine Months Ended September 30
Service cost	$	68		$	64		$	1		$	1
Interest cost	57			63			8			9
Expected (return) loss on plan assets	(61		)	(63		)	—			—
Amortization of net actuarial loss (gain)	19			20			—			—
Amortization of net prior service cost (credit)	—			(1		)	(18		)	(18		)
Settlement expense	9			80			—			—
Termination benefits expense	7			4			—			—
Net periodic benefit cost (1)	$	99		$	167		$	(9	)	$	(8	)

__________________________________________________________________

⁽¹⁾  The service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and all other components of net periodic benefit cost are included in other (income) expense on the Company’s Consolidated Statements of Income.

The Company contributed $161 million to funded pension plans and $36 million to unfunded pension plans during the nine months ended September 30, 2018. The Company expects to contribute an additional $1 million to funded pension plans and $26 million to unfunded pension plans during 2018.

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Stockholders' Equity

9 Months Ended

Sep. 30, 2018

Stockholders' Equity Note [Abstract]

Stockholders' Equity

14. Stockholders’ Equity

Earnings Per Share  The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and TEUs, if the inclusion of these items is dilutive. All outstanding TEUs were settled in June 2018. See Note 9—Tangible Equity Units for additional information.

The following provides a reconciliation between basic and diluted EPS attributable to common stockholders:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
millions except per-share amounts	2018		2017			2018			2017
Net income (loss)
Net income (loss) attributable to common stockholders	$	363	$	(699	)	$	513		$	(1,432	)
Income (loss) effect of TEUs	—		(2		)	(4		)	(6		)
Less distributions on participating securities	2		—			4			—
Less undistributed income allocated to participating securities	2		—			1			—
Basic	$	359	$	(701	)	$	504		$	(1,438	)
Income (loss) effect of TEUs	—		—			—			(1		)
Diluted	$	359	$	(701	)	$	504		$	(1,439	)
Shares
Average number of common shares outstanding—basic	499		553			507			552
Dilutive effect of stock options	1		—			1			—
Average number of common shares outstanding—diluted	500		553			508			552
Excluded due to anti-dilutive effect	8		11			9			11
Net income (loss) per common share
Basic	$	0.72	$	(1.27	)	$	0.99		$	(2.60	)
Diluted	$	0.72	$	(1.27	)	$	0.99		$	(2.61	)

14. Stockholders’ Equity (Continued)

Common Stock  The Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018. In July 2018, the program was further expanded to $4.0 billion and extended through June 30, 2019. The Share-Repurchase Program authorizes the repurchase of the Company’s common stock in the open market or through private transactions. As of the end of the third quarter of 2018, the Company had completed $3.5 billion of the Share-Repurchase Program through ASR Agreements and open-market repurchases. These transactions were accounted for as equity transactions, with all of the repurchased shares classified as treasury stock. Additionally, the receipt of these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS.

During the nine months ended September 30, 2018, the Company entered into and completed two ASR Agreements and open-market repurchases as presented below:

millions except per-share amounts
Agreement Date	Settlement Date	Amount		Average Price per Share		Initial Shares Delivered	Additional Shares Delivered	Total Shares Delivered
ASR Agreements
January 2018	February 2018	$	500	$	58.82	7.0	1.5	8.5
March 2018	June 2018	1,441		65.28		19.1	3.0	22.1
Total ASR Agreements		1,941				26.1	4.5	30.6
Open-market repurchases
August 2018	August 2018	250		66.14		N/A	N/A	3.8
September 2018	September 2018	250		63.11		N/A	N/A	3.9
Total open-market repurchases		500						7.7
Total		$	2,441					38.3

Under each ASR Agreement, the Company paid a specific amount in cash and received an initial delivery of shares of the Company’s common stock. The initial delivery of shares represented the minimum number of shares to be repurchased under the agreement. The final number of shares delivered upon settlement of each ASR Agreement was determined with reference to the volume-weighted average price of the shares during the term of the agreement less a negotiated settlement price adjustment.

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Noncontrolling Interests

9 Months Ended

Sep. 30, 2018

Noncontrolling Interest Items [Abstract]

Noncontrolling Interests

15. Noncontrolling Interests

WES is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During 2016, WES issued 22 million Series A Preferred units to private investors. Pursuant to an agreement between WES and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units were converted on May 2, 2017.

WES Class C units issued to Anadarko will convert into WES common units on a one-for-one basis on the conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The Class C units receive quarterly distributions in the form of additional Class C units until the March 1, 2020 conversion date, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 802 thousand Class C units to Anadarko during the nine months ended September 30, 2018, and 886 thousand Class C units to Anadarko during 2017.

WGP is a limited partnership formed by Anadarko to own interests in WES. In June 2018, Anadarko settled 9.2 million outstanding TEUs, originally issued in 2015, in exchange for approximately 8.2 million WGP common units. See Note 9—Tangible Equity Unitsfor additional information. At September 30, 2018, Anadarko’s ownership interest in WGP consisted of a 77.8% limited partner interest and the entire non-economic general partner interest. The remaining 22.2% limited partner interest in WGP was owned by the public.

At September 30, 2018, WGP’s ownership interest in WES consisted of a 29.6% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At September 30, 2018, Anadarko also owned a 9.5% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.4% limited partner interest in WES was owned by the public.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2018

Variable Interest Entities [Abstract]

Variable Interest Entities

16. Variable Interest Entities

Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES; therefore, Anadarko is considered the primary beneficiary and consolidates WGP, WES, and all of their consolidated subsidiaries. For additional information on WGP and WES, see Note 15—Noncontrolling Interests.

The following tables present selected financial data from the consolidated financial statements of WGP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2018		2017		2018		2017
Statement of Operations Data
Total revenues and other	$	508	$	575	$	1,432	$	1,616
Operating income (loss)	200		179		461		523
Net income (loss)	155		147		340		424

	Nine Months Ended
	September 30,
millions	2018			2017
Statement of Cash Flows Data
Net cash provided by (used in) operating activities	$	749		$	642
Net cash provided by (used in) investing activities	(1,161		)	(515		)
Net cash provided by (used in) financing activities	465			(334		)

	September 30,		December 31,
millions	2018		2017
Balance Sheet Data
Cash and cash equivalents	$	133	$	80
Net property, plant, and equipment	6,419		5,731
Total assets	9,034		8,016
Long-term debt	4,566		3,493
Total liabilities	5,417		4,071
Total equity and partners’ capital	3,617		3,945

Assets and Liabilities of VIEsThe assets of WGP, WES, and their subsidiaries cannot be used by Anadarko for general corporate purposes and are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP, WES, and their subsidiaries for which the creditors do not have recourse to other assets of the Company are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.

All outstanding debt for WES at September 30, 2018, and December 31, 2017, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at September 30, 2018, and December 31, 2017, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note 10—Debt for additional information on WGP and WES short-term and long-term debt balances.

16. Variable Interest Entities (Continued)

VIE Financing WGP’s sources of liquidity include borrowings under its RCF and distributions from WES. WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under its RCF, the issuance of additional partnership units, and debt offerings. See Note 10—DebtandNote 15—Noncontrolling Interestsfor additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $13 million for the nine months ended September 30, 2018 and 2017. The note receivable and related interest income are eliminated in consolidation.

To reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of its contracts, Anadarko has commodity price swap agreements in place with WES expiring on December 31, 2018. WES recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price, minus (ii) the amount by which the swap price for product purchases exceeds the market price. WES recorded a capital contribution from Anadarko of $41 million for the nine months ended September 30, 2018, and $47 million for the nine months ended September 30, 2017.

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

17. Supplemental Cash Flow Information

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

The following summarizes cash paid (received) for interest and income taxes as well as non-cash investing and financing activities:

	Nine Months Ended
	September 30,
millions	2018			2017
Cash paid (received)
Interest, net of amounts capitalized	$	813		$	764
Income taxes, net of refunds	48			169
Non-cash investing activities
Fair value of properties and equipment acquired	$	8		$	619
Asset retirement cost additions	261			228
Accruals of property, plant, and equipment	886			786
Net liabilities assumed (divested) in acquisitions and divestitures	(97		)	(115		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	14
Non-cash financing activities
Settlement of tangible equity units	$	300		$	—

The following table provides a reconciliation of Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents as reported in the Consolidated Statement of Cash Flows to the line items within the Consolidated Balance Sheets:

	September 30,		December 31,
millions	2018		2017
Cash and cash equivalents	$	1,883	$	4,553
Restricted cash and restricted cash equivalents included in Other Assets	110		121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	1,993	$	4,674

Included in cash and cash equivalents is restricted cash and restricted cash equivalents of $134 million at September 30, 2018, and $255 million at December 31, 2017. Total restricted cash and restricted cash equivalents are primarily associated with certain international joint venture operations, payments of future hard-minerals royalty revenues conveyed, like-kind exchanges of property, and a judicially-controlled account related to a Brazilian tax dispute. See Note 17—Contingencies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

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Segment Information

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Segment Information

18. Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences. Anadarko has three reporting segments: Exploration and Production, WES Midstream, and Other Midstream, which include their respective marketing results. The Company has reclassified prior-period amounts to conform to the current-period presentation.

The Exploration and Production reporting 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. The WES Midstream and Other Midstream reporting segments engage in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. The WES Midstream segment consists of WES midstream assets, and the Other Midstream segment consists of the Company’s other midstream assets.

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; DD&A; exploration expense; gains (losses) on divestitures, net; impairments; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; restructuring charges; and less net income (loss) attributable to noncontrolling interests.

The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.

Management believes Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial performance across periods. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions	2018			2017			2018			2017
Income (loss) before income taxes	$	683		$	(1,066	)	$	1,125		$	(1,616	)
Interest expense	240			230			705			682
DD&A	1,130			1,083			3,123			3,235
Exploration expense (1)	118			750			380			2,366
(Gains) losses on divestitures, net	(3		)	194			(31		)	(815		)
Impairments	172			—			319			383
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(167		)	98			73			(12		)
Restructuring charges	13			3			13			20
Less net income (loss) attributable to noncontrolling interests	64			58			105			182
Consolidated Adjusted EBITDAX	$	2,122		$	1,234		$	5,602		$	4,061

 __________________________________________________________________

⁽¹⁾  Includes restructuring charges of $20 million for the three and nine months ended September 30, 2018.

18. Segment Information (Continued)

Information presented below as “Other and Intersegment Eliminations” includes corporate costs, margin on sales of third-party commodity purchases, deficiency fee expenses, results from hard-minerals royalties, net cash from settlement of commodity derivatives, and net income (loss) attributable to noncontrolling interests. The following summarizes selected financial information for Anadarko’s reporting segments:

millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2018
Sales revenues	$	3,161	$	394	$	39	$	13		$	3,607
Intersegment revenues	25		114		78		(217		)	—
Other	1		52		11		23			87
Total revenues and other (1)	3,187		560		128		(181		)	3,694
Operating costs and expenses (2)	1,059		245		55		(67		)	1,292
Net cash from settlement of commodity derivatives	—		—		—		199			199
Other (income) expense, net (3)	—		—		—		17			17
Net income (loss) attributable to noncontrolling interests	—		—		—		64			64
Total expenses and other	1,059		245		55		213			1,572
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		—		—			—
Adjusted EBITDAX	$	2,128	$	315	$	73	$	(394	)	$	2,122
Three Months Ended September 30, 2017
Sales revenues	$	2,097	$	445	$	53	$	15		$	2,610
Intersegment revenues	4		119		43		(166		)	—
Other	6		39		7		28			80
Total revenues and other (1)	2,107		603		103		(123		)	2,690
Operating costs and expenses (2)	956		345		62		49			1,412
Net cash from settlement of commodity derivatives	—		—		—		(16		)	(16		)
Other (income) expense, net	—		—		—		2			2
Net income (loss) attributable to noncontrolling interests	—		—		—		58			58
Total expenses and other	956		345		62		93			1,456
Adjusted EBITDAX	$	1,151	$	258	$	41	$	(216	)	$	1,234

 __________________________________________________________________

⁽¹⁾  Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

⁽²⁾  Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

⁽³⁾  Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.

18. Segment Information (Continued)

millions	Exploration & Production			WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Nine Months Ended September 30, 2018
Sales revenues	$	8,589		$	1,063	$	73	$	76		$	9,801
Intersegment revenues	49			369		188		(606		)	—
Other	(5		)	113		30		63			201
Total revenues and other (1)	8,633			1,545		291		(467		)	10,002
Operating costs and expenses (2)	2,840			687		134		195			3,856
Net cash from settlement of commodity derivatives	—			—		—		437			437
Other (income) expense, net (3)	—			—		—		9			9
Net income (loss) attributable to noncontrolling interests	—			—		—		105			105
Total expenses and other	2,840			687		134		746			4,407
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		7			7
Adjusted EBITDAX	$	5,793		$	858	$	157	$	(1,206	)	$	5,602
Nine Months Ended September 30, 2017
Sales revenues	$	6,500		$	1,213	$	134	$	80		$	7,927
Intersegment revenues	10			387		125		(522		)	—
Other	16			124		20		77			237
Total revenues and other (1)	6,526			1,724		279		(365		)	8,164
Operating costs and expenses (2)	2,679			936		168		135			3,918
Net cash from settlement of commodity derivatives	—			—		—		(23		)	(23		)
Other (income) expense, net	—			—		—		24			24
Net income (loss) attributable to noncontrolling interests	—			—		—		182			182
Total expenses and other	2,679			936		168		318			4,101
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		(2		)	(2		)
Adjusted EBITDAX	$	3,847		$	788	$	111	$	(685	)	$	4,061

 __________________________________________________________________

⁽¹⁾  Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

⁽²⁾  Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

⁽³⁾  Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Consolidation

The consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. The Company has determined that WGP and WES are VIEs. Anadarko is considered the primary beneficiary and consolidates WGP and WES. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in noncontrolled entities that Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Investments are included in other assets.

Recently Issued Accounting Standards

Recently Adopted Accounting Standards  ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The Company adopted this ASU on January 1, 2018, with retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. Upon adoption, non-service cost components of net periodic benefit costs of $107 million for 2017, including $94 million for the nine months ended September 30, 2017, were reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense.

ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Company adopted this ASU using a retrospective approach on January 1, 2018. Adoption did not have a material impact on the Company’s consolidated financial statements. See Consolidated Statements of Cash Flows and Note 17—Supplemental Cash Flow Informationfor additional information.

1. Summary of Significant Accounting Policies (Continued)

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior-period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included a reduction to total equity of $47 million. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. See Note 2—Revenue from Contracts with Customers for additional information. The Company’s revenue recognition accounting policy effective January 1, 2018, is detailed below.

• Exploration and Production—The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. For natural gas and NGLs sold on our behalf by a processor, revenue is typically measured based on the price the processor receives for the sale, less certain costs withheld by the processor.

Revenues are recognized for the sale of Anadarko’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee to move oil from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income.

1. Summary of Significant Accounting Policies (Continued)

• WES Midstream and Other Midstream—Anadarko provides gathering, compressing, treating, processing, stabilizing, transporting, and disposal services pursuant to a variety of contracts. Under these arrangements, the Company receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Revenue is recognized for fee-based gathering and processing services in the month of service based on the volumes delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period.

The Company’s midstream business also purchases natural-gas volumes from producers at the wellhead or production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. These fees are treated as a reduction of the purchase cost when the fees relate to services performed after control of the product has transferred to Anadarko. Revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to a third party.

Revenue from percentage of proceeds gathering and processing contracts is recognized net of the cost of product for purchases from service customers when the Company is acting as their agent in the product sale, and any fees charged on these percentage of proceeds contracts are recognized in service revenues.

ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, provides entities the option to reclassify stranded tax effects resulting from the Tax Reform Legislation from accumulated other comprehensive income (AOCI) to retained earnings. In accordance with its accounting policy, the Company releases stranded income tax effects from AOCI in the period the underlying portfolio is liquidated. This ASU allows for the reclassification of stranded tax effects as a result of the change in tax rates from Tax Reform Legislation to be recorded upon adoption of the ASU, rather than at the actual portfolio liquidation date. The Company adopted this ASU on January 1, 2018, electing to reclassify $73 million from AOCI to retained earnings, including a $2 million federal benefit of state tax impact related to the Tax Reform Legislation.

New Accounting Standards Issued But Not Yet Adopted  ASU 2016-02, Leases (Topic 842), requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Company plans to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases. Anadarko continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU. The Company expects the adoption of this ASU to primarily impact other assets and other long-term liabilities and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko expects to implement new accounting software and complete the evaluation of its systems, processes, and internal controls by the end of 2018. Anadarko will adopt this ASU on January 1, 2019, using a modified retrospective approach. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements and will recognize a cumulative effect adjustment in the opening balance of retained earnings in the period of adoption.

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Revenue from Contracts with Customers (Tables)

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Schedule of Impact of New Accounting Pronouncements

The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements:

CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
September 30, 2018
Assets
Other current assets	$	397	$	395	$	2
Net properties and equipment	28,744		28,697		47
Other assets	2,292		2,282		10
Liabilities
Other current liabilities	1,502		1,494		8
Deferred income taxes	2,455		2,461		(6		)
Other	4,043		3,932		111
Equity
Total equity	11,237		11,291		(54		)

2. Revenue from Contracts with Customers (Continued)

CONSOLIDATED STATEMENT OF INCOME	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
Three Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	421	$	717	$	(296	)
Gains (losses) on divestitures and other, net	90		89		1
Expenses
Gathering, processing, and marketing	256		551		(295		)
Income tax expense (benefit)	256		254		2
Net income (loss) attributable to noncontrolling interests	64		71		(7		)
Net Income (Loss) Attributable to Common Stockholders	$	363	$	358	$	5
Nine Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	1,163	$	1,944	$	(781	)
Gains (losses) on divestitures and other, net	232		233		(1		)
Expenses
Gathering, processing, and marketing	745		1,520		(775		)
Income tax expense (benefit)	507		507		—
Net income (loss) attributable to noncontrolling interests	105		111		(6		)
Net Income (Loss) Attributable to Common Stockholders	$	513	$	514	$	(1	)

Schedule of Disaggregation of Revenue

The following table disaggregates revenue by significant product type and segment:

millions	Exploration & Production			WES Midstream			Other Midstream		Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2018
Oil sales	$	2,572		$	—		$	—	$	—		$	2,572
Natural-gas sales	232			—			—		—			232
Natural-gas liquids sales	382			—			—		—			382
Gathering, processing, and marketing sales (1)	—			511			113		1			625
Other, net	9			—			—		31			40
Total Revenue from Customers	$	3,195		$	511		$	113	$	32		$	3,851
Gathering, processing, and marketing sales(2)	—			(3		)	3		(204		)	(204		)
Gains (losses) on divestitures, net	5			—			1		(3		)	3
Other, net	(8		)	52			12		(9		)	47
Total Revenue from Other than Customers	$	(3	)	$	49		$	16	$	(216	)	$	(154	)
Total Revenue and Other	$	3,192		$	560		$	129	$	(184	)	$	3,697
Nine Months Ended September 30, 2018
Oil sales	$	6,964		$	—		$	—	$	—		$	6,964
Natural-gas sales	682			—			—		—			682
Natural-gas liquids sales	992			—			—		—			992
Gathering, processing, and marketing sales(1)	—			1,438			255		83			1,776
Other, net	16			—			—		71			87
Total Revenue from Customers	$	8,654		$	1,438		$	255	$	154		$	10,501
Gathering, processing, and marketing sales(2)	—			(6		)	6		(613		)	(613		)
Gains (losses) on divestitures, net	24			—			10		(3		)	31
Other, net	(21		)	113			30		(8		)	114
Total Revenue from Other than Customers	$	3		$	107		$	46	$	(624	)	$	(468	)
Total Revenue and Other	$	8,657		$	1,545		$	301	$	(470	)	$	10,033

 __________________________________________________________________

⁽¹⁾  The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $328 million and intercompany eliminations of $(312) million for the three months ended September 30, 2018, and sales of third-party natural gas and NGLs of $813 million and intercompany eliminations of $(715) million for the nine months ended September 30, 2018.

⁽²⁾  The amount in Other and Intersegment Eliminations represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table, as the purchases are not considered revenue from customers.

Schedule of Contract with Customer Liabilities Activity

The following table summarizes the current period activity related to contract liabilities from contracts with customers:

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 (1)	46
Decrease due to revenue recognized (2)	(30		)
Balance at September 30, 2018	$	151
Contract liabilities at September 30, 2018
Other current liabilities	$	23
Other long-term liabilities - other	128
Total contract liabilities from contracts with customers	$	151

 __________________________________________________________________

⁽¹⁾  Includes $(6) million for the three months ended September 30, 2018.

⁽²⁾  Includes $(9) million for the three months ended September 30, 2018.

Schedule of Expected Revenue Recognition from Satisfaction of Performance Obligations

Therefore, the following table represents only a small portion of Anadarko’s expected future consolidated revenues as future revenue from the sale of most products and services is dependent on future production or variable customer volumes and variable commodity prices for those volumes.

millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Remainder of 2018	$	27	$	124	$	31	$	(96	)	$	86
2019	104		480		204		(441		)	347
2020	103		545		293		(606		)	335
2021	103		525		361		(672		)	317
2022	7		529		417		(739		)	214
Thereafter	65		2,192		3,107		(4,662		)	702
Total	$	409	$	4,395	$	4,413	$	(7,216	)	$	2,001

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Commodity Inventories (Tables)

9 Months Ended

Sep. 30, 2018

Energy Related Inventory [Abstract]

Inventory Disclosure Table

The following summarizes the major classes of commodity inventories included in other current assets:

	September 30,		December 31,
millions	2018		2017
Oil	$	168	$	165
Natural gas	19		29
NGLs	131		122
Total commodity inventories	$	318	$	316

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Divestitures (Tables)

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Schedule of Proceeds Received and Gains (Losses) Recognized on Divestitures

The following summarizes the proceeds received and gains (losses) recognized on divestitures:

	Nine Months Ended
	September 30,
millions	2018		2017
Proceeds received, net of closing adjustments	$	393	$	3,480
Gains (losses) on divestitures, net (1)	31		815

__________________________________________________________________

⁽¹⁾  Includes the $126 million gain related to the 2017 property exchange discussed below.

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Current Liabilities (Tables)

9 Months Ended

Sep. 30, 2018

Payables and Accruals [Abstract]

Schedule of Other Current Liabilities

The following summarizes the Company’s other current liabilities:

	September 30,		December 31,
millions	2018		2017
Accrued income taxes	$	79	$	71
Interest payable	169		246
Production, property, and other taxes payable	344		216
Accrued employee benefits	270		210
Derivatives	491		384
Other	149		183
Total other current liabilities	$	1,502	$	1,310

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, 2018:

	2018 Settlement		2019 Settlement
Oil
Two-Way Collars (MBbls/d)	108		—
Average price per barrel (WTI)
Ceiling sold price (call)	$	60.48	$	—
Floor purchased price (put)	$	50.00	$	—
Three-Way Collars (MBbls/d)	—		87
Average price per barrel (WTI and Brent)
Ceiling sold price (call)	$	—	$	72.98
Floor purchased price (put)	$	—	$	56.72
Floor sold price (put)	$	—	$	46.72
Fixed-Price Contracts (MBbls/d)	84		—
Average price per barrel (Brent)	$	61.45	$	—
Natural Gas
Three-Way Collars (thousand MMBtu/d)	250		—
Average price per MMBtu (Henry Hub)
Ceiling sold price (call)	$	3.54	$	—
Floor purchased price (put)	$	2.75	$	—
Floor sold price (put)	$	2.00	$	—
Fixed-Price Contracts (thousand MMBtu/d)	280		—
Average price per MMBtu (Henry Hub)	$	3.02	$	—

The Company had the following outstanding interest-rate swaps at September 30, 2018:

millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418%
$	250	September 2016 - 2046	September 2022	6.809%
$	100	September 2017 - 2047	September 2020	6.891%
$	250	September 2017 - 2047	September 2021	6.570%
$	450	September 2017 - 2047	September 2023	6.445%

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The following summarizes the fair value of the Company’s derivative instruments:

	Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2018		2017		2018			2017
Commodity derivatives
Other current assets	$	2	$	7	$	—		$	(1	)
Other assets	—		2		—			—
Other current liabilities	20		45		(440		)	(206		)
Other liabilities	15		—		(56		)	(2		)
	37		54		(496		)	(209		)
Interest-rate derivatives
Other current assets	21		14		—			—
Other assets	54		40		—			—
Other current liabilities	—		—		(80		)	(236		)
Other liabilities	—		—		(1,028		)	(1,183		)
	75		54		(1,108		)	(1,419		)
Total derivatives	$	112	$	108	$	(1,604	)	$	(1,628	)

The following summarizes gains and losses related to derivative instruments:

millions	Three Months Ended September 30,					Nine Months Ended September 30,
Classification of (Gain) Loss Recognized	2018			2017		2018			2017
Commodity derivatives
Gathering, processing, and marketing sales	$	1		$	—	$	3		$	—
(Gains) losses on derivatives, net	104			43		734			(164		)
Interest-rate derivatives
(Gains) losses on derivatives, net	(72		)	39		(231		)	131
Total (gains) losses on derivatives, net	$	33		$	82	$	506		$	(33	)

________________________________

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:

millions	Level 1			Level 2			Level 3		Netting (1)			Collateral			Total
September 30, 2018
Assets
Commodity derivatives	$	—		$	37		$	—	$	(35	)	$	—		$	2
Interest-rate derivatives	—			75			—		—			—			75
Total derivative assets	$	—		$	112		$	—	$	(35	)	$	—		$	77
Liabilities
Commodity derivatives	$	—		$	(496	)	$	—	$	35		$	6		$	(455	)
Interest-rate derivatives	—			(1,108		)	—		—			49			(1,059		)
Total derivative liabilities	$	—		$	(1,604	)	$	—	$	35		$	55		$	(1,514	)
December 31, 2017
Assets
Commodity derivatives	$	1		$	53		$	—	$	(46	)	$	(1	)	$	7
Interest-rate derivatives	—			54			—		—			—			54
Total derivative assets	$	1		$	107		$	—	$	(46	)	$	(1	)	$	61
Liabilities
Commodity derivatives	$	(1	)	$	(208	)	$	—	$	46		$	3		$	(160	)
Interest-rate derivatives	—			(1,419		)	—		—			170			(1,249		)
Total derivative liabilities	$	(1	)	$	(1,627	)	$	—	$	46		$	173		$	(1,409	)

 __________________________________________________________________

⁽¹⁾  Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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Debt (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule or Debt Outstanding

The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the nine months ended September 30, 2018:

	Carrying Value
millions	WES			WGP (1)		Anadarko (2)			Anadarko Consolidated			Description
Balance at December 31, 2017	$	3,465		$	28	$	11,965		$	15,458
Issuances
	394			—		—			394			WES 4.500% Senior Notes due 2028
	687			—		—			687			WES 5.300% Senior Notes due 2048
	396			—		—			396			WES 4.750% Senior Notes due 2028
	342			—		—			342			WES 5.500% Senior Notes due 2048
Borrowings
	320			—		—			320			WES RCF
Repayments
	(690		)	—		—			(690		)	WES RCF
	—			—		(114		)	(114		)	7.050% Debentures due 2018
	(350		)	—		—			(350		)	WES 2.600% Senior Notes due 2018
	—			—		(17		)	(17		)	TEUs - senior amortizing notes
Other, net	2			—		39			41			Amortization of discounts, premiums, and debt issuance costs
Balance at September 30, 2018	$	4,566		$	28	$	11,873		$	16,467

__________________________________________________________________

⁽¹⁾  Excludes WES.

⁽²⁾  Excludes WES and WGP.

10. Debt (Continued)

Debt  The following summarizes the Company’s outstanding debt, including capital lease obligations, after eliminating the effect of intercompany transactions:

millions	WES			WGP (1)		Anadarko (2)			Consolidated
September 30, 2018
Total borrowings at face value	$	4,620		$	28	$	13,383		$	18,031
Net unamortized discounts, premiums, and debt issuance costs (3)	(54		)	—		(1,510		)	(1,564		)
Total borrowings (4)	4,566			28		11,873			16,467
Capital lease obligations	—			—		226			226
Less short-term debt	—			28		910			938
Total long-term debt	$	4,566		$	—	$	11,189		$	15,755
December 31, 2017
Total borrowings at face value	$	3,490		$	28	$	13,514		$	17,032
Net unamortized discounts, premiums, and debt issuance costs (3)	(25		)	—		(1,549		)	(1,574		)
Total borrowings (4)	3,465			28		11,965			15,458
Capital lease obligations	—			—		231			231
Less short-term debt	—			—		142			142
Total long-term debt	$	3,465		$	28	$	12,054		$	15,547

__________________________________________________________________

⁽¹⁾  Excludes WES.

⁽²⁾  Excludes WES and WGP.

⁽³⁾  Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

⁽⁴⁾  The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Schedule of Income Taxes and Effective Tax Rate

The following summarizes income tax expense (benefit) and effective tax rates:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions except percentages	2018			2017			2018			2017
Current income tax expense (benefit)	$	146		$	430		$	383		$	670
Deferred income tax expense (benefit)	110			(855		)	124			(1,036		)
Total income tax expense (benefit)	$	256		$	(425	)	$	507		$	(366	)
Income (loss) before income taxes	683			(1,066		)	1,125			(1,616		)
Effective tax rate	37		%	40		%	45		%	23		%

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Pension Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Components of Net Periodic Benefit Cost Table

The following summarizes the Company’s pension and other postretirement benefit cost:

	Pension Benefits						Other Benefits
millions	2018			2017			2018			2017
Three Months Ended September 30
Service cost	$	23		$	22		$	—		$	—
Interest cost	19			21			3			3
Expected (return) loss on plan assets	(20		)	(21		)	—			—
Amortization of net actuarial loss (gain)	6			7			—			—
Amortization of net prior service cost (credit)	—			(1		)	(6		)	(6		)
Settlement expense	9			22			—			—
Termination benefits expense	7			—			—			—
Net periodic benefit cost (1)	$	44		$	50		$	(3	)	$	(3	)
Nine Months Ended September 30
Service cost	$	68		$	64		$	1		$	1
Interest cost	57			63			8			9
Expected (return) loss on plan assets	(61		)	(63		)	—			—
Amortization of net actuarial loss (gain)	19			20			—			—
Amortization of net prior service cost (credit)	—			(1		)	(18		)	(18		)
Settlement expense	9			80			—			—
Termination benefits expense	7			4			—			—
Net periodic benefit cost (1)	$	99		$	167		$	(9	)	$	(8	)

__________________________________________________________________

⁽¹⁾  The service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and all other components of net periodic benefit cost are included in other (income) expense on the Company’s Consolidated Statements of Income.

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Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2018

Stockholders' Equity Note [Abstract]

Earnings Per Share Table

The following provides a reconciliation between basic and diluted EPS attributable to common stockholders:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
millions except per-share amounts	2018		2017			2018			2017
Net income (loss)
Net income (loss) attributable to common stockholders	$	363	$	(699	)	$	513		$	(1,432	)
Income (loss) effect of TEUs	—		(2		)	(4		)	(6		)
Less distributions on participating securities	2		—			4			—
Less undistributed income allocated to participating securities	2		—			1			—
Basic	$	359	$	(701	)	$	504		$	(1,438	)
Income (loss) effect of TEUs	—		—			—			(1		)
Diluted	$	359	$	(701	)	$	504		$	(1,439	)
Shares
Average number of common shares outstanding—basic	499		553			507			552
Dilutive effect of stock options	1		—			1			—
Average number of common shares outstanding—diluted	500		553			508			552
Excluded due to anti-dilutive effect	8		11			9			11
Net income (loss) per common share
Basic	$	0.72	$	(1.27	)	$	0.99		$	(2.60	)
Diluted	$	0.72	$	(1.27	)	$	0.99		$	(2.61	)

Schedule of Accelerated Share Repurchases

During the nine months ended September 30, 2018, the Company entered into and completed two ASR Agreements and open-market repurchases as presented below:

millions except per-share amounts
Agreement Date	Settlement Date	Amount		Average Price per Share		Initial Shares Delivered	Additional Shares Delivered	Total Shares Delivered
ASR Agreements
January 2018	February 2018	$	500	$	58.82	7.0	1.5	8.5
March 2018	June 2018	1,441		65.28		19.1	3.0	22.1
Total ASR Agreements		1,941				26.1	4.5	30.6
Open-market repurchases
August 2018	August 2018	250		66.14		N/A	N/A	3.8
September 2018	September 2018	250		63.11		N/A	N/A	3.9
Total open-market repurchases		500						7.7
Total		$	2,441					38.3

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2018

Variable Interest Entities [Abstract]

Schedule of Financial Data of VIE

The following tables present selected financial data from the consolidated financial statements of WGP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
millions	2018		2017		2018		2017
Statement of Operations Data
Total revenues and other	$	508	$	575	$	1,432	$	1,616
Operating income (loss)	200		179		461		523
Net income (loss)	155		147		340		424

	Nine Months Ended
	September 30,
millions	2018			2017
Statement of Cash Flows Data
Net cash provided by (used in) operating activities	$	749		$	642
Net cash provided by (used in) investing activities	(1,161		)	(515		)
Net cash provided by (used in) financing activities	465			(334		)

	September 30,		December 31,
millions	2018		2017
Balance Sheet Data
Cash and cash equivalents	$	133	$	80
Net property, plant, and equipment	6,419		5,731
Total assets	9,034		8,016
Long-term debt	4,566		3,493
Total liabilities	5,417		4,071
Total equity and partners’ capital	3,617		3,945

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Table

The following summarizes cash paid (received) for interest and income taxes as well as non-cash investing and financing activities:

	Nine Months Ended
	September 30,
millions	2018			2017
Cash paid (received)
Interest, net of amounts capitalized	$	813		$	764
Income taxes, net of refunds	48			169
Non-cash investing activities
Fair value of properties and equipment acquired	$	8		$	619
Asset retirement cost additions	261			228
Accruals of property, plant, and equipment	886			786
Net liabilities assumed (divested) in acquisitions and divestitures	(97		)	(115		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	14
Non-cash financing activities
Settlement of tangible equity units	$	300		$	—

Schedule of Cash and Cash Equivalents Balance Sheet Locations

The following table provides a reconciliation of Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents as reported in the Consolidated Statement of Cash Flows to the line items within the Consolidated Balance Sheets:

	September 30,		December 31,
millions	2018		2017
Cash and cash equivalents	$	1,883	$	4,553
Restricted cash and restricted cash equivalents included in Other Assets	110		121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	1,993	$	4,674

XML

Segment Information (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) Before Income Taxes

Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
millions	2018			2017			2018			2017
Income (loss) before income taxes	$	683		$	(1,066	)	$	1,125		$	(1,616	)
Interest expense	240			230			705			682
DD&A	1,130			1,083			3,123			3,235
Exploration expense (1)	118			750			380			2,366
(Gains) losses on divestitures, net	(3		)	194			(31		)	(815		)
Impairments	172			—			319			383
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(167		)	98			73			(12		)
Restructuring charges	13			3			13			20
Less net income (loss) attributable to noncontrolling interests	64			58			105			182
Consolidated Adjusted EBITDAX	$	2,122		$	1,234		$	5,602		$	4,061

 __________________________________________________________________

⁽¹⁾  Includes restructuring charges of $20 million for the three and nine months ended September 30, 2018.

Schedule of Segment Reporting Information, by Segment

The following summarizes selected financial information for Anadarko’s reporting segments:

millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2018
Sales revenues	$	3,161	$	394	$	39	$	13		$	3,607
Intersegment revenues	25		114		78		(217		)	—
Other	1		52		11		23			87
Total revenues and other (1)	3,187		560		128		(181		)	3,694
Operating costs and expenses (2)	1,059		245		55		(67		)	1,292
Net cash from settlement of commodity derivatives	—		—		—		199			199
Other (income) expense, net (3)	—		—		—		17			17
Net income (loss) attributable to noncontrolling interests	—		—		—		64			64
Total expenses and other	1,059		245		55		213			1,572
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		—		—			—
Adjusted EBITDAX	$	2,128	$	315	$	73	$	(394	)	$	2,122
Three Months Ended September 30, 2017
Sales revenues	$	2,097	$	445	$	53	$	15		$	2,610
Intersegment revenues	4		119		43		(166		)	—
Other	6		39		7		28			80
Total revenues and other (1)	2,107		603		103		(123		)	2,690
Operating costs and expenses (2)	956		345		62		49			1,412
Net cash from settlement of commodity derivatives	—		—		—		(16		)	(16		)
Other (income) expense, net	—		—		—		2			2
Net income (loss) attributable to noncontrolling interests	—		—		—		58			58
Total expenses and other	956		345		62		93			1,456
Adjusted EBITDAX	$	1,151	$	258	$	41	$	(216	)	$	1,234

 __________________________________________________________________

⁽¹⁾  Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

⁽²⁾  Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

⁽³⁾  Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.

18. Segment Information (Continued)

millions	Exploration & Production			WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Nine Months Ended September 30, 2018
Sales revenues	$	8,589		$	1,063	$	73	$	76		$	9,801
Intersegment revenues	49			369		188		(606		)	—
Other	(5		)	113		30		63			201
Total revenues and other (1)	8,633			1,545		291		(467		)	10,002
Operating costs and expenses (2)	2,840			687		134		195			3,856
Net cash from settlement of commodity derivatives	—			—		—		437			437
Other (income) expense, net (3)	—			—		—		9			9
Net income (loss) attributable to noncontrolling interests	—			—		—		105			105
Total expenses and other	2,840			687		134		746			4,407
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		7			7
Adjusted EBITDAX	$	5,793		$	858	$	157	$	(1,206	)	$	5,602
Nine Months Ended September 30, 2017
Sales revenues	$	6,500		$	1,213	$	134	$	80		$	7,927
Intersegment revenues	10			387		125		(522		)	—
Other	16			124		20		77			237
Total revenues and other (1)	6,526			1,724		279		(365		)	8,164
Operating costs and expenses (2)	2,679			936		168		135			3,918
Net cash from settlement of commodity derivatives	—			—		—		(23		)	(23		)
Other (income) expense, net	—			—		—		24			24
Net income (loss) attributable to noncontrolling interests	—			—		—		182			182
Total expenses and other	2,679			936		168		318			4,101
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		(2		)	(2		)
Adjusted EBITDAX	$	3,847		$	788	$	111	$	(685	)	$	4,061

 __________________________________________________________________

⁽¹⁾  Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

⁽²⁾  Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

⁽³⁾  Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.

XML

Summary of Significant Accounting Policies (Detail) - USD ($) $ in Millions			9 Months Ended		12 Months Ended
		Jan. 01, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change	[1]		$ (47)
Accounting Standards Update 2014-09 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change		$ 47
Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification from AOCI to retained earnings		73
Accounting Standards Update 2018-02 [Member] | State tax impacts [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification from AOCI to retained earnings		$ 2
Costs and expenses [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service cost component of net periodic benefit cost				$ (94)	$ (107)
WES Midstream and Other Midstream [Member] | Maximum [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract terms			Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally have initial terms ranging from 5 to 10 years.

[1] Beginning January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and 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.

XML

Revenue from Contracts with Customers - Impact on Financial Statements (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Revenues
Revenues from Customers	$ 3,851		$ 10,501
Gains (losses) on divestitures and other, net	90	$ (114)	232	$ 1,052
Expenses
Income tax expense (benefit)	256	(425)	507	(366)
Net income (loss) attributable to noncontrolling interests	64	58	105	182
Net income (loss) attributable to common stockholders	363	(699)	513	(1,432)
Assets
Other current assets	397		397		$ 380
Net properties and equipment	28,744		28,744		27,451
Other Assets	2,292		2,292		2,211
Liabilities
Other current liabilities	1,502		1,502		1,310
Deferred income taxes	2,455		2,455		2,234
Other	4,043		4,043		4,109
Equity
Total equity	11,237		11,237		$ 13,790
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member]
Revenues
Gains (losses) on divestitures and other, net	89		233
Expenses
Income tax expense (benefit)	254		507
Net income (loss) attributable to noncontrolling interests	71		111
Net income (loss) attributable to common stockholders	358		514
Assets
Other current assets	395		395
Net properties and equipment	28,697		28,697
Other Assets	2,282		2,282
Liabilities
Other current liabilities	1,494		1,494
Deferred income taxes	2,461		2,461
Other	3,932		3,932
Equity
Total equity	11,291		11,291
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/ (Decrease) [Member]
Revenues
Gains (losses) on divestitures and other, net	1		(1)
Expenses
Income tax expense (benefit)	2		0
Net income (loss) attributable to noncontrolling interests	(7)		(6)
Net income (loss) attributable to common stockholders	5		(1)
Assets
Other current assets	2		2
Net properties and equipment	47		47
Other Assets	10		10
Liabilities
Other current liabilities	8		8
Deferred income taxes	(6)		(6)
Other	111		111
Equity
Total equity	(54)		(54)
Gathering, processing, and marketing [Member]
Revenues
Revenues from Customers	421	509	1,163	1,417
Expenses
Gathering, processing, and marketing	256	$ 396	745	$ 1,101
Gathering, processing, and marketing [Member] | Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member]
Revenues
Revenues from Customers	717		1,944
Expenses
Gathering, processing, and marketing	551		1,520
Gathering, processing, and marketing [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/ (Decrease) [Member]
Revenues
Revenues from Customers	(296)		(781)
Expenses
Gathering, processing, and marketing	$ (295)		$ (775)

XML

Revenue from Contracts with Customers - Disaggregation of Revenue (Detail) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Revenues from Customers		$ 3,851		$ 10,501
Revenue from Other than Customers		(154)		(468)
Total		3,697	$ 2,496	10,033	$ 8,979
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		2,572		6,964
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		232	269	682	1,090
Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		382	$ 265	992	$ 768
Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	625		1,776
Revenue from Other than Customers	[2]	(204)		(613)
Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		3		31
Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		40		87
Revenue from Other than Customers		47		114
Operating Segments [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		3,195		8,654
Revenue from Other than Customers		(3)		3
Total		3,192		8,657
Operating Segments [Member] | Exploration and Production [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		2,572		6,964
Operating Segments [Member] | Exploration and Production [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		232		682
Operating Segments [Member] | Exploration and Production [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		382		992
Operating Segments [Member] | Exploration and Production [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	0		0
Revenue from Other than Customers	[2]	0		0
Operating Segments [Member] | Exploration and Production [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		5		24
Operating Segments [Member] | Exploration and Production [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		9		16
Revenue from Other than Customers		(8)		(21)
Operating Segments [Member] | WES Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		511		1,438
Revenue from Other than Customers		49		107
Total		560		1,545
Operating Segments [Member] | WES Midstream [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Operating Segments [Member] | WES Midstream [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Operating Segments [Member] | WES Midstream [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Operating Segments [Member] | WES Midstream [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	511		1,438
Revenue from Other than Customers	[2]	(3)		(6)
Operating Segments [Member] | WES Midstream [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		0		0
Operating Segments [Member] | WES Midstream [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Revenue from Other than Customers		52		113
Operating Segments [Member] | Other Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		113		255
Revenue from Other than Customers		16		46
Total		129		301
Operating Segments [Member] | Other Midstream [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Operating Segments [Member] | Other Midstream [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Operating Segments [Member] | Other Midstream [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Operating Segments [Member] | Other Midstream [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	113		255
Revenue from Other than Customers	[2]	3		6
Operating Segments [Member] | Other Midstream [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		1		10
Operating Segments [Member] | Other Midstream [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Revenue from Other than Customers		12		30
Other and Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		32		154
Revenue from Other than Customers		(216)		(624)
Total		(184)		(470)
Other and Intersegment Eliminations [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Other and Intersegment Eliminations [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Other and Intersegment Eliminations [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0		0
Other and Intersegment Eliminations [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	1		83
Revenue from Other than Customers	[2]	(204)		(613)
Intercompany eliminations		(312)		(715)
Third-party marketing revenue		328		813
Other and Intersegment Eliminations [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		(3)		(3)
Other and Intersegment Eliminations [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		31		71
Revenue from Other than Customers		$ (9)		$ (8)

[1] The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $328 million and intercompany eliminations of $(312) million for the three months ended September 30, 2018, and sales of third-party natural gas and NGLs of $813 million and intercompany eliminations of $(715) million for the nine months ended September 30, 2018.

[2] The amount in Other and Intersegment Eliminations represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table, as the purchases are not considered revenue from customers.

XML

Revenue from Contracts with Customers - Contract Liabilities (Detail) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2018
Change in Contract with Customer, Liability [Roll Forward]
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 (1)	$ (6)	46
Decrease due to revenue recognized (2)	9	(30)
Balance at September 30, 2018	151	151
Contract liabilities at September 30, 2018
Other current liabilities			$ 23
Other long-term liabilities - other			128
Total contract liabilities from contracts with customers	$ 151	$ 37	$ 151

XML

Revenue from Contracts with Customers - Revenue Recognition Expected (Detail) $ in Millions	Sep. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 86
Performance obligation expected to be satisfied, expected timing	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 347
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 335
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 317
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 214
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 702
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	2,001
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 27
Performance obligation expected to be satisfied, expected timing	3 months
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 104
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 103
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 103
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 7
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 65
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	409
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 124
Performance obligation expected to be satisfied, expected timing	3 months
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 480
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 545
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 525
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 529
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 2,192
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	4,395
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 31
Performance obligation expected to be satisfied, expected timing	3 months
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 204
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 293
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 361
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 417
Performance obligation expected to be satisfied, expected timing	1 year
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 3,107
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	4,413
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (96)
Performance obligation expected to be satisfied, expected timing	3 months
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (441)
Performance obligation expected to be satisfied, expected timing	1 year
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (606)
Performance obligation expected to be satisfied, expected timing	1 year
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (672)
Performance obligation expected to be satisfied, expected timing	1 year
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (739)
Performance obligation expected to be satisfied, expected timing	1 year
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (4,662)
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (7,216)

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Commodity Inventories (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Energy Related Inventory [Abstract]
Oil	$ 168	$ 165
Natural gas	19	29
NGLs	131	122
Total commodity inventories	$ 318	$ 316

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Divestitures - Divestitures (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures			$ 393	$ 3,480
Gain (loss) on divestitures			31	815	[1]
Exploration and Production [Member] | Certain Onshore Domestic Assets Ram Powell [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on divestitures			67
Exploration and Production [Member] | Certain U.S. Onshore Assets in Eagleford, South Texas [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures				2,100
Gain (loss) on divestitures				730
Exploration and Production [Member] | Certain Onshore Domestic Assets, Eaglebine, Southeast Texas [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures				533
Gain (loss) on divestitures				282
Exploration And Production And Other Midstream Reporting Segment [Member] | Certain Onshore Domestic Assets Alaska [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures			370
Gain (loss) on divestitures	$ (154)		$ (33)
Exploration And Production And Other Midstream Reporting Segment [Member] | Certain U.S. Onshore Assets in Marcellus, Pennsylvania [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures				758
Gain (loss) on divestitures		$ (129)		(56)
Exploration And Production And Other Midstream Reporting Segment [Member] | Certain Onshore Domestic Assets, CBM, Utah [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures				69
Gain (loss) on divestitures				$ (52)

[1] Includes the $126 million gain related to the 2017 property exchange discussed below.

XML

Divestitures - Property Exchange (Detail) - USD ($) $ in Millions		9 Months Ended
	Mar. 17, 2017	Sep. 30, 2018	Sep. 30, 2017
Nonmonetary Transaction [Line Items]
Cash payment to acquire a third party's interest in the DBJV system		$ 4,891	$ 3,538
Delaware Basin Joint Venture System [Member]
Nonmonetary Transaction [Line Items]
Third party nonoperated interest percentage to be acquired	50.00%
Western Gas Partners, LP [Member] | Delaware Basin Joint Venture System [Member]
Nonmonetary Transaction [Line Items]
Cash payment to acquire a third party's interest in the DBJV system	$ 155
Gain on exchange	$ 126
Operated interest percentage		100.00%
Western Gas Partners, LP [Member] | Marcellus Assets [Member]
Nonmonetary Transaction [Line Items]
Non operated interest percentage	33.75%

XML

Impairments - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Property, Plant, and Equipment [Line Items]
Impairments	$ 172	$ 0	$ 319	$ 383
Impairment of unproved properties			212	2,144
Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Impairments			319	383
Hard-minerals Properties [Member] | Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Impairment of long-lived assets held for use			145
Unproved Gulf of Mexico Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties			158	586
Unproved Shenandoah Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties				463
Exploration and Production [Member] | Gulf of Mexico Properties [Member] | Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Impairment of long-lived assets held for use				211
WES Midstream [Member] | DJ Basin Complex [Member] | Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Impairment of long-lived assets held for use			126
WES Midstream [Member] | Onshore Domestic [Member] | Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Impairment of long-lived assets held for use				168
Valuation, Income Approach [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Hard-minerals Properties [Member] | Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Fair value of long-lived assets held for use	$ 15		$ 15
Valuation, Income Approach [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Exploration and Production [Member] | Gulf of Mexico Properties [Member] | Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Fair value of long-lived assets held for use		231		231
Valuation, Income Approach [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | WES Midstream [Member] | Onshore Domestic [Member] | Assets Impaired During Fiscal Year to Date [Member]
Property, Plant, and Equipment [Line Items]
Fair value of long-lived assets held for use		$ 58		$ 58

XML

Exploratory Well Costs (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Capitalized Exploratory Well Costs [Abstract]
Suspended exploratory well costs	$ 510,000,000	$ 525,000,000
Suspended exploratory well costs previously capitalized for a period greater than one year since the completion of drilling at December 31, 2016, charged to exploration expense	$ 0

XML

Current Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Outstanding checks in excess of bank account balances	$ 205	$ 219
Other Current Liabilities
Accrued income taxes	79	71
Interest payable	169	246
Production, property, and other taxes payable	344	216
Accrued employee benefits	270	210
Derivatives	491	384
Other	149	183
Total other current liabilities	$ 1,502	$ 1,310

XML

Derivative Instruments - Oil and Natural-Gas Production/Processing Derivative Activities Table (Detail) - Not Designated as Hedging Instrument [Member]	9 Months Ended
	Sep. 30, 2018 MMBTU / d MBbls / d $ / bbl $ / MMBTU
Two Way Collars Oil 2018 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	108
Two Way Collars Oil 2018 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price | $ / bbl	60.48
Two Way Collars Oil 2018 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price | $ / bbl	50.00
Three Way Collars Oil 2019 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	87
Three Way Collars Oil 2019 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price | $ / bbl	72.98
Three Way Collars Oil 2019 [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average floor price	46.72
Three Way Collars Oil 2019 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price | $ / bbl	56.72
Forward Contracts Oil 2018 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	84
Average price per MMBtu or barrel
Average fixed price	61.45
Three Way Collars Natural Gas 2018 [Member]
Derivative [Line Items]
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	250
Three Way Collars Natural Gas 2018 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price	3.54
Three Way Collars Natural Gas 2018 [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average floor price	2.00
Three Way Collars Natural Gas 2018 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price	2.75
Forward Contracts Natural Gas 2018 [Member]
Derivative [Line Items]
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	280
Average price per MMBtu or barrel
Average fixed price	3.02

XML

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Aug. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Derivative [Line Items]
Additional collateral if credit rating downgraded		$ 124
Amount of collateral posted related to derivative instruments with credit-risk-related contingent features		49		$ 170
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed (net of collateral)		(1,400)		$ (1,400)
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Cash payment for interest-rate swap agreements		101	$ 118
Not Designated as Hedging Instrument [Member] | Interest-Rate Swap 3 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 200	100
Not Designated as Hedging Instrument [Member] | Interest-Rate Swap 3 [Member] | Cash Payments To Amend Interest Rate Swap Agreements [Member]
Derivative [Line Items]
Cash payment for interest-rate swap agreements	$ 10
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps 1 Through 5 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap		$ 1,600

XML

Derivative Instruments - Interest-Rate Derivatives Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Aug. 31, 2018
Interest-Rate Swap 1 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 550
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 01, 2020
Weighted-average interest rate for interest-rate swap	6.418%
Interest-Rate Swap 2 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 01, 2022
Weighted-average interest rate for interest-rate swap	6.809%
Interest-Rate Swap 3 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 100	$ 200
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 01, 2020
Weighted-average interest rate for interest-rate swap	6.891%
Interest-Rate Swap 4 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 01, 2021
Weighted-average interest rate for interest-rate swap	6.57%
Interest-Rate Swap 5 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 450
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 01, 2023
Weighted-average interest rate for interest-rate swap	6.445%

XML

Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 112	$ 108
Gross derivative liabilities	(1,604)	(1,628)
Commodity derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	37	54
Gross derivative liabilities	(496)	(209)
Commodity derivatives [Member] | Other current assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	2	7
Gross derivative liabilities	0	(1)
Commodity derivatives [Member] | Other assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	2
Gross derivative liabilities	0	0
Commodity derivatives [Member] | Other current liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	20	45
Gross derivative liabilities	(440)	(206)
Commodity derivatives [Member] | Other liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	15	0
Gross derivative liabilities	(56)	(2)
Interest-rate derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	75	54
Gross derivative liabilities	(1,108)	(1,419)
Interest-rate derivatives [Member] | Other current assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	21	14
Gross derivative liabilities	0	0
Interest-rate derivatives [Member] | Other assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	54	40
Gross derivative liabilities	0	0
Interest-rate derivatives [Member] | Other current liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	(80)	(236)
Interest-rate derivatives [Member] | Other liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	$ (1,028)	$ (1,183)

XML

Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative [Line Items]
Total (gains) losses on derivatives, net	$ 33	$ 82	$ 506	$ (33)
Commodity derivatives [Member] | Gathering, processing, and marketing sales [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	1	0	3	0
Commodity derivatives [Member] | (Gains) losses on derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	104	43	734	(164)
Interest-rate derivatives [Member] | (Gains) losses on derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	$ (72)	$ 39	$ (231)	$ 131

XML

Derivative Instruments - Fair Value Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	Sep. 30, 2018		Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	$ 112		$ 108
Gross derivative liabilities	(1,604)		(1,628)
Derivative assets Netting	(35)	[1]	(46)
Derivative liabilities Netting	35	[1]	46
Derivative assets, Collateral	0		(1)
Derivative liabilities, Collateral	55		173
Derivative assets	77		61
Derivative liabilities	(1,514)		(1,409)
Commodity derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	37		54
Gross derivative liabilities	(496)		(209)
Derivative assets Netting	(35)	[1]	(46)
Derivative liabilities Netting	35	[1]	46
Derivative assets, Collateral	0		(1)
Derivative liabilities, Collateral	6		3
Derivative assets	2		7
Derivative liabilities	(455)		(160)
Interest-rate derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	75		54
Gross derivative liabilities	(1,108)		(1,419)
Derivative assets Netting	0	[1]	0
Derivative liabilities Netting	0	[1]	0
Derivative assets, Collateral	0		0
Derivative liabilities, Collateral	49		170
Derivative assets	75		54
Derivative liabilities	(1,059)		(1,249)
Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		1
Gross derivative liabilities	0		(1)
Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	112		107
Gross derivative liabilities	(1,604)		(1,627)
Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Recurring [Member] | Commodity derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		1
Gross derivative liabilities	0		(1)
Recurring [Member] | Commodity derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	37		53
Gross derivative liabilities	(496)		(208)
Recurring [Member] | Commodity derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Recurring [Member] | Interest-rate derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Recurring [Member] | Interest-rate derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	75		54
Gross derivative liabilities	(1,108)		(1,419)
Recurring [Member] | Interest-rate derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	$ 0		$ 0

[1] Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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Tangible Equity Units - Additional Information (Detail) shares in Millions, $ in Millions		1 Months Ended	9 Months Ended
	Jun. 07, 2018 USD ($) $ / unit shares	Jun. 30, 2015 USD ($) $ / unit shares	Sep. 30, 2018 USD ($)
TEUs - senior amortizing notes due 2018 [Member]
Tangible Equity Units [Line Items]
Principal amount per amortizing note | $ / unit	10.95
Debt instrument, stated interest rate	1.50%
Final payment | $	$ 9		$ 17
Debt instrument, maturity date	Jun. 07, 2018
7.50% Tangible Equity Units [Member]
Tangible Equity Units [Line Items]
Number of tangible equity units issued		9.2
Tangible equity unit rate		7.50%
Stated amount per tangible equity unit | $ / unit		50.00
Total net proceeds | $		$ 445
Equity Component of 7.50% Tangible Equity Units [Member] | Settled in WGP Common Units [Member]
Tangible Equity Units [Line Items]
Purchase contract, mandatory settlement date	Jun. 07, 2018
Number of tangible equity units settled	9.2
Shares, Issued	8.2
Settlement rate	0.8921

XML

Debt - Debt Activity Table (Detail) - USD ($) $ in Millions			9 Months Ended
		Jun. 07, 2018	Sep. 30, 2018	Aug. 31, 2018	Mar. 31, 2018
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	[1]		$ 15,458
Other, net			41
Balance at September 30, 2018	[1]		16,467
Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	[1]		3,465
Other, net			2
Balance at September 30, 2018	[1]		4,566
Western Gas Equity Partners, LP excluding WES [Member]
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	[1],[2]		28
Balance at September 30, 2018	[1],[2]		28
Anadarko excluding WES and WGP [Member]
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	[1],[3]		11,965
Other, net	[3]		39
Balance at September 30, 2018	[1],[3]		11,873
WES RCF [Member]
Changes in Debt Outstanding [Roll Forward]
Borrowings, credit facility			320
Repayments, credit facility			(690)
WES RCF [Member] | Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Borrowings, credit facility			320
Repayments, credit facility			(690)
WES 4.500% Senior Notes due 2028 [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			394
WES 4.500% Senior Notes due 2028 [Member] | Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			$ 394
Debt instrument, stated interest rate			4.50%		4.50%
Debt instrument, maturity date			Mar. 01, 2028
WES 5.300% Senior Notes due 2048 [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			$ 687
WES 5.300% Senior Notes due 2048 [Member] | Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			$ 687
Debt instrument, stated interest rate			5.30%		5.30%
Debt instrument, maturity date			Mar. 01, 2048
WES 4.750% Senior Notes due 2028 [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			$ 396
WES 4.750% Senior Notes due 2028 [Member] | Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			$ 396
Debt instrument, stated interest rate			4.75%	4.75%
Debt instrument, maturity date			Aug. 01, 2028
WES 5.500% Senior Notes due 2048 [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			$ 342
WES 5.500% Senior Notes due 2048 [Member] | Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Issuances			$ 342
Debt instrument, stated interest rate			5.50%	5.50%
Debt instrument, maturity date			Aug. 01, 2048
Senior Note Component of 7.50% Tangible Equity Units [Member]
Changes in Debt Outstanding [Roll Forward]
Repayments, senior notes		$ (9)	$ (17)
Debt instrument, stated interest rate		1.50%
Debt instrument, maturity date		Jun. 07, 2018
Senior Note Component of 7.50% Tangible Equity Units [Member] | Anadarko excluding WES and WGP [Member]
Changes in Debt Outstanding [Roll Forward]
Repayments, senior notes	[3]		(17)
7.050% Debentures due 2018 [Member]
Changes in Debt Outstanding [Roll Forward]
Repayments, senior notes			(114)
7.050% Debentures due 2018 [Member] | Anadarko excluding WES and WGP [Member]
Changes in Debt Outstanding [Roll Forward]
Repayments, senior notes	[3]		$ (114)
Debt instrument, stated interest rate			7.05%
Debt instrument, maturity date			Mar. 01, 2018
WES 2.600% Senior Notes due 2018 [Member]
Changes in Debt Outstanding [Roll Forward]
Repayments, credit facility			$ (350)
WES 2.600% Senior Notes due 2018 [Member] | Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Repayments, credit facility			$ (350)
Debt instrument, stated interest rate			2.60%
Debt instrument, maturity date			Aug. 01, 2018

[1] The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

[2] Excludes WES.

[3] Excludes WES and WGP.

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Debt - Outstanding Debt Table (Detail) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total borrowings at face value		$ 18,031	$ 17,032
Net unamortized discounts, premiums, and debt issuance costs	[1]	(1,564)	(1,574)
Total borrowings	[2]	16,467	15,458
Capital lease obligations		226	231
Less short-term debt		938	142
Total long-term debt		15,755	15,547
Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Total borrowings at face value		4,620	3,490
Net unamortized discounts, premiums, and debt issuance costs	[1]	(54)	(25)
Total borrowings	[2]	4,566	3,465
Capital lease obligations		0	0
Less short-term debt		0	0
Total long-term debt		4,566	3,465
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Total borrowings at face value	[3]	28	28
Net unamortized discounts, premiums, and debt issuance costs	[1],[3]	0	0
Total borrowings	[2],[3]	28	28
Capital lease obligations	[3]	0	0
Less short-term debt	[3]	28	0
Total long-term debt	[3]	0	28
Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Total borrowings at face value	[4]	13,383	13,514
Net unamortized discounts, premiums, and debt issuance costs	[1],[4]	(1,510)	(1,549)
Total borrowings	[2],[4]	11,873	11,965
Capital lease obligations	[4]	226	231
Less short-term debt	[4]	910	142
Total long-term debt	[4]	$ 11,189	$ 12,054

[1] Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

[2] The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

[3] Excludes WES.

[4] Excludes WES and WGP.

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Debt - Additional Information (Detail) - USD ($)		1 Months Ended		9 Months Ended
		Feb. 28, 2018	Jan. 31, 2018	Sep. 30, 2018	Aug. 31, 2018	Jun. 07, 2018	Mar. 31, 2018	Feb. 01, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total borrowings at face value				$ 18,031,000,000					$ 17,032,000,000
APC RCF [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity			$ 3,000,000,000
Line of credit, expiration date			Jan. 23, 2022
Line of credit, outstanding borrowings				$ 0
364-Day Credit Facility Due 2017 [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity			$ 2,000,000,000
Line of credit, expiration date			Jan. 12, 2019
Debt instrument, term				364 days
Line of credit, outstanding borrowings				$ 0
WES RCF [Member]
Debt Instrument [Line Items]
Borrowings, credit facility				320,000,000
Repayments, credit facility				(690,000,000)
Fair Value, Inputs, Level 2 [Member] | Valuation, Market Approach [Member]
Debt Instrument [Line Items]
Estimated fair value of total borrowings				17,800,000,000					17,700,000,000
TEUs - senior amortizing notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate						1.50%
8.70% Senior Notes due March 2019
Debt Instrument [Line Items]
Outstanding borrowings				$ 600,000,000
Line of credit, interest rate				8.70%
6.950% Senior Notes Due June 2019 [Member]
Debt Instrument [Line Items]
Outstanding borrowings				$ 300,000,000
Line of credit, interest rate				6.95%
Zero-Coupon Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, earliest call date				Oct. 10, 2019
Zero-Coupon Senior Notes [Member] | Accreted Value at Next Potential Put Date [Member]
Debt Instrument [Line Items]
Debt instrument, accreted value				$ 980,000,000
WES 4.750% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Borrowings during period				396,000,000
WES 5.500% Senior Notes due 2048 [Member]
Debt Instrument [Line Items]
Borrowings during period				342,000,000
WES 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Repayments, credit facility				(350,000,000)
WES 4.500% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Borrowings during period				394,000,000
WES 5.300% Senior Notes due 2048 [Member]
Debt Instrument [Line Items]
Borrowings during period				687,000,000
Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Total borrowings at face value				4,620,000,000					3,490,000,000
Western Gas Partners, LP [Member] | WES RCF [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity		$ 1,500,000,000
Line of credit, expiration date		Feb. 26, 2023	Feb. 26, 2020
Line of credit, outstanding borrowings				0
Line of credit, expandable maximum capacity		$ 2,000,000,000
Borrowings, credit facility				320,000,000
Repayments, credit facility				(690,000,000)
Letters of credit, outstanding				5,000,000
Line of credit, available borrowing capacity				$ 1,495,000,000
Western Gas Partners, LP [Member] | WES 4.750% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				4.75%	4.75%
Total borrowings at face value					$ 400,000,000
Borrowings during period				$ 396,000,000
Western Gas Partners, LP [Member] | WES 5.500% Senior Notes due 2048 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				5.50%	5.50%
Total borrowings at face value					$ 350,000,000
Borrowings during period				$ 342,000,000
Western Gas Partners, LP [Member] | WES 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				2.60%
Repayments, credit facility				$ (350,000,000)
Total borrowings at face value				$ 350,000,000
Western Gas Partners, LP [Member] | WES 4.500% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				4.50%			4.50%
Total borrowings at face value							$ 400,000,000
Borrowings during period				$ 394,000,000
Western Gas Partners, LP [Member] | WES 5.300% Senior Notes due 2048 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				5.30%			5.30%
Total borrowings at face value							$ 700,000,000
Borrowings during period				$ 687,000,000
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Total borrowings at face value	[1]			28,000,000					$ 28,000,000
Western Gas Equity Partners, LP excluding WES [Member] | WGP RCF [Member]
Debt Instrument [Line Items]
Line of credit, expiration date		Mar. 14, 2019
Line of credit, outstanding borrowings				28,000,000
Line of credit, available borrowing capacity			$ 250,000,000	$ 7,000,000				$ 35,000,000
Line of credit, interest rate				4.25%

[1] Excludes WES.

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Income Taxes - Income Tax Expense (Benefit) Table (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Current income tax expense (benefit)	$ 146	$ 430	$ 383	$ 670
Deferred income tax expense (benefit)	110	(855)	124	(1,036)
Total income tax expense (benefit)	256	(425)	507	(366)
Income (loss) before income taxes	$ 683	$ (1,066)	$ 1,125	$ (1,616)
Effective tax rate	37.00%	40.00%	45.00%	23.00%

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Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Line Items]
Tax reform legislation income tax benefit	$ 5
Income tax benefit	(256)	$ 425	$ (507)	$ 366
Tronox Litigation [Member] | Judicial Ruling [Member]
Income Tax Disclosure [Line Items]
Income tax benefit			346		$ 346
Unrecognized tax benefits	$ 1,200		$ 1,200		$ 1,200
Income tax refunds						$ 881

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Pension Plans and Other Postretirement Benefits - Components of Net Periodic Benefit Cost Table (Detail) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Pension Benefits [Member]
Components of net periodic benefit cost
Service cost	$ 23		$ 22	$ 68		$ 64
Interest cost	19		21	57		63
Expected (return) loss on plan assets	(20)		(21)	(61)		(63)
Amortization of net actuarial loss (gain)	6		7	19		20
Amortization of net prior service cost (credit)	0		(1)	0		(1)
Settlement expense	9	[1]	22	9		80
Termination benefits expense	7		0	7		4
Net periodic benefit cost	44		50	99	[1]	167
Other Benefits [Member]
Components of net periodic benefit cost
Service cost	0		0	1		1
Interest cost	3		3	8		9
Expected (return) loss on plan assets	0		0	0		0
Amortization of net actuarial loss (gain)	0		0	0		0
Amortization of net prior service cost (credit)	(6)		(6)	(18)		(18)
Settlement expense	0	[1]	0	0		0
Termination benefits expense	0		0	0		0
Net periodic benefit cost	$ (3)		$ (3)	$ (9)	[1]	$ (8)

[1] The service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and all other components of net periodic benefit cost are included in other (income) expense on the Company’s Consolidated Statements of Income.

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Pension Plans and Other Postretirement Benefits - Additional Information (Detail) - Pension Benefits [Member] $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Funded Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 161
Expected employer contributions in 2018	1
Unfunded Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	36
Expected employer contributions in 2018	$ 26

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Stockholders' Equity - Earnings Per Share Reconciliation (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net income (loss)
Net income (loss) attributable to common stockholders	$ 363	$ (699)	$ 513	$ (1,432)
Income (loss) effect of TEUs	0	(2)	(4)	(6)
Less distributions on participating securities	2	0	4	0
Less undistributed income allocated to participating securities	2	0	1	0
Basic	359	(701)	504	(1,438)
Income (loss) effect of TEUs	0	0	0	(1)
Diluted	$ 359	$ (701)	$ 504	$ (1,439)
Shares
Average number of common shares outstanding—basic	499	553	507	552
Dilutive effect of stock options	1	0	1	0
Average number of common shares outstanding—diluted	500	553	508	552
Excluded due to anti-dilutive effect	8	11	9	11
Net income (loss) per common share
Basic (in usd per share)	$ 0.72	$ (1.27)	$ 0.99	$ (2.60)
Diluted (in usd per share)	$ 0.72	$ (1.27)	$ 0.99	$ (2.61)

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Stockholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended				9 Months Ended	12 Months Ended
	Sep. 30, 2018	Aug. 31, 2018	Jun. 30, 2018	Feb. 28, 2018	Sep. 30, 2018	Sep. 30, 2018	Jul. 31, 2018	Sep. 30, 2017
Equity, Class of Treasury Stock [Line Items]
Authorized share-repurchase program				$ 3,000			$ 4,000	$ 2,500
Total Shares Delivered					38.3
Amount of share repurchase program completed					$ 2,441	$ 3,500
Accelerated Stock Repurchase Program [Member]
Equity, Class of Treasury Stock [Line Items]
Amount	$ 1,941		$ 1,441	$ 500	$ 1,941	$ 1,941
Average Price per Share (in usd per share)			$ 65.28	$ 58.82
Initial Shares Delivered			19.1	7.0	26.1
Additional Shares Delivered			3.0	1.5	4.5
Total Shares Delivered			22.1	8.5	30.6
Open-market Stock Purchases [Member]
Equity, Class of Treasury Stock [Line Items]
Amount	$ 250	$ 250			$ 500
Average Price per Share (in usd per share)	$ 63.11	$ 66.14
Total Shares Delivered	3.9	3.8			7.7

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Noncontrolling Interests (Detail) - shares shares in Thousands			9 Months Ended	12 Months Ended
	Jun. 07, 2018	Mar. 01, 2017	Sep. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Western Gas Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Public ownership interest in subsidiary			59.40%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Western Gas Equity Partners, LP Ownership Interest in Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary			29.60%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Anadarko Limited Partner Interest in WES Owned Through Other Subsidiaries [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary			9.50%
Western Gas Partners, LP [Member] | General Partner [Member] | Western Gas Equity Partners, LP Ownership Interest in Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary			1.50%
Western Gas Equity Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary			77.80%
Public ownership interest in subsidiary			22.20%
Series A Preferred Units [Member] | Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement					22,000
Percentage of units converted		50.00%
Class C Units [Member] | Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement			802	886
Equity Component of 7.50% Tangible Equity Units [Member] | Settled in WGP Common Units [Member]
Noncontrolling Interest [Line Items]
Number of tangible equity units settled	9,200
Shares, Issued	8,200

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Variable Interest Entities (Detail) - Variable Interest Entity, Primary Beneficiary [Member] - Western Gas Partners, LP [Member] - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	May 31, 2008	Sep. 30, 2018	Sep. 30, 2017
Variable Interest Entity [Line Items]
Note receivable for WES	$ 260
Debt instrument, term	30 years
Fixed annual rate	6.50%
Interest income for WES		$ 13	$ 13
Above-market component of swap extensions with Anadarko		$ 41	$ 47

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Variable Interest Entities - Financial Data of WGP (Detail) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Statement of Operations Data
Total revenues and other		$ 3,697,000	$ 2,496,000	$ 10,033,000	$ 8,979,000
Operating income (loss)		979,000	(749,000)	2,349,000	(916,000)
Net Income (Loss)		427,000	(641,000)	618,000	(1,250,000)
Statement of Cash Flow Data
Net cash provided by (used in) operating activities				4,302,000	2,619,000
Net cash provided by (used in) investing activities				(4,659,000)	(28,000)
Net cash provided by (used in) financing activities				(2,306,000)	(527,000)
Balance Sheet Data
Cash and cash equivalents		1,883,000		1,883,000		$ 4,553,000
Net properties and equipment related to VIEs		28,744,000		28,744,000		27,451,000
Total assets		41,145,000		41,145,000		42,086,000
Long-term debt		15,755,000		15,755,000		15,547,000
Total equity		11,237,000		11,237,000		13,790,000
Variable Interest Entity, Primary Beneficiary [Member]
Balance Sheet Data
Cash and cash equivalents		133,000		133,000		80,000
Net properties and equipment related to VIEs		6,419,000		6,419,000		5,731,000
WGP [Member]
Balance Sheet Data
Long-term debt	[1]	0		0		28,000
WGP [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Statement of Operations Data
Total revenues and other		508	575	1,432	1,616
Operating income (loss)		200	179	461	523
Net Income (Loss)		155	$ 147	340	424
Statement of Cash Flow Data
Net cash provided by (used in) operating activities				749	642
Net cash provided by (used in) investing activities				(1,161)	(515)
Net cash provided by (used in) financing activities				465	$ (334)
Balance Sheet Data
Cash and cash equivalents		133		133		80
Net properties and equipment related to VIEs		6,419		6,419		5,731
Total assets		9,034		9,034		8,016
Long-term debt		4,566		4,566		3,493
Total liabilities		5,417		5,417		4,071
Total equity		$ 3,617		$ 3,617		$ 3,945

[1] Excludes WES.

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Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash paid (received)
Interest, net of amounts capitalized	$ 813	$ 764
Income taxes, net of refunds	48	169
Non-cash investing activities
Fair value of properties and equipment acquired	8	619
Asset retirement cost additions	261	228
Accruals of property, plant, and equipment	886	786
Net liabilities assumed (divested) in acquisitions and divestitures	(97)	(115)
Non-cash investing and financing activities
Deferred drilling lease liability	0	14
Settlement of tangible equity units	$ 300	$ 0

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Supplemental Cash Flow Information - Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$ 1,993	$ 4,674	$ 5,376	$ 3,308
Cash and Cash Equivalents [Member]
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	1,883	4,553
Restricted cash and restricted cash equivalents	134	255
Other Assets [Member]
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$ 110	$ 121

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Segment Information - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2018 Segment
Segment Reporting [Abstract]
Number of reporting segments	3

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Segment Information - Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) Before Income Taxes (Detail) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Segment Reporting Information [Line Items]
Income (loss) before income taxes	$ 683		$ (1,066)	$ 1,125		$ (1,616)
Interest expense	240		230	705		682
DD&A	1,130		1,083	3,123		3,235
Exploration expense	118	[1]	750	380	[1]	2,366
(Gains) losses on divestitures, net	(3)		194	(31)		(815)
Impairments	172		0	319		383
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(167)		98	73		(12)
Restructuring charges	13		3	13		20
Less net income (loss) attributable to noncontrolling interests	64		58	105		182
Consolidated Adjusted EBITDAX	2,122		$ 1,234	5,602		$ 4,061
Exploration Expense [Member]
Segment Reporting Information [Line Items]
Restructuring charges	$ 20			$ 20

[1] Includes restructuring charges of $20 million for the three and nine months ended September 30, 2018.

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Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
		Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Segment Reporting Information [Line Items]
Sales Revenues		$ 3,851			$ 10,501
Other		87		$ 80	201		$ 237
Total revenues and other		3,697		2,496	10,033		8,979
Operating costs and expenses		2,718		3,245	7,684		9,895
Net cash from settlement of commodity derivatives					433		(21)
Other (income) expense, net		24		5	16		51
Net income (loss) attributable to noncontrolling interests		64		58	105		182
Total expenses and other		1,572		1,456	4,407		4,101
Consolidated Adjusted EBITDAX		2,122		1,234	5,602		4,061
(Gains) losses on derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		199		(16)	437		(23)
Gathering, processing, and marketing sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		0			7		(2)
Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	3,694		2,690	10,002		8,164
Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	1,292		1,412	3,856		3,918
Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		17	[3]	2	9	[3]	24
Operating Segments [Member] | Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales Revenues		3,195			8,654
Other		1		6	(5)		16
Total revenues and other		3,192			8,657
Net income (loss) attributable to noncontrolling interests		0		0	0		0
Total expenses and other		1,059		956	2,840		2,679
Consolidated Adjusted EBITDAX		2,128		1,151	5,793		3,847
Operating Segments [Member] | Exploration and Production [Member] | (Gains) losses on derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		0		0	0		0
Operating Segments [Member] | Exploration and Production [Member] | Gathering, processing, and marketing sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		0			0		0
Operating Segments [Member] | Exploration and Production [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	3,187		2,107	8,633		6,526
Operating Segments [Member] | Exploration and Production [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	1,059		956	2,840		2,679
Operating Segments [Member] | Exploration and Production [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		0	[3]	0	0	[3]	0
Operating Segments [Member] | WES Midstream [Member]
Segment Reporting Information [Line Items]
Sales Revenues		511			1,438
Other		52		39	113		124
Total revenues and other		560			1,545
Net income (loss) attributable to noncontrolling interests		0		0	0		0
Total expenses and other		245		345	687		936
Consolidated Adjusted EBITDAX		315		258	858		788
Operating Segments [Member] | WES Midstream [Member] | (Gains) losses on derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		0		0	0		0
Operating Segments [Member] | WES Midstream [Member] | Gathering, processing, and marketing sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		0			0		0
Operating Segments [Member] | WES Midstream [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	560		603	1,545		1,724
Operating Segments [Member] | WES Midstream [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	245		345	687		936
Operating Segments [Member] | WES Midstream [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		0	[3]	0	0	[3]	0
Operating Segments [Member] | Other Midstream [Member]
Segment Reporting Information [Line Items]
Sales Revenues		113			255
Other		11		7	30		20
Total revenues and other		129			301
Net income (loss) attributable to noncontrolling interests		0		0	0		0
Total expenses and other		55		62	134		168
Consolidated Adjusted EBITDAX		73		41	157		111
Operating Segments [Member] | Other Midstream [Member] | (Gains) losses on derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		0		0	0		0
Operating Segments [Member] | Other Midstream [Member] | Gathering, processing, and marketing sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		0			0		0
Operating Segments [Member] | Other Midstream [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	128		103	291		279
Operating Segments [Member] | Other Midstream [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	55		62	134		168
Operating Segments [Member] | Other Midstream [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		0	[3]	0	0	[3]	0
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Sales Revenues		32			154
Other		23		28	63		77
Total revenues and other		(184)			(470)
Net income (loss) attributable to noncontrolling interests		64		58	105		182
Total expenses and other		213		93	746		318
Consolidated Adjusted EBITDAX		(394)		(216)	(1,206)		(685)
Other and Intersegment Eliminations [Member] | (Gains) losses on derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		199		(16)	437		(23)
Other and Intersegment Eliminations [Member] | Gathering, processing, and marketing sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		0			7		(2)
Other and Intersegment Eliminations [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	(181)		(123)	(467)		(365)
Other and Intersegment Eliminations [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	(67)		49	195		135
Other and Intersegment Eliminations [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		17	[3]	2	9	[3]	24
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Sales Revenues		3,607		2,610	9,801		7,927
Oil and Gas [Member] | Operating Segments [Member] | Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales Revenues		3,161		2,097	8,589		6,500
Oil and Gas [Member] | Operating Segments [Member] | Exploration and Production [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Sales Revenues		25		4	49		10
Oil and Gas [Member] | Operating Segments [Member] | WES Midstream [Member]
Segment Reporting Information [Line Items]
Sales Revenues		394		445	1,063		1,213
Oil and Gas [Member] | Operating Segments [Member] | WES Midstream [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Sales Revenues		114		119	369		387
Oil and Gas [Member] | Operating Segments [Member] | Other Midstream [Member]
Segment Reporting Information [Line Items]
Sales Revenues		39		53	73		134
Oil and Gas [Member] | Operating Segments [Member] | Other Midstream [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Sales Revenues		78		43	188		125
Oil and Gas [Member] | Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Sales Revenues		13		15	76		80
Oil and Gas [Member] | Other and Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Sales Revenues		$ (217)		$ (166)	$ (606)		$ (522)

[1] Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

[2] Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX

[3] Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.