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 March 31, 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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 April 30, 2018, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	515,088,252

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three Months Ended March 31, 2018 and 2017	4
	Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2018 and 2017	5
	Consolidated Balance Sheets at March 31, 2018, and December 31, 2017	6
	Consolidated Statement of Equity for the Three Months Ended March 31, 2018	7
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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—Inventories	14
	Note 4—Divestitures	15
	Note 5—Impairments	16
	Note 6—Suspended Exploratory Well Costs	17
	Note 7—Current Liabilities	17
	Note 8—Derivative Instruments	17
	Note 9—Tangible Equity Units	23
	Note 10—Debt	23
	Note 11—Income Taxes	26
	Note 12—Contingencies	27
	Note 13—Pension Plans and Other Postretirement Benefits	27
	Note 14—Stockholders’ Equity	28
	Note 15—Noncontrolling Interests	29
	Note 16—Variable Interest Entities	30
	Note 17—Supplemental Cash Flow Information	32
	Note 18—Segment Information	33
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
	Cautionary Statement About Forward-Looking Statements	35
	Management Overview	37
	Financial Results	39
	Liquidity and Capital Resources	49
	Recent Accounting Developments	52
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 4.	Controls and Procedures	54
PART II
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 6.	Exhibits	57

COMMONLY USED TERMS AND DEFINITIONS

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

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

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

GOM Acquisition - The acquisition of oil and natural-gas assets in the Gulf of Mexico that closed on December 15, 2016

IPO - Initial public offering

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

NGLs - Natural gas liquids

NM - Not meaningful

NTSB - National Transportation Safety Board

NYMEX - New York Mercantile Exchange

Oil - Includes crude oil and condensate

2

OPEC - Organization of the Petroleum Exporting Countries

RCF - Revolving credit facility

S&P - Standard and Poor’s

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   March 31,
millions except per-share amounts	2018			2017
Revenues and Other
Oil sales	$	2,127		$	1,663
Natural-gas sales	247			502
Natural-gas liquids sales	292			289
Gathering, processing, and marketing sales	360			444
Gains (losses) on divestitures and other, net	19			869
Total	3,045			3,767
Costs and Expenses
Oil and gas operating	276			256
Oil and gas transportation	196			249
Exploration	168			1,084
Gathering, processing, and marketing	237			350
General and administrative	278			263
Depreciation, depletion, and amortization	990			1,115
Production, property, and other taxes	190			155
Impairments	19			373
Other operating expense	140			22
Total	2,494			3,867
Operating Income (Loss)	551			(100		)
Other (Income) Expense
Interest expense	228			223
(Gains) losses on derivatives, net	35			(147		)
Other (income) expense, net	(12		)	2
Total	251			78
Income (Loss) Before Income Taxes	300			(178		)
Income tax expense (benefit)	126			97
Net Income (Loss)	174			(275		)
Net income (loss) attributable to noncontrolling interests	53			43
Net Income (Loss) Attributable to Common Stockholders	$	121		$	(318	)
Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.23		$	(0.58	)
Net income (loss) attributable to common stockholders—diluted	$	0.22		$	(0.58	)
Average Number of Common Shares Outstanding—Basic	518			551
Average Number of Common Shares Outstanding—Diluted	519			551
Dividends (per common share)	$	0.25		$	0.05

See accompanying Notes to Consolidated Financial Statements.

4

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended   March 31,
millions	2018			2017
Net Income (Loss)	$	174		$	(275	)
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	1			1
Total adjustments for derivative instruments, net of taxes	1			1
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	—			(4		)
Income taxes on net gain (loss) incurred during period	—			1
Amortization of net actuarial (gain) loss to other (income) expense, net	7			9
Income taxes on amortization of net actuarial (gain) loss	(2		)	(3		)
Amortization of net prior service (credit) cost to other (income) expense, net	(6		)	(6		)
Income taxes on amortization of net prior service (credit) cost	1			2
Total adjustments for pension and other postretirement plans, net of taxes	—			(1		)
Total	1			—
Comprehensive Income (Loss)	175			(275		)
Comprehensive income (loss) attributable to noncontrolling interests	53			43
Comprehensive Income (Loss) Attributable to Common Stockholders	$	122		$	(318	)

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

millions except per-share amounts	March 31,   2018			December 31,   2017
ASSETS
Current Assets
Cash and cash equivalents ($524 and $80 related to VIEs)	$	3,361		$	4,553
Accounts receivable (net of allowance of $14 and $14)
Customers ($125 and $106 related to VIEs)	1,156			1,222
Others ($13 and $19 related to VIEs)	639			607
Other current assets	374			380
Total	5,530			6,762
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $34,220 and $34,146) ($6,064 and $5,731 related to VIEs)	27,758			27,451
Other Assets ($572 and $579 related to VIEs)	2,134			2,211
Goodwill and Other Intangible Assets ($1,184 and $1,191 related to VIEs)	5,654			5,662
Total Assets	$	41,076		$	42,086
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade ($331 and $305 related to VIEs)	$	2,059		$	1,894
Other	191			266
Short-term debt - Anadarko (1)	733			142
Short-term debt - WGP/WES	28			—
Current asset retirement obligations	286			294
Other current liabilities	1,437			1,310
Total	4,734			3,906
Long-term Debt
Long-term debt - Anadarko (1)	11,467			12,054
Long-term debt - WGP/WES	4,176			3,493
Total	15,643			15,547
Other Long-term Liabilities
Deferred income taxes	2,267			2,234
Asset retirement obligations ($147 and $143 related to VIEs)	2,510			2,500
Other	4,166			4,109
Total	8,943			8,843
Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 575.2 million and 574.2 million shares issued)	57			57
Paid-in capital	11,701			12,000
Retained earnings	1,152			1,109
Treasury stock (71.3 million and 43.4 million shares)	(3,759		)	(2,132		)
Accumulated other comprehensive income (loss)	(410		)	(338		)
Total Stockholders’ Equity	8,741			10,696
Noncontrolling interests	3,015			3,094
Total Equity	11,756			13,790
Total Liabilities and Equity	$	41,076		$	42,086

__________________________________________________________________

Parenthetical references reflect amounts as of March 31, 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)	—		—			121			—			—			53			174
Share-based compensation expense	—		39			—			—			—			—			39
Dividends—common stock	—		—			(127		)	—			—			—			(127		)
Repurchases of common stock	—		(332		)	—			(1,627		)	—			—			(1,959		)
Subsidiary equity transactions	—		(6		)	—			—			—			9			3
Distributions to noncontrolling interest owners	—		—			—			—			—			(118		)	(118		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—			—			—			1			—			1
Cumulative effect of accounting change (1)	—		—			49			—			(73		)	(23		)	(47		)
Balance at March 31, 2018	$	57	$	11,701		$	1,152		$	(3,759	)	$	(410	)	$	3,015		$	11,756

 __________________________________________________________________

⁽¹⁾  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, beginning January 1, 2018; 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)

	Three Months Ended   March 31,
millions	2018			2017
Cash Flows from Operating Activities
Net income (loss)	$	174		$	(275	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	990			1,115
Deferred income taxes	42			(660		)
Dry hole expense and impairments of unproved properties	106			1,012
Impairments	19			373
(Gains) losses on divestitures, net	24			(804		)
Total (gains) losses on derivatives, net	36			(147		)
Operating portion of net cash received (paid) in settlement of derivative instruments	(63		)	(8		)
Other	74			83
Changes in assets and liabilities
(Increase) decrease in accounts receivable	23			68
Increase (decrease) in accounts payable and other current liabilities	45			395
Other items, net	(40		)	(29		)
Net cash provided by (used in) operating activities	1,430			1,123
Cash Flows from Investing Activities
Additions to properties and equipment	(1,547		)	(1,194		)
Divestitures of properties and equipment and other assets	371			2,851
Other, net	63			66
Net cash provided by (used in) investing activities	(1,113		)	1,723
Cash Flows from Financing Activities
Borrowings, net of issuance costs	1,333			—
Repayments of debt	(639		)	(10		)
Financing portion of net cash received (paid) for derivative instruments	54			(37		)
Increase (decrease) in outstanding checks	(26		)	28
Dividends paid	(127		)	(28		)
Repurchases of common stock	(1,959		)	(21		)
Distributions to noncontrolling interest owners	(118		)	(105		)
Payments of future hard-minerals royalty revenues conveyed	(25		)	(25		)
Net cash provided by (used in) financing activities	(1,507		)	(198		)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents	—			3
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	(1,190		)	2,651
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	$	3,484		$	5,959

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 $10 million for the three months ended March 31, 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. Refer to 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, and these fees are recognized to 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 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 liabilities and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko is implementing new accounting software and continuing to evaluate its systems, processes, and internal controls during 2018. The Company will adopt this ASU on January 1, 2019, using a modified retrospective approach for all comparative periods presented according to the ASU as it is currently written.

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. Refer to Note 1—Summary of Significant Accounting Policies for additional information. The primary impacts of the Company’s change in accounting policy for revenue recognition effective January 1, 2018, are detailed below.

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 will decrease for contracts where the Company is acting as an agent for its processing customer in the sale of processed volumes and increase 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 will not impact net earnings.

Impacts on Financial Statements The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements for the three months ended March 31, 2018, as described in the Change in Accounting Policy section above:

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 March 31, 2018
Revenues
Gathering, processing, and marketing sales	$	360	$	577	$	(217	)
Gains (losses) on divestitures and other, net	19		21		(2		)
Expenses
Gathering, processing, and marketing	237		451		(214		)
Income tax expense (benefit)	126		127		(1		)
Net income (loss) attributable to noncontrolling interests	53		54		(1		)
Net Income (Loss) Attributable to Common Stockholders	$	121	$	124	$	(3	)

CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
March 31, 2018
Assets
Net properties and equipment	$	27,758	$	27,715	$	43
Other assets	2,134		2,122		12
Liabilities
Other current liabilities	1,437		1,434		3
Deferred income taxes	2,267		2,274		(7		)
Other	4,166		4,056		110
Equity
Total equity	11,756		11,807		(51		)

12

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 March 31, 2018
Product Type
Oil sales	$	2,127		$	—		$	—	$	—		$	2,127
Natural-gas sales	247			—			—		—			247
Natural-gas liquids sales	292			—			—		—			292
Gathering, processing, and marketing sales(1)	—			438			86		24			548
Other, net	3			—			—		19			22
Total Revenue from Customers	$	2,669		$	438		$	86	$	43		$	3,236
Gathering, processing, and marketing sales(2)	—			(1		)	2		(189		)	(188		)
Gains (losses) on divestitures, net	(33		)	—			9		—			(24		)
Other, net	(12		)	29			10		(6		)	21
Total Revenue from Other than Customers	$	(45	)	$	28		$	21	$	(195	)	$	(191	)
Total Revenue and Other	$	2,624		$	466		$	107	$	(152	)	$	3,045

 __________________________________________________________________

⁽¹⁾  The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $224 million and intercompany eliminations of $(196) million.

⁽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.

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 to 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	40
Decrease due to revenue recognized	(12		)
Balance at March 31, 2018	$	163
Contract liabilities at March 31, 2018
Other current liabilities	$	39
Other long-term liabilities - other	124
Total contract liabilities from contracts with customers	$	163

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Revenue from Contracts with Customers(Continued)

Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of March 31, 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	$	74	$	268	$	38	$	(167	)	$	213
2019	102		440		74		(327		)	289
2020	103		496		87		(394		)	292
2021	103		470		94		(395		)	272
2022	7		461		98		(394		)	172
Thereafter	62		1,698		194		(1,321		)	633
Total	$	451	$	3,833	$	585	$	(2,998	)	$	1,871

3. Inventories

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

millions	March 31,   2018		December 31,   2017
Oil	$	184	$	165
Natural gas	8		29
NGLs	117		122
Total inventories	$	309	$	316

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Divestitures

Divestitures  The following summarizes the proceeds received and gains (losses) recognized on divestitures for the three months ended March 31:

millions	2018			2017
Proceeds received, net of closing adjustments	$	371		$	2,851
Gains (losses) on divestitures, net (1)	(24		)	804

__________________________________________________________________

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

2018During the three months ended March 31, 2018, the Company divested of the following assets:

• Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $383 million and net losses of $30 million in 2018 and $154 million in the fourth quarter of 2017. As this transaction is subject to regulatory approval, the Company recognized a contingent liability, which is presented net with the related assets, equal to the net proceeds received from the buyer.

2017During the three months ended March 31, 2017, the Company divested of the following 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 $726 million.

• Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $763 million and net losses of $44 million in 2017 and $129 million in the fourth quarter of 2016.

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. After the acquisition, the DBJV System is 100% owned by WES and consolidated by Anadarko.

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. Impairments

Impairments of Long-Lived Assets Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:

	Three Months Ended
millions	Impairment		Fair Value (1)
March 31, 2018
Exploration and Production
Gulf of Mexico properties	$	19	$	—
Total	$	19	$	—
March 31, 2017
Exploration and Production
Gulf of Mexico properties	$	204	$	231
WES Midstream	168		49
Other Midstream	1		—
Total	$	373	$	280

__________________________________________________________________

⁽¹⁾  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 during the three months ended March 31, 2017, were primarily related to oil and gas properties in the Gulf of Mexico due to lower forecasted commodity prices and a U.S. onshore midstream property due to a reduced throughput fee as a result of a producer’s bankruptcy.

Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. The Company recognized $532 million of impairments of unproved Gulf of Mexico properties during the three months ended March 31, 2017, of which $467 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.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $539 million at March 31, 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 three months ended March 31, 2018,no charges were booked to exploration expense for suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017.

7. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $193 million at March 31, 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:

millions	March 31,   2018		December 31,   2017
Accrued income taxes	$	54	$	71
Interest payable	167		246
Production, property, and other taxes payable	276		216
Accrued employee benefits	140		210
Derivatives	460		384
Other	340		183
Total other current liabilities	$	1,437	$	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 (Marketing and Trading Derivative Activities).

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.

17

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 March 31, 2018:

	2018 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
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)	256
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.

18

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.

At March 31, 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 the potential refinancing of the Company’s future debt maturities. 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 March 31, 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%
$	200	September 2017 - 2047	September 2018	6.049%
$	100	September 2017 - 2047	September 2020	6.891%
$	250	September 2017 - 2047	September 2021	6.570%
$	250	September 2017 - 2047	September 2023	6.761%

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 $46 million during the three months ended March 31, 2018, and $24 million during the three months ended March 31, 2017.

19

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	March 31,		December 31,		March 31,			December 31,
Balance Sheet Classification	2018		2017		2018			2017
Commodity derivatives
Other current assets	$	6	$	7	$	—		$	(1	)
Other assets	1		2		—			—
Other current liabilities	31		45		(292		)	(206		)
Other liabilities	—		—		(1		)	(2		)
	38		54		(293		)	(209		)
Interest-rate derivatives
Other current assets	17		14		—			—
Other assets	47		40		—			—
Other current liabilities	—		—		(211		)	(236		)
Other liabilities	—		—		(1,045		)	(1,183		)
	64		54		(1,256		)	(1,419		)
Total derivatives	$	102	$	108	$	(1,549	)	$	(1,628	)

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

millions	Three Months Ended   March 31,
Classification of (Gain) Loss Recognized	2018			2017
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	1		$	—
(Gains) losses on derivatives, net	162			(135		)
Interest-rate derivatives
(Gains) losses on derivatives, net	(127		)	(12		)
Total (gains) losses on derivatives, net	$	36		$	(147	)

__________________________________________________________________

⁽¹⁾  Represents the effect of Marketing and Trading Derivative Activities.

20

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 March 31, 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. For example, based on the derivative positions as of March 31, 2018, if Anadarko’s credit rating were to be downgraded one level by either S&P or Moody’s, the Company would be required to post additional collateral of up to approximately $60 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 $69 million of collateral) at March 31, 2018, and $1.4 billion (net of $170 million of collateral) at December 31, 2017.

21

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
March 31, 2018
Assets
Commodity derivatives	$	—		$	38		$	—	$	(31	)	$	—		$	7
Interest-rate derivatives	—			64			—		—			—			64
Total derivative assets	$	—		$	102		$	—	$	(31	)	$	—		$	71
Liabilities
Commodity derivatives	$	—		$	(293	)	$	—	$	31		$	7		$	(255	)
Interest-rate derivatives	—			(1,256		)	—		—			69			(1,187		)
Total derivative liabilities	$	—		$	(1,549	)	$	—	$	31		$	76		$	(1,442	)
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.

22

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 is comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification.

Equity ComponentUnless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver not more than 0.8862 WGP common units and not less than 0.7383 WGP common units (or a computed number of APC shares) per TEU on the settlement date, subject to adjustment, at the settlement rate based upon the applicable market value of WGP common units (or APC shares).

Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. The senior amortizing notes have a final installment payment date of June 7, 2018, and are senior unsecured obligations of the Company. 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 three months ended March 31, 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
Borrowings	260			—		—			260			WES RCF
Repayments	(630		)	—		—			(630		)	WES RCF
	—			—		(8		)	(8		)	TEUs - senior amortizing notes
Other, net	—			—		13			13			Amortization of discounts, premiums, and debt issuance costs
Balance at March 31, 2018	$	4,176		$	28	$	11,970		$	16,174

__________________________________________________________________

⁽¹⁾  Excludes WES.

⁽²⁾  Excludes WES and WGP.

23

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
March 31, 2018
Total borrowings at face value	$	4,220		$	28	$	13,506		$	17,754
Net unamortized discounts, premiums, and debt issuance costs (3)	(44		)	—		(1,536		)	(1,580		)
Total borrowings (4)	4,176			28		11,970			16,174
Capital lease obligations	—			—		230			230
Less short-term debt	—			28		733			761
Total long-term debt	$	4,176		$	—	$	11,467		$	15,643
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 $18.1 billion at March 31, 2018, and $17.7 billion at December 31, 2017.

24

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 March 31, 2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

At March 31, 2018, Anadarko had outstanding borrowings of $9 million of senior amortizing notes associated with the TEUs, $114 million of 7.05% Debentures due May 2018, and $600 million of 8.70% Debentures due March 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, which, if put in whole, will be $930 million at the next put date in October 2018. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2018, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.

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 three months ended March 31, 2018, WES borrowed $260 million under its RCF, which was used for general partnership purposes, and made repayments of $630 million. At March 31, 2018, WES had no outstanding borrowings under its RCF, had outstanding letters of credit of $5 million, had available borrowing capacity of $1.495 billion, and was in compliance with all covenants. WES’s $350 million2.600% Senior Notes due August 2018 were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2018, as WES has the ability and intent to refinance these obligations using long-term debt.

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 the remaining net proceeds were used 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 March 31, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 3.88%, classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $7 million. At March 31, 2018, WGP was in compliance with all covenants.

25

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%. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation and record any necessary adjustments to provisional tax amounts 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   March 31,
millions except percentages	2018			2017
Current income tax expense (benefit)	$	90		$	762
Deferred income tax expense (benefit)	36			(665		)
Total income tax expense (benefit)	$	126		$	97
Income (loss) before income taxes	300			(178		)
Effective tax rate	42		%	(54		)%

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 increase from the U.S. federal statutory rate of 21% for the three months ended March 31, 2018, was primarily attributable to the following:

• state taxes, net of federal benefits

• tax impact from foreign operations

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

• net changes in uncertain tax positions

These increases were partially offset by income attributable to noncontrolling interests.

The Company reported a loss before income taxes for the three months ended March 31, 2017. As a result, items that ordinarily increase or decrease tax rate will have the opposite effect. The decrease from the U.S. federal statutory rate of 35% for the three months ended March 31, 2017, was primarily attributable to the following decreases:

• state taxes, net of federal benefit

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

• tax impact from foreign operations

• net changes in uncertain tax positions

• tax deficiency related to share-based compensation due to the adoption of ASU 2016-09

These decreases were partially offset by the following increases:

• income attributable to noncontrolling interests

• federal manufacturing deduction

26

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 March 31, 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 March 31, 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. The Company disagrees and plans to defend its tax position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company defends its tax position through the appeals process and other available avenues. The Company could be required to repay all or a portion of the tentative refund received with interest prior to determining the final outcome of its position either upon IRS request or litigation of the matter in District or Federal Claims Court. If the payment is ultimately determined not to be deductible, the Company would be required to repay the tentative refund received plus interest and reverse the net benefit of $346 million previously recognized in its consolidated financial statements.

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.

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 March 31
Service cost	$	23		$	21		$	—		$	—
Interest cost	19			21			3			3
Expected (return) loss on plan assets	(21		)	(21		)	—			—
Amortization of net actuarial loss (gain)	7			6			—			—
Amortization of net prior service cost (credit)	—			—			(6		)	(6		)
Settlement expense	—			3			—			—
Termination benefits expense	—			4			—			—
Net periodic benefit cost (1)	$	28		$	34		$	(3	)	$	(3	)

__________________________________________________________________

⁽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 $46 million to funded pension plans and $16 million to unfunded pension plans during the three months ended March 31, 2018. The Company expects to contribute an additional $116 million to funded pension plans and $14 million to unfunded pension plans during 2018.

27

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.

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

	Three Months Ended   March 31,
millions except per-share amounts	2018			2017
Net income (loss)
Net income (loss) attributable to common stockholders	$	121		$	(318	)
Income (loss) effect of TEUs	(3		)	(2		)
Less distributions on participating securities	1			—
Basic	$	117		$	(320	)
Income (loss) effect of TEUs	(1		)	—
Diluted	$	116		$	(320	)
Shares
Average number of common shares outstanding—basic	518			551
Dilutive effect of stock options	1			—
Average number of common shares outstanding—diluted	519			551
Excluded due to anti-dilutive effect	10			11
Net income (loss) per common share
Basic	$	0.23		$	(0.58	)
Diluted	$	0.22		$	(0.58	)

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 ($3.0 Billion Share-Repurchase Program). The program authorizes the repurchase of the Company’s common stock in the open market or through private transactions through the end of 2018. In February 2018, Anadarko 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. All of the repurchased shares were classified as treasury stock.

In March 2018, Anadarko entered into an additional ASR Agreement to repurchase the remaining $1.4 billion of the Company’s common stock under the $3.0 Billion Share-Repurchase Program. Under the terms of the agreement, the Company paid $1.4 billion in cash and received an initial delivery of 19.1 million 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 value of the initial 19.1 million shares delivered on the date of purchase was $1.1 billion (average price of $58.16 per share) and was recorded in treasury stock, with the remaining $332 million recorded in paid-in capital on the Company’s Consolidated Balance Sheet at March 31, 2018. The final number of shares to be delivered upon settlement of this ASR Agreement will be determined in the second quarter of 2018 with reference to the volume-weighted average price of the shares during the term of the agreement less a negotiated settlement price adjustment. The value recorded in paid-in capital at March 31, 2018, will be transferred to treasury stock upon final settlement. The $3.0 Billion Share-Repurchase Program is expected to be completed in the second quarter of 2018.

These transactions were accounted for as equity transactions. For shares received and recorded as treasury stock, these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS.

28

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 261 thousand Class C units to Anadarko during the three months ended March 31, 2018, and 886 thousand Class C units to Anadarko during 2017.

WGP is a limited partnership formed by Anadarko to own interests in WES. At March 31, 2018, Anadarko’s ownership interest in WGP consisted of an 81.6% limited partner interest and the entire non-economic general partner interest. The remaining 18.4% limited partner interest in WGP was owned by the public.

At March 31, 2018, WGP’s ownership interest in WES consisted of a 29.7% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At March 31, 2018, Anadarko also owned a 9.2% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.6% limited partner interest in WES was owned by the public.

29

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 isconsideredtheprimary 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   March 31,
millions	2018			2017
Statement of Operations Data
Total revenues and other	$	437		$	516
Operating income (loss)	187			138
Net income (loss)	150			103
Statement of Cash Flows Data
Net cash provided by (used in) operating activities	$	241		$	192
Net cash provided by (used in) investing activities	(294		)	(252		)
Net cash provided by (used in) financing activities	497			(176		)

millions	March 31,   2018		December 31,   2017
Balance Sheet Data
Cash and cash equivalents	$	524	$	80
Net property, plant, and equipment	6,064		5,731
Total assets	8,816		8,016
Long-term debt	4,176		3,493
Total liabilities	4,967		4,071
Total equity and partners’ capital	3,849		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 March 31, 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 March 31, 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.

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.

30

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. Variable Interest Entities (Continued)

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 $4 million for each of the three months ended March 31, 2018 and 2017. The note receivable and related interest income are eliminated in consolidation.

In March 2015, WES acquired the Company’s interest in DBJV. The acquisition was financed using a deferred purchase price obligation that required a cash payment from WES to the Company due on March 31, 2020. In May 2017, WES reached an agreement with the Company to settle this obligation whereby WES made a cash payment to the Company of $37 million, equal to the estimated net present value of the obligation at March 31, 2017.

In order 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 has 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 $14 million for the three months ended March 31, 2018, and $12 million for the three months ended March 31, 2017.

31

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:

	Three Months Ended   March 31,
millions	2018			2017
Cash paid (received)
Interest, net of amounts capitalized	$	326		$	308
Income taxes, net of refunds	12			1
Non-cash investing activities
Fair value of properties and equipment acquired	$	2		$	549
Asset retirement cost additions	63			61
Accruals of property, plant, and equipment	965			608
Net liabilities assumed (divested) in acquisitions and divestitures	(25		)	(82		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	7

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:

millions	March 31,   2018		December 31,   2017
Cash and cash equivalents	$	3,361	$	4,553
Restricted cash and restricted cash equivalents included in Other Assets	123		121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	3,484	$	4,674

Included in cash and cash equivalents is restricted cash and restricted cash equivalents of $225 million at March 31, 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.

32

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’s 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; 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   March 31,
millions	2018			2017
Income (loss) before income taxes	$	300		$	(178	)
Interest expense	228			223
DD&A	990			1,115
Exploration expense	168			1,084
(Gains) losses on divestitures, net	24			(804		)
Impairments	19			373
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(27		)	(155		)
Restructuring charges	—			(1		)
Less net income (loss) attributable to noncontrolling interests	53			43
Consolidated Adjusted EBITDAX	$	1,649		$	1,614

33

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 March 31, 2018
Sales revenues	$	2,656		$	310	$	36	$	24		$	3,026
Intersegment revenues	10			127		52		(189		)	—
Other	(9		)	29		10		13			43
Total revenues and other (1)	2,657			466		98		(152		)	3,069
Operating costs and expenses (2)	876			194		54		193			1,317
Net cash from settlement of commodity derivatives	—			—		—		68			68
Other (income) expense, net	—			—		—		(12		)	(12		)
Net income (loss) attributable to noncontrolling interests	—			—		—		53			53
Total expenses and other	876			194		54		302			1,426
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		6			6
Adjusted EBITDAX	$	1,781		$	272	$	44	$	(448	)	$	1,649
Three Months Ended March 31, 2017
Sales revenues	$	2,451		$	366	$	36	$	45		$	2,898
Intersegment revenues	3			151		42		(196		)	—
Other	2			30		6		27			65
Total revenues and other (1)	2,456			547		84		(124		)	2,963
Operating costs and expenses (2)	923			292		50		31			1,296
Net cash from settlement of commodity derivatives	—			—		—		6			6
Other (income) expense, net	—			—		—		2			2
Net income (loss) attributable to noncontrolling interests	—			—		—		43			43
Total expenses and other	923			292		50		82			1,347
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		(2		)	(2		)
Adjusted EBITDAX	$	1,533		$	255	$	34	$	(208	)	$	1,614

 __________________________________________________________________

⁽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.

34

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; 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

35

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

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

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

• the Company’s ability to successfully complete its $3.0 Billion Share-Repurchase Program

• uncertainties associated with acquired properties and businesses

• disruptions in international oil and NGLs cargo shipping activities

• physical, digital, internal, and external security breaches

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

• 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.

36

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

Anadarko 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 the deepwater Gulf of Mexico. The Company expects to use the cash flows generated from its Gulf of Mexico and international producing assets to fund activity in its unconventional assets in the U.S. onshore.

In 2018, the Company plans to leverage its foundational principle of efficient capital allocation to generate attractive returns on, and of, capital and expects to invest within cash flow. If realized commodity prices are above investment assumptions, Anadarko plans to return capital to stakeholders versus materially increasing activity for incremental production-volume growth. In the first quarter of 2018, the Company increased the quarterly cash dividend by 400% and expanded its share-repurchase program from $2.5 billion to $3.0 billion. The Company also announced its plans to retire debt at par for over $1.0 billion of fixed income securities over the balance of 2018 and 2019. These actions demonstrate the strength of the Company’s portfolio and commitment to capital efficiency.

In the Delaware basin, the Company continues to build out one of the most expansive and integrated infrastructure positions in the region and advance its efforts to capture operatorship on 70% of its acreage position, primarily in Reeves and Loving counties. Additionally, Anadarko continues to progress the construction of two regional oil treating facilities to support its more cost-effective and environmentally beneficial tankless battery design field-wide, while also securing necessary gathering, processing, and takeaway capacity. This comprehensive build-out plan and phased development approach in the Delaware basin is expected to deliver incremental oil sales volumes during the second half of 2018. The Company ended the first quarter of 2018 with 8 operated drilling rigs in the Delaware basin, which compares to 10 operated drilling rigs at year-end 2017. Subsequent to quarter end, the Company reduced the operated drilling rig count to seven and plans to operate at this level for the remainder of 2018.

In the DJ basin, 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 first quarter of 2018 with five operated drilling rigs in the DJ basin, which compares to six operated drilling rigs at year-end 2017. Subsequent to quarter end, the Company reduced the operated drilling rig count to four and plans to operate at this level for the remainder of 2018.

In the deepwater Gulf of Mexico, Anadarko has three floating drillships and one platform rig drilling with a focus toward high-return oil development opportunities near the Company’s expansive infrastructure. Internationally, drilling has resumed in offshore Ghana with continued TEN development drilling and completion activity as well as additional drilling operations in the Jubilee field following the Ghanaian government’s approval of the full-field plan of development in October 2017.

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 for 2018, including approximately 100% of its expected international, Brent-levered sales volumes. In January 2018, the Company entered into additional fixed-price swaps consisting of 280 MMBtu/d at an average price of $3.02, increasing its coverage to slightly more than 50% of its anticipated 2018 natural-gas sales volumes. See Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

In January 2018, the Company divested its nonoperated interest in Alaska for net proceeds of $383 million. This transaction is subject to regulatory approval.

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

Total Company

• Anadarko’s overall sales-volume product mix increased to 57% oil in the first quarter of 2018, compared to 46% in the first quarter of 2017, which significantly improved margins and returns.

U.S. Onshore

• Oil sales volumes in the Delaware basin increased by 21 MBbls/d, representing a 70%increase from the first quarter of 2017, primarily due to continued drilling and completion activities.

International

Ghana

• The operating agreement with the Ghanaian Government for the TEN fields was not affected by the 2017 ruling from the International Tribunal for the Law of the Sea regarding the delimitation of the maritime boundary between Ghana and Côte d’Ivoire in the Atlantic Ocean, and the operator resumed drilling operations in the first quarter of 2018.

• In the first quarter of 2018, the operator of the FPSO at the Jubilee field in Ghana completed the first of three shutdown periods that are expected to occur in 2018 to effectively stabilize the turret and rotate the FPSO to its permanent heading. In addition, the operator resumed drilling operations after receiving Ghanaian Government approval for the full-field plan of development.

Mozambique

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

• In Mozambique, the Company continues to progress the resettlement and site preparation activities, which will position the onshore area for construction of the LNG facilities.

• Anadarko and its co-venturers in Offshore Area 1 in Mozambique reached agreement on a long-term sale and purchase agreement for 1.2 million tonnes per annum for 15 years with Électricité de France, S.A.

Financial

• The Company generated $1.4 billion of cash flow from operations and ended the quarter with $3.4 billion of cash.

• In February 2018, the Company expanded the announced share-repurchase program to $3.0 billion and 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 to repurchase the remaining $1.4 billion of the Company’s common stock under the $3.0 Billion Share-Repurchase Program and received an initial delivery of 19.1 million shares. The $3.0 Billion Share-Repurchase Program is expected to be completed in the second quarter of 2018.

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FINANCIAL RESULTS

	Three Months Ended   March 31,
millions except per-share amounts	2018		2017
Oil, natural-gas, and NGLs sales	$	2,666	$	2,454
Gathering, processing, and marketing sales	360		444
Gains (losses) on divestitures and other, net	19		869
Revenues and other	$	3,045	$	3,767
Costs and expenses	2,494		3,867
Other (income) expense	251		78
Income tax expense (benefit)	126		97
Net income (loss) attributable to common stockholders	$	121	$	(318	)
Net income (loss) per common share attributable to common stockholders—diluted	$	0.22	$	(0.58	)
Average number of common shares outstanding—diluted	519		551

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Increases or decreases “for the three months ended March 31, 2018,” refer to the comparison of the three months ended March 31, 2018, to the three months ended March 31, 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.

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Revenues and Sales Volumes

	Three Months Ended March 31,
millions except percentages	Oil			Natural Gas			NGLs			Total
2017 sales revenues	$	1,663		$	502		$	289		$	2,454
Changes associated with prices	445			(37		)	56			464
Changes associated with sales volumes	19			(218		)	(53		)	(252		)
2018 sales revenues	$	2,127		$	247		$	292		$	2,666
Increase (decrease) vs. 2017	28		%	(51		)%	1		%	9		%

The above table illustrates the effects of changes in prices and sales volumes. The changes in sales volumes 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 months ended March 31:

	2018	Inc (Dec)   vs. 2017		2017
Barrels of Oil Equivalent
(MMBOE except percentages)
United States	50	(20	)%	62
International	8	(16	)	10
Total barrels of oil equivalent	58	(19	)	72
Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States	555	(20	)%	691
International	88	(16	)	104
Total barrels of oil equivalent per day	643	(19	)	795

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.

40

Oil Sales Revenues, Average Prices, and Volumes

	Three Months Ended   March 31,
	2018		Inc (Dec)   vs. 2017		2017
Oil sales revenues (millions)	$	2,127	28	%	$	1,663
United States
Sales volumes—MMBbls	25		7	%	24
MBbls/d	288		7		269
Price per barrel	$	62.58	27		$	49.23
International
Sales volumes—MMBbls	8		(15	)%	9
MBbls/d	83		(15	)	98
Price per barrel	$	67.39	26		$	53.36
Total
Sales volumes—MMBbls	33		1	%	33
MBbls/d	371		1		367
Price per barrel	$	63.66	26		$	50.34

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 March 31, 2018 vs. 2017	$	464	$	445	$	19

Oil Prices

The average oil price received increased for the three months ended March 31, 2018, primarily due to the expectation of decreasing global oversupply as a result of OPEC’s agreement to reduce production through the end of 2018.

Oil Sales Volumes

2018 vs. 2017  The Company’s oil sales volumes increased by 4 MBbls/d for the three months ended March 31, 2018, primarily due to the following:

U.S. Onshore

• Sales volumes increased for Delaware basin by 21 MBbls/d and for DJ basin by 19 MBbls/d, primarily due to continued drilling and completion activities in 2018.

• Divestitures resulted in a decrease in sales volumes of 25 MBbls/d, primarily related to the sale of the Eagleford and West Chalk assets in the first half of 2017 and the Alaska nonoperated assets in the first quarter of 2018.

International

• Sales volumes for Algeria decreased by 15 MBbls/d, primarily due to a decrease in production driven by statutory maintenance completed on the El Merk facility and timing of liftings.

41

Natural-Gas Sales Revenues, Average Prices, and Volumes

	Three Months Ended   March 31,
	2018		Inc (Dec)   vs. 2017		2017
Natural-gas sales revenues (millions)	$	247	(51	)%	$	502
United States
Sales volumes—Bcf	95		(43	)%	167
MMcf/d	1,051		(43	)	1,859
Price per Mcf	$	2.61	(13	)	$	3.00

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 March 31, 2018 vs. 2017	$	(255	)	$	(37	)	$	(218	)

Natural-Gas Prices

The average natural-gas price received decreased for the three months ended March 31, 2018, primarily due to increased U.S. natural-gas production, partially offset by increased weather-driven residential and commercial demand coupled with an increase in exports to Mexico.

Natural-Gas Sales Volumes

2018 vs. 2017TheCompany’snatural-gassalesvolumesdecreasedby808MMcf/dforthethree months ended March 31, 2018, primarily due to the sale of the Marcellus, Eagleford, West Chalk, and Utah CBM assets in the first half of 2017 and the Moxa assets in the second half of 2017.

42

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

	Three Months Ended   March 31,
	2018		Inc (Dec)   vs. 2017		2017
Natural-gas liquids sales revenues (millions)	$	292	1	%	$	289
Total
Sales volumes—MMBbls (1)	9		(18	)%	11
MBbls/d (1)	97		(18	)	118
Price per barrel	$	33.63	24		$	27.17

 _______________________________________________________________________________

⁽¹⁾  The percentage of total and daily NGLs sales volumes from the U.S. was 95% for the three months ended March 31, 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 March 31, 2018 vs. 2017	$	3	$	56	$	(53	)

NGLs Prices

The average NGLs price received increased for the three months ended March 31, 2018, primarily due to increased ethane and propane prices stemming from higher exports and increased domestic demand.

NGLs Sales Volumes

2018 vs. 2017The Company’s NGLs sales volumes decreased by 21 MBbls/d for the three months ended March 31, 2018, primarily due to the sale of the Eagleford assets in the first quarter of 2017.

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Gathering, Processing, and Marketing

	Three Months Ended   March 31,
millions except percentages	2018		Inc (Dec)   vs. 2017		2017
Gathering, processing, and marketing sales (1)	$	360	(19	)%	$	444
Gathering, processing, and marketing expense (1)	237		(32	)	350
Gathering, processing, and marketing, net	$	123	31		$	94

 __________________________________________________________________

⁽¹⁾  As a result of adopting ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as of January 1, 2018, the change in accounting policy decreased gathering, processing, and marketing sales by $217 million and decreased gathering, processing, and marketing expenses by $214 million for the three months ended March 31, 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 agent is also included. Gathering and processing expense includes the cost of third-party natural gas purchased and processed by Anadarko as well as other operating and transportation 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 marketing activities.

Total gathering, processing, and marketing, net increased by $29 million for the three months ended March 31, 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 higher overall liquid prices and increased throughput volumes at the DJ Basin Complex.

Gains (Losses) on Divestitures and Other, net

	Three Months Ended   March 31,
millions except percentages	2018			Inc (Dec)   vs. 2017		2017
Gains (losses) on divestitures, net	$	(24	)	(103	)%	$	804
Other	43			(34	)	65
Gains (losses) on divestitures and other, net	$	19		(98	)	$	869

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

During the three months ended March 31, 2018 and 2017, Anadarko divested certain non-core U.S. onshore assets. See Note 4—Divestituresin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

44

Costs and Expenses

The following provides Anadarko’s total costs and expenses for three months ended March 31:

millions	2018		2017
Oil and gas operating	$	276	$	256
Oil and gas transportation	196		249
Exploration	168		1,084
Gathering, processing, and marketing (1)	237		350
G&A	278		263
DD&A	990		1,115
Production, property, and other taxes	190		155
Impairments	19		373
Other operating expense	140		22
Total	$	2,494	$	3,867

__________________________________________________________________

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

Oil and Gas Operating and Transportation Expenses

	Three Months Ended   March 31,
	2018		Inc (Dec)   vs. 2017		2017
Oil and gas operating (millions)	$	276	8	%	$	256
Oil and gas operating—per BOE	4.77		33		3.60
Oil and gas transportation (millions)	196		(21	)	249
Oil and gas transportation—per BOE	3.38		(3	)	3.47

Oil and Gas Operating Expense

Oil and gas operating expenses increased by $20 million for the three months ended March 31, 2018, primarily due to the following:

• higher operating costs of $32 million related to increased activity in the DJ and Delaware basins, partially offset by lower expenses of $24 million as a result of U.S. onshore asset divestitures in 2017

• higher operating costs of $14 million, primarily related to increased platform maintenance and workovers in the Gulf of Mexico

The related costs per BOE increased by $1.17 for the three months ended March 31, 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 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 expenses decreased by $53 million, primarily due to U.S. onshore divestitures in 2018 and 2017. Oil and gas transportation expenses per BOE remained relatively flat.

45

Exploration Expense

	Three Months Ended   March 31,
millions	2018		2017
Dry hole expense	$	53	$	476
Impairments of unproved properties	53		537
Geological and geophysical, exploration overhead, and other expense	62		71
Total	$	168	$	1,084

For the three months ended March 31, 2018, total exploration expense decreased by $916 million, primarily related to the following:

Dry Hole Expense

Dry hole expense decreased by $423 million, primarily due to the following:

• The Company expensed exploratory well costs of $49 million in the Gulf of Mexico related to unsuccessful drilling activities in the first quarter of 2018.

• The Company expensed suspended exploratory well costs of $435 million related to the Shenandoah project in the Gulf of Mexico in the first quarter of 2017. See Note 6—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part II, Item 8 of the Form 10-K.

Impairments of Unproved Properties

For further 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   March 31,
millions except percentages	2018		Inc (Dec)   vs. 2017		2017
G&A	$	278	6	%	$	263

G&A increased by $15 million for the three months ended March 31, 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.

46

DD&A Expense

	Three Months Ended   March 31,
millions except percentages	2018		Inc (Dec)   vs. 2017		2017
DD&A	$	990	(11	)%	$	1,115

DD&A expense decreased by $125 million for the three months ended March 31, 2018, primarily due to the following:

• $46 million related to U.S. onshore properties as a result of divestitures in 2018 and 2017

• $43 million related to the DJ and Delaware basins as a result of decreased DD&A rates due to an increase in reserves, partially offset by higher sales volumes

• $24 million related to Ghana as a result of decreased DD&A rates due to an increase in reserves

Impairments

	Three Months Ended   March 31,
millions	2018		2017
Impairments	$	19	$	373

For further discussion related to impairments, 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   March 31,
millions except percentages	2018		Inc (Dec)   vs. 2017	2017
Other operating expense	$	140	NM	$	22

Other operating expense includes contingency accruals, adjustments to estimated early rig termination fees, and surface owner payments.

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Other (Income) Expense

The following provides Anadarko’s other (income) expense for the three months ended March 31:

millions	2018			2017
Interest expense	$	228		$	223
(Gains) losses on derivatives, net (1)	35			(147		)
Other (income) expense, net	(12		)	2
Total	$	251		$	78

__________________________________________________________________

⁽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.

Income Tax Expense (Benefit)

	Three Months Ended   March 31,
millions except percentages	2018			2017
Income tax expense (benefit)	$	126		$	97
Income (loss) before income taxes	300			(178		)
Effective tax rate	42		%	(54		)%

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%. The Company expects to make any necessary adjustments to the provisional income tax estimates related to the adoption of the Tax Reform Legislation 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. Additionally, the Company’s effective tax rate is typically impacted by state income taxes (net of federal benefit), non-deductible Algerian exceptional profits tax for Algerian income tax purposes, net changes in uncertain tax positions, and dispositions of non-deductible goodwill.

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. If the payment is ultimately determined to not be deductible, the Company would be required to repay the tentative refund previously received plus interest, and the Company would be required to reverse the net benefit of $346 million previously recognized in its financial statements.

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.

48

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended   March 31,
millions	2018			2017
Net cash provided by (used in) operating activities	$	1,430		$	1,123
Net cash provided by (used in) investing activities	(1,113		)	1,723
Net cash provided by (used in) financing activities	(1,507		)	(198		)

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 first quarter of 2018, Anadarko paid $1.9 billion to repurchase shares under the $3.0 Billion Share-Repurchase Program and received net proceeds of $371 million from divestitures, primarily related to the sale of the Company’s nonoperated interest in Alaska, which is subject to regulatory approval. As of March 31, 2018, Anadarko had $3.4 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 anticipated operating cash flows will be sufficient to fund the Company’s projected long-term operational and capital programs as well as its quarterly dividends and to fund the retirement of Anadarko’s debt maturing in 2018 and 2019. 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 was $1.4 billion for the three months ended March 31, 2018, $307 million higher compared to the same period of 2017, primarily as a result of higher sales revenues due to the impact of higher commodity prices and a higher oil composition of sales volumes.

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Investing Activities

Capital ExpendituresThe following presents the Company’s capital expenditures for the three months endedMarch 31:

millions	2018		2017
Cash Flows from Investing Activities
Additions to properties and equipment (1)	$	1,547	$	1,194
Adjustments for capital expenditures
Changes in capital accruals	142		58
Other	15		3
Total capital expenditures	$	1,704	$	1,255
Exploration and Production and other capital expenditures	$	1,115	$	945
WES Midstream capital expenditures	327		286
Other Midstream capital expenditures	262		24

 ________________________________________________________________________________________

⁽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 $449 million for the three months ended March 31, 2018. Exploration and Production capital expenditures increased primarily due to higher development costs of $391 million driven by increased drilling and completion activity primarily in the DJ and Delaware basins and Gulf of Mexico. This increase was partially offset by decreased exploration costs of $138 million primarily related to decreased exploration drilling in the Gulf of Mexico and Colombia. Other Midstream capital expenditures increased $238 million due to asset development primarily in the Delaware basin. WES Midstream capital expenditures increased $41 million primarily related to the development of assets in the Delaware and DJ basins.

Divestitures  During the three months ended March 31, 2018, Anadarko received net proceeds of $371 million from divestitures, primarily related to the sale of the Company’s nonoperated interest in Alaska, which is subject to regulatory approval. See Note 4—Divestituresin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

50

Financing Activities

millions except percentages	March 31,   2018			December 31,   2017
Anadarko	$	12,200		$	12,196
WES	4,176			3,465
WGP	28			28
Total debt	$	16,404		$	15,689
Total equity	11,756			13,790
Consolidated debt to total capitalization ratio	58.3		%	53.2		%

Debt Activity

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 March 31, 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 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 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 three months ended March 31, 2018, WES borrowed $260 million under its RCF, which was used for general partnership purposes, and made repayments of $630 million. At March 31, 2018, WES had no outstanding borrowings under its RCF, had outstanding letters of credit of $5 million, had 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 March 31, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 3.88%, 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 March 31, 2018, Anadarko had outstanding borrowings of $9 million of senior amortizing notes associated with the TEUs, $114 million of 7.05% Debentures due May 2018, and $600 million of 8.70% Debentures due March 2019 classified as short-term debt on the Company’s Consolidated Balance Sheet. In addition, WES has a scheduled debt maturity during 2018 of $350 million of 2.600% Senior Notes due August 2018, which was classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2018, as WES has the ability and intent to refinance these obligations using long-term debt.

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, which, if put in whole, will be $930 million at the next put date in October 2018. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2018, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.

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.

51

Equity Transactions  In February 2018, the Company expanded the announced share-repurchase program to $3.0 billion and 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 to repurchase the remaining $1.4 billion under the $3.0 Billion Share-Repurchase Program. The Company received an initial delivery of 19.1 million shares (average price of $58.16 per share) of its common stock, of which $1.1 billion was recorded in treasury stock with the remaining $332 million recorded in paid-in capital. The $3.0 Billion Share-Repurchase Program is expected to be completed in the second quarter of 2018. 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 $127 million during the three months ended March 31, 2018. In February 2018, the Company announced an increase in 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 for the three months ended March 31:

millions	2018		2017
WES distributions to unitholders (excluding Anadarko and WGP) (1)	$	92	$	68
WES distributions to Series A Preferred unitholders (2)	—		15
WGP distributions to unitholders (excluding Anadarko) (3)	22		19

__________________________________________________________________

⁽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 $0.935 per common unit for the first quarter of 2018 (to be paid in May 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 $0.56875 per unit for the first quarter of 2018 (to be paid in May 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.

52

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 53 MMBbls of oil and 146 Bcf of natural gas at March 31, 2018, with a net derivative liability position of $255 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $338 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $307 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 balance of Anadarko’s short-term and long-term debt on the Company’s Consolidated Balance Sheets 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 LIBOR would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.

At March 31, 2018, the Company had a net derivative liability position of $1.2 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by $93 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.

53

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 March 31, 2018.

Changes in Internal Control over Financial Reporting

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

54

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 wholly owned 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.

Anadarko E&P Onshore LLC, a wholly owned subsidiary of the Company, is currently in negotiations with the Pennsylvania Department of Environmental Protection concerning enforcement over a produced water release in Pennsylvania in 2015. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

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

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

Delaware Basin Midstream, LLC, a subsidiary of the Company, is currently in negotiations with the EPA with respect to alleged noncompliance with certain Risk Management Plan regulations under the Clean Air Act at its Ramsey Gas Plant. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

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.

Item 1A.  Risk Factors

There have been no material changes from the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

55

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 first 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)
January 1 - 31, 2018 (2)	6,982,477	$	58.82	6,981,212	$	1,030,085,039
February 1 - 28, 2018 (2)	1,521,555	$	58.82	1,518,778	$	1,440,745,052
March 1 - 31, 2018 (3)	19,362,473	$	58.16	19,054,147	$	—
Total	27,866,505	$	58.36	27,554,137

 ____________________________________________________________

⁽¹⁾  During the first quarter of 2018, (i) 27.6 million shares were purchased under the $3.0 Billion Share-Repurchase Program and (ii) 312 thousand shares were purchased related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans. For additional information, see Note 14—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.

⁽²⁾  In January 2018, the Company entered into an ASR Agreement to repurchase $500 million of the Company’s common stock as part of the $3.0 Billion Share-Repurchase Program and received an initial delivery of 7.0 million shares. The transaction was completed in February 2018, at which time the Company received an additional 1.5 million shares to settle the agreement. The settlement price was determined by the volume-weighted average price of the shares during the term less a negotiated settlement price adjustment. In February 2018, the $3.0 Billion Share-Repurchase Program was expanded from its original announcement by the Company as a $2.5 billion share-repurchase program. 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⁾  In March 2018, the Company entered into an additional ASR Agreement to repurchase the remaining $1.4 billion of the Company’s common stock under the $3.0 Billion Share-Repurchase Program and received an initial delivery of 19.1 million shares, of which $1.1 billion was recorded in treasury stock with the remaining $332 million recorded in paid-in capital. The $3.0 Billion Share-Repurchase Program is expected to be completed in the second quarter of 2018. 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.

56

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
	10	(i)	Third Amendment and Maturity Extension Agreement, dated January 12, 2018, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 16, 2018
		(ii)	Second Amendment to 364-Day Revolving Credit Agreement, dated January 12, 2018, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the additional lenders party thereto, filed as Exhibit 10.2 to Form 8-K filed on January 16, 2018
*		(iii)	Terms and Conditions of Elective Deferred Share Awards for the Anadarko Petroleum Corporation 2008 Director Compensation Plan and the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, each as amended
*	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

57

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)
May 1, 2018	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

58

EX-10.III

Exhibit 10(iii)

Terms and Conditions of Elective Deferred Share Awards

• Grant of Deferred Shares:On the last business day of each quarter during 2018, you will be granted a number of Deferred Shares with a grant date fair value equal to the amount of your quarterly fees you elected to defer for such quarter in the form of Deferred Shares in accordance with your compensation election form (your “Election Form”). You will be provided a quarterly summary of the number of Deferred Shares issued hereunder, which shall be subject to the terms and conditions set forth herein.

• Deferred Shares Generally:Deferred Shares represent a vested contractual right to receive shares of Anadarko Petroleum Corporation (the “Company”) common stock, par value $0.10 per share (“CommonStock”), at the time(s) of settlement specified in your Election Form. Upon grant, the Deferred Shares will not be issued in your name, but will be held by the Company, either in book-entry form or by the Company’s Benefits Trust (the “Trust”) until the time of settlement set forth in your Election Form. Deferred Shares are considered an unsecured obligation of the Company and any and all assets held in the Trust are subject to claims of the general creditors of the Company. Until the issuance of Common Stock in settlement of your Deferred Shares, you will not have rights as a stockholder of the Company.

• Voting Rights: Although you will not have beneficial ownership of the Deferred Shares prior to settlement, to the extent the shares underlying your Deferred Shares are held by the Trust, you may have the opportunity to direct the voting of your Deferred Shares (which voting instructions the Trustee of the Trust may not follow, in its sole discretion) and such Deferred Shares will be counted toward your stock ownership requirements.

• Dividend Equivalents: You will receive a cash payment equal to the cash dividends that are paid on the Company’s common stock each quarter, with such cash amount to be paid within 30 days after the date that such dividends are paid to the Company’s regular stockholders.

• Mandatory Holding Period: Except as expressly set forth in the Election Form, no shares of Common Stock will be issued in settlement of your Deferred Shares prior to the one-year anniversary of the grant of the applicable Deferred Shares.

• Subject to Terms of Plan: Your Deferred Shares are subject to the terms and conditions of the Election Form and, with respect to Deferred Shares awarded on or before May 19, 2018, the Company’s 2008 Director Compensation Plan, and, with respect to Deferred Shares awarded after such date, the Company’s 2012 Omnibus Incentive Compensation Plan. In the event of any conflict between the 2008 Director Compensation Plan or the 2012 Omnibus Incentive Compensation Plan, as applicable, and the Election Form, the 2008 Director Compensation Plan or the 2012 Omnibus Incentive Compensation Plan, as applicable, shall control.

• Payment of Taxes: You are solely responsible for the payment of any taxes associated with the issuance or settlement of Deferred Shares. You acknowledge that the Company has made no representation as to the tax consequences of your Deferred Shares hereunder.

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.

May 1, 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.

May 1, 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 March 31, 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.

May 1, 2018
	/s/ R. A. WALKER
	R. A. Walker
	Chairman, President and Chief Executive Officer
May 1, 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	3 Months Ended
	Mar. 31, 2018	Apr. 30, 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	Mar. 31, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		515,088,252

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues and Other
Oil sales	$ 2,127	$ 1,663
Natural-gas sales	247	502
Natural-gas liquids sales	292	289
Gathering, processing, and marketing sales	360	444
Gains (losses) on divestitures and other, net	19	869
Total	3,045	3,767
Costs and Expenses
Oil and gas operating	276	256
Oil and gas transportation	196	249
Exploration	168	1,084
Gathering, processing, and marketing	237	350
General and administrative	278	263
Depreciation, depletion, and amortization	990	1,115
Production, property, and other taxes	190	155
Impairments	19	373
Other operating expense	140	22
Total	2,494	3,867
Operating Income (Loss)	551	(100)
Other (Income) Expense
Interest expense	228	223
(Gains) losses on derivatives, net	36	(147)
Other (income) expense, net	(12)	2
Total	251	78
Income (Loss) Before Income Taxes	300	(178)
Income tax expense (benefit)	126	97
Net Income (Loss)	174	(275)
Net income (loss) attributable to noncontrolling interests	53	43
Net Income (Loss) Attributable to Common Stockholders	$ 121	$ (318)
Per Common Share
Net income (loss) attributable to common stockholders—basic (in usd per share)	$ 0.23	$ (0.58)
Net income (loss) attributable to common stockholders—diluted (in usd per share)	$ 0.22	$ (0.58)
Average Number of Common Shares Outstanding—Basic	518	551
Average Number of Common Shares Outstanding—Diluted	519	551
Dividends (in usd per share)	$ 0.25	$ 0.05
Commodity Contract and Interest Rate Swap [Member]
Other (Income) Expense
(Gains) losses on derivatives, net	$ 35	$ (147)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 174	$ (275)
Adjustments for derivative instruments
Total adjustments for derivative instruments, net of taxes	1	1
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	0	(4)
Income taxes on net gain (loss) incurred during period	0	1
Amortization of net actuarial (gain) loss to other (income) expense, net	7	9
Income taxes on amortization of net actuarial (gain) loss	(2)	(3)
Amortization of net prior service (credit) cost to other (income) expense, net	(6)	(6)
Income taxes on amortization of net prior service (credit) cost	1	2
Total adjustments for pension and other postretirement plans, net of taxes	0	(1)
Total	1	0
Comprehensive Income (Loss)	175	(275)
Comprehensive income (loss) attributable to noncontrolling interests	53	43
Comprehensive Income (Loss) Attributable to Common Stockholders	$ 122	$ (318)

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents ($524 and $80 related to VIEs)		$ 3,361	$ 4,553
Accounts receivable (net of allowance of $14 and $14)
Customers ($125 and $106 related to VIEs)		1,156	1,222
Others ($13 and $19 related to VIEs)		639	607
Other current assets		374	380
Total		5,530	6,762
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $34,220 and $34,146) ($6,064 and $5,731 related to VIEs)		27,758	27,451
Other Assets ($572 and $579 related to VIEs)		2,134	2,211
Goodwill and Other Intangible Assets ($1,184 and $1,191 related to VIEs)		5,654	5,662
Total Assets		41,076	42,086
Accounts payable
Trade ($331 and $305 related to VIEs)		2,059	1,894
Other		191	266
Short-term debt		761	142
Current asset retirement obligations		286	294
Other current liabilities		1,437	1,310
Total		4,734	3,906
Long-term Debt		15,643	15,547
Other Long-term Liabilities
Deferred income taxes		2,267	2,234
Asset retirement obligations ($147 and $143 related to VIEs)		2,510	2,500
Other		4,166	4,109
Total		8,943	8,843
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 575.2 million and 574.2 million shares issued)		57	57
Paid-in capital		11,701	12,000
Retained earnings		1,152	1,109
Treasury stock (71.3 million and 43.4 million shares)		(3,759)	(2,132)
Accumulated other comprehensive income (loss)		(410)	(338)
Total Stockholders’ Equity		8,741	10,696
Noncontrolling interests		3,015	3,094
Total Equity		11,756	13,790
Total Liabilities and Equity		41,076	42,086
Anadarko [Member]
Accounts payable
Short-term debt	[1]	733	142
Long-term Debt		11,467	12,054
WES and WGP [Member]
Accounts payable
Short-term debt		28	0
Long-term Debt		$ 4,176	$ 3,493

[1] Excludes WES and WGP.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 3,361	$ 4,553
Accounts receivable
Allowance for uncollectible accounts	14	14
Customers	1,156	1,222
Others	639	607
Property, Plant and Equipment, Net [Abstract]
Net properties and equipment related to VIEs	27,758	27,451
Accumulated depreciation, depletion and amortization	34,220	34,146
Other Assets	2,134	2,211
Goodwill and Other Intangible Assets	5,654	5,662
Accounts payable
Trade	2,059	1,894
Other Long-term Liabilities
Asset retirement obligations	$ 2,510	$ 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	575,200,000	574,200,000
Treasury stock, shares	71,300,000	43,400,000
Variable Interest Entity, Primary Beneficiary [Member]
Current Assets
Cash and cash equivalents	$ 524	$ 80
Accounts receivable
Customers	125	106
Others	13	19
Property, Plant and Equipment, Net [Abstract]
Net properties and equipment related to VIEs	6,064	5,731
Other Assets	572	579
Goodwill and Other Intangible Assets	1,184	1,191
Accounts payable
Trade	331	305
Other Long-term Liabilities
Asset retirement obligations	$ 147	$ 143

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CONSOLIDATED STATEMENT OF EQUITY - 3 months ended Mar. 31, 2018 - USD ($) $ in Millions		Total	Common Stock [Member]	Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Subsidiary Equity Transactions [Member]	Subsidiary Equity Transactions [Member] Paid-in Capital [Member]	Subsidiary Equity Transactions [Member] Noncontrolling Interests [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)		174			121			53
Share-based compensation expense		39		39
Dividends—common stock		(127)			(127)
Repurchases of common stock		(1,959)		(332)		(1,627)
Subsidiary equity transactions									$ 3	$ (6)	$ 9
Distributions to noncontrolling interest owners		(118)						(118)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net		1					1
Balance at Mar. 31, 2018		11,756	$ 57	$ 11,701	1,152	$ (3,759)	(410)	3,015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect of accounting change (1)	[1]	$ (47)			$ 49		$ (73)	$ (23)

[1] 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, beginning January 1, 2018; 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	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Flows from Operating Activities
Net income (loss)	$ 174	$ (275)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	990	1,115
Deferred income taxes	42	(660)
Dry hole expense and impairments of unproved properties	106	1,012
Impairments	19	373
(Gains) losses on divestitures, net	24	(804)
Total (gains) losses on derivatives, net	36	(147)
Operating portion of net cash received (paid) in settlement of derivative instruments	(63)	(8)
Other	74	83
Changes in assets and liabilities
(Increase) decrease in accounts receivable	23	68
Increase (decrease) in accounts payable and other current liabilities	45	395
Other items, net	(40)	(29)
Net cash provided by (used in) operating activities	1,430	1,123
Cash Flows from Investing Activities
Additions to properties and equipment	(1,547)	(1,194)
Divestitures of properties and equipment and other assets	371	2,851
Other, net	63	66
Net cash provided by (used in) investing activities	(1,113)	1,723
Cash Flows from Financing Activities
Borrowings, net of issuance costs	1,333	0
Repayments of debt	(639)	(10)
Financing portion of net cash received (paid) for derivative instruments	54	(37)
Increase (decrease) in outstanding checks	(26)	28
Dividends paid	(127)	(28)
Repurchases of common stock	(1,959)	(21)
Distributions to noncontrolling interest owners	(118)	(105)
Payments of future hard-minerals royalty revenues conveyed	(25)	(25)
Net cash provided by (used in) financing activities	(1,507)	(198)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents	0	3
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	(1,190)	2,651
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	$ 3,484	$ 5,959

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 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 $10 million for the three months ended March 31, 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. Refer to 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, and these fees are recognized to 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 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 liabilities and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko is implementing new accounting software and continuing to evaluate its systems, processes, and internal controls during 2018. The Company will adopt this ASU on January 1, 2019, using a modified retrospective approach for all comparative periods presented according to the ASU as it is currently written.

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Revenue from Contracts with Customers

3 Months Ended

Mar. 31, 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. Refer to Note 1—Summary of Significant Accounting Policies for additional information. The primary impacts of the Company’s change in accounting policy for revenue recognition effective January 1, 2018, are detailed below.

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 will decrease for contracts where the Company is acting as an agent for its processing customer in the sale of processed volumes and increase 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 will not impact net earnings.

Impacts on Financial Statements The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements for the three months ended March 31, 2018, as described in the Change in Accounting Policy section above:

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 March 31, 2018
Revenues
Gathering, processing, and marketing sales	$	360	$	577	$	(217	)
Gains (losses) on divestitures and other, net	19		21		(2		)
Expenses
Gathering, processing, and marketing	237		451		(214		)
Income tax expense (benefit)	126		127		(1		)
Net income (loss) attributable to noncontrolling interests	53		54		(1		)
Net Income (Loss) Attributable to Common Stockholders	$	121	$	124	$	(3	)

CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
March 31, 2018
Assets
Net properties and equipment	$	27,758	$	27,715	$	43
Other assets	2,134		2,122		12
Liabilities
Other current liabilities	1,437		1,434		3
Deferred income taxes	2,267		2,274		(7		)
Other	4,166		4,056		110
Equity
Total equity	11,756		11,807		(51		)

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 March 31, 2018
Product Type
Oil sales	$	2,127		$	—		$	—	$	—		$	2,127
Natural-gas sales	247			—			—		—			247
Natural-gas liquids sales	292			—			—		—			292
Gathering, processing, and marketing sales(1)	—			438			86		24			548
Other, net	3			—			—		19			22
Total Revenue from Customers	$	2,669		$	438		$	86	$	43		$	3,236
Gathering, processing, and marketing sales(2)	—			(1		)	2		(189		)	(188		)
Gains (losses) on divestitures, net	(33		)	—			9		—			(24		)
Other, net	(12		)	29			10		(6		)	21
Total Revenue from Other than Customers	$	(45	)	$	28		$	21	$	(195	)	$	(191	)
Total Revenue and Other	$	2,624		$	466		$	107	$	(152	)	$	3,045

 __________________________________________________________________

⁽¹⁾  The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $224 million and intercompany eliminations of $(196) million.

⁽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.

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 to 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	40
Decrease due to revenue recognized	(12		)
Balance at March 31, 2018	$	163
Contract liabilities at March 31, 2018
Other current liabilities	$	39
Other long-term liabilities - other	124
Total contract liabilities from contracts with customers	$	163

2. Revenue from Contracts with Customers(Continued)

Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of March 31, 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	$	74	$	268	$	38	$	(167	)	$	213
2019	102		440		74		(327		)	289
2020	103		496		87		(394		)	292
2021	103		470		94		(395		)	272
2022	7		461		98		(394		)	172
Thereafter	62		1,698		194		(1,321		)	633
Total	$	451	$	3,833	$	585	$	(2,998	)	$	1,871

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Inventories

3 Months Ended

Mar. 31, 2018

Energy Related Inventory [Abstract]

Inventories

3. Inventories

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

millions	March 31,   2018		December 31,   2017
Oil	$	184	$	165
Natural gas	8		29
NGLs	117		122
Total inventories	$	309	$	316

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Divestitures

3 Months Ended

Mar. 31, 2018

Property, Plant and Equipment [Abstract]

Divestitures

4. Divestitures

Divestitures  The following summarizes the proceeds received and gains (losses) recognized on divestitures for the three months ended March 31:

millions	2018			2017
Proceeds received, net of closing adjustments	$	371		$	2,851
Gains (losses) on divestitures, net (1)	(24		)	804

__________________________________________________________________

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

2018During the three months ended March 31, 2018, the Company divested of the following assets:

• Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $383 million and net losses of $30 million in 2018 and $154 million in the fourth quarter of 2017. As this transaction is subject to regulatory approval, the Company recognized a contingent liability, which is presented net with the related assets, equal to the net proceeds received from the buyer.

2017During the three months ended March 31, 2017, the Company divested of the following 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 $726 million.

• Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $763 million and net losses of $44 million in 2017 and $129 million in the fourth quarter of 2016.

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. After the acquisition, the DBJV System is 100% owned by WES and consolidated by Anadarko.

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Impairments

3 Months Ended

Mar. 31, 2018

Asset Impairment Charges [Abstract]

Impairments

5. Impairments

Impairments of Long-Lived Assets Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:

	Three Months Ended
millions	Impairment		Fair Value (1)
March 31, 2018
Exploration and Production
Gulf of Mexico properties	$	19	$	—
Total	$	19	$	—
March 31, 2017
Exploration and Production
Gulf of Mexico properties	$	204	$	231
WES Midstream	168		49
Other Midstream	1		—
Total	$	373	$	280

__________________________________________________________________

⁽¹⁾  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 during the three months ended March 31, 2017, were primarily related to oil and gas properties in the Gulf of Mexico due to lower forecasted commodity prices and a U.S. onshore midstream property due to a reduced throughput fee as a result of a producer’s bankruptcy.

Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. The Company recognized $532 million of impairments of unproved Gulf of Mexico properties during the three months ended March 31, 2017, of which $467 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

3 Months Ended

Mar. 31, 2018

Capitalized Exploratory Well Costs [Abstract]

Exploratory Well Costs

6. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $539 million at March 31, 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 three months ended March 31, 2018,no charges were booked to exploration expense for suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017.

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Current Liabilities

3 Months Ended

Mar. 31, 2018

Payables and Accruals [Abstract]

Current Liabilities

7. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $193 million at March 31, 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:

millions	March 31,   2018		December 31,   2017
Accrued income taxes	$	54	$	71
Interest payable	167		246
Production, property, and other taxes payable	276		216
Accrued employee benefits	140		210
Derivatives	460		384
Other	340		183
Total other current liabilities	$	1,437	$	1,310

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Derivative Instruments

3 Months Ended

Mar. 31, 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 (Marketing and Trading Derivative Activities).

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 March 31, 2018:

	2018 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
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)	256
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.

At March 31, 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 the potential refinancing of the Company’s future debt maturities. 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 March 31, 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%
$	200	September 2017 - 2047	September 2018	6.049%
$	100	September 2017 - 2047	September 2020	6.891%
$	250	September 2017 - 2047	September 2021	6.570%
$	250	September 2017 - 2047	September 2023	6.761%

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 $46 million during the three months ended March 31, 2018, and $24 million during the three months ended March 31, 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	March 31,		December 31,		March 31,			December 31,
Balance Sheet Classification	2018		2017		2018			2017
Commodity derivatives
Other current assets	$	6	$	7	$	—		$	(1	)
Other assets	1		2		—			—
Other current liabilities	31		45		(292		)	(206		)
Other liabilities	—		—		(1		)	(2		)
	38		54		(293		)	(209		)
Interest-rate derivatives
Other current assets	17		14		—			—
Other assets	47		40		—			—
Other current liabilities	—		—		(211		)	(236		)
Other liabilities	—		—		(1,045		)	(1,183		)
	64		54		(1,256		)	(1,419		)
Total derivatives	$	102	$	108	$	(1,549	)	$	(1,628	)

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

millions	Three Months Ended   March 31,
Classification of (Gain) Loss Recognized	2018			2017
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	1		$	—
(Gains) losses on derivatives, net	162			(135		)
Interest-rate derivatives
(Gains) losses on derivatives, net	(127		)	(12		)
Total (gains) losses on derivatives, net	$	36		$	(147	)

__________________________________________________________________

⁽¹⁾  Represents the effect of Marketing and Trading Derivative Activities.

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 March 31, 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. For example, based on the derivative positions as of March 31, 2018, if Anadarko’s credit rating were to be downgraded one level by either S&P or Moody’s, the Company would be required to post additional collateral of up to approximately $60 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 $69 million of collateral) at March 31, 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
March 31, 2018
Assets
Commodity derivatives	$	—		$	38		$	—	$	(31	)	$	—		$	7
Interest-rate derivatives	—			64			—		—			—			64
Total derivative assets	$	—		$	102		$	—	$	(31	)	$	—		$	71
Liabilities
Commodity derivatives	$	—		$	(293	)	$	—	$	31		$	7		$	(255	)
Interest-rate derivatives	—			(1,256		)	—		—			69			(1,187		)
Total derivative liabilities	$	—		$	(1,549	)	$	—	$	31		$	76		$	(1,442	)
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

3 Months Ended

Mar. 31, 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 is comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification.

Equity ComponentUnless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver not more than 0.8862 WGP common units and not less than 0.7383 WGP common units (or a computed number of APC shares) per TEU on the settlement date, subject to adjustment, at the settlement rate based upon the applicable market value of WGP common units (or APC shares).

Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. The senior amortizing notes have a final installment payment date of June 7, 2018, and are senior unsecured obligations of the Company. For activity related to the senior amortizing notes, see Note 10—Debt.

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Debt

3 Months Ended

Mar. 31, 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 three months ended March 31, 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
Borrowings	260			—		—			260			WES RCF
Repayments	(630		)	—		—			(630		)	WES RCF
	—			—		(8		)	(8		)	TEUs - senior amortizing notes
Other, net	—			—		13			13			Amortization of discounts, premiums, and debt issuance costs
Balance at March 31, 2018	$	4,176		$	28	$	11,970		$	16,174

__________________________________________________________________

⁽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
March 31, 2018
Total borrowings at face value	$	4,220		$	28	$	13,506		$	17,754
Net unamortized discounts, premiums, and debt issuance costs (3)	(44		)	—		(1,536		)	(1,580		)
Total borrowings (4)	4,176			28		11,970			16,174
Capital lease obligations	—			—		230			230
Less short-term debt	—			28		733			761
Total long-term debt	$	4,176		$	—	$	11,467		$	15,643
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 $18.1 billion at March 31, 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 March 31, 2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

At March 31, 2018, Anadarko had outstanding borrowings of $9 million of senior amortizing notes associated with the TEUs, $114 million of 7.05% Debentures due May 2018, and $600 million of 8.70% Debentures due March 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, which, if put in whole, will be $930 million at the next put date in October 2018. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2018, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.

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 three months ended March 31, 2018, WES borrowed $260 million under its RCF, which was used for general partnership purposes, and made repayments of $630 million. At March 31, 2018, WES had no outstanding borrowings under its RCF, had outstanding letters of credit of $5 million, had available borrowing capacity of $1.495 billion, and was in compliance with all covenants. WES’s $350 million2.600% Senior Notes due August 2018 were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2018, as WES has the ability and intent to refinance these obligations using long-term debt.

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 the remaining net proceeds were used 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 March 31, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 3.88%, classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $7 million. At March 31, 2018, WGP was in compliance with all covenants.

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Income Taxes

3 Months Ended

Mar. 31, 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%. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation and record any necessary adjustments to provisional tax amounts 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   March 31,
millions except percentages	2018			2017
Current income tax expense (benefit)	$	90		$	762
Deferred income tax expense (benefit)	36			(665		)
Total income tax expense (benefit)	$	126		$	97
Income (loss) before income taxes	300			(178		)
Effective tax rate	42		%	(54		)%

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 increase from the U.S. federal statutory rate of 21% for the three months ended March 31, 2018, was primarily attributable to the following:

• state taxes, net of federal benefits

• tax impact from foreign operations

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

• net changes in uncertain tax positions

These increases were partially offset by income attributable to noncontrolling interests.

The Company reported a loss before income taxes for the three months ended March 31, 2017. As a result, items that ordinarily increase or decrease tax rate will have the opposite effect. The decrease from the U.S. federal statutory rate of 35% for the three months ended March 31, 2017, was primarily attributable to the following decreases:

• state taxes, net of federal benefit

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

• tax impact from foreign operations

• net changes in uncertain tax positions

• tax deficiency related to share-based compensation due to the adoption of ASU 2016-09

These decreases were partially offset by the following increases:

• income attributable to noncontrolling interests

• federal manufacturing deduction

11. Income Taxes (Continued)

The Company recognized a net tax benefit of $346 million as of March 31, 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 March 31, 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. The Company disagrees and plans to defend its tax position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company defends its tax position through the appeals process and other available avenues. The Company could be required to repay all or a portion of the tentative refund received with interest prior to determining the final outcome of its position either upon IRS request or litigation of the matter in District or Federal Claims Court. If the payment is ultimately determined not to be deductible, the Company would be required to repay the tentative refund received plus interest and reverse the net benefit of $346 million previously recognized in its consolidated financial statements.

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Contingencies

3 Months Ended

Mar. 31, 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

3 Months Ended

Mar. 31, 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 March 31
Service cost	$	23		$	21		$	—		$	—
Interest cost	19			21			3			3
Expected (return) loss on plan assets	(21		)	(21		)	—			—
Amortization of net actuarial loss (gain)	7			6			—			—
Amortization of net prior service cost (credit)	—			—			(6		)	(6		)
Settlement expense	—			3			—			—
Termination benefits expense	—			4			—			—
Net periodic benefit cost (1)	$	28		$	34		$	(3	)	$	(3	)

__________________________________________________________________

⁽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 $46 million to funded pension plans and $16 million to unfunded pension plans during the three months ended March 31, 2018. The Company expects to contribute an additional $116 million to funded pension plans and $14 million to unfunded pension plans during 2018.

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Stockholders' Equity

3 Months Ended

Mar. 31, 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.

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

	Three Months Ended   March 31,
millions except per-share amounts	2018			2017
Net income (loss)
Net income (loss) attributable to common stockholders	$	121		$	(318	)
Income (loss) effect of TEUs	(3		)	(2		)
Less distributions on participating securities	1			—
Basic	$	117		$	(320	)
Income (loss) effect of TEUs	(1		)	—
Diluted	$	116		$	(320	)
Shares
Average number of common shares outstanding—basic	518			551
Dilutive effect of stock options	1			—
Average number of common shares outstanding—diluted	519			551
Excluded due to anti-dilutive effect	10			11
Net income (loss) per common share
Basic	$	0.23		$	(0.58	)
Diluted	$	0.22		$	(0.58	)

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 ($3.0 Billion Share-Repurchase Program). The program authorizes the repurchase of the Company’s common stock in the open market or through private transactions through the end of 2018. In February 2018, Anadarko 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. All of the repurchased shares were classified as treasury stock.

In March 2018, Anadarko entered into an additional ASR Agreement to repurchase the remaining $1.4 billion of the Company’s common stock under the $3.0 Billion Share-Repurchase Program. Under the terms of the agreement, the Company paid $1.4 billion in cash and received an initial delivery of 19.1 million 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 value of the initial 19.1 million shares delivered on the date of purchase was $1.1 billion (average price of $58.16 per share) and was recorded in treasury stock, with the remaining $332 million recorded in paid-in capital on the Company’s Consolidated Balance Sheet at March 31, 2018. The final number of shares to be delivered upon settlement of this ASR Agreement will be determined in the second quarter of 2018 with reference to the volume-weighted average price of the shares during the term of the agreement less a negotiated settlement price adjustment. The value recorded in paid-in capital at March 31, 2018, will be transferred to treasury stock upon final settlement. The $3.0 Billion Share-Repurchase Program is expected to be completed in the second quarter of 2018.

These transactions were accounted for as equity transactions. For shares received and recorded as treasury stock, these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS.

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Noncontrolling Interests

3 Months Ended

Mar. 31, 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 261 thousand Class C units to Anadarko during the three months ended March 31, 2018, and 886 thousand Class C units to Anadarko during 2017.

WGP is a limited partnership formed by Anadarko to own interests in WES. At March 31, 2018, Anadarko’s ownership interest in WGP consisted of an 81.6% limited partner interest and the entire non-economic general partner interest. The remaining 18.4% limited partner interest in WGP was owned by the public.

At March 31, 2018, WGP’s ownership interest in WES consisted of a 29.7% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At March 31, 2018, Anadarko also owned a 9.2% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.6% limited partner interest in WES was owned by the public.

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Variable Interest Entities

3 Months Ended

Mar. 31, 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 isconsideredtheprimary 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   March 31,
millions	2018			2017
Statement of Operations Data
Total revenues and other	$	437		$	516
Operating income (loss)	187			138
Net income (loss)	150			103
Statement of Cash Flows Data
Net cash provided by (used in) operating activities	$	241		$	192
Net cash provided by (used in) investing activities	(294		)	(252		)
Net cash provided by (used in) financing activities	497			(176		)

millions	March 31,   2018		December 31,   2017
Balance Sheet Data
Cash and cash equivalents	$	524	$	80
Net property, plant, and equipment	6,064		5,731
Total assets	8,816		8,016
Long-term debt	4,176		3,493
Total liabilities	4,967		4,071
Total equity and partners’ capital	3,849		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 March 31, 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 March 31, 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.

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.

16. Variable Interest Entities (Continued)

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 $4 million for each of the three months ended March 31, 2018 and 2017. The note receivable and related interest income are eliminated in consolidation.

In March 2015, WES acquired the Company’s interest in DBJV. The acquisition was financed using a deferred purchase price obligation that required a cash payment from WES to the Company due on March 31, 2020. In May 2017, WES reached an agreement with the Company to settle this obligation whereby WES made a cash payment to the Company of $37 million, equal to the estimated net present value of the obligation at March 31, 2017.

In order 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 has 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 $14 million for the three months ended March 31, 2018, and $12 million for the three months ended March 31, 2017.

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 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:

	Three Months Ended   March 31,
millions	2018			2017
Cash paid (received)
Interest, net of amounts capitalized	$	326		$	308
Income taxes, net of refunds	12			1
Non-cash investing activities
Fair value of properties and equipment acquired	$	2		$	549
Asset retirement cost additions	63			61
Accruals of property, plant, and equipment	965			608
Net liabilities assumed (divested) in acquisitions and divestitures	(25		)	(82		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	7

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:

millions	March 31,   2018		December 31,   2017
Cash and cash equivalents	$	3,361	$	4,553
Restricted cash and restricted cash equivalents included in Other Assets	123		121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	3,484	$	4,674

Included in cash and cash equivalents is restricted cash and restricted cash equivalents of $225 million at March 31, 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

3 Months Ended

Mar. 31, 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’s 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; 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   March 31,
millions	2018			2017
Income (loss) before income taxes	$	300		$	(178	)
Interest expense	228			223
DD&A	990			1,115
Exploration expense	168			1,084
(Gains) losses on divestitures, net	24			(804		)
Impairments	19			373
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(27		)	(155		)
Restructuring charges	—			(1		)
Less net income (loss) attributable to noncontrolling interests	53			43
Consolidated Adjusted EBITDAX	$	1,649		$	1,614

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 March 31, 2018
Sales revenues	$	2,656		$	310	$	36	$	24		$	3,026
Intersegment revenues	10			127		52		(189		)	—
Other	(9		)	29		10		13			43
Total revenues and other (1)	2,657			466		98		(152		)	3,069
Operating costs and expenses (2)	876			194		54		193			1,317
Net cash from settlement of commodity derivatives	—			—		—		68			68
Other (income) expense, net	—			—		—		(12		)	(12		)
Net income (loss) attributable to noncontrolling interests	—			—		—		53			53
Total expenses and other	876			194		54		302			1,426
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		6			6
Adjusted EBITDAX	$	1,781		$	272	$	44	$	(448	)	$	1,649
Three Months Ended March 31, 2017
Sales revenues	$	2,451		$	366	$	36	$	45		$	2,898
Intersegment revenues	3			151		42		(196		)	—
Other	2			30		6		27			65
Total revenues and other (1)	2,456			547		84		(124		)	2,963
Operating costs and expenses (2)	923			292		50		31			1,296
Net cash from settlement of commodity derivatives	—			—		—		6			6
Other (income) expense, net	—			—		—		2			2
Net income (loss) attributable to noncontrolling interests	—			—		—		43			43
Total expenses and other	923			292		50		82			1,347
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		(2		)	(2		)
Adjusted EBITDAX	$	1,533		$	255	$	34	$	(208	)	$	1,614

 __________________________________________________________________

⁽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.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 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 $10 million for the three months ended March 31, 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. Refer to 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, and these fees are recognized to 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 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 liabilities and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko is implementing new accounting software and continuing to evaluate its systems, processes, and internal controls during 2018. The Company will adopt this ASU on January 1, 2019, using a modified retrospective approach for all comparative periods presented according to the ASU as it is currently written.

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Revenue from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 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 for the three months ended March 31, 2018, as described in the Change in Accounting Policy section above:

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 March 31, 2018
Revenues
Gathering, processing, and marketing sales	$	360	$	577	$	(217	)
Gains (losses) on divestitures and other, net	19		21		(2		)
Expenses
Gathering, processing, and marketing	237		451		(214		)
Income tax expense (benefit)	126		127		(1		)
Net income (loss) attributable to noncontrolling interests	53		54		(1		)
Net Income (Loss) Attributable to Common Stockholders	$	121	$	124	$	(3	)

CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
March 31, 2018
Assets
Net properties and equipment	$	27,758	$	27,715	$	43
Other assets	2,134		2,122		12
Liabilities
Other current liabilities	1,437		1,434		3
Deferred income taxes	2,267		2,274		(7		)
Other	4,166		4,056		110
Equity
Total equity	11,756		11,807		(51		)

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 March 31, 2018
Product Type
Oil sales	$	2,127		$	—		$	—	$	—		$	2,127
Natural-gas sales	247			—			—		—			247
Natural-gas liquids sales	292			—			—		—			292
Gathering, processing, and marketing sales(1)	—			438			86		24			548
Other, net	3			—			—		19			22
Total Revenue from Customers	$	2,669		$	438		$	86	$	43		$	3,236
Gathering, processing, and marketing sales(2)	—			(1		)	2		(189		)	(188		)
Gains (losses) on divestitures, net	(33		)	—			9		—			(24		)
Other, net	(12		)	29			10		(6		)	21
Total Revenue from Other than Customers	$	(45	)	$	28		$	21	$	(195	)	$	(191	)
Total Revenue and Other	$	2,624		$	466		$	107	$	(152	)	$	3,045

 __________________________________________________________________

⁽¹⁾  The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $224 million and intercompany eliminations of $(196) million.

⁽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	40
Decrease due to revenue recognized	(12		)
Balance at March 31, 2018	$	163
Contract liabilities at March 31, 2018
Other current liabilities	$	39
Other long-term liabilities - other	124
Total contract liabilities from contracts with customers	$	163

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	$	74	$	268	$	38	$	(167	)	$	213
2019	102		440		74		(327		)	289
2020	103		496		87		(394		)	292
2021	103		470		94		(395		)	272
2022	7		461		98		(394		)	172
Thereafter	62		1,698		194		(1,321		)	633
Total	$	451	$	3,833	$	585	$	(2,998	)	$	1,871

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Inventories (Tables)

3 Months Ended

Mar. 31, 2018

Energy Related Inventory [Abstract]

Inventory Disclosure Table

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

millions	March 31,   2018		December 31,   2017
Oil	$	184	$	165
Natural gas	8		29
NGLs	117		122
Total inventories	$	309	$	316

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Divestitures (Tables)

3 Months Ended

Mar. 31, 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 for the three months ended March 31:

millions	2018			2017
Proceeds received, net of closing adjustments	$	371		$	2,851
Gains (losses) on divestitures, net (1)	(24		)	804

__________________________________________________________________

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

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Impairments (Tables)

3 Months Ended

Mar. 31, 2018

Asset Impairment Charges [Abstract]

Schedule of Impairment Expense

The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:

	Three Months Ended
millions	Impairment		Fair Value (1)
March 31, 2018
Exploration and Production
Gulf of Mexico properties	$	19	$	—
Total	$	19	$	—
March 31, 2017
Exploration and Production
Gulf of Mexico properties	$	204	$	231
WES Midstream	168		49
Other Midstream	1		—
Total	$	373	$	280

__________________________________________________________________

⁽¹⁾  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.

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Current Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Payables and Accruals [Abstract]

Schedule of Other Current Liabilities

The following summarizes the Company’s other current liabilities:

millions	March 31,   2018		December 31,   2017
Accrued income taxes	$	54	$	71
Interest payable	167		246
Production, property, and other taxes payable	276		216
Accrued employee benefits	140		210
Derivatives	460		384
Other	340		183
Total other current liabilities	$	1,437	$	1,310

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2018:

	2018 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
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)	256
Average price per MMBtu (Henry Hub)	$	3.02

The Company had the following outstanding interest-rate swaps at March 31, 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%
$	200	September 2017 - 2047	September 2018	6.049%
$	100	September 2017 - 2047	September 2020	6.891%
$	250	September 2017 - 2047	September 2021	6.570%
$	250	September 2017 - 2047	September 2023	6.761%

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	March 31,		December 31,		March 31,			December 31,
Balance Sheet Classification	2018		2017		2018			2017
Commodity derivatives
Other current assets	$	6	$	7	$	—		$	(1	)
Other assets	1		2		—			—
Other current liabilities	31		45		(292		)	(206		)
Other liabilities	—		—		(1		)	(2		)
	38		54		(293		)	(209		)
Interest-rate derivatives
Other current assets	17		14		—			—
Other assets	47		40		—			—
Other current liabilities	—		—		(211		)	(236		)
Other liabilities	—		—		(1,045		)	(1,183		)
	64		54		(1,256		)	(1,419		)
Total derivatives	$	102	$	108	$	(1,549	)	$	(1,628	)

The following summarizes gains and losses related to derivative instruments:

millions	Three Months Ended   March 31,
Classification of (Gain) Loss Recognized	2018			2017
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	1		$	—
(Gains) losses on derivatives, net	162			(135		)
Interest-rate derivatives
(Gains) losses on derivatives, net	(127		)	(12		)
Total (gains) losses on derivatives, net	$	36		$	(147	)

__________________________________________________________________

⁽¹⁾  Represents the effect of Marketing and Trading Derivative Activities.

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
March 31, 2018
Assets
Commodity derivatives	$	—		$	38		$	—	$	(31	)	$	—		$	7
Interest-rate derivatives	—			64			—		—			—			64
Total derivative assets	$	—		$	102		$	—	$	(31	)	$	—		$	71
Liabilities
Commodity derivatives	$	—		$	(293	)	$	—	$	31		$	7		$	(255	)
Interest-rate derivatives	—			(1,256		)	—		—			69			(1,187		)
Total derivative liabilities	$	—		$	(1,549	)	$	—	$	31		$	76		$	(1,442	)
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)

3 Months Ended

Mar. 31, 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 three months ended March 31, 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
Borrowings	260			—		—			260			WES RCF
Repayments	(630		)	—		—			(630		)	WES RCF
	—			—		(8		)	(8		)	TEUs - senior amortizing notes
Other, net	—			—		13			13			Amortization of discounts, premiums, and debt issuance costs
Balance at March 31, 2018	$	4,176		$	28	$	11,970		$	16,174

__________________________________________________________________

⁽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
March 31, 2018
Total borrowings at face value	$	4,220		$	28	$	13,506		$	17,754
Net unamortized discounts, premiums, and debt issuance costs (3)	(44		)	—		(1,536		)	(1,580		)
Total borrowings (4)	4,176			28		11,970			16,174
Capital lease obligations	—			—		230			230
Less short-term debt	—			28		733			761
Total long-term debt	$	4,176		$	—	$	11,467		$	15,643
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)

3 Months Ended

Mar. 31, 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   March 31,
millions except percentages	2018			2017
Current income tax expense (benefit)	$	90		$	762
Deferred income tax expense (benefit)	36			(665		)
Total income tax expense (benefit)	$	126		$	97
Income (loss) before income taxes	300			(178		)
Effective tax rate	42		%	(54		)%

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Pension Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 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 March 31
Service cost	$	23		$	21		$	—		$	—
Interest cost	19			21			3			3
Expected (return) loss on plan assets	(21		)	(21		)	—			—
Amortization of net actuarial loss (gain)	7			6			—			—
Amortization of net prior service cost (credit)	—			—			(6		)	(6		)
Settlement expense	—			3			—			—
Termination benefits expense	—			4			—			—
Net periodic benefit cost (1)	$	28		$	34		$	(3	)	$	(3	)

__________________________________________________________________

⁽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)

3 Months Ended

Mar. 31, 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   March 31,
millions except per-share amounts	2018			2017
Net income (loss)
Net income (loss) attributable to common stockholders	$	121		$	(318	)
Income (loss) effect of TEUs	(3		)	(2		)
Less distributions on participating securities	1			—
Basic	$	117		$	(320	)
Income (loss) effect of TEUs	(1		)	—
Diluted	$	116		$	(320	)
Shares
Average number of common shares outstanding—basic	518			551
Dilutive effect of stock options	1			—
Average number of common shares outstanding—diluted	519			551
Excluded due to anti-dilutive effect	10			11
Net income (loss) per common share
Basic	$	0.23		$	(0.58	)
Diluted	$	0.22		$	(0.58	)

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Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 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   March 31,
millions	2018			2017
Statement of Operations Data
Total revenues and other	$	437		$	516
Operating income (loss)	187			138
Net income (loss)	150			103
Statement of Cash Flows Data
Net cash provided by (used in) operating activities	$	241		$	192
Net cash provided by (used in) investing activities	(294		)	(252		)
Net cash provided by (used in) financing activities	497			(176		)

millions	March 31,   2018		December 31,   2017
Balance Sheet Data
Cash and cash equivalents	$	524	$	80
Net property, plant, and equipment	6,064		5,731
Total assets	8,816		8,016
Long-term debt	4,176		3,493
Total liabilities	4,967		4,071
Total equity and partners’ capital	3,849		3,945

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 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:

	Three Months Ended   March 31,
millions	2018			2017
Cash paid (received)
Interest, net of amounts capitalized	$	326		$	308
Income taxes, net of refunds	12			1
Non-cash investing activities
Fair value of properties and equipment acquired	$	2		$	549
Asset retirement cost additions	63			61
Accruals of property, plant, and equipment	965			608
Net liabilities assumed (divested) in acquisitions and divestitures	(25		)	(82		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	7

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:

millions	March 31,   2018		December 31,   2017
Cash and cash equivalents	$	3,361	$	4,553
Restricted cash and restricted cash equivalents included in Other Assets	123		121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	3,484	$	4,674

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Segment Information (Tables)

3 Months Ended

Mar. 31, 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   March 31,
millions	2018			2017
Income (loss) before income taxes	$	300		$	(178	)
Interest expense	228			223
DD&A	990			1,115
Exploration expense	168			1,084
(Gains) losses on divestitures, net	24			(804		)
Impairments	19			373
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(27		)	(155		)
Restructuring charges	—			(1		)
Less net income (loss) attributable to noncontrolling interests	53			43
Consolidated Adjusted EBITDAX	$	1,649		$	1,614

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 March 31, 2018
Sales revenues	$	2,656		$	310	$	36	$	24		$	3,026
Intersegment revenues	10			127		52		(189		)	—
Other	(9		)	29		10		13			43
Total revenues and other (1)	2,657			466		98		(152		)	3,069
Operating costs and expenses (2)	876			194		54		193			1,317
Net cash from settlement of commodity derivatives	—			—		—		68			68
Other (income) expense, net	—			—		—		(12		)	(12		)
Net income (loss) attributable to noncontrolling interests	—			—		—		53			53
Total expenses and other	876			194		54		302			1,426
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		6			6
Adjusted EBITDAX	$	1,781		$	272	$	44	$	(448	)	$	1,649
Three Months Ended March 31, 2017
Sales revenues	$	2,451		$	366	$	36	$	45		$	2,898
Intersegment revenues	3			151		42		(196		)	—
Other	2			30		6		27			65
Total revenues and other (1)	2,456			547		84		(124		)	2,963
Operating costs and expenses (2)	923			292		50		31			1,296
Net cash from settlement of commodity derivatives	—			—		—		6			6
Other (income) expense, net	—			—		—		2			2
Net income (loss) attributable to noncontrolling interests	—			—		—		43			43
Total expenses and other	923			292		50		82			1,347
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		(2		)	(2		)
Adjusted EBITDAX	$	1,533		$	255	$	34	$	(208	)	$	1,614

 __________________________________________________________________

⁽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.

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Summary of Significant Accounting Policies (Detail) - USD ($) $ in Millions			3 Months Ended		12 Months Ended
		Jan. 01, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change (1)	[1]		$ (47)
Accounting Standards Update 2014-09 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change (1)		$ (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				$ (10)	$ (107)
WES Midstream and Other Midstream [Member] | Minimum [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract term			5 years
WES Midstream and Other Midstream [Member] | Maximum [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract term			10 years

[1] 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, beginning January 1, 2018; see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

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Revenue from Contracts with Customers - Impact on Financial Statements (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Revenues
Gathering, processing, and marketing sales	$ 360	$ 444
Gains (losses) on divestitures and other, net	19	869
Expenses
Gathering, processing, and marketing	237	350
Income tax expense (benefit)	126	97
Net income (loss) attributable to noncontrolling interests	53	43
Net income (loss) attributable to common stockholders	121	$ (318)
Assets
Net properties and equipment	27,758		$ 27,451
Other Assets	2,134		2,211
Liabilities
Other current liabilities	1,437		1,310
Deferred income taxes	2,267		2,234
Other	4,166		4,109
Equity
Total equity	11,756		$ 13,790
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member]
Revenues
Gathering, processing, and marketing sales	577
Gains (losses) on divestitures and other, net	21
Expenses
Gathering, processing, and marketing	451
Income tax expense (benefit)	127
Net income (loss) attributable to noncontrolling interests	54
Net income (loss) attributable to common stockholders	124
Assets
Net properties and equipment	27,715
Other Assets	2,122
Liabilities
Other current liabilities	1,434
Deferred income taxes	2,274
Other	4,056
Equity
Total equity	11,807
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/ (Decrease) [Member]
Revenues
Gathering, processing, and marketing sales	(217)
Gains (losses) on divestitures and other, net	(2)
Expenses
Gathering, processing, and marketing	(214)
Income tax expense (benefit)	(1)
Net income (loss) attributable to noncontrolling interests	(1)
Net income (loss) attributable to common stockholders	(3)
Assets
Net properties and equipment	43
Other Assets	12
Liabilities
Other current liabilities	3
Deferred income taxes	(7)
Other	110
Equity
Total equity	$ (51)

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Revenue from Contracts with Customers - Disaggregation of Revenue (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues from Customers		$ 3,236
Revenue from Other than Customers		(191)
Total		3,045	$ 3,767
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		2,127
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		247
Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		292
Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	548
Revenue from Other than Customers	[2]	(188)
Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		(24)
Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		22
Revenue from Other than Customers		21
Operating Segments [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		2,669
Revenue from Other than Customers		(45)
Total		2,624
Operating Segments [Member] | Exploration and Production [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		2,127
Operating Segments [Member] | Exploration and Production [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		247
Operating Segments [Member] | Exploration and Production [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		292
Operating Segments [Member] | Exploration and Production [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	0
Revenue from Other than Customers	[2]	0
Operating Segments [Member] | Exploration and Production [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		(33)
Operating Segments [Member] | Exploration and Production [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		3
Revenue from Other than Customers		(12)
Operating Segments [Member] | WES Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		438
Revenue from Other than Customers		28
Total		466
Operating Segments [Member] | WES Midstream [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Operating Segments [Member] | WES Midstream [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Operating Segments [Member] | WES Midstream [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Operating Segments [Member] | WES Midstream [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	438
Revenue from Other than Customers	[2]	(1)
Operating Segments [Member] | WES Midstream [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		0
Operating Segments [Member] | WES Midstream [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Revenue from Other than Customers		29
Operating Segments [Member] | Other Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		86
Revenue from Other than Customers		21
Total		107
Operating Segments [Member] | Other Midstream [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Operating Segments [Member] | Other Midstream [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Operating Segments [Member] | Other Midstream [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Operating Segments [Member] | Other Midstream [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	86
Revenue from Other than Customers	[2]	2
Operating Segments [Member] | Other Midstream [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		9
Operating Segments [Member] | Other Midstream [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Revenue from Other than Customers		10
Other and Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		43
Revenue from Other than Customers		(195)
Total		(152)
Other and Intersegment Eliminations [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Other and Intersegment Eliminations [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Other and Intersegment Eliminations [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Other and Intersegment Eliminations [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	24
Revenue from Other than Customers	[2]	(189)
Third-party marketing revenue		224
Intercompany eliminations		(196)
Other and Intersegment Eliminations [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		0
Other and Intersegment Eliminations [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		19
Revenue from Other than Customers		$ (6)

[1] The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $224 million and intercompany eliminations of $(196) million.

[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.

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Revenue from Contracts with Customers - Contract Liabilities (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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	40
Decrease due to revenue recognized	(12)
Balance at March 31, 2018	163
Contract liabilities at March 31, 2018
Other current liabilities		$ 39
Other long-term liabilities - other		124
Total contract liabilities from contracts with customers	$ 37	$ 163

XML

Revenue from Contracts with Customers - Revenue Recognition Expected (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 213
Performance obligation expected to be satisfied, expected timing	9 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	$ 289
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	$ 292
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	$ 272
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	$ 172
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	$ 633
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	1,871
Operating Segments [Member] | Exploration and Production [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 74
Performance obligation expected to be satisfied, expected timing	9 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	$ 102
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	$ 62
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	451
Operating Segments [Member] | WES Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 268
Performance obligation expected to be satisfied, expected timing	9 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	$ 440
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	$ 496
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	$ 470
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	$ 461
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	$ 1,698
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	3,833
Operating Segments [Member] | Other Midstream [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 38
Performance obligation expected to be satisfied, expected timing	9 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	$ 74
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	$ 87
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	$ 94
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	$ 98
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	$ 194
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	585
Other and Intersegment Eliminations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (167)
Performance obligation expected to be satisfied, expected timing	9 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	$ (327)
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	$ (394)
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	$ (395)
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	$ (394)
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	$ (1,321)
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	$ (2,998)

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Inventories (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Energy Related Inventory [Abstract]
Oil	$ 184	$ 165
Natural gas	8	29
NGLs	117	122
Total inventories	$ 309	$ 316

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Divestitures - Divestitures and Assets Held for Sale (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017		Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures	$ 371		$ 2,851
Gain (loss) on divestitures	24		(804)	[1]
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			(726)
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	383
Gain (loss) on divestitures	$ (30)	$ (154)
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			763
Gain (loss) on divestitures			$ (44)		$ (129)

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

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Divestitures - Property Exchange (Detail) - USD ($) $ in Millions		3 Months Ended
	Mar. 17, 2017	Mar. 31, 2018	Mar. 31, 2017
Nonmonetary Transaction [Line Items]
Cash payment to acquire a third party's interest in the DBJV system		$ 1,547	$ 1,194
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 - Impairments and Fair Values by Segment Table (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Impaired Long Lived Assets Held and Used [Line Items]
Total impairments		$ 19	$ 373
Exploration and Production [Member] | Gulf of Mexico Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		19
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total fair value	[1]	0
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Income Approach Valuation Technique [Member] | Exploration and Production [Member] | Gulf of Mexico Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	$ 0
Assets Impaired During Fiscal Year to Date [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total impairments			373
Assets Impaired During Fiscal Year to Date [Member] | Exploration and Production [Member] | Gulf of Mexico Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use			204
Assets Impaired During Fiscal Year to Date [Member] | WES Midstream [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use			168
Assets Impaired During Fiscal Year to Date [Member] | Other Midstream [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use			1
Assets Impaired During Fiscal Year to Date [Member] | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total fair value	[1]		280
Assets Impaired During Fiscal Year to Date [Member] | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Income Approach Valuation Technique [Member] | Exploration and Production [Member] | Gulf of Mexico Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]		231
Assets Impaired During Fiscal Year to Date [Member] | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Income Approach Valuation Technique [Member] | WES Midstream [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]		49
Assets Impaired During Fiscal Year to Date [Member] | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Income Approach Valuation Technique [Member] | Other Midstream [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]		$ 0

[1] 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.

XML

Impairments - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties	$ 106	$ 1,012
Unproved Gulf of Mexico Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties		532
Unproved Shenandoah Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties		$ 467

XML

Exploratory Well Costs (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Capitalized Exploratory Well Costs [Abstract]
Suspended exploratory well costs	$ 539,000,000	$ 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	Mar. 31, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Outstanding checks in excess of bank account balances	$ 193	$ 219
Other Current Liabilities
Accrued income taxes	54	71
Interest payable	167	246
Production, property, and other taxes payable	276	216
Accrued employee benefits	140	210
Derivatives	460	384
Other	340	183
Total other current liabilities	$ 1,437	$ 1,310

XML

Derivative Instruments - Oil and Natural-Gas Production/Processing Derivative Activities Table (Detail) - Not Designated as Hedging Instrument [Member] MMBTU / d in Thousands	3 Months Ended
	Mar. 31, 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
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	256
Average price per MMBtu or barrel
Average fixed price	3.02

XML

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Derivative [Line Items]
Additional collateral if credit rating downgraded	$ 60
Amount of collateral posted related to derivative instruments with credit-risk-related contingent features	69		$ 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	46	$ 24
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps 1 Through 6 [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] $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
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. 15, 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. 15, 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	$ 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. 15, 2018
Weighted-average interest rate for interest-rate swap	6.049%
Interest-Rate Swap 4 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 100
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. 15, 2020
Weighted-average interest rate for interest-rate swap	6.891%
Interest-Rate Swap 5 [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. 15, 2021
Weighted-average interest rate for interest-rate swap	6.57%
Interest-Rate Swap 6 [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. 15, 2023
Weighted-average interest rate for interest-rate swap	6.761%

XML

Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 102	$ 108
Gross derivative liabilities	(1,549)	(1,628)
Commodity derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	38	54
Gross derivative liabilities	(293)	(209)
Commodity derivatives [Member] | Other current assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	6	7
Gross derivative liabilities	0	(1)
Commodity derivatives [Member] | Other assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	1	2
Gross derivative liabilities	0	0
Commodity derivatives [Member] | Other current liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	31	45
Gross derivative liabilities	(292)	(206)
Commodity derivatives [Member] | Other liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	(1)	(2)
Interest-rate derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	64	54
Gross derivative liabilities	(1,256)	(1,419)
Interest-rate derivatives [Member] | Other current assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	17	14
Gross derivative liabilities	0	0
Interest-rate derivatives [Member] | Other assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	47	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	(211)	(236)
Interest-rate derivatives [Member] | Other liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	$ (1,045)	$ (1,183)

XML

Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ 36	$ (147)
Commodity derivatives [Member] | Gathering, processing, and marketing sales [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	[1]	1	0
Commodity derivatives [Member] | (Gains) losses on derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		162	(135)
Interest-rate derivatives [Member] | (Gains) losses on derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ (127)	$ (12)

[1] Represents the

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Derivative Instruments - Fair Value Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		$ 102	$ 108
Gross derivative liabilities		(1,549)	(1,628)
Derivative assets Netting	[1]	(31)	(46)
Derivative liabilities Netting	[1]	31	46
Derivative assets, Collateral		0	(1)
Derivative liabilities, Collateral		76	173
Derivative assets		71	61
Derivative liabilities		(1,442)	(1,409)
Commodity derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		38	54
Gross derivative liabilities		(293)	(209)
Derivative assets Netting	[1]	(31)	(46)
Derivative liabilities Netting	[1]	31	46
Derivative assets, Collateral		0	(1)
Derivative liabilities, Collateral		7	3
Derivative assets		7	7
Derivative liabilities		(255)	(160)
Interest-rate derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		64	54
Gross derivative liabilities		(1,256)	(1,419)
Derivative assets Netting	[1]	0	0
Derivative liabilities Netting	[1]	0	0
Derivative assets, Collateral		0	0
Derivative liabilities, Collateral		69	170
Derivative assets		64	54
Derivative liabilities		(1,187)	(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		102	107
Gross derivative liabilities		(1,549)	(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		38	53
Gross derivative liabilities		(293)	(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		64	54
Gross derivative liabilities		(1,256)	(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	3 Months Ended
	Jun. 30, 2015 USD ($) $ / unit shares	Mar. 31, 2018 unit $ / unit
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%
Debt instrument, maturity date		Jun. 07, 2018
7.50% Tangible Equity Units [Member]
Tangible Equity Units [Line Items]
Number of tangible equity units issued | shares	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]
Tangible Equity Units [Line Items]
Purchase contract, mandatory settlement date		Jun. 07, 2018
Less Than Reference Price [Member] | Equity Component of 7.50% Tangible Equity Units [Member] | Settled in WGP Common Units [Member]
Tangible Equity Units [Line Items]
Maximum settlement rate | unit		0.8862
Exceeds Threshold Appreciation Price [Member] | Equity Component of 7.50% Tangible Equity Units [Member] | Settled in WGP Common Units [Member]
Tangible Equity Units [Line Items]
Minimum settlement rate | unit		0.7383

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Debt - Debt Activity Table (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	$ 15,458	[1]
Other, net	13
Balance at March 31, 2018	16,174	[1]
Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	3,465	[1]
Balance at March 31, 2018	4,176	[1]
Western Gas Equity Partners, LP excluding WES [Member]
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	28	[1],[2]
Balance at March 31, 2018	28	[1],[2]
Anadarko excluding WES and WGP [Member]
Changes in Debt Outstanding [Roll Forward]
Balance at December 31, 2017	11,965	[1],[3]
Other, net	13	[3]
Balance at March 31, 2018	11,970	[1],[3]
WES RCF [Member]
Changes in Debt Outstanding [Roll Forward]
Borrowings, credit facility	260
Repayments, credit facility	(630)
WES RCF [Member] | Western Gas Partners, LP [Member]
Changes in Debt Outstanding [Roll Forward]
Borrowings, credit facility	260
Repayments, credit facility	(630)
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%
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%
Debt instrument, maturity date	Mar. 01, 2048
Senior Note Component of 7.50% Tangible Equity Units [Member]
Changes in Debt Outstanding [Roll Forward]
Repayments, senior notes	$ (8)
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	$ (8)	[3]

[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		Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total borrowings at face value		$ 17,754	$ 17,032
Net unamortized discounts, premiums, and debt issuance costs	[1]	(1,580)	(1,574)
Total borrowings	[2]	16,174	15,458
Capital lease obligations		230	231
Less short-term debt		761	142
Total long-term debt		15,643	15,547
Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Total borrowings at face value		4,220	3,490
Net unamortized discounts, premiums, and debt issuance costs	[1]	(44)	(25)
Total borrowings	[2]	4,176	3,465
Capital lease obligations		0	0
Less short-term debt		0	0
Total long-term debt		4,176	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]	13,506	13,514
Net unamortized discounts, premiums, and debt issuance costs	[1],[4]	(1,536)	(1,549)
Total borrowings	[2],[4]	11,970	11,965
Capital lease obligations	[4]	230	231
Less short-term debt	[4]	733	142
Total long-term debt	[4]	$ 11,467	$ 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		3 Months Ended
		Feb. 28, 2018	Jan. 31, 2018	Mar. 31, 2018	Feb. 01, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total borrowings at face value				$ 17,754,000,000		$ 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				260,000,000
Repayments, credit facility				(630,000,000)
Fair Value, Inputs, Level 2 [Member] | Market Approach Valuation Technique [Member]
Debt Instrument [Line Items]
Estimated fair value of total borrowings				18,100,000,000		17,700,000,000
TEUs - senior amortizing notes due 2018 [Member]
Debt Instrument [Line Items]
Outstanding borrowings				$ 9,000,000
Debt instrument, stated interest rate				1.50%
7.05% Debentures due May 2018
Debt Instrument [Line Items]
Outstanding borrowings				$ 114,000,000
Debt instrument, stated interest rate				7.05%
8.70% Debentures due March 2019
Debt Instrument [Line Items]
Outstanding borrowings				$ 600,000,000
Debt instrument, stated interest rate				8.70%
Zero-Coupon Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, earliest call date				Oct. 10, 2018
Zero-Coupon Senior Notes [Member] | Accreted Value at Next Potential Put Date [Member]
Debt Instrument [Line Items]
Debt instrument, accreted value				$ 930,000,000
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				4,220,000,000		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				260,000,000
Repayments, credit facility				(630,000,000)
Letters of credit, outstanding				5,000,000
Line of credit, available borrowing capacity				$ 1,495,000,000
Western Gas Partners, LP [Member] | Senior Notes 3 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate				2.60%
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%
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%
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				3.88%

[1] Excludes WES.

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Income Taxes - Income Tax Expense (Benefit) Table (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Current income tax expense (benefit)	$ 90	$ 762
Deferred income tax expense (benefit)	36	(665)
Total income tax expense (benefit)	126	97
Income (loss) before income taxes	$ 300	$ (178)
Effective tax rate	42.00%	(54.00%)

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Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		12 Months Ended	48 Months Ended	51 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Mar. 31, 2018
Income Tax Disclosure [Line Items]
Income Tax Expense (Benefit)	$ 126	$ 97
Tronox Litigation [Member] | Judicial Ruling [Member]
Income Tax Disclosure [Line Items]
Income Tax Expense (Benefit)				$ (346)	$ (346)
Unrecognized tax benefits	$ 1,200			$ 1,200	$ 1,200
Income tax refunds			$ 881

XML

Pension Plans and Other Postretirement Benefits - Components of Net Periodic Benefit Cost Table (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Pension Benefits [Member]
Components of net periodic benefit cost
Service cost		$ 23	$ 21
Interest cost		19	21
Expected (return) loss on plan assets		(21)	(21)
Amortization of net actuarial loss (gain)		7	6
Amortization of net prior service cost (credit)		0	0
Settlement expense (1)		0	3
Termination benefits expense		0	4
Net periodic benefit cost	[1]	28	34
Other Benefits [Member]
Components of net periodic benefit cost
Service cost		0	0
Interest cost		3	3
Expected (return) loss on plan assets		0	0
Amortization of net actuarial loss (gain)		0	0
Amortization of net prior service cost (credit)		(6)	(6)
Settlement expense (1)		0	0
Termination benefits expense		0	0
Net periodic benefit cost	[1]	$ (3)	$ (3)

[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	3 Months Ended
	Mar. 31, 2018 USD ($)
Funded Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 46
Expected employer contributions in 2018	116
Unfunded Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	16
Expected employer contributions in 2018	$ 14

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Stockholders' Equity - Earnings Per Share Reconciliation (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net income (loss)
Net income (loss) attributable to common stockholders	$ 121	$ (318)
Income (loss) effect of TEUs	(3)	(2)
Less distributions on participating securities	1	0
Basic	117	(320)
Net Income Loss Effect Of Tangible Equity Units Diluted	(1)	0
Diluted	$ 116	$ (320)
Shares
Average number of common shares outstanding—basic	518	551
Dilutive effect of stock options	1	0
Average number of common shares outstanding—diluted	519	551
Excluded due to anti-dilutive effect	10	11
Net income (loss) per common share
Basic (in usd per share)	$ 0.23	$ (0.58)
Diluted (in usd per share)	$ 0.22	$ (0.58)

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Stockholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended
	Mar. 31, 2018	Feb. 28, 2018	Sep. 30, 2017
Equity, Class of Treasury Stock [Line Items]
Authorized share-repurchase program		$ 3,000	$ 2,500
Accelerated Stock Repurchase Program [Member]
Equity, Class of Treasury Stock [Line Items]
Accelerated share repurchase agreement amount	$ 1,400	$ 500
Shares repurchased	19.1	8.5
Price per share repurchased	$ 58.16	$ 58.82
Treasury Stock [Member] | Accelerated Stock Repurchase Program [Member]
Equity, Class of Treasury Stock [Line Items]
Accelerated share repurchase agreement amount	$ 1,100
Paid-in Capital [Member] | Accelerated Stock Repurchase Program [Member]
Equity, Class of Treasury Stock [Line Items]
Accelerated share repurchase agreement amount	$ 332

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Noncontrolling Interests (Detail) - shares shares in Thousands		3 Months Ended	12 Months Ended
	Mar. 01, 2017	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Western Gas Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Public ownership interest in subsidiary		59.60%
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		29.70%
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		9.20%
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		81.60%
Public ownership interest in subsidiary		18.40%
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		261	886

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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		3 Months Ended
	May 31, 2017	May 31, 2008	Mar. 31, 2018	Mar. 31, 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			$ 4	$ 4
Proceeds from settlement of related party obligation	$ 37
Above-market component of swap extensions with Anadarko			$ 14	$ 12

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Variable Interest Entities - Financial Data of WGP (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Statement of Operations Data
Total revenues and other		$ 3,045	$ 3,767
Operating income (loss)		551	(100)
Net Income (Loss)		174	(275)
Statement of Cash Flow Data
Net cash provided by (used in) operating activities		1,430	1,123
Net cash provided by (used in) investing activities		(1,113)	1,723
Net cash provided by (used in) financing activities		(1,507)	(198)
Balance Sheet Data
Cash and cash equivalents		3,361		$ 4,553
Net properties and equipment related to VIEs		27,758		27,451
Total assets		41,076		42,086
Long-term debt		15,643		15,547
Total equity		11,756		13,790
Variable Interest Entity, Primary Beneficiary [Member]
Balance Sheet Data
Cash and cash equivalents		524		80
Net properties and equipment related to VIEs		6,064		5,731
WGP [Member]
Balance Sheet Data
Long-term debt	[1]	0		28
WGP [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Statement of Operations Data
Total revenues and other		437	516
Operating income (loss)		187	138
Net Income (Loss)		150	103
Statement of Cash Flow Data
Net cash provided by (used in) operating activities		241	192
Net cash provided by (used in) investing activities		(294)	(252)
Net cash provided by (used in) financing activities		497	$ (176)
Balance Sheet Data
Cash and cash equivalents		524		80
Net properties and equipment related to VIEs		6,064		5,731
Total assets		8,816		8,016
Long-term debt		4,176		3,493
Total liabilities		4,967		4,071
Total equity		$ 3,849		$ 3,945

[1] Excludes WES.

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Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash paid (received)
Interest, net of amounts capitalized	$ 326	$ 308
Income taxes, net of refunds	12	1
Non-cash investing activities
Fair value of properties and equipment acquired	2	549
Asset retirement cost additions	63	61
Accruals of property, plant, and equipment	965	608
Net liabilities assumed (divested) in acquisitions and divestitures	(25)	(82)
Non-cash investing and financing activities
Deferred drilling lease liability	$ 0	$ 7

XML

Supplemental Cash Flow Information - Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$ 3,484	$ 4,674	$ 5,959	$ 3,308
Cash and Cash Equivalents [Member]
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	3,361	4,553
Restricted cash and restricted cash equivalents	225	255
Other Assets [Member]
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$ 123	$ 121

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Segment Information - Additional Information (Detail)	3 Months Ended
	Mar. 31, 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
	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income (loss) before income taxes	$ 300	$ (178)
Interest expense	228	223
DD&A	990	1,115
Exploration expense	168	1,084
(Gains) losses on divestitures, net	24	(804)
Impairments	19	373
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(27)	(155)
Restructuring charges	0	1
Less net income (loss) attributable to noncontrolling interests	53	43
Consolidated Adjusted EBITDAX	$ 1,649	$ 1,614

XML

Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Revenues		$ 3,026	$ 2,898
Other		43	65
Total revenues and other		3,045	3,767
Operating costs and expenses		2,494	3,867
Net cash from settlement of commodity derivatives		63	8
Other (income) expense, net		(12)	2
Net income (loss) attributable to noncontrolling interests		53	43
Total expenses and other		1,426	1,347
Consolidated Adjusted EBITDAX		1,649	1,614
(Gains) losses on derivatives, net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		68	6
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		6	(2)
Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	3,069	2,963
Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	1,317	1,296
Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		(12)	2
Operating Segments [Member] | Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenues		2,656	2,451
Other		(9)	2
Total revenues and other		2,624
Net income (loss) attributable to noncontrolling interests		0	0
Total expenses and other		876	923
Consolidated Adjusted EBITDAX		1,781	1,533
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
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
Operating Segments [Member] | Exploration and Production [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	2,657	2,456
Operating Segments [Member] | Exploration and Production [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	876	923
Operating Segments [Member] | Exploration and Production [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		0	0
Operating Segments [Member] | Exploration and Production [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		10	3
Operating Segments [Member] | WES Midstream [Member]
Segment Reporting Information [Line Items]
Revenues		310	366
Other		29	30
Total revenues and other		466
Net income (loss) attributable to noncontrolling interests		0	0
Total expenses and other		194	292
Consolidated Adjusted EBITDAX		272	255
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
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
Operating Segments [Member] | WES Midstream [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	466	547
Operating Segments [Member] | WES Midstream [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	194	292
Operating Segments [Member] | WES Midstream [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		0	0
Operating Segments [Member] | WES Midstream [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		127	151
Operating Segments [Member] | Other Midstream [Member]
Segment Reporting Information [Line Items]
Revenues		36	36
Other		10	6
Total revenues and other		107
Net income (loss) attributable to noncontrolling interests		0	0
Total expenses and other		54	50
Consolidated Adjusted EBITDAX		44	34
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
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
Operating Segments [Member] | Other Midstream [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	98	84
Operating Segments [Member] | Other Midstream [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	54	50
Operating Segments [Member] | Other Midstream [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		0	0
Operating Segments [Member] | Other Midstream [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		52	42
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues		24	45
Other		13	27
Total revenues and other		(152)
Net income (loss) attributable to noncontrolling interests		53	43
Total expenses and other		302	82
Consolidated Adjusted EBITDAX		(448)	(208)
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		68	6
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		6	(2)
Other and Intersegment Eliminations [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	[1]	(152)	(124)
Other and Intersegment Eliminations [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	[2]	193	31
Other and Intersegment Eliminations [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		(12)	2
Other and Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		$ (189)	$ (196)

[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.