Anadarko Petroleum 8-K 15 May 19 Other Events Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2018
Document And Entity Information [Abstract]
Trading Symbol	APC
Entity Registrant Name	ANADARKO PETROLEUM CORP
Entity Central Index Key	0000773910
Document Type	8-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Entity Emerging Growth Company	false

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and Other
Sales revenues		$ 14,044		$ 8,447
Gains (losses) on divestitures and other, net		312	$ 939	(578)
Total		13,382	11,908	7,869
Costs and Expenses
Oil and gas operating		1,153	988	807
Oil and gas transportation		878	914	1,002
Exploration	[1]	459	2,535	944
General and administrative		1,084	994	1,223
Depreciation, depletion, and amortization		4,254	4,279	4,301
Production, property, and other taxes		826	582	536
Impairments		800	408	227
Other operating expense		262	221	118
Total		10,763	12,473	10,241
Operating Income (Loss)		2,619	(565)	(2,372)
Other (Income) Expense
Interest expense		947	932	890
(Gains) losses on early extinguishment of debt		(2)	2	155
(Gains) losses on derivatives, net		138	131	292
Other (income) expense, net		59	54	126
Total		1,134	1,123	1,457
Income (Loss) Before Income Taxes		1,485	(1,688)	(3,829)
Income tax expense (benefit)		733	(1,477)	(1,021)
Net Income (Loss)		752	(211)	(2,808)
Net income (loss) attributable to noncontrolling interests		137	245	263
Net Income (Loss) Attributable to Common Stockholders		$ 615	$ (456)	$ (3,071)
Per Common Share
Net income (loss) attributable to common stockholders—basic (in usd per share)		$ 1.20	$ (0.85)	$ (5.90)
Net income (loss) attributable to common stockholders—diluted (in usd per share)		$ 1.20	$ (0.85)	$ (5.90)
Average Number of Common Shares Outstanding—Basic (in shares)		504	548	522
Average Number of Common Shares Outstanding—Diluted (in shares)		504	548	522
Commodity Contract and Interest-Rate Swap [Member]
Other (Income) Expense
(Gains) losses on derivatives, net		$ 130	$ 135	$ 286
Oil sales [Member]
Revenues and Other
Sales revenues		9,206	6,552	4,668
Natural-gas sales [Member]
Revenues and Other
Sales revenues		1,005	1,348	1,564
Natural-gas liquids sales [Member]
Revenues and Other
Sales revenues		1,271	1,069	921
Gathering, processing, and marketing [Member]
Revenues and Other
Sales revenues		1,588	2,000	1,294
Costs and Expenses
Gathering, processing, and marketing		$ 1,047	$ 1,552	$ 1,083
[1]	Includes reorganization-related charges of $20 million for the year ended December 31, 2018.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net Income (Loss)		$ 752	$ (211)	$ (2,808)
Adjustments for derivative instruments
Cumulative effect of accounting change	[1]	(7)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net		3	3	8
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net		(1)	(1)	(3)
Total adjustments for derivative instruments, net of taxes		(5)
Total adjustments for derivative instruments, net of taxes		(2)	(2)	(5)
Adjustments for pension and other postretirement plans
Cumulative effect of accounting change	[1]	(66)
Net gain (loss) incurred during period		50	(14)	(175)
Income taxes on net gain (loss) incurred during period		(11)	4	68
Amortization of net actuarial (gain) loss to other (income) expense, net		74	116	188
Income taxes on amortization of net actuarial (gain) loss		(20)	(40)	(73)
Amortization of net prior service (credit) cost to other (income) expense, net		(24)	(25)	(34)
Income taxes on amortization of net prior service (credit) cost		5	10	13
Total adjustments for pension and other postretirement plans, net of taxes		8
Total adjustments for pension and other postretirement plans, net of taxes		(74)	(51)	13
Total		3	53	(8)
Comprehensive Income (Loss)		755	(158)	(2,816)
Comprehensive income (loss) attributable to noncontrolling interests		137	245	263
Comprehensive Income (Loss) Attributable to Common Stockholders		$ 618	$ (403)	$ (3,079)
[1]	Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents ($92 and $80 related to VIEs)		$ 1,295	$ 4,553
Accounts receivable (net of allowance of $13 and $14)
Customers ($138 and $106 related to VIEs)		1,491	1,222
Others ($15 and $19 related to VIEs)		535	607
Other current assets		474	380
Total		3,795	6,762
Net properties and equipment (net of accumulated depreciation, depletion, and amortization of $37,905 and $34,107) ($6,612 and $5,731 related to VIEs)		28,615	27,451
Other Assets ($868 and $579 related to VIEs)		2,336	2,211
Goodwill and Other Intangible Assets ($1,163 and $1,191 related to VIEs)		5,630	5,662
Total Assets		40,376	42,086
Current Liabilities
Accounts payable		2,003	1,894
Other ($15 and $1 related to VIEs)		161	266
Short-term debt		947	142
Current asset retirement obligations		252	294
Other current liabilities		1,295	1,310
Total		4,658	3,906
Long-term Debt		15,470	15,547
Other Long-term Liabilities
Deferred income taxes		2,437	2,234
Asset retirement obligations ($260 and $143 related to VIEs)		2,847	2,500
Other		4,021	4,109
Total		9,305	8,843
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.6 million and 574.2 million shares issued)		57	57
Paid-in capital		12,393	12,000
Retained earnings		1,245	1,109
Treasury stock (87.2 million and 43.4 million shares)		(4,864)	(2,132)
Accumulated other comprehensive income (loss)		(335)	(338)
Total Stockholders’ Equity		8,496	10,696
Noncontrolling interests		2,447	3,094
Total Equity		10,943	13,790
Total Liabilities and Equity		40,376	42,086
Anadarko Excluding WES and WGP [Member]
Current Liabilities
Short-term debt	[1]	919	142
Long-term Debt	[1]	10,683	12,054
WGP and WES [Member]
Current Liabilities
Short-term debt		28	0
Long-term Debt		$ 4,787	$ 3,493
[1]	Excludes WES and WGP.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 1,295	$ 4,553
Accounts Receivable
Accounts receivable (net of allowance of $13 and $14)	13	14
Customers	1,491	1,222
Others	535	607
Properties and Equipment
Net properties and equipment	28,615	27,451
Accumulated depreciation, depletion and amortization	37,905	34,107
Other assets	2,336	2,211
Goodwill and Other Intangible Assets	5,630	5,662
Accounts Payable [Abstract]
Accounts payable	2,003	1,894
Other ($15 and $1 related to VIEs)	161	266
Other Long-term Liabilities
Asset retirement obligations ($260 and $143 related to VIEs)	$ 2,847	$ 2,500
Common stock, par value (in usd per share)	$ 0.1	$ 0.1
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	576,600,000	574,200,000
Treasury stock, shares (in shares)	87,200,000	43,400,000
Variable Interest Entity, Primary Beneficiary [Member]
Current Assets
Cash and cash equivalents	$ 92	$ 80
Accounts Receivable
Customers	138	106
Others	15	19
Properties and Equipment
Net properties and equipment	6,612	5,731
Other assets	868	579
Goodwill and Other Intangible Assets	1,163	1,191
Accounts Payable [Abstract]
Accounts payable	263	305
Other ($15 and $1 related to VIEs)	15	1
Other Long-term Liabilities
Asset retirement obligations ($260 and $143 related to VIEs)	$ 260	$ 143

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Subsidiary Equity Transactions [Member]	Equity Component of 7.5% Tangible Equity Units [Member]	Common Stock [Member]	Paid-in Capital [Member]	Paid-in Capital [Member]Subsidiary Equity Transactions [Member]	Paid-in Capital [Member]Equity Component of 7.5% Tangible Equity Units [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member]Subsidiary Equity Transactions [Member]	Noncontrolling Interests [Member]Equity Component of 7.5% Tangible Equity Units [Member]
Balance at Dec. 31, 2015	$ 15,457			$ 52	$ 9,265			$ 4,880	$ (995)	$ (383)	$ 2,638
Net income (loss)	(2,808)							(3,071)			263
Common stock issued	2,155			5	2,150
Share-based compensation expense	197				197
Dividends—common stock	(105)							(105)
Repurchases of common stock	(38)								(38)
Subsidiary equity transactions		$ 1,009				$ 263						$ 746
Distributions to noncontrolling interest owners	(362)										(362)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	5									5
Adjustments for pension and other postretirement plans	(13)									(13)
Balance at Dec. 31, 2016	15,497			57	11,875			1,704	(1,033)	(391)	3,285
Net income (loss)	(211)							(456)			245
Share-based compensation expense	163				163
Dividends—common stock	(111)							(111)
Repurchases of common stock	(1,099)								(1,099)
Subsidiary equity transactions		(26)				(35)						9
Distributions to noncontrolling interest owners	(445)										(445)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2									2
Adjustments for pension and other postretirement plans	51									51
Balance at Dec. 31, 2017	13,790			57	12,000			1,109	(2,132)	(338)	3,094
Net income (loss)	752							615			137
Common stock issued	7				7
Share-based compensation expense	169				169
Dividends—common stock	(528)							(528)
Repurchases of common stock	(2,732)								(2,732)
Subsidiary equity transactions		$ 19				$ (15)						$ 34
Settlement of tangible equity units			$ (68)				$ 232						$ (300)
Distributions to noncontrolling interest owners	(495)										(495)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2									2
Adjustments for pension and other postretirement plans	74									74
Balance at Dec. 31, 2018	$ 10,943			$ 57	$ 12,393			$ 1,245	$ (4,864)	$ (335)	$ 2,447

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities
Net income (loss)		$ 752	$ (211)	$ (2,808)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization		4,254	4,279	4,301
Deferred income taxes		139	(2,169)	(1,238)
Dry hole expense and impairments of unproved properties		246	2,221	613
Impairments		800	408	227
(Gains) losses on divestitures, net	[1],[2]	(20)	(674)	757
(Gains) losses on early extinguishment of debt		(2)	2	155
Total (gains) losses on derivatives, net		138	131	292
Operating portion of net cash received (paid) in settlement of derivative instruments		(545)	25	267
Other		294	303	342
Changes in assets and liabilities
(Increase) decrease in accounts receivable		(211)	(147)	677
Increase (decrease) in accounts payable and other current liabilities		348	(32)	(443)
Other items, net		(264)	(127)	(142)
Net cash provided by (used in) operating activities		5,929	4,009	3,000
Cash Flows from Investing Activities
Additions to properties and equipment		(6,183)	(5,031)	(3,505)
Acquisition of businesses		0	25	(1,740)
Divestitures of properties and equipment and other assets		417	4,008	2,356
Other, net		(216)	(32)	147
Net cash provided by (used in) investing activities		(5,982)	(1,030)	(2,742)
Cash Flows from Financing Activities
Borrowings, net of issuance costs		2,343	369	6,042
Repayments of debt		(1,689)	(58)	(6,832)
Financing portion of net cash received (paid) for derivative instruments		12	(165)	(333)
Increase (decrease) in outstanding checks		(39)	(43)	(103)
Dividends paid		(528)	(111)	(105)
Repurchases of common stock		(2,732)	(1,092)	(38)
Issuances of common stock		7	0	2,188
Distributions to noncontrolling interest owners		(495)	(445)	(362)
Proceeds from conveyance of future hard-minerals royalty revenues, net of transaction costs		0	0	413
Payments of future hard-minerals royalty revenues conveyed		(50)	(50)	(25)
Other financing activities		(6)	(18)	0
Net cash provided by (used in) financing activities		(3,177)	(1,613)	2,008
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents		(15)	0	17
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents		(3,245)	1,366	2,283
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period		4,674	3,308	1,025
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period		1,429	4,674	3,308
Subsidiary Equity Transactions [Member]
Cash Flows from Financing Activities
Sales of subsidiary units		$ 0	$ 0	$ 1,163
[1]	Includes gain of $126 million related to the 2017 property exchange discussed below.
[2]	Includes goodwill allocated to divestitures of $209 million in 2017 and $397 million in 2016.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 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 is continuing to advance 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 consolidated financial statements have been prepared in conformity with GAAP. Certain prior-period amounts have been reclassified to conform to the current-year presentation. 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 on the Company’s Consolidated Balance Sheets. Use of Estimates The preparation of financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; AROs; litigation liabilities; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. 1. Summary of Significant Accounting Policies (Continued) Fair Value Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows: Level 1 —Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities (for example, exchange-traded futures contracts for which parties are willing to transact at the exchange-quoted price). Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 —Inputs that are not observable from objective sources such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement). In determining fair value, the Company uses observable market data when available or models that incorporate observable market data. When the Company is required to measure fair value and there is not a market-observable price for the asset or liability or for a similar asset or liability, the Company uses the cost or income approach depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions. In arriving at fair-value estimates, the Company uses relevant observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. For Anadarko, recurring fair-value measurements are performed for interest-rate derivatives, commodity derivatives, and investments in trading securities. The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable reported on the Company’s Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 13—Debt and Interest Expense , are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, AROs, exit or disposal costs, and capital lease assets and liabilities where the present value of lease payments is greater than the fair value of the leased asset. 1. Summary of Significant Accounting Policies (Continued) Revenues 2018 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 volume. 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. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income. WES 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 volume delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period. The Company’s midstream business also purchases natural-gas volume 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. If the fees relate to services performed before control of the product has transferred to Anadarko, the fees are treated as Gathering, processing and marketing sales revenues. 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. 1. Summary of Significant Accounting Policies (Continued) 2017 This section reflects the Company’s revenue recognition policies through December 31, 2017, prior to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . 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. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volume for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. Anadarko provides gathering, processing, treating, and transporting services pursuant to a variety of contracts. Under these arrangements, the Company receives fees or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. 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 from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These transactions are reported on a net basis and included in oil and gas transportation in the Company’s Consolidated Statements of Income. Cash Equivalents and Restricted Cash Equivalents The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents. The cash equivalents and restricted cash equivalents balance at December 31, 2018 , includes commercial paper and investments in government money market funds in which the carrying value approximates fair value. Accounts Receivable and Allowance for Uncollectible Accounts The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based on these analyses, the Company may require a standby letter of credit or a financial guarantee. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued. Inventories Commodity inventories are stated at the lower of average cost or net realizable value. 1. Summary of Significant Accounting Policies (Continued) Properties and Equipment Properties and equipment are stated at cost less accumulated DD&A. Costs of improvements that extend the lives of existing properties are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gain or loss is recognized in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. Oil and Gas Properties The Company applies the successful efforts method of accounting for oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are charged against earnings as incurred. Exploratory drilling costs are initially capitalized pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average lease terms at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense in the Company’s Consolidated Statements of Income. Capitalized Interest For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity-method affiliates that are undergoing the construction of assets that have not commenced principle operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 13—Debt and Interest Expense . 1. Summary of Significant Accounting Policies (Continued) Asset Retirement Obligations AROs associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and is included in DD&A in the Company’s Consolidated Statements of Income. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. See Note 15—Asset Retirement Obligations . Impairments Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. See Note 6—Impairments . Depreciation, Depletion, and Amortization Costs of drilling and equipping successful wells, costs to construct or acquire facilities other than offshore platforms, associated asset retirement costs, and capital lease assets used in oil and gas activities are depreciated using the UOP method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the UOP method. All other properties are stated at historical acquisition cost, net of impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 40 years for buildings, and up to 40 years for gathering facilities. Goodwill and Other Intangible Assets Anadarko has allocated goodwill to the following reporting units: Exploration and Production; WES Gathering and Processing; and WES Transportation. Goodwill is subject to annual impairment testing in October (or more frequent testing as circumstances dictate). Anadarko’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill, the Company will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, acquisitions, or divestitures. See Note 8—Goodwill and Other Intangible Assets . Other intangible assets represent contractual rights obtained in connection with business combinations that had favorable contractual terms relative to market at the acquisition date as well as customer-related intangible assets, including customer relationships established by acquired contracts. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment with the associated long-lived asset group whenever impairment indicators are present. See Note 8—Goodwill and Other Intangible Assets . Derivative Instruments Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Derivatives are carried on the balance sheet at fair value and are included in other current assets, other assets, other current liabilities, or other long-term liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the normal purchases and sales exception criteria. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis. Gains and losses on derivative instruments are recognized currently in earnings. Net losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 11—Derivative Instruments . 1. Summary of Significant Accounting Policies (Continued) Legal Contingencies The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. If the Company determines that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 18—Contingencies . Environmental Contingencies The Company is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. Except for environmental contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 18—Contingencies . Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 24—Noncontrolling Interests . Income Taxes The Company files various U.S. federal, state, and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. Deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). The Company uses the flow-through method to account for its investment tax credits. See Note 14—Income Taxes . Share-Based Compensation The Company accounts for share-based compensation at fair value. The Company grants equity-classified awards, including stock options and non-vested equity shares (restricted stock awards and units). The Company may also grant equity-classified and liability-classified awards based on a comparison of the Company’s TSR to the TSR of a predetermined group of peer companies (performance units). The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of Anadarko common stock. For other share-based compensation awards, fair value is determined using a Monte Carlo simulation. The Company records compensation cost, net of actual forfeitures, for share-based compensation awards over the requisite service period using the straight-line method. For equity-classified share-based compensation awards, expense is recognized based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid. See Note 23—Share-Based Compensation . 1. Summary of Significant Accounting Policies (Continued) 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 This ASU 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 the year ended December 31, 2017, and $225 million for the year ended December 31, 2016, 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 This ASU 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 26—Supplemental Cash Flow Information for additional information. ASU 2014-09, Revenue from Contracts with Customers (Topic 606) This ASU 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 . See Note 2—Revenue from Contracts with Customers for additional information. ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income This ASU 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 the 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 T

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	2. Revenue from Contracts with Customers Change in Accounting Policy As stated above, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. See Note 1—Summary of Significant Accounting Policies for additional information. Impacts on Financial Statements Exploration and Production There were no significant changes to the timing or valuation of revenue recognized for sales of production by the Exploration and Production reporting segment. WES Midstream Gathering and processing revenues decreased for contracts where the Company is acting as an agent for its processing customer in the sale of processed volume and increased for contracts with noncash consideration, with an offset to gathering and processing expense upon product sale. The magnitude of these presentation changes in subsequent periods is dependent on future customer volume subject to the impacted contracts and commodity prices for this volume. These presentation changes do not impact net earnings. The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements: CONSOLIDATED BALANCE SHEET Impact of Change in Accounting Policy millions As Reported Without Adoption of Topic 606 Effect of Change Increase/(Decrease) December 31, 2018 Assets Other current assets $ 474 $ 472 $ 2 Net properties and equipment 28,615 28,548 67 Other assets 2,336 2,326 10 Liabilities Other current liabilities 1,295 1,290 5 Deferred income taxes 2,437 2,441 (4 ) Other 4,021 3,914 107 Equity Total equity 10,943 10,972 (29 ) 2. Revenue from Contracts with Customers (Continued) CONSOLIDATED STATEMENT OF INCOME Impact of Change in Accounting Policy millions As Reported Without Adoption of Topic 606 Effect of Change Increase/(Decrease) Year Ended December 31, 2018 Revenues Gathering, processing, and marketing sales $ 1,588 $ 2,592 $ (1,004 ) Gains (losses) on divestitures and other, net 312 316 (4 ) Expenses Gathering, processing, and marketing 1,047 2,075 (1,028 ) Income tax expense (benefit) 733 731 2 Net income (loss) attributable to noncontrolling interests 137 127 10 Net Income (Loss) Attributable to Common Stockholders $ 615 $ 607 $ 8 Disaggregation of Revenue from Contracts with Customers The following table disaggregates revenue by significant product type and segment: millions Exploration WES Midstream Other and Total Year Ended December 31, 2018 Oil sales $ 9,206 $ — $ — $ 9,206 Natural-gas sales 1,005 — — 1,005 Natural-gas liquids sales 1,271 — — 1,271 Gathering, processing, and marketing sales (1) 3 2,305 126 2,434 Other, net 30 — 98 128 Total Revenue from Customers $ 11,515 $ 2,305 $ 224 $ 14,044 Gathering, processing, and marketing sales (2) — (5 ) (841 ) (846 ) Gains (losses) on divestitures, net 20 — — 20 Other, net (34 ) 211 (13 ) 164 Total Revenue from Other than Customers $ (14 ) $ 206 $ (854 ) $ (662 ) Total Revenue and Other $ 11,501 $ 2,511 $ (630 ) $ 13,382 (1) The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $957 million and intersegment eliminations of $(772) million for the year ended December 31, 2018 . (2) The amount in Other and Intersegment Eliminations primarily represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table as the purchases are not considered revenue from customers. 2. Revenue from Contracts with Customers (Continued) Contract Liabilities Contract liabilities primarily relate to midstream fees and capital reimbursements that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of benefit, fixed and variable fees that are received from customers but revenue recognition is deferred under midstream cost of service contracts, and hard-minerals bonus payments received from customers that must be recognized as revenue over the expected period of benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers: millions Balance at December 31, 2017 $ 37 Increase due to cumulative effect of adopting Topic 606 98 Increase due to cash received, excluding revenues recognized in the period 66 Increase due to assets received from customer 13 Decrease due to revenue recognized (42 ) Decrease due to change in estimated consideration (22 ) Balance at December 31, 2018 $ 150 Contract liabilities at December 31, 2018 Other current liabilities $ 31 Other long-term liabilities - other 119 Total contract liabilities from contracts with customers $ 150 Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of December 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 volume and variable commodity prices for this volume. millions Exploration WES Midstream Other and Total 2019 $ 104 $ 675 $ (433 ) $ 346 2020 103 847 (614 ) 336 2021 103 895 (681 ) 317 2022 7 947 (740 ) 214 2023 7 913 (750 ) 170 Thereafter 58 4,565 (4,077 ) 546 Total $ 382 $ 8,842 $ (7,295 ) $ 1,929

Commodity Inventories

Commodity Inventories	12 Months Ended
	Dec. 31, 2018
Energy Related Inventory [Abstract]
Commodity Inventories	3. Commodity Inventories The following summarizes the major classes of commodity inventories included in other current assets at December 31: millions 2018 2017 Oil $ 139 $ 165 Natural gas 18 29 NGLs 78 122 Total commodity inventories $ 235 $ 316

Divestitures and Assets Held fo

Divestitures and Assets Held for Sale	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Divestitures and Assets Held for Sale	4. Divestitures and Assets Held for Sale Divestitures and Assets Held for Sale The following summarizes the proceeds received and gains (losses) recognized on divestitures and assets held for sale for the years ended December 31: millions 2018 2017 2016 Proceeds received, net of closing adjustments $ 417 $ 4,008 $ 2,356 Gains (losses) on divestitures, net (1) (2) 20 674 (757 ) (1) Includes goodwill allocated to divestitures of $209 million in 2017 and $397 million in 2016 . (2) Includes gain of $126 million related to the 2017 property exchange discussed below. 2018 During the year ended December 31, 2018, the Company divested of the following U.S. onshore and Gulf of Mexico assets: – Alaska nonoperated assets, included primarily in the Exploration and Production reporting segment, for net proceeds of $370 million and net losses of $33 million in 2018 and $154 million in the fourth quarter of 2017 – Ram Powell nonoperated assets in the Gulf of Mexico, included in the Exploration and Production reporting segment, resulting in a net gain of $67 million 2017 During the year ended December 31, 2017, the Company divested of the following U.S. onshore assets: – Eagleford assets in South Texas, included in the Exploration and Production reporting segment, for net proceeds of $2.1 billion and a net gain of $729 million – Eaglebine assets in Southeast Texas, included in the Exploration and Production reporting segment, for net proceeds of $533 million and a net gain of $282 million – Utah CBM assets, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $69 million and a net loss of $52 million – Marcellus assets in Pennsylvania, included primarily in the Exploration and Production reporting segment, for net proceeds of $951 million and net losses of $55 million in 2017 and $129 million in 2016 – Moxa assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $313 million and a net loss of $204 million Certain nonoperated assets located in Alaska included in the Exploration and Production reporting segment satisfied criteria to be considered held for sale during the fourth quarter of 2017, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $154 million . At December 31, 2017, the Company’s Consolidated Balance Sheet included long‑term assets of $573 million and long-term liabilities of $27 million associated with assets held for sale. 4. Divestitures and Assets Held for Sale (Continued) 2016 During the year ended December 31, 2016, the Company divested of the following U.S. onshore assets: – Hugoton assets in Kansas, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $159 million and a loss of $4 million – Ozona and Steward assets in West Texas, included primarily in the Exploration and Production reporting segment, for net proceeds of $221 million and a loss of $52 million – Wamsutter assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $588 million and a loss of $58 million – Elm Grove assets in East Texas, included in the Exploration and Production reporting segment, for net proceeds of $89 million and a loss of $64 million – East Chalk and Carthage assets in East Texas/Louisiana, included primarily in the Exploration and Production reporting segment, for net proceeds of $1.0 billion and a net loss of $439 million Certain Marcellus U.S. onshore assets located in Pennsylvania included in the Exploration and Production reporting segment satisfied criteria to be considered held for sale during the fourth quarter of 2016, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $129 million . Property Exchange On March 17, 2017, WES acquired a third party’s 50% nonoperated interest in the DBJV System, now part of the West Texas Complex, in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash. WES 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.

Properties and Equipment

Properties and Equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment, Gross [Abstract]
Properties and Equipment	5. Properties and Equipment The following summarizes properties and equipment at December 31: millions 2018 2017 Exploration and Production (1) $ 52,796 $ 50,221 WES Midstream 11,259 8,980 Other 2,465 2,357 Gross properties and equipment $ 66,520 $ 61,558 Less accumulated DD&A 37,905 34,107 Net properties and equipment $ 28,615 $ 27,451 (1) Includes costs associated with unproved properties of $1.7 billion at December 31, 2018 , and $2.4 billion at December 31, 2017 .

Impairments

Impairments	12 Months Ended
	Dec. 31, 2018
Asset Impairment Charges [Abstract]
Impairments	6. 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 at December 31: 2018 2017 2016 millions Impairment Fair Value (1) Impairment Fair Value (1) Impairment Fair Value (1) Exploration and Production U.S. onshore properties $ 397 $ 172 $ 2 $ 3 $ 28 $ 617 Gulf of Mexico properties 27 — 227 216 27 61 Cost-method investment — — — — 59 — WES Midstream 231 30 178 58 18 3 Other 145 15 1 — 95 29 Total impairments $ 800 $ 217 $ 408 $ 277 $ 227 $ 710 (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. 2018 Impairments were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties due to the steep decline in NGL commodity prices in the fourth quarter of 2018 and a gathering system in the DJ basin that was permanently taken out of service in the second quarter of 2018. Impairments also related to hard-minerals properties as a result of the Company’s primary consumer of coal stating its intent to retire its existing coal-fired power generation plant earlier than expected, coupled with the outlook for limited new markets for the Company’s coal in the Rockies region. 2017 Impairments 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. 2016 Impairments were primarily related to the uncertain recovery of the Company’s Venezuelan cost-method investment, negative developments related to commercial negotiations of a certain midstream asset, impairment of an office building, changes in development plans for certain U.S. onshore oil and gas assets, and a reduction in estimated future cash flows related to an oil and gas property in the Gulf of Mexico. 6. Impairments (Continued) Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. 2018 The Company recognized $159 million of impairments of unproved Gulf of Mexico properties primarily related to GOM blocks where the Company determined it would no longer pursue exploration activities. 2017 The Company recognized $610 million of impairments of unproved Gulf of Mexico properties primarily due to an impairment of $463 million to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. The Company also recognized $88 million of impairments of unproved international properties. See Note 7—Suspended Exploratory Well Costs . 2016 The Company recognized a $72 million impairment of unproved properties in the Gulf of Mexico and $92 million of unproved international properties primarily in Brazil and Tunisia due to the Company’s intentions to not pursue future exploration activities. It is also 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 additional impairments.

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2018
Capitalized Exploratory Well Costs [Abstract]
Suspended Exploratory Well Costs	7. Suspended Exploratory Well Costs The following summarizes the changes in suspended exploratory well costs at December 31 for each of the last three years: millions 2018 2017 2016 Balance at January 1 $ 525 $ 1,230 $ 1,124 Additions pending the determination of proved reserves (1) 90 349 490 Divestitures and other (38 ) (36 ) (11 ) Reclassifications to proved properties (132 ) (41 ) (50 ) Charges to exploration expense (1 ) (977 ) (323 ) Balance at December 31 $ 444 $ 525 $ 1,230 (1) Excludes amounts capitalized and subsequently charged to expense within the same year. 2018 During the year ended December 31, 2018 , the Company expensed $87 million of exploratory well costs, including $1 million of costs that were suspended as of December 31, 2017. 2017 During the year ended December 31, 2017, exploratory well costs charged to exploration expense primarily related to the following: Gulf of Mexico – Shenandoah The Company expensed $437 million of exploratory well costs, including $326 million of costs that were suspended as of December 31, 2016 . The Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017 and did not encounter oil in the eastern portion of the field. Given the results of this well and the commodity-price environment at the time, the Company suspended further appraisal activities. In 2018, the Company relinquished its ownership interest in Shenandoah. – Phobos The Company expensed $215 million of exploratory well costs, including $99 million of costs that were suspended as of December 31, 2016, in the third quarter of 2017 related to wells at the Phobos project. These wells found insufficient quantities of oil pay to justify development in the current price environment. – Warrior The Company expensed $108 million of exploratory well costs in the third quarter of 2017 related to the northern appraisal well and sidetrack at the Warrior project. These wells found insufficient quantities of oil pay to justify development of the northern portion of the field in the current price environment. Evaluation of tie-back opportunities in the southern portion of the field is ongoing. Colombia – The Company expensed $243 million of exploratory well costs, including $109 million of costs that were suspended as of December 31, 2016, related to wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater gas development. All remaining leases are contractually in good standing. Côte d’Ivoire – The Company expensed $329 million of exploratory well costs, including $237 million of costs that were suspended as of December 31, 2016, in Côte d’Ivoire. During 2017, the Company had unsuccessful drilling activities in the south channel of the Paon prospect and in Block CI-527 and after further evaluation of the well results Anadarko withdrew from all exploration blocks in Côte d’Ivoire. The Company expects to complete the withdrawal from its remaining appraisal block in 2019. 7. Suspended Exploratory Well Costs (Continued) 2016 During the year ended December 31, 2016, suspended exploratory well costs charged to exploration expense primarily related to the following: Gulf of Mexico – The Company expensed $231 million of suspended exploratory well costs in the Gulf of Mexico primarily related to the Yeti project, as the Company did not expect to have exploration activities on this prospect in the foreseeable future, and a Shenandoah well that was expensed, as it was no longer reasonably possible that the wellbore could be used in the development of the project. Mozambique – The Company expensed $92 million of suspended exploratory well costs in Mozambique. The Tubarão-Tigre discovery wells were expensed based on the outlook for development viability, the commodity market conditions, and the complexity introduced by the depth and characteristics of the reservoir. The Orca-4 well was expensed after additional reservoir analysis and the determination that the well was not associated with the first three Orca wells. The following provides an aging of suspended well balances at December 31: millions 2018 2017 2016 Exploratory well costs capitalized for a period of one year or less $ 152 $ 201 $ 460 Exploratory well costs capitalized for a period greater than one year 292 324 770 Balance at December 31 $ 444 $ 525 $ 1,230 7. Suspended Exploratory Well Costs (Continued) The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2018 : millions except projects Number of Projects Total 2017 2016 2015 and U.S. onshore 1 $ 2 $ — $ — $ 2 U.S. offshore 1 73 (1 ) 74 — International 3 217 11 14 192 5 $ 292 $ 10 $ 88 $ 194 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. Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling at December 31, 2018 , primarily related to the Gulf of Mexico, Ghana, and Mozambique. Gulf of Mexico Exploratory well costs are primarily related to the Warrior discovery and have been suspended pending further appraisal activities for potential tieback to the existing infrastructure, including analysis of well results and geologic and geophysical studies, and project sanctioning. Ghana Exploratory well costs are related to the Mahogany East and Teak prospects, which are included in the Greater Jubilee Full Field Development Plan approved by the Ghanaian government in October 2017. Well costs remain suspended pending further technical analysis and future drilling results. Mozambique Exploratory well costs are related to the initial two-train Golfinho/Atum project. In 2018, the Company obtained government approval of the Development Plan, advanced major infrastructure projects, advanced onshore and offshore construction and installation contracts, executed long-term LNG sales and purchase agreements (SPAs), and launched project financing. During 2018 and subsequent to year end, additional SPAs were executed, increasing the contracted volume to more than 7.5 MTPA. Execution of SPAs representing 2.0 MTPA of additional contracted volume is anticipated prior to FID. The Company is working to finalize project finance arrangements with lenders and secure all partner and government-related approvals required to proceed with making a final investment decision in the first half of 2019. 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.

Goodwill and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangible Assets	8. Goodwill and Other Intangible Assets Goodwill At December 31, 2018 , the Company had $4.8 billion of goodwill allocated to the following reporting segments: $4.3 billion to Exploration and Production, and $446 million to WES Midstream. The Company’s 2018 annual qualitative impairment assessment of goodwill indicated no impairment. Qualitative factors were also assessed in the fourth quarter of 2018 to review any changes in circumstances subsequent to the annual test, including changes in commodity prices. This assessment also indicated no impairment. Other Intangible Assets Intangible assets and associated amortization expense were as follows at December 31: millions 2018 2017 Gross carrying amount $ 980 $ 1,013 Accumulated amortization (139 ) (140 ) Net carrying amount $ 841 $ 873 Amortization expense $ 32 $ 31 Intangible assets are primarily related to customer contracts associated with WES’s 2014 acquisition of Delaware basin processing infrastructure. These contracts are being amortized over 30 years . The annual aggregate amortization expense for intangible assets is expected to be $32 million for each of the next five years.

Equity-Method Investments

Equity-Method Investments	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Equity-Method Investments	9. Equity-Method Investments In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of $2.9 billion at the time of the contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable LIBOR-based preferred interests in those entities. The common equity of the investee entities is 95% owned by third parties that also maintain control over the assets. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion , each with a 35-year term. The Company accounts for its investment in these entities using the equity method of accounting. The carrying amount of these investments was $2.8 billion and the carrying amount of notes payable to affiliates was $2.9 billion at December 31, 2018 . Anadarko’s noncontrolling interest may be redeemed beginning in 2022 by Anadarko or the owner of the controlling interest. Anadarko’s interest is mandatorily redeemable in 2037 . Anadarko has legal right of setoff and intends to net settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investment for each entity and the related obligation are presented net on the Company’s Consolidated Balance Sheets. Other long-term liabilities—other included $41 million at December 31, 2018 , and $46 million at December 31, 2017 , and other assets included $4 million at December 31, 2018 and $4 million at December 31, 2017 , related to these investments. Interest on the notes issued by Anadarko is variable, and is equivalent to LIBOR plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 3.79% at December 31, 2018 , and 2.59% at December 31, 2017 . The note payable agreement contains a quarterly covenant that provides for a maximum Anadarko debt-to-capital ratio of 67% (excluding the effect of non-cash write-downs). Anadarko was in compliance with this covenant at December 31, 2018 . Other (income) expense, net includes interest expense on the notes payable of $91 million in 2018 , $64 million in 2017 , and $49 million in 2016 , and equity (earnings) losses from Anadarko’s investments in the investee entities of $(87) million in 2018 , $(56) million in 2017 , and $(33) million in 2016 .

Current Liabilities

Current Liabilities	12 Months Ended
	Dec. 31, 2018
Payables and Accruals [Abstract]
Current Liabilities	10. Current Liabilities Accounts Payable Accounts payable, trade included liabilities of $180 million at December 31, 2018 , and $219 million at December 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 at December 31: millions 2018 2017 Accrued income taxes $ 167 $ 71 Interest payable 267 246 Production, property, and other taxes payable 309 216 Accrued employee benefits 319 210 Derivatives 89 384 Other 144 183 Total other current liabilities $ 1,295 $ 1,310

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	11. Derivative Instruments Objective and Strategy The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities. Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates. The Company does not apply hedge accounting to any of its currently outstanding 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. See Note 22—Accumulated Other Comprehensive Income (Loss) . 11. 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 Company had no natural-gas production/processing derivatives at December 31, 2018 . The following is a summary of the Company’s oil derivative instruments at December 31, 2018 : 2019 Settlement Oil Three-Way Collars (MBbls/d) 87 Average price per barrel Ceiling sold price (call) $ 72.98 Floor purchased price (put) $ 56.72 Floor sold price (put) $ 46.72 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 volume. The purchased put establishes the minimum price that the Company will receive for the contracted volume 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. Anadarko Interest-Rate Derivatives (Excluding WES) Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. In August 2018, the Company amended an interest-rate swap with a notional principal amount of $200 million , extending the mandatory termination date from 2018 to 2023 in exchange for a cash payment of approximately $10 million . At December 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 potential future debt issuances. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at December 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 % $ 100 September 2017 - 2047 September 2020 6.891 % $ 250 September 2017 - 2047 September 2021 6.570 % $ 450 September 2017 - 2047 September 2023 6.445 % Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in Anadarko’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 $92 million in 2018 and $112 million in 2017 . 11. Derivative Instruments (Continued) WES Interest-Rate Derivatives In December 2018, WES entered into interest-rate swap agreements with an aggregate notional amount of $750 million to manage interest-rate risk associated with anticipated 2019 debt issuances. WES has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. Depending on market conditions, liability management actions, or other factors, WES may settle or amend certain or all of the currently outstanding interest-rate swaps. The following interest-rate swaps were outstanding at December 31, 2018 : millions except percentages Mandatory Fixed Notional Principal Amount Reference Period Termination Date Interest Rate $ 250 December 2019 - 2024 December 2019 2.730 % $ 250 December 2019 - 2029 December 2019 2.856 % $ 250 December 2019 - 2049 December 2019 2.905 % Effect of Derivative Instruments — Balance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31: millions Gross Derivative Assets Gross Derivative Liabilities Balance Sheet Classification 2018 2017 2018 2017 Commodity derivatives - Anadarko (1) Other current assets $ 300 $ 7 $ (126 ) $ (1 ) Other assets — 2 — — Other current liabilities 1 45 (6 ) (206 ) Other liabilities — — — (2 ) 301 54 (132 ) (209 ) Interest-rate derivatives - Anadarko (1) Other current assets 22 14 — — Other assets 34 40 — — Other current liabilities — — (82 ) (236 ) Other liabilities — — (1,156 ) (1,183 ) 56 54 (1,238 ) (1,419 ) Interest-rate derivatives - WES Other current liabilities — — (8 ) — Total derivatives $ 357 $ 108 $ (1,378 ) $ (1,628 ) (1) Excludes amounts related to WES interest-rate swap agreements. 11. Derivative Instruments (Continued) Effect of Derivative Instruments — Statement of Income The following summarizes gains and losses related to derivative instruments: millions Classification of (Gain) Loss Recognized 2018 2017 2016 Commodity derivatives - Anadarko (1) Gathering, processing, and marketing sales $ 8 $ (4 ) $ 6 (Gains) losses on derivatives, net 213 3 147 Interest-rate derivatives - Anadarko (1) (Gains) losses on derivatives, net (91 ) 132 139 Interest-rate derivatives - WES (Gains) losses on derivatives, net 8 — — Total (gains) losses on derivatives, net $ 138 $ 131 $ 292 (1) Excludes amounts related to WES interest-rate swap agreements. 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 December 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. Subsequent to year end, Moody’s changed its outlook with respect to its rating from stable to positive. The Company may be required to post additional collateral with respect to its derivative instruments if its credit ratings decline below current levels or if the liability associated with any such derivative instrument increases above the credit threshold. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.1 billion (net of $66 million of collateral) at December 31, 2018 , and $1.4 billion (net of $170 million of collateral) at December 31, 2017 . 11. 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 December 31, 2018 Assets Anadarko (2) Commodity derivatives $ 1 $ 300 $ — $ (127 ) $ — $ 174 Interest-rate derivatives — 56 — — — 56 Total derivative assets $ 1 $ 356 $ — $ (127 ) $ — $ 230 Liabilities Anadarko (2) Commodity derivatives $ (2 ) $ (130 ) $ — $ 127 $ 2 $ (3 ) Interest-rate derivatives — (1,238 ) — — 66 (1,172 ) WES Interest-rate derivatives — (8 ) — — — (8 ) Total derivative liabilities $ (2 ) $ (1,376 ) $ — $ 127 $ 68 $ (1,183 ) December 31, 2017 Assets Anadarko (2) Commodity derivatives $ 1 $ 53 $ — $ (46 ) $ (1 ) $ 7 Interest-rate derivatives — 54 — — — 54 Total derivative assets $ 1 $ 107 $ — $ (46 ) $ (1 ) $ 61 Liabilities Anadarko (2) 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. (2) Excludes amounts related to WES interest-rate swap agreements.

Tangible Equity Units

Tangible Equity Units	12 Months Ended
	Dec. 31, 2018
Tangible Equity Units [Abstract]
Tangible Equity Units	12. Tangible Equity Units In June 2015, the Company issued 9.2 million 7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million . Each TEU was comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. The prepaid equity purchase contract was considered a freestanding financial instrument, indexed to WGP common units, and met the conditions for equity classification. Equity Component On June 7, 2018 , the mandatory settlement date, Anadarko settled 9.2 million outstanding TEUs in exchange for approximately 8.2 million WGP common units based on the determined final settlement rate of 0.8921 WGP common units per outstanding TEU. See settlement of tangible equity units in the Company’s Consolidated Statement of Equity. Debt Component Each senior amortizing note had an initial principal amount of $10.95 and bore interest at 1.50% per year. The final installment payment of $9 million was made on June 7, 2018 . For activity related to the senior amortizing notes, see Note 13—Debt and Interest Expense .

Debt and Interest Expense

Debt and Interest Expense	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt and Interest Expense	13. Debt and Interest Expense Debt Activity The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions: Carrying Value millions WES WGP (1) Anadarko (2) Anadarko Consolidated Description Balance at December 31, 2016 $ 3,091 $ 28 $ 11,959 $ 15,078 Borrowings 370 — — 370 WES RCF Repayments — — (6 ) (6 ) 7.000% Debentures due 2027 — — (3 ) (3 ) 6.625% Debentures due 2028 — — (1 ) (1 ) 7.950% Debentures due 2029 — — (34 ) (34 ) TEUs - senior amortizing notes Other, net 4 — 50 54 Amortization of discounts, premiums, and debt issuance costs Balance at December 31, 2017 $ 3,465 $ 28 $ 11,965 $ 15,458 Issuances 394 — — 394 WES 4.500% Senior Notes due 2028 687 — — 687 WES 5.300% Senior Notes due 2048 396 — — 396 WES 4.750% Senior Notes due 2028 342 — — 342 WES 5.500% Senior Notes due 2048 Borrowings 540 — — 540 WES RCF Repayments — — (114 ) (114 ) 7.050% Debentures due 2018 — — (123 ) (123 ) 4.850% Senior Notes due 2021 — — (375 ) (375 ) 3.450% Senior Notes due 2024 — — (35 ) (35 ) Zero Coupon Notes due 2036 (350 ) — — (350 ) WES 2.600% Senior Notes due 2018 (690 ) — — (690 ) WES RCF — — (17 ) (17 ) TEUs - senior amortizing notes Other, net 3 — 53 56 Amortization of discounts, premiums, and debt issuance costs Balance at December 31, 2018 $ 4,787 $ 28 $ 11,354 $ 16,169 (1) Excludes WES. (2) Excludes WES and WGP. 13. Debt and Interest Expense (Continued) Debt See Note 9—Equity-Method Investments for disclosure regarding Anadarko’s 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. The following summarizes the Company’s outstanding debt, including capital lease obligations, after eliminating the effect of intercompany transactions: December 31, 2018 millions WES WGP (1) Anadarko (2) Anadarko Consolidated 6.950% Senior Notes due 2019 $ — $ — $ 300 $ 300 8.700% Senior Notes due 2019 — — 600 600 4.850% Senior Notes due 2021 — — 677 677 WES 5.375% Senior Notes due 2021 500 — — 500 WES 4.000% Senior Notes due 2022 670 — — 670 3.450% Senior Notes due 2024 — — 248 248 6.950% Senior Notes due 2024 — — 650 650 WES 3.950% Senior Notes due 2025 500 — — 500 WES 4.650% Senior Notes due 2026 500 — — 500 5.550% Senior Notes due 2026 — — 1,100 1,100 7.500% Debentures due 2026 — — 112 112 7.000% Debentures due 2027 — — 48 48 7.125% Debentures due 2027 — — 150 150 WES 4.500% Notes due 2028 400 — — 400 WES 4.750% Notes due 2028 400 — — 400 6.625% Debentures due 2028 — — 14 14 7.150% Debentures due 2028 — — 235 235 7.200% Debentures due 2029 — — 135 135 7.950% Debentures due 2029 — — 116 116 7.500% Senior Notes due 2031 — — 900 900 7.875% Senior Notes due 2031 — — 500 500 Zero Coupon Senior Notes due 2036 — — 2,270 2,270 6.450% Senior Notes due 2036 — — 1,750 1,750 7.950% Senior Notes due 2039 — — 325 325 6.200% Senior Notes due 2040 — — 750 750 4.500% Senior Notes due 2044 — — 625 625 WES 5.450% Senior Notes due 2044 600 — — 600 6.600% Senior Notes due 2046 — — 1,100 1,100 WES 5.300% Notes due 2048 700 — — 700 WES 5.500% Notes due 2048 350 — — 350 7.730% Debentures due 2096 — — 61 61 7.500% Debentures due 2096 — — 78 78 7.250% Debentures due 2096 — — 49 49 WES RCF 220 — — 220 WGP RCF — 28 — 28 Total borrowings at face value $ 4,840 $ 28 $ 12,793 $ 17,661 Net unamortized discounts, premiums, and debt issuance costs (3) (53 ) — (1,439 ) (1,492 ) Total borrowings (4) 4,787 28 11,354 16,169 Capital lease obligations — — 248 248 Less short-term debt — 28 919 947 Total long-term debt $ 4,787 $ — $ 10,683 $ 15,470 13. Debt and Interest Expense (Continued) December 31, 2017 millions WES WGP (1) Anadarko (2) Anadarko Consolidated 7.050% Debentures due 2018 $ — $ — $ 114 $ 114 TEUs - senior amortizing notes due 2018 — — 17 17 WES 2.600% Senior Notes due 2018 350 — — 350 6.950% Senior Notes due 2019 — — 300 300 8.700% Senior Notes due 2019 — — 600 600 4.850% Senior Notes due 2021 — — 800 800 WES 5.375% Senior Notes due 2021 500 — — 500 WES 4.000% Senior Notes due 2022 670 — — 670 3.450% Senior Notes due 2024 — — 625 625 6.950% Senior Notes due 2024 — — 650 650 WES 3.950% Senior Notes due 2025 500 — — 500 WES 4.650% Senior Notes due 2026 500 — — 500 5.550% Senior Notes due 2026 — — 1,100 1,100 7.500% Debentures due 2026 — — 112 112 7.000% Debentures due 2027 — — 48 48 7.125% Debentures due 2027 — — 150 150 6.625% Debentures due 2028 — — 14 14 7.150% Debentures due 2028 — — 235 235 7.200% Debentures due 2029 — — 135 135 7.950% Debentures due 2029 — — 116 116 7.500% Senior Notes due 2031 — — 900 900 7.875% Senior Notes due 2031 — — 500 500 Zero Coupon Senior Notes due 2036 — — 2,360 2,360 6.450% Senior Notes due 2036 — — 1,750 1,750 7.950% Senior Notes due 2039 — — 325 325 6.200% Senior Notes due 2040 — — 750 750 4.500% Senior Notes due 2044 — — 625 625 WES 5.450% Senior Notes due 2044 600 — — 600 6.600% Senior Notes due 2046 — — 1,100 1,100 7.730% Debentures due 2096 — — 61 61 7.500% Debentures due 2096 — — 78 78 7.250% Debentures due 2096 — — 49 49 WES RCF 370 — — 370 WGP RCF — 28 — 28 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. 13. Debt and Interest Expense (Continued) Scheduled Maturities Total principal amount of debt maturities related to borrowings for the five years ending December 31, 2023 , excluding the potential repayment of the outstanding Zero Coupons that may be put by the holders to the Company annually, were as follows: Principal Amount of Debt Maturities millions WES WGP (1) Anadarko (2) Anadarko Consolidated 2019 $ — $ 28 $ 900 $ 928 2020 — — — — 2021 500 — 677 1,177 2022 670 — — 670 2023 220 — — 220 (1) Excludes WES. (2) Excludes WES and WGP. 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 $16.8 billion at December 31, 2018 , and $17.7 billion at December 31, 2017 . 13. Debt and Interest Expense (Continued) Anadarko Debt (Excluding WES and WGP) In December 2018, the Company purchased and retired $377 million of its $625 million 3.450% Senior Notes due 2024 and $123 million of its $800 million 4.850% Senior Notes due 2021 pursuant to a tender offer. The Company recognized a net gain of $7 million for the early retirement of these senior notes. The Company repaid $114 million of 7.050% Debentures at maturity in May 2018 . In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the Zero Coupons. The Zero Coupons mature in 2036 and have an aggregate principal amount due at maturity of approximately $2.3 billion , reflecting a yield to maturity of 5.24% . In December 2018, the Company purchased and retired $36 million of the accreted value of its Zero Coupons due 2036 and recognized a loss of $3 million for the early retirement of these senior notes. This early retirement results in a reduction of $90 million of the $2.4 billion originally due at maturity in 2036. 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, would be $942 million at the next put date in October 2019 . None of the Zero Coupons were put to the Company in October 2018. The accreted value of the outstanding Zero Coupons was $905 million at December 31, 2018 . Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2018 , as the Company has the ability and intent to refinance these obligations using long-term debt, should a put be exercised. Principal payments related to the Zero Coupons are reported in financing activities and interest accretion payments related to the Zero Coupons are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. 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 billion 364 -day senior unsecured RCF to extend the maturity date to January 2019 ( 364 -Day Facility). In December 2018, the Company amended its APC RCF to extend the maturity date to January 2023 . The 364 -Day Facility expired in January 2019 . Borrowings under the APC RCF and the 364 -Day Facility (collectively, the Credit Facilities) generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the APC RCF denominated in Euro) or an alternate base rate, in each case plus an applicable margin ranging from 0.00% to 1.65% for the APC RCF and 0.00% to 1.675% for the 364 -Day Facility. The applicable margin will vary depending on Anadarko’s credit ratings. The Credit Facilities contain certain customary affirmative and negative covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65% (excluding the effect of non-cash write-downs), and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes. At December 31, 2018 , the Company had no outstanding borrowings under the Credit Facilities and was in compliance with all covenants. In January 2015, the Company initiated a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes. The maturities of the commercial paper notes may vary, but may not exceed 397 days . As a result of Moody’s credit rating on Anadarko, the Company’s access to the commercial paper market has been limited. The Company has not issued commercial paper notes since the downgrade and had no outstanding borrowings under the commercial paper program at December 31, 2018 . 13. Debt and Interest Expense (Continued) WES and WGP Debt In February 2018, WES amended its RCF to extend the maturity date from February 2020 to February 2023 and expand 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 . In December 2018, WES entered into an amendment to extend the maturity date from February 2023 to February 2024 effective on February 15, 2019 and to expand the borrowing capacity to $2.0 billion , while leaving the $500 million accordion feature unexercised. Expansion of the borrowing capacity is subject to the completion of the WES Merger anticipated in the first quarter of 2019. See Note 24—Noncontrolling Interests for additional information related to the WES Merger. Borrowings under the WES RCF bear interest at LIBOR plus an applicable margin ranging from 0.975% to 1.45% depending on WES’s credit rating, or the greatest of (i) rates at a margin above the one-month LIBOR, (ii) the federal funds rate, or (iii) prime rates offered by certain designated banks. During 2018, WES borrowed $540 million under its RCF, which was used for general partnership purposes, and made repayments of $690 million . At December 31, 2018, WES had outstanding borrowings under its RCF of $220 million at an interest rate of 3.74% , outstanding letters of credit of $5 million , available borrowing capacity of $1.3 billion , and was in compliance with all covenants. In March 2018, WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048 . Net proceeds from the public offerings were used to repay amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures. In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048 . The net proceeds from the public offerings were used to repay the maturing $350 million of 2.600% Senior Notes due August 2018, and amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures. In December 2018, WES entered into a $2.0 billion 364 -day senior unsecured credit agreement (WES 364 -Day Facility), the proceeds of which will be used to fund substantially all of the cash portion of the consideration under the WES midstream asset contribution and sale and the payment of related transaction costs. The WES 364 -Day Facility will mature on the day prior to the one-year anniversary of the completion of the WES Merger, and will bear interest at LIBOR, plus applicable margins ranging from 1.000% to 1.625% , or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% , or (c) LIBOR plus 1% , in each case as defined in the WES 364 -Day Facility and plus applicable margins currently ranging from zero to 0.625% , based upon WES’s senior unsecured debt rating. WES is also required to pay a ticking fee of 0.175% on the commitment amount beginning 90 days after the effective date of the credit agreement through the date of funding under the WES 364 -Day Facility. The WES 364 -Day Facility contains covenants and customary events of default that are substantially similar to the WES RCF. Additionally, funding of the WES 364 -Day Facility is conditioned upon the completion of the WES Merger, and net cash proceeds received from future asset sales and debt or equity offerings by WES must be used to repay amounts outstanding under the WES 364 -Day Facility. See Note 24—Noncontrolling Interests for additional information related to the WES Merger. During 2016, WGP had a $250 million senior secured RCF that matures in March 2019 and was expandable to $500 million , subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions (WGP RCF). In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under the WGP RCF from $250 million to $35 million . In December 2018, the WGP RCF was amended to extend the maturity date from March 2019 to the earlier of June 2019 or three business days following the completion of the WES Merger. See Note 24—Noncontrolling Interests for additional information related to the WES Merger. 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. Borrowings under the WGP RCF bear interest at LIBOR (with a floor of 0% ), plus applicable margins ranging from 2.00% to 2.75% depending on WGP’s consolidated leverage ratio, or at a base rate equal to the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50% , or (iii) LIBOR plus 1.00% , in each case plus applicable margins ranging from 1.00% to 1.75% based upon WGP’s consolidated leverage ratio. At December 31, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.53% classified as short-term debt on the Company’s Consolidated Balance Sheet, available borrowing capacity of $7 million , and was in compliance with all covenants. 13. Debt and Interest Expense (Continued) Capital Lease Obligations Construction of a FPSO for the Company’s TEN field in Ghana commenced in 2013. The Company recognized an asset and related obligation for its approximate 19% nonoperated participating interest share during the construction period. Upon completion of construction in the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s proportionate share of the fair value of the FPSO. The FPSO lease provides for an initial term of 10 years with annual renewal periods for an additional 10 years, annual purchase options that decrease over time, and no residual value guarantees. The capital lease asset is being depreciated over the estimated proved reserves of the TEN field using the UOP method, with the associated depreciation included in DD&A in the Company’s Consolidated Statement of Income. The accumulated depreciation of the FPSO capital lease asset was $72 million at December 31, 2018 , and $41 million at December 31, 2017 . The capital lease obligation is being accreted to the present value of the minimum lease payments using the effective interest method. The Company made capital lease payments of $46 million in 2018 and $44 million in 2017. At December 31, 2018 , future minimum lease payments related to the Company’s capital leases were: millions 2019 $ 58 2020 50 2021 48 2022 45 2023 43 Thereafter 323 Total future minimum lease payments $ 567 Less portion representing imputed interest 319 Capital lease obligations $ 248 Interest Expense The following summarizes interest expense for the years ended December 31: millions 2018 2017 2016 Debt and other $ 1,028 $ 1,003 $ 1,022 Capitalized interest (81 ) (71 ) (132 ) Total interest expense $ 947 $ 932 $ 890

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	14. Income Taxes The Tax Reform Legislation enacted on December 22, 2017, reduced the U.S. corporate tax rate from 35% to 21% . Upon enactment, the Company recognized a provisional and one-time deferred tax benefit of $1.2 billion , inclusive of a $236 million increase to the Company’s valuation allowance on its foreign tax credit carryforwards, due to the remeasurement of its U.S. deferred tax assets and liabilities based on the rate reduction. During 2018, the Company completed the accounting for the income tax effects related to the adoption of the Tax Reform Legislation before the end of the measurement period. The Company revised the provisional amount recorded in 2017 and recognized an additional current tax benefit of $26 million , primarily related to the acceleration of pension deductions into 2017. This benefit was offset by deferred tax expense of $121 million , primarily related to additional valuation allowance on the Company’s foreign tax credit carryforwards. The following summarizes components of income tax expense (benefit) for the years ended December 31: millions 2018 2017 2016 Current Federal $ 14 $ 236 $ (140 ) State (1 ) 48 (1 ) Foreign 595 414 378 Total current tax expense (benefit) 608 698 237 Deferred Federal 150 (2,082 ) (1,020 ) State (26 ) (17 ) (148 ) Foreign 1 (76 ) (90 ) Total deferred tax expense (benefit) 125 (2,175 ) (1,258 ) Total income tax expense (benefit) $ 733 $ (1,477 ) $ (1,021 ) 14. Income Taxes (Continued) Total income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate to income (loss) before income taxes. The following summarizes the sources of these differences for the years ended December 31: millions except percentages 2018 2017 2016 Income (loss) before income taxes Domestic $ 492 $ (1,322 ) $ (3,728 ) Foreign 993 (366 ) (101 ) Total $ 1,485 $ (1,688 ) $ (3,829 ) U.S. federal statutory tax rate 21 % 35 % 35 % Tax computed at the U.S. federal statutory rate $ 312 $ (591 ) $ (1,340 ) (Income) loss attributable to noncontrolling interests (29 ) (85 ) (92 ) Adjustments resulting from State income taxes (net of federal income tax benefit) (18 ) 25 (108 ) U.S. federal tax reform 95 (1,168 ) — Tax impact from foreign operations 181 166 80 Non-deductible Algerian exceptional profits tax 154 110 106 Net changes in uncertain tax positions (29 ) 90 90 Dispositions of non-deductible goodwill — 6 205 Other, net 67 (30 ) 38 Total income tax expense (benefit) $ 733 $ (1,477 ) $ (1,021 ) Effective tax rate 49 % 88 % 27 % The following summarizes components of total deferred taxes at December 31: millions 2018 2017 Federal $ (1,972 ) $ (1,758 ) State, net of federal (176 ) (200 ) Foreign (255 ) (255 ) Total deferred taxes (1) $ (2,403 ) $ (2,213 ) (1) Net deferred tax assets related to Algeria of $34 million in 2018 and $21 million in 2017 are presented in other assets on the Company’s Consolidated Balance Sheet. 14. Income Taxes (Continued) The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31: millions 2018 2017 Deferred tax liabilities Oil and gas exploration and development operations $ (2,403 ) $ (2,622 ) Midstream and other depreciable properties (662 ) (543 ) Mineral operations (238 ) (312 ) Other (134 ) (53 ) Gross long-term deferred tax liabilities (3,437 ) (3,530 ) Deferred tax assets Oil and gas exploration and development costs 303 309 Foreign and state net operating loss carryforwards 445 562 U.S. foreign tax credit carryforwards 2,665 2,685 Compensation and benefit plans 301 365 Other 308 420 Gross long-term deferred tax assets 4,022 4,341 Valuation allowances on deferred tax assets not expected to be realized (2,988 ) (3,024 ) Net long-term deferred tax assets 1,034 1,317 Total deferred taxes $ (2,403 ) $ (2,213 ) The valuation allowance primarily relates to U.S. foreign tax credit carryforwards and foreign and state net operating loss carryforwards, which reduces the Company’s net deferred tax asset to an amount that will more likely than not be realized within the carryforward period. The following summarizes changes in the balance of valuation allowances on deferred tax assets: millions 2018 2017 2016 Balance at January 1 $ (3,024 ) $ (1,755 ) $ (1,403 ) Changes due to U.S. foreign tax credits (50 ) (1,287 ) (477 ) Changes due to foreign and state net operating loss carryforwards 72 75 13 Changes due to foreign capitalized costs 14 (57 ) 112 Balance at December 31 $ (2,988 ) $ (3,024 ) $ (1,755 ) Tax carryforwards available, prior to valuation allowance, at December 31, 2018 , were as follows: millions Domestic Foreign Expiration Net operating loss—state (1) $ 4,250 $ — 2019-2038 Net operating loss—foreign $ — $ 820 2019-Indefinite Foreign tax credits (2) $ 2,665 $ — 2023-2028 Texas margins tax credit $ 27 $ — 2026 (1) Net of $711 million uncertain tax position at December 31, 2018. (2) Net of $378 million uncertain tax position at December 31, 2018. 14. Income Taxes (Continued) The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31: millions Balance Sheet Classification 2018 2017 Income taxes receivable Accounts receivable—other $ 46 $ 53 Other assets 51 101 97 154 Income taxes (payable) Other current liabilities (167 ) (71 ) Total net income taxes receivable (payable) $ (70 ) $ 83 Changes in the balance of unrecognized tax benefits, excluding interest and penalties on uncertain tax positions, were as follows: Assets (Liabilities) millions 2018 2017 2016 Balance at January 1 $ (1,317 ) $ (1,456 ) $ (1,780 ) Increases related to prior-year tax positions (21 ) (15 ) (86 ) Decreases related to prior-year tax positions 48 214 436 Increases related to current-year tax positions — (72 ) (26 ) Settlements 1 12 — Lapse of statute of limitations 2 — — Balance at December 31 $ (1,287 ) $ (1,317 ) $ (1,456 ) The December 31, 2018 balance of unrecognized tax benefits includes potential benefits of $1.24 billion , of which, if recognized, $1.26 billion would affect the effective tax rate on income. Also included are benefits of $43 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain. The Company recognized a net tax benefit of $346 million at December 31, 2018 and 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 at December 31, 2018 and 2017 , due to uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment, the Company had a net operating loss carryback for 2015, which resulted in a tentative tax refund of $881 million in 2016. The IRS has audited this position and, in April 2018, issued a final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s refund claim. As a result, the Company filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018, and pursuant to standard U.S. Tax Court procedures, the Company is not required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the Tax Court, the court will issue an opinion and then enter a decision. If the Company does not prevail on the issue, the earliest date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company asserts its position in the Tax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not anticipate a decision to be entered within the next three years. 14. Income Taxes (Continued) Income tax audits and the Company’s acquisition and divestiture activity have given rise to tax disputes in U.S. and foreign jurisdictions. See Note 18—Contingencies —Litigation. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $70 million to $90 million due to settlements with taxing authorities or lapse in statutes of limitation. With the exception of the deductibility of the Tronox settlement payment discussed above, management believes that the final resolution of outstanding tax audits and litigation will not have a material adverse effect on the Company’s consolidated financial condition, results of operations, or cash flows. The Company accrued approximately $95 million of interest related to uncertain tax positions at December 31, 2018 , and $86 million at December 31, 2017 . The Company recognized interest and penalties in income tax expense (benefit) of $9 million during 2018 and $55 million during 2017 . Anadarko is subject to audit by tax authorities in the U.S. federal, state, and local tax jurisdictions as well as in various foreign jurisdictions. The following lists the tax years subject to examination by major tax jurisdiction: Tax Years United States 2013-2018 Algeria 2015-2018 Ghana 2015-2018

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	15. Asset Retirement Obligations The majority of Anadarko’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement. The following summarizes changes in the Company’s AROs: millions 2018 2017 Carrying amount at January 1 $ 2,794 $ 2,931 Liabilities acquired — 4 Liabilities incurred 153 191 Property dispositions (99 ) (154 ) Liabilities settled (274 ) (135 ) Accretion expense 130 144 Revisions in estimated liabilities 395 (187 ) Carrying amount at December 31 $ 3,099 $ 2,794

Conveyance of Future Hard Miner

Conveyance of Future Hard Minerals Royalty Revenues	12 Months Ended
	Dec. 31, 2018
Deferred Revenue Disclosure [Abstract]
Conveyance of Future Hard Minerals Royalty Revenues	16. Conveyance of Future Hard-Minerals Royalty Revenues During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million , net of transaction costs. Such conveyance entitles the third party to receive up to $553 million in future royalty revenue over a period of not less than 10 years and not greater than 15 years. Additionally, such third party is entitled to receive 3% of the aggregate royalties earned during the first 10 years between $800 million and $900 million and 4% of the aggregate royalties earned during the first 10 years that exceed $900 million . Generally, such third party relies solely on the royalty payments to recover its investment and, as such, has the risk of the royalties not being sufficient to recover its investment over the term of the conveyance. Proceeds from this transaction were accounted for as deferred revenues and are included in other current liabilities and other long-term liabilities - other on the Company’s Consolidated Balance Sheet. The deferred revenues will be amortized to other revenues, included in gains (losses) on divestitures and other, net, on a unit-of-revenue basis over the term of the agreement. Net proceeds received from the third party were reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Semi-annual payments to the third party are scheduled on March 1 and September 1 of each year through March 1, 2026. The specified future amounts that the Company expects to pay and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the conveyance. Royalties received by Anadarko under this agreement are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. The semi-annual payments to the third party, up to the aggregate amount of the $413 million net proceeds the Company received for the conveyance in the first quarter of 2016, are reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Any additional payments to the third party are reported in operating activities on the Company’s Consolidated Statement of Cash Flows to offset the royalties received. The Company amortized deferred revenues of $36 million in 2018 , $38 million in 2017 , and $37 million in 2016 as a result of this agreement. The Company made payments for royalties totaling $50 million in 2018 and 2017 , and $25 million in 2016 . The following summarizes the remaining amounts that the Company expects to pay, prior to the potential 3% to 4% of any excess described above: millions 2019 $ 52 2020 57 2021 57 2022 58 2023 60 Thereafter 144 Total $ 428

Commitments

Commitments	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments	17. Commitments Operating Leases At December 31, 2018 , the Company had $262 million in long-term drilling rig commitments that are accounted for as operating leases. These drilling rig operating leases expire at various dates through 2021 . The Company also had $392 million of various commitments under non-cancelable operating lease agreements for production platforms and equipment, buildings, facilities, compressors, and aircraft. These operating leases expire at various dates through 2033 . Certain of these operating leases contain residual value guarantees at the end of the lease term of $73 million at December 31, 2018 . A $5 million liability was accrued for residual value guarantees. In addition, these operating leases include options to purchase the leased property during or at the end of the lease term for the fair market value or other specified amount at that time. The following summarizes future minimum lease payments under operating leases at December 31, 2018 : millions 2019 $ 264 2020 139 2021 57 2022 35 2023 24 Thereafter 135 Total future minimum lease payments $ 654 Anadarko has entered into various agreements to secure drilling rigs necessary to support the execution of its drilling plans over the next several years. The table of future minimum lease payments above includes $209 million related to three offshore drilling vessels, $41 million related to certain contracts for U.S. onshore drilling rigs, and $12 million related to certain contracts for two international drilling rigs. Lease payments associated with the drilling of exploratory wells and development wells net of amounts billed to partners will initially be capitalized as a component of oil and gas properties and either depreciated or impaired in future periods or written off as exploration expense. Total rent expense, net of sublease income and amounts capitalized, amounted to $74 million in 2018 , $55 million in 2017 , and $73 million in 2016 . Total rent expense included contingent rent expense related to transportation and processing fees of $4 million in 2018 , $3 million in 2017 , and $6 million in 2016 . Other Commitments Anadarko has various long-term contractual commitments pertaining to oil and natural-gas activities such as work-related commitments for drilling wells, obtaining and processing seismic data, and fulfilling rig commitments. Anadarko also enters into various processing, transportation, storage, and purchase agreements to access markets and provide flexibility to sell its oil, natural gas, and NGLs in certain areas. These agreements expire at various dates through 2033 . The following summarizes the gross aggregate future payments under these contracts at December 31, 2018 : millions 2019 $ 1,147 2020 1,155 2021 993 2022 786 2023 646 Thereafter 1,498 Total (1) $ 6,225 (1) Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Contingencies	18. Contingencies The Company is a defendant in a number of lawsuits, is involved in governmental proceedings, and is subject to regulatory controls arising in the ordinary course of business, including personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, 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. As of December 31, 2018 , the Company had $33 million accrued for litigation-related contingencies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, 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 consolidated financial condition, results of operations, or cash flows. Litigation In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. In December 2008, the Company deposited the amount of tax originally in dispute in a Brazilian real-denominated judicially-controlled Brazilian bank account pending final resolution of the matter. At December 31, 2018 , the deposit of $88 million is included in other assets on the Company’s Consolidated Balance Sheet. In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court’s ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior Court and the Brazilian Supreme Court. The appeal to the Brazilian Supreme Court has been stayed pending a decision in the Superior Court appeal. In August 2013, following a determination by an administrative court in a related matter that the amount of tax in dispute was not calculated properly, the Company filed a petition requesting the withdrawal of a portion of the judicial deposit to the extent it exceeds the amount of tax currently in dispute and any interest on such excess amount. In April 2015, the Company’s petition was denied. The Company appealed this decision. The appeal was denied in November 2015. The Company believes that it will more likely than not prevail in the Brazilian Superior Court and the Brazilian Supreme Court. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at December 31, 2018 . The Company continues to vigorously defend its tax position in the Brazilian courts. Guarantees and Indemnifications The Company provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation, or tax matters existing at the date of disposition. Environmental Matters Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. The Company’s Consolidated Balance Sheets include liabilities for remediation and reclamation obligations of $109 million at December 31, 2018 , and $113 million at December 31, 2017 . The current portion of these amounts was included in other current liabilities and the long-term portion of these amounts was included in other long-term liabilities — other on the Company’s Consolidated Balance Sheets. The Company continually monitors remediation and reclamation processes and adjusts its liability for these obligations as necessary.

Restructuring Charges

Restructuring Charges	12 Months Ended
	Dec. 31, 2018
Restructuring and Related Activities [Abstract]
Restructuring Charges	19. Restructuring Charges In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. The Company recognized $389 million of restructuring charges, comprised of $192 million in G&A and $197 million in Other (income) expense, net, in the Company’s Consolidated Statements of Income during the year ended December 31, 2016 . All restructuring charges were recognized in 2016, with the exception of $21 million , primarily related to defined-benefit pension settlement expense, which was recognized during 2017 for lump-sum payments to terminated participants.

Pension Plans, Other Postretire

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans	20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans 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 non-contributory. The following sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2018 and 2017 , as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2018 and 2017 : Pension Benefits Other Benefits millions 2018 2017 2018 2017 Change in benefit obligation Benefit obligation at beginning of year $ 2,218 $ 2,301 $ 302 $ 296 Service cost 90 87 1 2 Interest cost 77 84 11 12 Actuarial (gain) loss (176 ) 107 (23 ) 15 Curtailments, settlements, and special termination benefits expense 15 23 — (1 ) Participant contributions — — 7 5 Benefit payments (268 ) (396 ) (25 ) (27 ) Foreign-currency exchange-rate changes (8 ) 12 — — Benefit obligation at end of year (1) $ 1,948 $ 2,218 $ 273 $ 302 Change in plan assets Fair value of plan assets at beginning of year $ 1,424 $ 1,340 $ — $ — Actual return on plan assets (57 ) 209 — — Employer contributions 225 254 19 22 Participant contributions — — 7 5 Benefits paid related to plan settlements (212 ) (337 ) (1 ) (3 ) Benefit payments, other (56 ) (59 ) (25 ) (24 ) Foreign-currency exchange-rate changes (10 ) 17 — — Fair value of plan assets at end of year $ 1,314 $ 1,424 $ — $ — Funded status of the plans at end of year $ (634 ) $ (794 ) $ (273 ) $ (302 ) Amounts recognized on the balance sheet Other assets $ 63 $ 58 $ — $ — Other current liabilities (42 ) (16 ) (21 ) (21 ) Other long-term liabilities—other (655 ) (836 ) (252 ) (281 ) Total $ (634 ) $ (794 ) $ (273 ) $ (302 ) Amounts recognized in accumulated other comprehensive income Prior service (credit) cost $ 1 $ — $ (2 ) $ (26 ) Net actuarial (gain) loss 399 501 (9 ) 14 Total $ 400 $ 501 $ (11 ) $ (12 ) (1) The accumulated benefit obligation for all defined-benefit pension plans was $1.6 billion at December 31, 2018 and $1.9 billion at December 31, 2017 . 20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued) The following summarizes the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets for the years ended December 31: millions 2018 2017 Projected benefit obligation $ 1,828 $ 2,079 Accumulated benefit obligation 1,527 1,749 Fair value of plan assets 1,131 1,227 The following summarizes the Company’s pension and other postretirement benefit cost for the years ended December 31: Pension Benefits Other Benefits millions 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost Service cost $ 90 $ 87 $ 99 $ 1 $ 2 $ 3 Interest cost 77 84 95 11 12 12 Expected (return) loss on plan assets (83 ) (84 ) (97 ) — — — Amortization of net actuarial (gain) loss 25 25 42 — — — Amortization of net prior service (credit) cost — (1 ) — (24 ) (24 ) (25 ) Settlement expense (1) 49 91 146 — — — Termination benefits expense (1) 7 4 44 — — — Curtailment expense (1) (1 ) — 8 — — — Net periodic benefit cost (2) $ 164 $ 206 $ 337 $ (12 ) $ (10 ) $ (10 ) (1) Settlement expense, termination benefits expense, and curtailment expense for 2016 relate to the workforce reduction program initiated in the first quarter of 2016. See Note 19—Restructuring Charges . (2) 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 following summarizes the amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31: Pension Benefits Other Benefits millions 2018 2017 2016 2018 2017 2016 Amounts recognized in other comprehensive income (expense) Net actuarial gain (loss) $ 27 $ — $ (150 ) $ 23 $ (14 ) $ (25 ) Amortization of net actuarial (gain) loss 74 116 188 — — — Amortization of net prior service (credit) cost — (1 ) — (24 ) (24 ) (34 ) Total amounts recognized in other comprehensive income (expense) $ 101 $ 115 $ 38 $ (1 ) $ (38 ) $ (59 ) The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. In 2019 , an estimated $12 million of net actuarial loss and $2 million of net prior service credit for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost. 20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued) Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and inflation (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually. Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. Assumed rates of compensation increases for active participants vary by age group, with the resulting weighted-average assumed rate (weighted by the plan-level benefit obligation) provided in the preceding table. The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations and net periodic benefit cost for the years ended December 31: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Benefit obligation assumptions Discount rate 4.30 % 3.62 % 4.06 % 4.43 % 3.75 % 4.26 % Rates of increase in compensation levels 5.33 % 5.36 % 5.40 % 5.43 % 5.46 % 5.48 % Net periodic benefit cost assumptions Discount rate 3.62 % 4.06 % 4.62 % 3.75 % 4.26 % 5.00 % Long-term rate of return on plan assets 6.09 % 6.12 % 6.77 % N/A N/A N/A Rates of increase in compensation levels 5.36 % 5.40 % 5.34 % 5.46 % 5.48 % 5.41 % An annual rate of increase indexed to the Consumer Price Index is assumed for purposes of measuring other postretirement benefit obligations. A rate of 1.70% at December 31, 2018 , and 2.00% at December 31, 2017 and 2016 was assumed for purposes of measuring other postretirement benefit obligations. 20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued) Plan Assets Investment Policies and Strategies The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (domestic equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 50% equity securities, 25% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines. Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2018 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, changes in valuation, and inflation. Returns on fixed-income securities are generally developed based on expected cash returns and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are generally derived from their relationship to the equity and fixed-income markets. Risks and Uncertainties The plan assets include various investment securities that are exposed to various risks such as interest-rate, credit, and market risks. Due to the level of risk associated with certain investment securities, it is possible that changes in the values of investment securities could significantly impact the plan assets. The plan assets may include securities with contractual cash flows such as asset-backed securities, collateralized mortgage obligations, and commercial mortgage-backed securities, including securities backed by subprime mortgage loans. The value, liquidity, and related income of those securities are sensitive to changes in economic conditions, including real estate values, delinquencies or defaults, or both, and may be adversely affected by shifts in the market’s perception of the issuers and changes in interest rates. 20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued) Investments in securities traded in active markets are measured based on unadjusted quoted prices, which represent Level 1 inputs. Investments based on Level 2 inputs include direct investments in corporate debt and other fixed-income securities. Investments included as Level 3 inputs are not observable from objective sources. The fair value of the Company’s pension plan assets by asset class and input level within the fair-value hierarchy were as follows: millions December 31, 2018 Level 1 Level 2 Level 3 (3) Total Investments Cash and cash equivalents $ 28 $ — $ — $ 28 Fixed income 43 28 — 71 Equity securities 189 — — 189 Other Real estate — — 13 13 Other — 49 — 49 Investments measured at net asset value (1) — — — 964 Total investments (2) $ 260 $ 77 $ 13 $ 1,314 December 31, 2017 Investments Cash and cash equivalents $ 1 $ — $ — $ 1 Fixed income 55 31 — 86 Equity securities 185 — — 185 Other Real estate — — 13 13 Other — 53 — 53 Investments measured at net asset value (1) — — — 1,086 Total investments (2) $ 241 $ 84 $ 13 $ 1,424 (1) Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. (2) Amount excludes receivables and payables, primarily related to Level 1 investments. (3) There were no changes in Level 3 investments for the year ended December 31, 2018 . The changes in Level 3 investments of $3 million for the year ended December 31, 2017 , were attributable to the actual return on plan assets still held at the reporting date. 20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued) Cash Contributions and Expected Benefit Payments While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2018 , the Company monitors the status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. Contributions to funded plans increase plan assets, while contributions to unfunded plans are used to fund current benefit payments. The following summarizes the Company’s contributions for 2018 and expected contributions for 2019 : millions Expected 2019 2018 Funded pension plans $ 90 $ 161 Unfunded pension plans 43 64 Unfunded other postretirement plans 22 19 Total $ 155 $ 244 The following summarizes estimated benefit payments for the next 10 years, including benefit increases due to continuing employee service: millions Pension Benefit Payments Other Benefit Payments 2019 $ 223 $ 22 2020 148 21 2021 150 20 2022 190 20 2023 181 20 2024-2028 839 86 Defined-Contribution Plans The Company maintains several defined-contribution benefit plans, the most significant of which is the Anadarko Employee Savings Plan (ESP). All regular employees of the Company on its U.S. payroll are eligible to participate in the ESP by making elective contributions that are matched by the Company, subject to certain limitations. The Company recognized expense related to these plans of $63 million for 2018 and 2017 , and $64 million for 2016 .

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
Stockholders' Equity	21. Stockholders’ Equity Common Stock The Company announced a $2.5 billion Share-Repurchase Program in September 2017. During 2018, the Share-Repurchase Program was ultimately expanded to $5.0 billion and extended through mid-year 2020. The Share-Repurchase Program authorizes the repurchase of the Company’s common stock in the open market or through private transactions. As of December 31, 2018 , the Company had completed $3.75 billion of the Share-Repurchase Program through ASR Agreements and open-market repurchases. These transactions were accounted for as equity transactions, with all of the repurchased shares classified as treasury stock. Additionally, the receipt of these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS. During the years ended December 31, 2018 and 2017 , the Company entered into and completed ASR Agreements and open-market repurchases as presented below: millions except per-share amounts Agreement Date Settlement Date Amount Average Price per Share Initial Shares Delivered Additional Shares Delivered Total Shares Delivered ASR Agreements October 2017 December 2017 $ 1,000 $ 48.13 15.7 5.1 20.8 January 2018 February 2018 500 58.82 7.0 1.5 8.5 March 2018 June 2018 1,441 65.28 19.1 3.0 22.1 Total ASR Agreements 2,941 41.8 9.6 51.4 Open-market repurchases December 2017 December 2017 59 52.00 N/A N/A 1.1 August 2018 August 2018 250 66.14 N/A N/A 3.8 September 2018 September 2018 250 63.11 N/A N/A 3.9 December 2018 December 2018 250 52.34 N/A N/A 4.8 Total open-market repurchases 809 13.6 Total $ 3,750 $ 57.69 65.0 Under each ASR Agreement, the Company paid a specific amount in cash and received an initial delivery of shares of the Company’s common stock. The initial delivery of shares represented the minimum number of shares to be repurchased under the agreement. The final number of shares delivered upon settlement of each ASR Agreement was determined with reference to the volume-weighted average price of the shares during the term of the agreement less a negotiated settlement price adjustment. 21. Stockholders’ Equity (Continued) In September 2016, the Company completed a public offering of 40.5 million shares of its common stock at a price of $53.23 per share. Net proceeds of $2.16 billion from this equity issuance were primarily used to fund the GOM Acquisition, with the remainder used for general corporate purposes. The following summarizes the changes in the Company’s outstanding shares of common stock: millions 2018 2017 2016 Shares of common stock issued Shares at January 1 574 572 528 Exercise of stock options — — 1 Issuance of common stock — — 41 Issuance of restricted stock 3 2 2 Shares at December 31 577 574 572 Shares of common stock held in treasury Shares at January 1 43 21 20 Purchase of treasury stock 43 22 — Shares received for restricted stock vested and stock options exercised 1 — 1 Shares at December 31 87 43 21 Shares of common stock outstanding at December 31 490 531 551 Earnings Per Share The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and TEUs, if the inclusion of these items is dilutive. All outstanding TEUs were settled in June 2018. See Note 12—Tangible Equity Units for additional information. The following provides a reconciliation between basic and diluted EPS attributable to common stockholders for the years ended December 31: millions except per-share amounts 2018 2017 2016 Net income (loss) Net income (loss) attributable to common stockholders $ 615 $ (456 ) $ (3,071 ) Income (loss) effect of TEUs (4 ) (7 ) (6 ) Less distributions on participating securities 5 1 1 Basic $ 606 $ (464 ) $ (3,078 ) Income (loss) effect of TEUs (1 ) (2 ) (1 ) Diluted $ 605 $ (466 ) $ (3,079 ) Shares Average number of common shares outstanding—basic 504 548 522 Average number of common shares outstanding—diluted 504 548 522 Excluded due to anti-dilutive effect 9 11 11 Net income (loss) per common share Basic $ 1.20 $ (0.85 ) $ (5.90 ) Diluted $ 1.20 $ (0.85 ) $ (5.90 ) Dividends per common share $ 1.05 $ 0.20 $ 0.20

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	22. Accumulated Other Comprehensive Income (Loss) The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss): millions Interest-rate Derivatives Previously Subject to Hedge Accounting Pension and Other Postretirement Plans Total Balance at December 31, 2015 $ (42 ) $ (341 ) $ (383 ) Other comprehensive income (loss), before reclassifications — (107 ) (107 ) Reclassifications to Consolidated Statement of Income 5 94 99 Net other comprehensive income (loss) 5 (13 ) (8 ) Balance at December 31, 2016 $ (37 ) $ (354 ) $ (391 ) Other comprehensive income (loss), before reclassifications — (10 ) (10 ) Reclassifications to Consolidated Statement of Income 2 61 63 Net other comprehensive income (loss) 2 51 53 Balance at December 31, 2017 $ (35 ) $ (303 ) $ (338 ) Other comprehensive income (loss), before reclassifications — 39 39 Reclassifications to Consolidated Statement of Income 2 35 37 Cumulative effect of accounting change (1) (7 ) (66 ) (73 ) Net other comprehensive income (loss) (5 ) 8 3 Balance at December 31, 2018 $ (40 ) $ (295 ) $ (335 ) (1) Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	23. Share-Based Compensation At December 31, 2018 , 20 million shares of the 41 million shares of Anadarko common stock authorized for awards under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. The following summarizes share-based compensation expense for the years ended December 31: millions 2018 2017 2016 Restricted stock (1) $ 147 $ 145 $ 175 Stock options (1) 21 17 20 Other equity-classified awards 1 1 2 Performance-based unit awards (1) 19 (13 ) 38 Pretax share-based compensation expense $ 188 $ 150 $ 235 Income tax benefit $ 43 $ 35 $ 86 (1) Includes restructuring charges of $(7) million for performance-based unit awards in 2017 and $31 million for restricted stock, $1 million for stock options, and $7 million for performance-based unit awards in 2016. See Note 19—Restructuring Charges for additional information. Equity-Classified Awards Restricted Stock Certain employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. A restricted stock unit is equivalent to a restricted stock award except that unit holders do not have the right to vote. Restricted stock vests over service periods ranging from the date of grant generally up to three years and is not considered issued and outstanding for accounting purposes until vested. Non-employee directors are granted deferred shares, which are also considered restricted stock, that are held in a grantor trust by the Company until payable. Non-employee directors may elect to receive these shares in a lump-sum payment or in annual installments. The following summarizes the Company’s restricted stock activity: Shares (millions) Weighted-Average Grant-Date Fair Value (per share) Non-vested at January 1, 2018 4.69 $ 59.24 Granted 2.72 $ 58.30 Vested (2.30 ) $ 61.19 Forfeited (0.42 ) $ 58.07 Non-vested at December 31, 2018 4.69 $ 57.88 The weighted-average grant-date fair value per share of restricted stock granted was $59.92 during 2017 and $52.03 during 2016 . The total fair value of restricted shares vested was $142 million during 2018 , $132 million during 2017 , and $114 million during 2016 , based on the market price at the vesting date. At December 31, 2018 , total unrecognized compensation cost related to restricted stock of $172 million is expected to be recognized over a weighted-average remaining service period of 1.5 years . 23. Share-Based Compensation (Continued) Stock Options Certain employees may be granted nonqualified options to purchase shares of Anadarko common stock with an exercise price equal to, or greater than, the fair market value of Anadarko common stock on the date of grant. These stock options generally vest over three years from the date of grant and terminate at the earlier of the date of exercise or seven years from the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model with the following assumptions: • Expected life —Based on historical exercise behavior. • Volatility —Based on an average of historical volatility over the expected life of an option and the 12-month average implied volatility. • Risk-free interest rates —Based on the U.S. Treasury rate over the expected life of an option. • Dividend yield —Based on a 12-month average dividend yield, taking into account the Company’s expected dividend policy over the expected life of an option. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted: 2018 2017 2016 Weighted-average grant-date fair value $ 15.36 $ 14.77 $ 15.92 Assumptions Expected option life—years 4.8 4.8 4.1 Volatility 33.5 % 33.6 % 38.2 % Risk-free interest rate 2.9 % 2.0 % 1.3 % Dividend yield 1.9 % 0.4 % 0.6 % The following summarizes the Company’s stock option activity: Shares (millions) Weighted- Average Exercise Price (per share) Weighted- Average Remaining Contractual Term (years) Aggregate Intrinsic Value (millions) Outstanding at January 1, 2018 6.57 $ 71.44 Granted 1.19 $ 55.47 Exercised (1) (0.10 ) $ 65.03 Forfeited or expired (1.30 ) $ 79.55 Outstanding at December 31, 2018 6.36 $ 67.00 3.92 $ — Vested or expected to vest at December 31, 2018 6.36 $ 67.00 3.92 $ — Exercisable at December 31, 2018 4.12 $ 74.19 2.66 $ — (1) The total intrinsic value of stock options exercised was $1 million during 2018 , zero during 2017 , and $7 million during 2016 , based on the difference between the market price at the exercise date and the exercise price. Cash received from stock option exercises was $7 million in 2018 , zero in 2017 , and $30 million in 2016 , and the tax benefit from these exercises was zero in both 2018 and 2017 , and $2 million in 2016 . At December 31, 2018 , total unrecognized compensation cost related to stock options of $25 million is expected to be recognized over a weighted-average remaining service period of 1.6 years . 23. Share-Based Compensation (Continued) Liability-Classified Awards Performance-Based Unit Awards Certain officers of the Company were provided Performance Unit Award Agreements with three -year performance periods. The vesting of these units is based on comparing the Company’s TSR to the TSR of a predetermined group of peer companies over the specified performance period, with the ultimate value of any vested units determined by the Company’s share price at the time of payment, as each performance unit represents the value of one share of the Company’s common stock. Following the end of each performance period, the value of the vested performance units, if any, is paid in cash. The Company paid no cash related to vested performance units in 2018 , $10 million in 2017 , and $6 million in 2016 . At December 31, 2018 , the Company’s liability under Performance Unit Award Agreements was $46 million , with total unrecognized compensation cost related to these awards of $28 million expected to be recognized over a weighted-average remaining performance period of 2.5 years.

Noncontrolling Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2018
Noncontrolling Interest Items [Abstract]
Noncontrolling Interests	24. 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 for net proceeds of $687 million and issued 1.3 million common units to the Company. Proceeds from these issuances were primarily used to acquire interests in Springfield Pipeline LLC from the Company. 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 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 conversion into WES common units. All outstanding WES Class C units will convert into WES common units on a one-for-one basis immediately prior to the closing of the WES Merger, if completed. If the WES Merger is not completed, the conversion will occur on March 1, 2020, unless WES elects to convert such units earlier or Anadarko extends the conversion date. WES distributed 1.1 million Class C units to Anadarko during 2018 , and 886 thousand Class C units to Anadarko during 2017 , and 946 thousand Class C units to Anadarko during 2016 . See Midstream Asset Sale and WES Merger below. WGP is a limited partnership formed by Anadarko to own interests in WES. Anadarko sold 12.5 million WGP common units to the public for net proceeds of $476 million in 2016. In June 2018, Anadarko settled 9.2 million outstanding TEUs, originally issued in 2015, in exchange for approximately 8.2 million WGP common units. For additional disclosure of the TEU effect on noncontrolling interests, see Note 12—Tangible Equity Units . At December 31, 2018 , Anadarko’s ownership interest in WGP consisted of a 77.8% limited partner interest and the entire non-economic general partner interest. The remaining 22.2% limited partner interest in WGP was owned by the public. At December 31, 2018 , WGP’s ownership interest in WES consisted of a 29.6% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At December 31, 2018 , Anadarko also owned a 9.7% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.2% limited partner interest in WES was owned by the public. Midstream Asset Sale and WES Merger At the end of 2018, Anadarko announced the planned contribution and sale of substantially all of its midstream assets not owned by WES, which are largely associated with Anadarko's two premier U.S. onshore oil plays in the Delaware and DJ basins, to WES for approximately $4.0 billion , with approximately $2.0 billion of cash proceeds and the balance to be paid in WES common units. Additionally, at the end of 2018, WES announced that a wholly owned subsidiary of WGP will merge with and into WES, with WES continuing as the surviving entity and a subsidiary of WGP, which will result in a simplified midstream structure. Under the terms of the WES Merger, WGP will acquire all of the outstanding publicly held common units of WES and substantially all of the WES common units owned by Anadarko, including the Class C units, which will be converted into WES common units immediately prior to the transaction, in a unit-for-unit, tax-free exchange. WES will survive as a partnership with no publicly traded equity, owned 98% by WGP and 2% by Anadarko. WES will remain the borrower for all existing debt, is expected to remain the borrower for all future debt, and will remain the owner of all operating assets and equity investments. Anadarko will maintain operating control of WGP, with approximately 55.5% pro forma ownership of the combined entity. The WES Merger closed in the first quarter of 2019 concurrently with the asset contribution and sale.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2018
Variable Interest Entities [Abstract]
Variable Interest Entities	25. Variable Interest Entities Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES; therefore, Anadarko is considered the primary beneficiary and consolidates WGP, WES, and all of their consolidated subsidiaries. See Note 24—Noncontrolling Interests for additional information on WGP and WES. The following tables present selected financial data from the consolidated financial statements of WGP: millions 2018 2017 2016 Statement of Operations Data Total revenues and other $ 1,990 $ 2,248 $ 1,804 Operating income (loss) 625 704 705 Net income (loss) 449 573 597 Statement of Cash Flows Data Net cash provided by (used in) operating activities $ 1,017 $ 897 $ 913 Net cash provided by (used in) investing activities (1,460 ) (764 ) (1,106 ) Net cash provided by (used in) financing activities 456 (413 ) 452 millions 2018 2017 Balance Sheet Data Net property, plant, and equipment $ 6,612 $ 5,731 Total assets 9,239 8,016 Long-term debt 4,787 3,493 Total liabilities 5,734 4,071 Total equity and partners’ capital 3,505 3,945 millions 2018 2017 2016 WGP distributions to Anadarko (1) $ 408 $ 368 $ 321 WGP distributions to third parties 494 443 362 (1) WGP distributions to Anadarko are eliminated upon consolidation. 25. Variable Interest Entities (Continued) Assets and Liabilities of VIEs The 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 December 31, 2018 and 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 December 31, 2018 and 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 13—Debt and Interest Expense for additional information on WGP and WES 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, or debt offerings. See Note 13—Debt and Interest Expense and Note 24—Noncontrolling Interests for additional information on WGP and WES financing activity. Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES loaned the Company $260 million in exchange for a 30 -year note bearing interest at a fixed annual rate of 6.50% , payable quarterly. The related interest income for WES was $17 million for each of the years ended December 31, 2018 , 2017 , and 2016 . 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. To reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of its contracts, Anadarko had commodity price swap agreements in place with WES during 2018. These commodity price swap agreements expired without renewal on December 31, 2018. WES recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for the amount by which the swap price for product purchases exceeds the market price. WES recorded a capital contribution from Anadarko of $52 million for the year ended December 31, 2018 , $59 million for the year ended December 31, 2017 , and $46 million for the year ended December 31, 2016 .

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	26. 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, for the years ended December 31: millions 2018 2017 2016 Cash paid (received) Interest, net of amounts capitalized $ 982 $ 906 $ 856 Income taxes, net of refunds (1) 51 64 (882 ) Non-cash investing activities Fair value of properties and equipment acquired $ 22 $ 640 $ 3 Asset retirement cost additions 523 66 298 Accruals of property, plant, and equipment 822 824 549 Net liabilities assumed (divested) in acquisitions and divestitures (111 ) (158 ) 723 Non-cash investing and financing activities Acquisition contingent consideration $ — $ — $ 103 Non-cash financing activities Settlement of tangible equity units $ 300 $ — $ — (1) Includes $881 million from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback. 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: December 31, millions 2018 2017 Cash and cash equivalents $ 1,295 $ 4,553 Restricted cash and restricted cash equivalents included in Other Assets 134 121 Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents $ 1,429 $ 4,674 Included in cash and cash equivalents is restricted cash and restricted cash equivalents of $139 million at December 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 18—Contingencies for additional information.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Information	27. Segment Information Anadarko has two reporting segments: Exploration and Production and WES Midstream, which include their respective marketing results. 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 an FID. The WES Midstream reporting segment 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. 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 certain items not related to the Company’s normal operations, less net income (loss) attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included restructuring charges related to the workforce reduction program included in G&A, (gains) losses on early extinguishment of debt, and certain other nonoperating items included in other (income) expense, net. 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 for the years ended December 31: millions 2018 2017 2016 Income (loss) before income taxes $ 1,485 $ (1,688 ) $ (3,829 ) (Gains) losses on divestitures, net (20 ) (674 ) 757 Exploration expense (1) 459 2,535 944 DD&A 4,254 4,279 4,301 Impairments 800 408 227 Interest expense 947 932 890 Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives (407 ) 156 559 Restructuring and reorganization-related charges 53 21 389 Other operating expense — — 1 (Gains) losses on early extinguishment of debt (2 ) 2 155 Certain other nonoperating items — — (58 ) Less net income (loss) attributable to noncontrolling interests 137 245 263 Consolidated Adjusted EBITDAX $ 7,432 $ 5,726 $ 4,073 (1) Includes reorganization-related charges of $20 million for the year ended December 31, 2018 . 27. Segment Information (Continued) The Company’s accounting policies for individual segments are the same as those described in the summary of significant accounting policies, with the following exception: certain intersegment commodity contracts may meet the GAAP definition of a derivative instrument, which would be accounted for at fair value under GAAP. However, Anadarko does not recognize any mark-to-market adjustments on such intersegment arrangements. Additionally, intersegment asset transfers are accounted for at historical cost basis and do not give rise to gain or loss recognition. 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 and Intersegment Eliminations Total 2018 Sales revenues $ 11,404 $ 1,610 $ 56 $ 13,070 Intersegment revenues 81 690 (771 ) — Other (4 ) 211 85 292 Total revenues and other (1) 11,481 2,511 (630 ) 13,362 Operating costs and expenses (2) 3,896 1,019 328 5,243 Net cash from settlement of commodity derivatives — — 545 545 Other (income) expense, net (3) — (8 ) 21 13 Net income (loss) attributable to noncontrolling interests — — 137 137 Total expenses and other 3,896 1,011 1,031 5,938 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 8 8 Adjusted EBITDAX $ 7,585 $ 1,500 $ (1,653 ) $ 7,432 Net properties and equipment $ 18,276 $ 8,410 $ 1,929 $ 28,615 Capital expenditures $ 4,103 $ 1,912 $ 170 $ 6,185 Goodwill $ 4,343 $ 446 $ — $ 4,789 (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, reorganization-related charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes reorganization-related charges since these expenses are excluded from Adjusted EBITDAX. 27. Segment Information (Continued) millions Exploration & Production WES Midstream Other and Intersegment Eliminations Total 2017 Sales revenues $ 8,952 $ 1,824 $ 193 $ 10,969 Intersegment revenues 21 606 (627 ) — Other 15 189 61 265 Total revenues and other (1) 8,988 2,619 (373 ) 11,234 Operating costs and expenses (2) 3,517 1,423 318 5,258 Net cash from settlement of commodity derivatives — — (27 ) (27 ) Other (income) expense, net (3) — — 26 26 Net income (loss) attributable to noncontrolling interests — — 245 245 Total expenses and other 3,517 1,423 562 5,502 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — (6 ) (6 ) Adjusted EBITDAX $ 5,471 $ 1,196 $ (941 ) $ 5,726 Net properties and equipment $ 18,729 $ 6,766 $ 1,956 $ 27,451 Capital expenditures $ 3,785 $ 1,409 $ 106 $ 5,300 Goodwill $ 4,343 $ 446 $ — $ 4,789 2016 Sales revenues $ 7,152 $ 1,146 $ 149 $ 8,447 Intersegment revenues 4 795 (799 ) — Other (5 ) 154 30 179 Total revenues and other (1) 7,151 2,095 (620 ) 8,626 Operating costs and expenses (2) 3,485 955 136 4,576 Net cash from settlement of commodity derivatives — — (265 ) (265 ) Other (income) expense, net (3) — — (13 ) (13 ) Net income (loss) attributable to noncontrolling interests — — 263 263 Total expenses and other 3,485 955 121 4,561 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 8 8 Adjusted EBITDAX $ 3,666 $ 1,140 $ (733 ) $ 4,073 Net properties and equipment $ 24,391 $ 5,658 $ 2,119 $ 32,168 Capital expenditures $ 2,689 $ 551 $ 74 $ 3,314 Goodwill $ 4,550 $ 450 $ — $ 5,000 (1) Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX. (2) Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes certain other nonoperating items and restructuring charges since these items are excluded from Adjusted EBITDAX. 27. Segment Information (Continued) The following represents Anadarko’s sales revenues (based on the origin of the sales) and net properties and equipment by geographic area: Years Ended December 31, millions 2018 2017 2016 Sales Revenues United States $ 10,659 $ 9,176 $ 7,049 Algeria 1,596 1,249 1,103 Other International 815 544 295 Total sales revenues $ 13,070 $ 10,969 $ 8,447 December 31, millions 2018 2017 Net Properties and Equipment United States $ 25,891 $ 24,382 Algeria 808 965 Other International (1) 1,916 2,104 Total net properties and equipment $ 28,615 $ 27,451 (1) Includes $519 million of capitalized costs related to the Mozambique LNG project at December 31, 2018 . Major Customers In 2018, sales to Royal Dutch Shell PLC were $1.4 billion . Sales to BP PLC were $1.3 billion in 2018 and $1.1 billion in 2017. These amounts are included in the Exploration and Production reporting segment. In 2016, there were no sales to customers that exceeded 10% of the Company’s total sales revenues.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Consolidation	Basis of Presentation The consolidated financial statements have been prepared in conformity with GAAP. Certain prior-period amounts have been reclassified to conform to the current-year presentation. 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 on the Company’s Consolidated Balance Sheets. Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 24—Noncontrolling Interests .
Use of Estimates	Use of Estimates The preparation of financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; AROs; litigation liabilities; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value	Fair Value Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows: Level 1 —Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities (for example, exchange-traded futures contracts for which parties are willing to transact at the exchange-quoted price). Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 —Inputs that are not observable from objective sources such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement). In determining fair value, the Company uses observable market data when available or models that incorporate observable market data. When the Company is required to measure fair value and there is not a market-observable price for the asset or liability or for a similar asset or liability, the Company uses the cost or income approach depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions. In arriving at fair-value estimates, the Company uses relevant observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. For Anadarko, recurring fair-value measurements are performed for interest-rate derivatives, commodity derivatives, and investments in trading securities. The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable reported on the Company’s Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 13—Debt and Interest Expense , are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, AROs, exit or disposal costs, and capital lease assets and liabilities where the present value of lease payments is greater than the fair value of the leased asset.
Revenues	Revenues 2018 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 volume. 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. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income. WES 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 volume delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period. The Company’s midstream business also purchases natural-gas volume 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. If the fees relate to services performed before control of the product has transferred to Anadarko, the fees are treated as Gathering, processing and marketing sales revenues. 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. 1. Summary of Significant Accounting Policies (Continued) 2017 This section reflects the Company’s revenue recognition policies through December 31, 2017, prior to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . 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. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volume for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. Anadarko provides gathering, processing, treating, and transporting services pursuant to a variety of contracts. Under these arrangements, the Company receives fees or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. 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 from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These transactions are reported on a net basis and included in oil and gas transportation in the Company’s Consolidated Statements of Income.
Cash Equivalents	Cash Equivalents and Restricted Cash Equivalents The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents. The cash equivalents and restricted cash equivalents balance at December 31, 2018 , includes commercial paper and investments in government money market funds in which the carrying value approximates fair value.
Accounts Receivable and Allowance for Uncollectible Accounts	Accounts Receivable and Allowance for Uncollectible Accounts The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based on these analyses, the Company may require a standby letter of credit or a financial guarantee. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued.
Inventories	Inventories Commodity inventories are stated at the lower of average cost or net realizable value.
Properties and Equipment	Properties and Equipment Properties and equipment are stated at cost less accumulated DD&A. Costs of improvements that extend the lives of existing properties are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gain or loss is recognized in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income.
Oil and Gas Properties	Oil and Gas Properties The Company applies the successful efforts method of accounting for oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are charged against earnings as incurred. Exploratory drilling costs are initially capitalized pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average lease terms at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense in the Company’s Consolidated Statements of Income.
Capitalized Interest	Capitalized Interest For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity-method affiliates that are undergoing the construction of assets that have not commenced principle operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 13—Debt and Interest Expense .
Asset Retirement Obligations	Asset Retirement Obligations AROs associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and is included in DD&A in the Company’s Consolidated Statements of Income. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. See Note 15—Asset Retirement Obligations .
Impairments	Impairments Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. See Note 6—Impairments .
Depreciation, Depletion, and Amortization	Depreciation, Depletion, and Amortization Costs of drilling and equipping successful wells, costs to construct or acquire facilities other than offshore platforms, associated asset retirement costs, and capital lease assets used in oil and gas activities are depreciated using the UOP method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the UOP method. All other properties are stated at historical acquisition cost, net of impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 40 years for buildings, and up to 40 years for gathering facilities.
Goodwill	Goodwill and Other Intangible Assets Anadarko has allocated goodwill to the following reporting units: Exploration and Production; WES Gathering and Processing; and WES Transportation. Goodwill is subject to annual impairment testing in October (or more frequent testing as circumstances dictate). Anadarko’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill, the Company will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, acquisitions, or divestitures. See Note 8—Goodwill and Other Intangible Assets .
Other Intangible Assets	Other intangible assets represent contractual rights obtained in connection with business combinations that had favorable contractual terms relative to market at the acquisition date as well as customer-related intangible assets, including customer relationships established by acquired contracts. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment with the associated long-lived asset group whenever impairment indicators are present. See Note 8—Goodwill and Other Intangible Assets .
Derivative Instruments	Derivative Instruments Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Derivatives are carried on the balance sheet at fair value and are included in other current assets, other assets, other current liabilities, or other long-term liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the normal purchases and sales exception criteria. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis. Gains and losses on derivative instruments are recognized currently in earnings. Net losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 11—Derivative Instruments .
Legal Contingencies	Legal Contingencies The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. If the Company determines that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 18—Contingencies .
Environmental Contingencies	Environmental Contingencies The Company is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. Except for environmental contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 18—Contingencies .
Income Taxes	Income Taxes The Company files various U.S. federal, state, and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. Deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). The Company uses the flow-through method to account for its investment tax credits. See Note 14—Income Taxes .
Share-Based Compensation	Share-Based Compensation The Company accounts for share-based compensation at fair value. The Company grants equity-classified awards, including stock options and non-vested equity shares (restricted stock awards and units). The Company may also grant equity-classified and liability-classified awards based on a comparison of the Company’s TSR to the TSR of a predetermined group of peer companies (performance units). The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of Anadarko common stock. For other share-based compensation awards, fair value is determined using a Monte Carlo simulation. The Company records compensation cost, net of actual forfeitures, for share-based compensation awards over the requisite service period using the straight-line method. For equity-classified share-based compensation awards, expense is recognized based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid. See Note 23—Share-Based Compensation .
Recently Issued Accounting Standards	Accounting Standards Adopted in 2019 ASU 2016-02, Leases (Topic 842) This ASU 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. This standard is effective for periods beginning after December 15, 2018, and in the first quarter of 2019, the Company fully adopted this standard using the modified retrospective method applied to all leases that existed on January 1, 2019. Anadarko made certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases. Upon adoption, the Company recognized approximately $600 million of ROU assets and lease liabilities on its Consolidated Balance Sheet related to leases existing on January 1, 2019. The adoption of this ASU did not have a material impact on the Company’s Consolidated Statement of Income or Consolidated Statement of Cash Flows. Anadarko has not identified any material leases in which Anadarko is a lessor. The Company has implemented the necessary changes to its business processes, systems, and controls to support accounting and disclosure requirements under this ASU.
Pension and Other Postretirement Plans	The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and inflation (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually. Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. Assumed rates of compensation increases for active participants vary by age group, with the resulting weighted-average assumed rate (weighted by the plan-level benefit obligation) provided in the preceding table. Investment Policies and Strategies The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (domestic equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 50% equity securities, 25% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines. Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2018 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, changes in valuation, and inflation. Returns on fixed-income securities are generally developed based on expected cash returns, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are generally derived from their relationship to the equity and fixed-income markets.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 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: CONSOLIDATED BALANCE SHEET Impact of Change in Accounting Policy millions As Reported Without Adoption of Topic 606 Effect of Change Increase/(Decrease) December 31, 2018 Assets Other current assets $ 474 $ 472 $ 2 Net properties and equipment 28,615 28,548 67 Other assets 2,336 2,326 10 Liabilities Other current liabilities 1,295 1,290 5 Deferred income taxes 2,437 2,441 (4 ) Other 4,021 3,914 107 Equity Total equity 10,943 10,972 (29 ) 2. Revenue from Contracts with Customers (Continued) CONSOLIDATED STATEMENT OF INCOME Impact of Change in Accounting Policy millions As Reported Without Adoption of Topic 606 Effect of Change Increase/(Decrease) Year Ended December 31, 2018 Revenues Gathering, processing, and marketing sales $ 1,588 $ 2,592 $ (1,004 ) Gains (losses) on divestitures and other, net 312 316 (4 ) Expenses Gathering, processing, and marketing 1,047 2,075 (1,028 ) Income tax expense (benefit) 733 731 2 Net income (loss) attributable to noncontrolling interests 137 127 10 Net Income (Loss) Attributable to Common Stockholders $ 615 $ 607 $ 8
Schedule of Disaggregation of Revenue	The following table disaggregates revenue by significant product type and segment: millions Exploration WES Midstream Other and Total Year Ended December 31, 2018 Oil sales $ 9,206 $ — $ — $ 9,206 Natural-gas sales 1,005 — — 1,005 Natural-gas liquids sales 1,271 — — 1,271 Gathering, processing, and marketing sales (1) 3 2,305 126 2,434 Other, net 30 — 98 128 Total Revenue from Customers $ 11,515 $ 2,305 $ 224 $ 14,044 Gathering, processing, and marketing sales (2) — (5 ) (841 ) (846 ) Gains (losses) on divestitures, net 20 — — 20 Other, net (34 ) 211 (13 ) 164 Total Revenue from Other than Customers $ (14 ) $ 206 $ (854 ) $ (662 ) Total Revenue and Other $ 11,501 $ 2,511 $ (630 ) $ 13,382 (1) The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $957 million and intersegment eliminations of $(772) million for the year ended December 31, 2018 . (2) The amount in Other and Intersegment Eliminations primarily 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 66 Increase due to assets received from customer 13 Decrease due to revenue recognized (42 ) Decrease due to change in estimated consideration (22 ) Balance at December 31, 2018 $ 150 Contract liabilities at December 31, 2018 Other current liabilities $ 31 Other long-term liabilities - other 119 Total contract liabilities from contracts with customers $ 150
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 volume and variable commodity prices for this volume. millions Exploration WES Midstream Other and Total 2019 $ 104 $ 675 $ (433 ) $ 346 2020 103 847 (614 ) 336 2021 103 895 (681 ) 317 2022 7 947 (740 ) 214 2023 7 913 (750 ) 170 Thereafter 58 4,565 (4,077 ) 546 Total $ 382 $ 8,842 $ (7,295 ) $ 1,929

Commodity Inventories (Tables)

Commodity Inventories (Tables)	12 Months Ended
	Dec. 31, 2018
Energy Related Inventory [Abstract]
Inventory Disclosure Table	The following summarizes the major classes of commodity inventories included in other current assets at December 31: millions 2018 2017 Oil $ 139 $ 165 Natural gas 18 29 NGLs 78 122 Total commodity inventories $ 235 $ 316

Divestitures and Assets Held _2

Divestitures and Assets Held for Sale Divestitures and Assets Held for Sale (Tables)	12 Months Ended
	Dec. 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 and assets held for sale for the years ended December 31: millions 2018 2017 2016 Proceeds received, net of closing adjustments $ 417 $ 4,008 $ 2,356 Gains (losses) on divestitures, net (1) (2) 20 674 (757 ) (1) Includes goodwill allocated to divestitures of $209 million in 2017 and $397 million in 2016 . (2) Includes gain of $126 million related to the 2017 property exchange discussed below.

Properties and Equipment (Table

Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment, Gross [Abstract]
Cost of Properties and Equipment by Segment Table	The following summarizes properties and equipment at December 31: millions 2018 2017 Exploration and Production (1) $ 52,796 $ 50,221 WES Midstream 11,259 8,980 Other 2,465 2,357 Gross properties and equipment $ 66,520 $ 61,558 Less accumulated DD&A 37,905 34,107 Net properties and equipment $ 28,615 $ 27,451 (1) Includes costs associated with unproved properties of $1.7 billion at December 31, 2018 , and $2.4 billion at December 31, 2017 .

Impairments (Tables)

Impairments (Tables)	12 Months Ended
	Dec. 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 at December 31: 2018 2017 2016 millions Impairment Fair Value (1) Impairment Fair Value (1) Impairment Fair Value (1) Exploration and Production U.S. onshore properties $ 397 $ 172 $ 2 $ 3 $ 28 $ 617 Gulf of Mexico properties 27 — 227 216 27 61 Cost-method investment — — — — 59 — WES Midstream 231 30 178 58 18 3 Other 145 15 1 — 95 29 Total impairments $ 800 $ 217 $ 408 $ 277 $ 227 $ 710 (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.

Suspended Exploratory Well Co_2

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2018
Capitalized Exploratory Well Costs [Abstract]
Suspended Exploratory Well Costs Rollforward	The following summarizes the changes in suspended exploratory well costs at December 31 for each of the last three years: millions 2018 2017 2016 Balance at January 1 $ 525 $ 1,230 $ 1,124 Additions pending the determination of proved reserves (1) 90 349 490 Divestitures and other (38 ) (36 ) (11 ) Reclassifications to proved properties (132 ) (41 ) (50 ) Charges to exploration expense (1 ) (977 ) (323 ) Balance at December 31 $ 444 $ 525 $ 1,230 (1) Excludes amounts capitalized and subsequently charged to expense within the same year.
Schedule of Aging of Capitalized Exploratory Well Costs	The following provides an aging of suspended well balances at December 31: millions 2018 2017 2016 Exploratory well costs capitalized for a period of one year or less $ 152 $ 201 $ 460 Exploratory well costs capitalized for a period greater than one year 292 324 770 Balance at December 31 $ 444 $ 525 $ 1,230 7. Suspended Exploratory Well Costs (Continued) The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2018 : millions except projects Number of Projects Total 2017 2016 2015 and U.S. onshore 1 $ 2 $ — $ — $ 2 U.S. offshore 1 73 (1 ) 74 — International 3 217 11 14 192 5 $ 292 $ 10 $ 88 $ 194

Goodwill and Other Intangible_2

Goodwill and Other Intangible Assets Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Other Intangible Assets	Intangible assets and associated amortization expense were as follows at December 31: millions 2018 2017 Gross carrying amount $ 980 $ 1,013 Accumulated amortization (139 ) (140 ) Net carrying amount $ 841 $ 873 Amortization expense $ 32 $ 31

Current Liabilities (Tables)

Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Payables and Accruals [Abstract]
Schedule of Other Current Liabilities	The following summarizes the Company’s other current liabilities at December 31: millions 2018 2017 Accrued income taxes $ 167 $ 71 Interest payable 267 246 Production, property, and other taxes payable 309 216 Accrued employee benefits 319 210 Derivatives 89 384 Other 144 183 Total other current liabilities $ 1,295 $ 1,310

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The Company had the following outstanding interest-rate swaps at December 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 % $ 100 September 2017 - 2047 September 2020 6.891 % $ 250 September 2017 - 2047 September 2021 6.570 % $ 450 September 2017 - 2047 September 2023 6.445 % The following interest-rate swaps were outstanding at December 31, 2018 : millions except percentages Mandatory Fixed Notional Principal Amount Reference Period Termination Date Interest Rate $ 250 December 2019 - 2024 December 2019 2.730 % $ 250 December 2019 - 2029 December 2019 2.856 % $ 250 December 2019 - 2049 December 2019 2.905 % The following is a summary of the Company’s oil derivative instruments at December 31, 2018 : 2019 Settlement Oil Three-Way Collars (MBbls/d) 87 Average price per barrel Ceiling sold price (call) $ 72.98 Floor purchased price (put) $ 56.72 Floor sold price (put) $ 46.72
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 at December 31: millions Gross Derivative Assets Gross Derivative Liabilities Balance Sheet Classification 2018 2017 2018 2017 Commodity derivatives - Anadarko (1) Other current assets $ 300 $ 7 $ (126 ) $ (1 ) Other assets — 2 — — Other current liabilities 1 45 (6 ) (206 ) Other liabilities — — — (2 ) 301 54 (132 ) (209 ) Interest-rate derivatives - Anadarko (1) Other current assets 22 14 — — Other assets 34 40 — — Other current liabilities — — (82 ) (236 ) Other liabilities — — (1,156 ) (1,183 ) 56 54 (1,238 ) (1,419 ) Interest-rate derivatives - WES Other current liabilities — — (8 ) — Total derivatives $ 357 $ 108 $ (1,378 ) $ (1,628 ) (1) Excludes amounts related to WES interest-rate swap agreements. The following summarizes gains and losses related to derivative instruments: millions Classification of (Gain) Loss Recognized 2018 2017 2016 Commodity derivatives - Anadarko (1) Gathering, processing, and marketing sales $ 8 $ (4 ) $ 6 (Gains) losses on derivatives, net 213 3 147 Interest-rate derivatives - Anadarko (1) (Gains) losses on derivatives, net (91 ) 132 139 Interest-rate derivatives - WES (Gains) losses on derivatives, net 8 — — Total (gains) losses on derivatives, net $ 138 $ 131 $ 292 (1) Excludes amounts related to WES interest-rate swap agreements.
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 December 31, 2018 Assets Anadarko (2) Commodity derivatives $ 1 $ 300 $ — $ (127 ) $ — $ 174 Interest-rate derivatives — 56 — — — 56 Total derivative assets $ 1 $ 356 $ — $ (127 ) $ — $ 230 Liabilities Anadarko (2) Commodity derivatives $ (2 ) $ (130 ) $ — $ 127 $ 2 $ (3 ) Interest-rate derivatives — (1,238 ) — — 66 (1,172 ) WES Interest-rate derivatives — (8 ) — — — (8 ) Total derivative liabilities $ (2 ) $ (1,376 ) $ — $ 127 $ 68 $ (1,183 ) December 31, 2017 Assets Anadarko (2) Commodity derivatives $ 1 $ 53 $ — $ (46 ) $ (1 ) $ 7 Interest-rate derivatives — 54 — — — 54 Total derivative assets $ 1 $ 107 $ — $ (46 ) $ (1 ) $ 61 Liabilities Anadarko (2) 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. (2) Excludes amounts related to WES interest-rate swap agreements.

Debt and Interest Expense (Tabl

Debt and Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt Activity and Debt Outstanding Tables	The following summarizes the Company’s outstanding debt, including capital lease obligations, after eliminating the effect of intercompany transactions: December 31, 2018 millions WES WGP (1) Anadarko (2) Anadarko Consolidated 6.950% Senior Notes due 2019 $ — $ — $ 300 $ 300 8.700% Senior Notes due 2019 — — 600 600 4.850% Senior Notes due 2021 — — 677 677 WES 5.375% Senior Notes due 2021 500 — — 500 WES 4.000% Senior Notes due 2022 670 — — 670 3.450% Senior Notes due 2024 — — 248 248 6.950% Senior Notes due 2024 — — 650 650 WES 3.950% Senior Notes due 2025 500 — — 500 WES 4.650% Senior Notes due 2026 500 — — 500 5.550% Senior Notes due 2026 — — 1,100 1,100 7.500% Debentures due 2026 — — 112 112 7.000% Debentures due 2027 — — 48 48 7.125% Debentures due 2027 — — 150 150 WES 4.500% Notes due 2028 400 — — 400 WES 4.750% Notes due 2028 400 — — 400 6.625% Debentures due 2028 — — 14 14 7.150% Debentures due 2028 — — 235 235 7.200% Debentures due 2029 — — 135 135 7.950% Debentures due 2029 — — 116 116 7.500% Senior Notes due 2031 — — 900 900 7.875% Senior Notes due 2031 — — 500 500 Zero Coupon Senior Notes due 2036 — — 2,270 2,270 6.450% Senior Notes due 2036 — — 1,750 1,750 7.950% Senior Notes due 2039 — — 325 325 6.200% Senior Notes due 2040 — — 750 750 4.500% Senior Notes due 2044 — — 625 625 WES 5.450% Senior Notes due 2044 600 — — 600 6.600% Senior Notes due 2046 — — 1,100 1,100 WES 5.300% Notes due 2048 700 — — 700 WES 5.500% Notes due 2048 350 — — 350 7.730% Debentures due 2096 — — 61 61 7.500% Debentures due 2096 — — 78 78 7.250% Debentures due 2096 — — 49 49 WES RCF 220 — — 220 WGP RCF — 28 — 28 Total borrowings at face value $ 4,840 $ 28 $ 12,793 $ 17,661 Net unamortized discounts, premiums, and debt issuance costs (3) (53 ) — (1,439 ) (1,492 ) Total borrowings (4) 4,787 28 11,354 16,169 Capital lease obligations — — 248 248 Less short-term debt — 28 919 947 Total long-term debt $ 4,787 $ — $ 10,683 $ 15,470 13. Debt and Interest Expense (Continued) December 31, 2017 millions WES WGP (1) Anadarko (2) Anadarko Consolidated 7.050% Debentures due 2018 $ — $ — $ 114 $ 114 TEUs - senior amortizing notes due 2018 — — 17 17 WES 2.600% Senior Notes due 2018 350 — — 350 6.950% Senior Notes due 2019 — — 300 300 8.700% Senior Notes due 2019 — — 600 600 4.850% Senior Notes due 2021 — — 800 800 WES 5.375% Senior Notes due 2021 500 — — 500 WES 4.000% Senior Notes due 2022 670 — — 670 3.450% Senior Notes due 2024 — — 625 625 6.950% Senior Notes due 2024 — — 650 650 WES 3.950% Senior Notes due 2025 500 — — 500 WES 4.650% Senior Notes due 2026 500 — — 500 5.550% Senior Notes due 2026 — — 1,100 1,100 7.500% Debentures due 2026 — — 112 112 7.000% Debentures due 2027 — — 48 48 7.125% Debentures due 2027 — — 150 150 6.625% Debentures due 2028 — — 14 14 7.150% Debentures due 2028 — — 235 235 7.200% Debentures due 2029 — — 135 135 7.950% Debentures due 2029 — — 116 116 7.500% Senior Notes due 2031 — — 900 900 7.875% Senior Notes due 2031 — — 500 500 Zero Coupon Senior Notes due 2036 — — 2,360 2,360 6.450% Senior Notes due 2036 — — 1,750 1,750 7.950% Senior Notes due 2039 — — 325 325 6.200% Senior Notes due 2040 — — 750 750 4.500% Senior Notes due 2044 — — 625 625 WES 5.450% Senior Notes due 2044 600 — — 600 6.600% Senior Notes due 2046 — — 1,100 1,100 7.730% Debentures due 2096 — — 61 61 7.500% Debentures due 2096 — — 78 78 7.250% Debentures due 2096 — — 49 49 WES RCF 370 — — 370 WGP RCF — 28 — 28 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. The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions: Carrying Value millions WES WGP (1) Anadarko (2) Anadarko Consolidated Description Balance at December 31, 2016 $ 3,091 $ 28 $ 11,959 $ 15,078 Borrowings 370 — — 370 WES RCF Repayments — — (6 ) (6 ) 7.000% Debentures due 2027 — — (3 ) (3 ) 6.625% Debentures due 2028 — — (1 ) (1 ) 7.950% Debentures due 2029 — — (34 ) (34 ) TEUs - senior amortizing notes Other, net 4 — 50 54 Amortization of discounts, premiums, and debt issuance costs Balance at December 31, 2017 $ 3,465 $ 28 $ 11,965 $ 15,458 Issuances 394 — — 394 WES 4.500% Senior Notes due 2028 687 — — 687 WES 5.300% Senior Notes due 2048 396 — — 396 WES 4.750% Senior Notes due 2028 342 — — 342 WES 5.500% Senior Notes due 2048 Borrowings 540 — — 540 WES RCF Repayments — — (114 ) (114 ) 7.050% Debentures due 2018 — — (123 ) (123 ) 4.850% Senior Notes due 2021 — — (375 ) (375 ) 3.450% Senior Notes due 2024 — — (35 ) (35 ) Zero Coupon Notes due 2036 (350 ) — — (350 ) WES 2.600% Senior Notes due 2018 (690 ) — — (690 ) WES RCF — — (17 ) (17 ) TEUs - senior amortizing notes Other, net 3 — 53 56 Amortization of discounts, premiums, and debt issuance costs Balance at December 31, 2018 $ 4,787 $ 28 $ 11,354 $ 16,169 (1) Excludes WES. (2) Excludes WES and WGP.
Scheduled Maturities Table	Total principal amount of debt maturities related to borrowings for the five years ending December 31, 2023 , excluding the potential repayment of the outstanding Zero Coupons that may be put by the holders to the Company annually, were as follows: Principal Amount of Debt Maturities millions WES WGP (1) Anadarko (2) Anadarko Consolidated 2019 $ — $ 28 $ 900 $ 928 2020 — — — — 2021 500 — 677 1,177 2022 670 — — 670 2023 220 — — 220 (1) Excludes WES. (2) Excludes WES and WGP.
Schedule of Future Minimum Lease Payments for Capital Leases	At December 31, 2018 , future minimum lease payments related to the Company’s capital leases were: millions 2019 $ 58 2020 50 2021 48 2022 45 2023 43 Thereafter 323 Total future minimum lease payments $ 567 Less portion representing imputed interest 319 Capital lease obligations $ 248
Interest Expense Table	The following summarizes interest expense for the years ended December 31: millions 2018 2017 2016 Debt and other $ 1,028 $ 1,003 $ 1,022 Capitalized interest (81 ) (71 ) (132 ) Total interest expense $ 947 $ 932 $ 890

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The following summarizes components of income tax expense (benefit) for the years ended December 31: millions 2018 2017 2016 Current Federal $ 14 $ 236 $ (140 ) State (1 ) 48 (1 ) Foreign 595 414 378 Total current tax expense (benefit) 608 698 237 Deferred Federal 150 (2,082 ) (1,020 ) State (26 ) (17 ) (148 ) Foreign 1 (76 ) (90 ) Total deferred tax expense (benefit) 125 (2,175 ) (1,258 ) Total income tax expense (benefit) $ 733 $ (1,477 ) $ (1,021 )
Schedule of Effective Income Tax Rate Reconciliation	The following summarizes the sources of these differences for the years ended December 31: millions except percentages 2018 2017 2016 Income (loss) before income taxes Domestic $ 492 $ (1,322 ) $ (3,728 ) Foreign 993 (366 ) (101 ) Total $ 1,485 $ (1,688 ) $ (3,829 ) U.S. federal statutory tax rate 21 % 35 % 35 % Tax computed at the U.S. federal statutory rate $ 312 $ (591 ) $ (1,340 ) (Income) loss attributable to noncontrolling interests (29 ) (85 ) (92 ) Adjustments resulting from State income taxes (net of federal income tax benefit) (18 ) 25 (108 ) U.S. federal tax reform 95 (1,168 ) — Tax impact from foreign operations 181 166 80 Non-deductible Algerian exceptional profits tax 154 110 106 Net changes in uncertain tax positions (29 ) 90 90 Dispositions of non-deductible goodwill — 6 205 Other, net 67 (30 ) 38 Total income tax expense (benefit) $ 733 $ (1,477 ) $ (1,021 ) Effective tax rate 49 % 88 % 27 %
Deferred Tax Assets (Liabilities) Table	The following summarizes components of total deferred taxes at December 31: millions 2018 2017 Federal $ (1,972 ) $ (1,758 ) State, net of federal (176 ) (200 ) Foreign (255 ) (255 ) Total deferred taxes (1) $ (2,403 ) $ (2,213 ) (1) Net deferred tax assets related to Algeria of $34 million in 2018 and $21 million in 2017 are presented in other assets on the Company’s Consolidated Balance Sheet. 14. Income Taxes (Continued) The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31: millions 2018 2017 Deferred tax liabilities Oil and gas exploration and development operations $ (2,403 ) $ (2,622 ) Midstream and other depreciable properties (662 ) (543 ) Mineral operations (238 ) (312 ) Other (134 ) (53 ) Gross long-term deferred tax liabilities (3,437 ) (3,530 ) Deferred tax assets Oil and gas exploration and development costs 303 309 Foreign and state net operating loss carryforwards 445 562 U.S. foreign tax credit carryforwards 2,665 2,685 Compensation and benefit plans 301 365 Other 308 420 Gross long-term deferred tax assets 4,022 4,341 Valuation allowances on deferred tax assets not expected to be realized (2,988 ) (3,024 ) Net long-term deferred tax assets 1,034 1,317 Total deferred taxes $ (2,403 ) $ (2,213 )
Valuation Allowances on Deferred Tax Assets Rollforward	The following summarizes changes in the balance of valuation allowances on deferred tax assets: millions 2018 2017 2016 Balance at January 1 $ (3,024 ) $ (1,755 ) $ (1,403 ) Changes due to U.S. foreign tax credits (50 ) (1,287 ) (477 ) Changes due to foreign and state net operating loss carryforwards 72 75 13 Changes due to foreign capitalized costs 14 (57 ) 112 Balance at December 31 $ (2,988 ) $ (3,024 ) $ (1,755 )
Schedule of Operating Loss Carryforwards	Tax carryforwards available, prior to valuation allowance, at December 31, 2018 , were as follows: millions Domestic Foreign Expiration Net operating loss—state (1) $ 4,250 $ — 2019-2038 Net operating loss—foreign $ — $ 820 2019-Indefinite Foreign tax credits (2) $ 2,665 $ — 2023-2028 Texas margins tax credit $ 27 $ — 2026 (1) Net of $711 million uncertain tax position at December 31, 2018. (2) Net of $378 million uncertain tax position at December 31, 2018.
Schedule of Tax Credit Carryforwards	Tax carryforwards available, prior to valuation allowance, at December 31, 2018 , were as follows: millions Domestic Foreign Expiration Net operating loss—state (1) $ 4,250 $ — 2019-2038 Net operating loss—foreign $ — $ 820 2019-Indefinite Foreign tax credits (2) $ 2,665 $ — 2023-2028 Texas margins tax credit $ 27 $ — 2026 (1) Net of $711 million uncertain tax position at December 31, 2018. (2) Net of $378 million uncertain tax position at December 31, 2018.
Taxes Receivable (Payable) Table	The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31: millions Balance Sheet Classification 2018 2017 Income taxes receivable Accounts receivable—other $ 46 $ 53 Other assets 51 101 97 154 Income taxes (payable) Other current liabilities (167 ) (71 ) Total net income taxes receivable (payable) $ (70 ) $ 83
Unrecognized Tax Benefits Rollforward	Changes in the balance of unrecognized tax benefits, excluding interest and penalties on uncertain tax positions, were as follows: Assets (Liabilities) millions 2018 2017 2016 Balance at January 1 $ (1,317 ) $ (1,456 ) $ (1,780 ) Increases related to prior-year tax positions (21 ) (15 ) (86 ) Decreases related to prior-year tax positions 48 214 436 Increases related to current-year tax positions — (72 ) (26 ) Settlements 1 12 — Lapse of statute of limitations 2 — — Balance at December 31 $ (1,287 ) $ (1,317 ) $ (1,456 )
Tax Years Subject to Examination by Major Tax Jurisdiction Table	The following lists the tax years subject to examination by major tax jurisdiction: Tax Years United States 2013-2018 Algeria 2015-2018 Ghana 2015-2018

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Rollforward	The following summarizes changes in the Company’s AROs: millions 2018 2017 Carrying amount at January 1 $ 2,794 $ 2,931 Liabilities acquired — 4 Liabilities incurred 153 191 Property dispositions (99 ) (154 ) Liabilities settled (274 ) (135 ) Accretion expense 130 144 Revisions in estimated liabilities 395 (187 ) Carrying amount at December 31 $ 3,099 $ 2,794

Conveyance of Future Hard Min_2

Conveyance of Future Hard Minerals Royalty Revenues (Tables)	12 Months Ended
	Dec. 31, 2018
Deferred Revenue Disclosure [Abstract]
Schedule of Future Royalty Payments	The following summarizes the remaining amounts that the Company expects to pay, prior to the potential 3% to 4% of any excess described above: millions 2019 $ 52 2020 57 2021 57 2022 58 2023 60 Thereafter 144 Total $ 428

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Lease Payments	The following summarizes future minimum lease payments under operating leases at December 31, 2018 : millions 2019 $ 264 2020 139 2021 57 2022 35 2023 24 Thereafter 135 Total future minimum lease payments $ 654
Schedule of Gross Aggregate Future Payments of Other Commitments	The following summarizes the gross aggregate future payments under these contracts at December 31, 2018 : millions 2019 $ 1,147 2020 1,155 2021 993 2022 786 2023 646 Thereafter 1,498 Total (1) $ 6,225 (1) Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.

Pension Plans, Other Postreti_2

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Schedule of Changes in Benefit Obligations, Fair Value of Plan Assets, and Funded Status of the Plans	The following sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2018 and 2017 , as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2018 and 2017 : Pension Benefits Other Benefits millions 2018 2017 2018 2017 Change in benefit obligation Benefit obligation at beginning of year $ 2,218 $ 2,301 $ 302 $ 296 Service cost 90 87 1 2 Interest cost 77 84 11 12 Actuarial (gain) loss (176 ) 107 (23 ) 15 Curtailments, settlements, and special termination benefits expense 15 23 — (1 ) Participant contributions — — 7 5 Benefit payments (268 ) (396 ) (25 ) (27 ) Foreign-currency exchange-rate changes (8 ) 12 — — Benefit obligation at end of year (1) $ 1,948 $ 2,218 $ 273 $ 302 Change in plan assets Fair value of plan assets at beginning of year $ 1,424 $ 1,340 $ — $ — Actual return on plan assets (57 ) 209 — — Employer contributions 225 254 19 22 Participant contributions — — 7 5 Benefits paid related to plan settlements (212 ) (337 ) (1 ) (3 ) Benefit payments, other (56 ) (59 ) (25 ) (24 ) Foreign-currency exchange-rate changes (10 ) 17 — — Fair value of plan assets at end of year $ 1,314 $ 1,424 $ — $ — Funded status of the plans at end of year $ (634 ) $ (794 ) $ (273 ) $ (302 ) __________________________________________________________________ (1) The accumulated benefit obligation for all defined-benefit pension plans was $1.6 billion at December 31, 2018 and $1.9 billion at December 31, 2017 .
Schedule of Amounts Recognized in Balance Sheet	Amounts recognized on the balance sheet Other assets $ 63 $ 58 $ — $ — Other current liabilities (42 ) (16 ) (21 ) (21 ) Other long-term liabilities—other (655 ) (836 ) (252 ) (281 ) Total $ (634 ) $ (794 ) $ (273 ) $ (302 )
Schedule of Amounts Recognized in Accumulated Other Comprehensive Income	Amounts recognized in accumulated other comprehensive income Prior service (credit) cost $ 1 $ — $ (2 ) $ (26 ) Net actuarial (gain) loss 399 501 (9 ) 14 Total $ 400 $ 501 $ (11 ) $ (12 )
Schedule of Defined-Benefit Pension Plans With Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	The following summarizes the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets for the years ended December 31: millions 2018 2017 Projected benefit obligation $ 1,828 $ 2,079 Accumulated benefit obligation 1,527 1,749 Fair value of plan assets 1,131 1,227
Components of Net Periodic Benefit Cost Table	The following summarizes the Company’s pension and other postretirement benefit cost for the years ended December 31: Pension Benefits Other Benefits millions 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost Service cost $ 90 $ 87 $ 99 $ 1 $ 2 $ 3 Interest cost 77 84 95 11 12 12 Expected (return) loss on plan assets (83 ) (84 ) (97 ) — — — Amortization of net actuarial (gain) loss 25 25 42 — — — Amortization of net prior service (credit) cost — (1 ) — (24 ) (24 ) (25 ) Settlement expense (1) 49 91 146 — — — Termination benefits expense (1) 7 4 44 — — — Curtailment expense (1) (1 ) — 8 — — — Net periodic benefit cost (2) $ 164 $ 206 $ 337 $ (12 ) $ (10 ) $ (10 ) (1) Settlement expense, termination benefits expense, and curtailment expense for 2016 relate to the workforce reduction program initiated in the first quarter of 2016. See Note 19—Restructuring Charges . (2) 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.
Schedule of Amounts Recognized in Other Comprehensive Income	The following summarizes the amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31: Pension Benefits Other Benefits millions 2018 2017 2016 2018 2017 2016 Amounts recognized in other comprehensive income (expense) Net actuarial gain (loss) $ 27 $ — $ (150 ) $ 23 $ (14 ) $ (25 ) Amortization of net actuarial (gain) loss 74 116 188 — — — Amortization of net prior service (credit) cost — (1 ) — (24 ) (24 ) (34 ) Total amounts recognized in other comprehensive income (expense) $ 101 $ 115 $ 38 $ (1 ) $ (38 ) $ (59 )
Schedule of Assumptions Used	The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations and net periodic benefit cost for the years ended December 31: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Benefit obligation assumptions Discount rate 4.30 % 3.62 % 4.06 % 4.43 % 3.75 % 4.26 % Rates of increase in compensation levels 5.33 % 5.36 % 5.40 % 5.43 % 5.46 % 5.48 % Net periodic benefit cost assumptions Discount rate 3.62 % 4.06 % 4.62 % 3.75 % 4.26 % 5.00 % Long-term rate of return on plan assets 6.09 % 6.12 % 6.77 % N/A N/A N/A Rates of increase in compensation levels 5.36 % 5.40 % 5.34 % 5.46 % 5.48 % 5.41 %
Fair Value Hierarchy of Plan Assets Table	The fair value of the Company’s pension plan assets by asset class and input level within the fair-value hierarchy were as follows: millions December 31, 2018 Level 1 Level 2 Level 3 (3) Total Investments Cash and cash equivalents $ 28 $ — $ — $ 28 Fixed income 43 28 — 71 Equity securities 189 — — 189 Other Real estate — — 13 13 Other — 49 — 49 Investments measured at net asset value (1) — — — 964 Total investments (2) $ 260 $ 77 $ 13 $ 1,314 December 31, 2017 Investments Cash and cash equivalents $ 1 $ — $ — $ 1 Fixed income 55 31 — 86 Equity securities 185 — — 185 Other Real estate — — 13 13 Other — 53 — 53 Investments measured at net asset value (1) — — — 1,086 Total investments (2) $ 241 $ 84 $ 13 $ 1,424 (1) Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. (2) Amount excludes receivables and payables, primarily related to Level 1 investments. (3) There were no changes in Level 3 investments for the year ended December 31, 2018 . The changes in Level 3 investments of $3 million for the year ended December 31, 2017 , were attributable to the actual return on plan assets still held at the reporting date.
Schedule Of Estimated Future and Current Year Employer Contributions	The following summarizes the Company’s contributions for 2018 and expected contributions for 2019 : millions Expected 2019 2018 Funded pension plans $ 90 $ 161 Unfunded pension plans 43 64 Unfunded other postretirement plans 22 19 Total $ 155 $ 244
Schedule of Estimated Future Benefit Payments	The following summarizes estimated benefit payments for the next 10 years, including benefit increases due to continuing employee service: millions Pension Benefit Payments Other Benefit Payments 2019 $ 223 $ 22 2020 148 21 2021 150 20 2022 190 20 2023 181 20 2024-2028 839 86

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
Schedule of Accelerated Share Repurchases	During the years ended December 31, 2018 and 2017 , the Company entered into and completed ASR Agreements and open-market repurchases as presented below: millions except per-share amounts Agreement Date Settlement Date Amount Average Price per Share Initial Shares Delivered Additional Shares Delivered Total Shares Delivered ASR Agreements October 2017 December 2017 $ 1,000 $ 48.13 15.7 5.1 20.8 January 2018 February 2018 500 58.82 7.0 1.5 8.5 March 2018 June 2018 1,441 65.28 19.1 3.0 22.1 Total ASR Agreements 2,941 41.8 9.6 51.4 Open-market repurchases December 2017 December 2017 59 52.00 N/A N/A 1.1 August 2018 August 2018 250 66.14 N/A N/A 3.8 September 2018 September 2018 250 63.11 N/A N/A 3.9 December 2018 December 2018 250 52.34 N/A N/A 4.8 Total open-market repurchases 809 13.6 Total $ 3,750 $ 57.69 65.0
Common Stock Rollforward	The following summarizes the changes in the Company’s outstanding shares of common stock: millions 2018 2017 2016 Shares of common stock issued Shares at January 1 574 572 528 Exercise of stock options — — 1 Issuance of common stock — — 41 Issuance of restricted stock 3 2 2 Shares at December 31 577 574 572 Shares of common stock held in treasury Shares at January 1 43 21 20 Purchase of treasury stock 43 22 — Shares received for restricted stock vested and stock options exercised 1 — 1 Shares at December 31 87 43 21 Shares of common stock outstanding at December 31 490 531 551
Earnings Per Share Table	The following provides a reconciliation between basic and diluted EPS attributable to common stockholders for the years ended December 31: millions except per-share amounts 2018 2017 2016 Net income (loss) Net income (loss) attributable to common stockholders $ 615 $ (456 ) $ (3,071 ) Income (loss) effect of TEUs (4 ) (7 ) (6 ) Less distributions on participating securities 5 1 1 Basic $ 606 $ (464 ) $ (3,078 ) Income (loss) effect of TEUs (1 ) (2 ) (1 ) Diluted $ 605 $ (466 ) $ (3,079 ) Shares Average number of common shares outstanding—basic 504 548 522 Average number of common shares outstanding—diluted 504 548 522 Excluded due to anti-dilutive effect 9 11 11 Net income (loss) per common share Basic $ 1.20 $ (0.85 ) $ (5.90 ) Diluted $ 1.20 $ (0.85 ) $ (5.90 ) Dividends per common share $ 1.05 $ 0.20 $ 0.20

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule Of Accumulated Other Comprehensive Income (Loss) Table	The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss): millions Interest-rate Derivatives Previously Subject to Hedge Accounting Pension and Other Postretirement Plans Total Balance at December 31, 2015 $ (42 ) $ (341 ) $ (383 ) Other comprehensive income (loss), before reclassifications — (107 ) (107 ) Reclassifications to Consolidated Statement of Income 5 94 99 Net other comprehensive income (loss) 5 (13 ) (8 ) Balance at December 31, 2016 $ (37 ) $ (354 ) $ (391 ) Other comprehensive income (loss), before reclassifications — (10 ) (10 ) Reclassifications to Consolidated Statement of Income 2 61 63 Net other comprehensive income (loss) 2 51 53 Balance at December 31, 2017 $ (35 ) $ (303 ) $ (338 ) Other comprehensive income (loss), before reclassifications — 39 39 Reclassifications to Consolidated Statement of Income 2 35 37 Cumulative effect of accounting change (1) (7 ) (66 ) (73 ) Net other comprehensive income (loss) (5 ) 8 3 Balance at December 31, 2018 $ (40 ) $ (295 ) $ (335 ) (1) Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation Cost Table	The following summarizes share-based compensation expense for the years ended December 31: millions 2018 2017 2016 Restricted stock (1) $ 147 $ 145 $ 175 Stock options (1) 21 17 20 Other equity-classified awards 1 1 2 Performance-based unit awards (1) 19 (13 ) 38 Pretax share-based compensation expense $ 188 $ 150 $ 235 Income tax benefit $ 43 $ 35 $ 86 (1) Includes restructuring charges of $(7) million for performance-based unit awards in 2017 and $31 million for restricted stock, $1 million for stock options, and $7 million for performance-based unit awards in 2016. See Note 19—Restructuring Charges for additional information.
Restricted Stock Activity Table	The following summarizes the Company’s restricted stock activity: Shares (millions) Weighted-Average Grant-Date Fair Value (per share) Non-vested at January 1, 2018 4.69 $ 59.24 Granted 2.72 $ 58.30 Vested (2.30 ) $ 61.19 Forfeited (0.42 ) $ 58.07 Non-vested at December 31, 2018 4.69 $ 57.88
Stock Option Valuation Assumptions Table	The Company used the following weighted-average assumptions to estimate the fair value of stock options granted: 2018 2017 2016 Weighted-average grant-date fair value $ 15.36 $ 14.77 $ 15.92 Assumptions Expected option life—years 4.8 4.8 4.1 Volatility 33.5 % 33.6 % 38.2 % Risk-free interest rate 2.9 % 2.0 % 1.3 % Dividend yield 1.9 % 0.4 % 0.6 %
Stock Option Activity Table	The following summarizes the Company’s stock option activity: Shares (millions) Weighted- Average Exercise Price (per share) Weighted- Average Remaining Contractual Term (years) Aggregate Intrinsic Value (millions) Outstanding at January 1, 2018 6.57 $ 71.44 Granted 1.19 $ 55.47 Exercised (1) (0.10 ) $ 65.03 Forfeited or expired (1.30 ) $ 79.55 Outstanding at December 31, 2018 6.36 $ 67.00 3.92 $ — Vested or expected to vest at December 31, 2018 6.36 $ 67.00 3.92 $ — Exercisable at December 31, 2018 4.12 $ 74.19 2.66 $ — (1) The total intrinsic value of stock options exercised was $1 million during 2018 , zero during 2017 , and $7 million during 2016 , based on the difference between the market price at the exercise date and the exercise price.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 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: millions 2018 2017 2016 Statement of Operations Data Total revenues and other $ 1,990 $ 2,248 $ 1,804 Operating income (loss) 625 704 705 Net income (loss) 449 573 597 Statement of Cash Flows Data Net cash provided by (used in) operating activities $ 1,017 $ 897 $ 913 Net cash provided by (used in) investing activities (1,460 ) (764 ) (1,106 ) Net cash provided by (used in) financing activities 456 (413 ) 452 millions 2018 2017 Balance Sheet Data Net property, plant, and equipment $ 6,612 $ 5,731 Total assets 9,239 8,016 Long-term debt 4,787 3,493 Total liabilities 5,734 4,071 Total equity and partners’ capital 3,505 3,945 millions 2018 2017 2016 WGP distributions to Anadarko (1) $ 408 $ 368 $ 321 WGP distributions to third parties 494 443 362 (1) WGP distributions to Anadarko are eliminated upon consolidation.

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 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, for the years ended December 31: millions 2018 2017 2016 Cash paid (received) Interest, net of amounts capitalized $ 982 $ 906 $ 856 Income taxes, net of refunds (1) 51 64 (882 ) Non-cash investing activities Fair value of properties and equipment acquired $ 22 $ 640 $ 3 Asset retirement cost additions 523 66 298 Accruals of property, plant, and equipment 822 824 549 Net liabilities assumed (divested) in acquisitions and divestitures (111 ) (158 ) 723 Non-cash investing and financing activities Acquisition contingent consideration $ — $ — $ 103 Non-cash financing activities Settlement of tangible equity units $ 300 $ — $ — (1) Includes $881 million from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.
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: December 31, millions 2018 2017 Cash and cash equivalents $ 1,295 $ 4,553 Restricted cash and restricted cash equivalents included in Other Assets 134 121 Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents $ 1,429 $ 4,674

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 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 for the years ended December 31: millions 2018 2017 2016 Income (loss) before income taxes $ 1,485 $ (1,688 ) $ (3,829 ) (Gains) losses on divestitures, net (20 ) (674 ) 757 Exploration expense (1) 459 2,535 944 DD&A 4,254 4,279 4,301 Impairments 800 408 227 Interest expense 947 932 890 Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives (407 ) 156 559 Restructuring and reorganization-related charges 53 21 389 Other operating expense — — 1 (Gains) losses on early extinguishment of debt (2 ) 2 155 Certain other nonoperating items — — (58 ) Less net income (loss) attributable to noncontrolling interests 137 245 263 Consolidated Adjusted EBITDAX $ 7,432 $ 5,726 $ 4,073 (1) Includes reorganization-related charges of $20 million for the year ended December 31, 2018 .
Schedule of Segment Reporting Information by Segment	The following summarizes selected financial information for Anadarko’s reporting segments: millions Exploration & Production WES Midstream Other and Intersegment Eliminations Total 2018 Sales revenues $ 11,404 $ 1,610 $ 56 $ 13,070 Intersegment revenues 81 690 (771 ) — Other (4 ) 211 85 292 Total revenues and other (1) 11,481 2,511 (630 ) 13,362 Operating costs and expenses (2) 3,896 1,019 328 5,243 Net cash from settlement of commodity derivatives — — 545 545 Other (income) expense, net (3) — (8 ) 21 13 Net income (loss) attributable to noncontrolling interests — — 137 137 Total expenses and other 3,896 1,011 1,031 5,938 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 8 8 Adjusted EBITDAX $ 7,585 $ 1,500 $ (1,653 ) $ 7,432 Net properties and equipment $ 18,276 $ 8,410 $ 1,929 $ 28,615 Capital expenditures $ 4,103 $ 1,912 $ 170 $ 6,185 Goodwill $ 4,343 $ 446 $ — $ 4,789 (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, reorganization-related charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes reorganization-related charges since these expenses are excluded from Adjusted EBITDAX. 27. Segment Information (Continued) millions Exploration & Production WES Midstream Other and Intersegment Eliminations Total 2017 Sales revenues $ 8,952 $ 1,824 $ 193 $ 10,969 Intersegment revenues 21 606 (627 ) — Other 15 189 61 265 Total revenues and other (1) 8,988 2,619 (373 ) 11,234 Operating costs and expenses (2) 3,517 1,423 318 5,258 Net cash from settlement of commodity derivatives — — (27 ) (27 ) Other (income) expense, net (3) — — 26 26 Net income (loss) attributable to noncontrolling interests — — 245 245 Total expenses and other 3,517 1,423 562 5,502 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — (6 ) (6 ) Adjusted EBITDAX $ 5,471 $ 1,196 $ (941 ) $ 5,726 Net properties and equipment $ 18,729 $ 6,766 $ 1,956 $ 27,451 Capital expenditures $ 3,785 $ 1,409 $ 106 $ 5,300 Goodwill $ 4,343 $ 446 $ — $ 4,789 2016 Sales revenues $ 7,152 $ 1,146 $ 149 $ 8,447 Intersegment revenues 4 795 (799 ) — Other (5 ) 154 30 179 Total revenues and other (1) 7,151 2,095 (620 ) 8,626 Operating costs and expenses (2) 3,485 955 136 4,576 Net cash from settlement of commodity derivatives — — (265 ) (265 ) Other (income) expense, net (3) — — (13 ) (13 ) Net income (loss) attributable to noncontrolling interests — — 263 263 Total expenses and other 3,485 955 121 4,561 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 8 8 Adjusted EBITDAX $ 3,666 $ 1,140 $ (733 ) $ 4,073 Net properties and equipment $ 24,391 $ 5,658 $ 2,119 $ 32,168 Capital expenditures $ 2,689 $ 551 $ 74 $ 3,314 Goodwill $ 4,550 $ 450 $ — $ 5,000 (1) Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX. (2) Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes certain other nonoperating items and restructuring charges since these items are excluded from Adjusted EBITDAX.
Schedule of Sales Revenues by Geographic Areas	The following represents Anadarko’s sales revenues (based on the origin of the sales) and net properties and equipment by geographic area: Years Ended December 31, millions 2018 2017 2016 Sales Revenues United States $ 10,659 $ 9,176 $ 7,049 Algeria 1,596 1,249 1,103 Other International 815 544 295 Total sales revenues $ 13,070 $ 10,969 $ 8,447
Schedule of Net Properties and Equipment by Geographic Areas	December 31, millions 2018 2017 Net Properties and Equipment United States $ 25,891 $ 24,382 Algeria 808 965 Other International (1) 1,916 2,104 Total net properties and equipment $ 28,615 $ 27,451 (1) Includes $519 million of capitalized costs related to the Mozambique LNG project at December 31, 2018 .

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018
Furniture and Equipment [Member] | Minimum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	3 years
Furniture and Equipment [Member] | Maximum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	15 years
Buildings [Member] | Maximum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	40 years
Gathering Facilities [Member] | Maximum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	40 years

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Recently Issued Accounting Standards (Detail) - USD ($) $ in Millions		Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2019	Jan. 01, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change		$ (47)				$ (31)
Accounting Standards Update 2017-07 [Member] | Costs and Expenses [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service cost component of net periodic benefit cost			$ 107	$ 225
Accounting Standards Update 2014-09 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change		47
Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change	[1]	(73)
Reclassification from AOCI to retained earnings		73
Accounting Standards Update 2018-02 [Member] | State tax impact [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification from AOCI to retained earnings		$ 2
Accounting Standards Update 2016-02 [Member] | Subsequent Event [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
ROU assets					$ 600
Lease liabilities					$ 600
[1]	Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Impact on Financial Statements (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Assets
Other current assets	$ 474	$ 380
Net properties and equipment	28,615	27,451	$ 32,168
Other assets	2,336	2,211
Liabilities
Other current liabilities	1,295	1,310
Deferred income taxes	2,437	2,234
Other	4,021	4,109
Equity
Total Equity	10,943	13,790	15,497	$ 15,457
Revenues
Revenues from Customers	14,044		8,447
Gains (losses) on divestitures and other, net	312	939	(578)
Expenses
Income tax expense (benefit)	733	(1,477)	(1,021)
Net income (loss) attributable to noncontrolling interests	137	245	263
Net income (loss) attributable to common stockholders	615	(456)	(3,071)
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member]
Assets
Other current assets	472
Net properties and equipment	28,548
Other assets	2,326
Liabilities
Other current liabilities	1,290
Deferred income taxes	2,441
Other	3,914
Equity
Total Equity	10,972
Revenues
Gains (losses) on divestitures and other, net	316
Expenses
Income tax expense (benefit)	731
Net income (loss) attributable to noncontrolling interests	127
Net income (loss) attributable to common stockholders	607
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/ (Decrease) [Member]
Assets
Other current assets	2
Net properties and equipment	67
Other assets	10
Liabilities
Other current liabilities	5
Deferred income taxes	(4)
Other	107
Equity
Total Equity	(29)
Revenues
Gains (losses) on divestitures and other, net	(4)
Expenses
Income tax expense (benefit)	2
Net income (loss) attributable to noncontrolling interests	10
Net income (loss) attributable to common stockholders	8
Gathering, processing, and marketing [Member]
Revenues
Revenues from Customers	1,588	2,000	1,294
Expenses
Gathering, processing, and marketing	1,047	$ 1,552	$ 1,083
Gathering, processing, and marketing [Member] | Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member]
Revenues
Revenues from Customers	2,592
Expenses
Gathering, processing, and marketing	2,075
Gathering, processing, and marketing [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/ (Decrease) [Member]
Revenues
Revenues from Customers	(1,004)
Expenses
Gathering, processing, and marketing	$ (1,028)

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Disaggregation of Revenue (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenues from Customers		$ 14,044		$ 8,447
Revenue from Other than Customers		(662)
Total		13,382	$ 11,908	7,869
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		9,206
Natural-gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		1,005	1,348	1,564
Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		1,271	$ 1,069	921
Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	2,434
Revenue from Other than Customers	[2]	(846)
Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		20
Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		128
Revenue from Other than Customers		164
Operating Segments [Member] | Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		11,515		7,152
Revenue from Other than Customers		(14)
Total		11,501
Operating Segments [Member] | Exploration and Production [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		9,206
Operating Segments [Member] | Exploration and Production [Member] | Natural-gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		1,005
Operating Segments [Member] | Exploration and Production [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		1,271
Operating Segments [Member] | Exploration and Production [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	3
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		20
Operating Segments [Member] | Exploration and Production [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		30
Revenue from Other than Customers		(34)
Operating Segments [Member] | WES Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		2,305		1,146
Revenue from Other than Customers		206
Total		2,511
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]	2,305
Revenue from Other than Customers	[2]	(5)
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		211
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		224		$ 149
Revenue from Other than Customers		(854)
Total		(630)
Other [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Other [Member] | Natural-gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Other [Member] | Natural-gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		0
Other [Member] | Gathering, processing, and marketing sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers	[1]	126
Revenue from Other than Customers	[2]	(841)
Intercompany eliminations		(772)
Third-party marketing revenue		957
Other [Member] | Gains (losses) on divestitures, net [Member]
Disaggregation of Revenue [Line Items]
Revenue from Other than Customers		0
Other [Member] | Other, net [Member]
Disaggregation of Revenue [Line Items]
Revenues from Customers		98
Revenue from Other than Customers		$ (13)
[1]	The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $957 million and intersegment eliminations of $(772) million for the year ended December 31, 2018.
[2]	The amount in Other and Intersegment Eliminations primarily 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.

Revenue from Contracts with C_5

Revenue from Contracts with Customers - Contract Liabilities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 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	66
Increase due to assets received from customer	13
Decrease due to revenue recognized	(42)
Decrease due to change in estimated consideration	(22)
Balance at December 31, 2018	150
Contract liabilities at December 31, 2018
Other current liabilities		$ 31
Other long-term liabilities - other		119
Total contract liabilities from contracts with customers	$ 37	$ 150

Revenue from Contracts with C_6

Revenue from Contracts with Customers - Revenue Recognition Expected (Detail) $ in Millions	Dec. 31, 2018USD ($)
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	$ 346
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Operating Segments [Member] | Exploration and Production [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 104
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Operating Segments [Member] | WES Midstream [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 675
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Other [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (433)
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	$ 336
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Operating Segments [Member] | Exploration and Production [Member]
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
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Operating Segments [Member] | WES Midstream [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 847
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Other [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (614)
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 317
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Operating Segments [Member] | Exploration and Production [Member]
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
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Operating Segments [Member] | WES Midstream [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 895
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Other [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (681)
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 214
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Operating Segments [Member] | Exploration and Production [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Operating Segments [Member] | WES Midstream [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	947
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Other [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	(740)
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	$ 170
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Operating Segments [Member] | Exploration and Production [Member]
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
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Operating Segments [Member] | WES Midstream [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 913
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Other [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (750)
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 546
Performance obligation expected to be satisfied, expected timing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Operating Segments [Member] | Exploration and Production [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 58
Performance obligation expected to be satisfied, expected timing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Operating Segments [Member] | WES Midstream [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 4,565
Performance obligation expected to be satisfied, expected timing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Other [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (4,077)
Performance obligation expected to be satisfied, expected timing
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	$ 1,929
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Operating Segments [Member] | Exploration and Production [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	382
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Operating Segments [Member] | WES Midstream [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	8,842
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Other [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ (7,295)

Commodity Inventories (Detail)

Commodity Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Energy Related Inventory [Abstract]
Oil	$ 139	$ 165
Natural gas	18	29
NGLs	78	122
Total commodity inventories	$ 235	$ 316

Divestitures and Assets Held _3

Divestitures and Assets Held for Sale (Detail) - USD ($) $ in Millions		Mar. 17, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments				$ 417	$ 4,008	$ 2,356
Gains (losses) on divestitures, net	[1],[2]			20	674	(757)
Amount of goodwill written off allocated to divestitures					209	397
Cash payment to acquire a third party's interest in the DBJV system				6,183	5,031	3,505
Assets Held for Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term liabilities associated with assets held for sale			$ 27		27
Exploration and Production [Member] | Certain South Texas Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments					2,100
Gain (loss) on divestitures					729
Exploration and Production [Member] | Certain Southeast Texas Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments					533
Gain (loss) on divestitures					282
Exploration and Production [Member] | Certain Marcellus Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments					951
Gain (loss) on divestitures					(55)
Exploration and Production [Member] | Certain Marcellus Assets [Member] | Assets Disposed of by Sale [Member] | Fair Value, Inputs, Level 2 [Member] | Valuation, Market Approach [Member] | Nonrecurring [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Losses on assets held for sale						129
Exploration and Production [Member] | Certain Moxa Wyoming Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments					313
Gain (loss) on divestitures					(204)
Exploration and Production [Member] | Certain Alaska Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments				370
Gain (loss) on divestitures			(154)	(33)
Exploration and Production [Member] | Certain Alaska Assets [Member] | Assets Held for Sale [Member] | Fair Value, Inputs, Level 2 [Member] | Valuation, Market Approach [Member] | Nonrecurring [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Losses on assets held for sale					154
Long-term assets associated with assets held for sale			$ 573		573
Exploration and Production [Member] | Certain Nonoperated Gulf Of Mexico Assets, Ram Powell [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on divestitures				$ 67
Exploration and Production [Member] | Certain West Texas Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments						221
Gain (loss) on divestitures						(52)
Exploration and Production [Member] | Certain Wyoming Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments						588
Gain (loss) on divestitures						(58)
Exploration and Production [Member] | Certain Elm Grove East Texas Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments						89
Gain (loss) on divestitures						(64)
Exploration and Production [Member] | Certain East Chalk and Carthage East Texas/Louisiana Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments						1,000
Gain (loss) on divestitures						(439)
Exploration And Production And WES Midstream Reporting Segment [Member] | Certain Utah Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments					69
Gain (loss) on divestitures					$ (52)
Exploration And Production And WES Midstream Reporting Segment [Member] | Certain Kansas Assets [Member] | Assets Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received, net of closing adjustments						159
Gain (loss) on divestitures						$ (4)
Delaware Basin Joint Venture System [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Third party non operated interest percentage		50.00%
Western Gas Partners LP [Member] | Delaware Basin Joint Venture System [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on property exchange		$ 126
Cash payment to acquire a third party's interest in the DBJV system		$ 155
Operated interest percentage				100.00%
Western Gas Partners LP [Member] | Marcellus Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Non Operated Interest Percentage		33.75%
[1]	Includes gain of $126 million related to the 2017 property exchange discussed below.
[2]	Includes goodwill allocated to divestitures of $209 million in 2017 and $397 million in 2016.

Properties and Equipment (Detai

Properties and Equipment (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant, and Equipment [Line Items]
Gross properties and equipment		$ 66,520	$ 61,558
Less accumulated depreciation, depletion, and amortization		37,905	34,107
Net properties and equipment		28,615	27,451	$ 32,168
Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Gross properties and equipment	[1]	52,796	50,221
Costs associated with unproved properties		1,700	2,400
WES Midstream [Member]
Property, Plant, and Equipment [Line Items]
Gross properties and equipment		11,259	8,980
Other [Member]
Property, Plant, and Equipment [Line Items]
Gross properties and equipment		$ 2,465	$ 2,357
[1]	Includes costs associated with unproved properties of $1.7 billion at December 31, 2018, and $2.4 billion at December 31, 2017.

Impairments - Impairments and

Impairments - Impairments and Fair Values by Segment Table (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Impaired Long Lived Assets Held and Used [Line Items]
Total impairments		$ 800		$ 408	$ 227
Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total fair value				277	710
Exploration and Production [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of cost-method investment		0		0	59
Exploration and Production [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of cost-method investment		0	[1]	0	0
Exploration and Production [Member] | U.S. Onshore Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		397		2	28
Exploration and Production [Member] | U.S. Onshore Properties [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use		172	[1]	3	617
Exploration and Production [Member] | Gulf Of Mexico Projects [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use				227	27
Exploration and Production [Member] | Gulf Of Mexico Projects [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use				216	61
WES Midstream [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use				178	18
WES Midstream [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use				58	3
Other [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		145		1	95
Other [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use		15	[1]	$ 0	$ 29
Assets Impaired During Fiscal Year to Date [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total impairments		800
Assets Impaired During Fiscal Year to Date [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total fair value	[1]	217
Assets Impaired During Fiscal Year to Date [Member] | Exploration and Production [Member] | Gulf Of Mexico Projects [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		27
Assets Impaired During Fiscal Year to Date [Member] | Exploration and Production [Member] | Gulf Of Mexico Projects [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [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] | WES Midstream [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		231
Assets Impaired During Fiscal Year to Date [Member] | WES Midstream [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Income Approach [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	$ 30
[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 - Additional Infor

Impairments - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties	$ 246	$ 2,221	$ 613
Unproved Gulf of Mexico Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties	$ 159	610	72
Gulf Of Mexico, Shenandoah Project [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties		463
Unproved International Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties		$ 88	$ 92

Suspended Exploratory Well Co_3

Suspended Exploratory Well Costs - Rollforward (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 525	$ 1,230	$ 1,124
Additions pending the determination of proved reserves (1)	90	349	490
Divestitures and other	(38)	(36)	(11)
Reclassifications to proved properties	(132)	(41)	(50)
Charges to exploration expense	(1)	(977)	(323)
Balance at December 31	$ 444	$ 525	$ 1,230

Suspended Exploratory Well Co_4

Suspended Exploratory Well Costs - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant, and Equipment [Line Items]
Charges to exploration expense		$ 1	$ 977	$ 323
Capitalized exploratory well costs		444	525	1,230	$ 1,124
Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense		87
Capitalized exploratory well costs			1
Gulf Of Mexico, Shenandoah Project [Member] | Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense		$ 437
Capitalized exploratory well costs			326
Gulf Of Mexico, Phobos Project [Member] | Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense	$ 215
Capitalized exploratory well costs				99
Gulf Of Mexico, Warrior Project [Member] | Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense	$ 108
Colombia Project [Member] | Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense			243
Capitalized exploratory well costs				109
Cote d’Ivoire Project [Member] | Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense			$ 329
Capitalized exploratory well costs				237
Gulf of Mexico, Yeti Project [Member] | Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense				231
Mozambique Project [Member] | Exploration and Production [Member]
Property, Plant, and Equipment [Line Items]
Charges to exploration expense				$ 92

Suspended Exploratory Well Co_5

Suspended Exploratory Well Costs - Aging of Suspended Well Balances (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Exploratory Well Costs Associated with Wells Suspended for a Period Greater Than One Year [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 152	$ 201	$ 460
Exploratory well costs capitalized for a period greater than one year	292	324	770
Balance at December 31	$ 444	$ 525	$ 1,230	$ 1,124

Suspended Exploratory Well Co_6

Suspended Exploratory Well Costs - Aging by Geographic Area of Exploratory Well Costs Capitalized for a Period Greater Than One Year (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)Project	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Capitalized Exploratory Well Costs [Line Items]
Projects with exploratory well costs capitalized for a period greater than one year after completion of drilling | Project	5
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 292	$ 324	$ 770
Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 10
Aging of capitalized exploratory well costs, period start date	Jan. 1, 2017
Aging of capitalized exploratory well costs, period end date	Dec. 31, 2017
Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 88
Aging of capitalized exploratory well costs, period start date	Jan. 1, 2016
Aging of capitalized exploratory well costs, period end date	Dec. 31, 2016
Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 194
Aging of capitalized exploratory well costs, period end date	Dec. 31, 2015
U.S. Onshore [Member]
Capitalized Exploratory Well Costs [Line Items]
Projects with exploratory well costs capitalized for a period greater than one year after completion of drilling | Project	1
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 2
U.S. Onshore [Member] | Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	0
U.S. Onshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	0
U.S. Onshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 2
U.S. Offshore [Member]
Capitalized Exploratory Well Costs [Line Items]
Projects with exploratory well costs capitalized for a period greater than one year after completion of drilling | Project	1
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 73
U.S. Offshore [Member] | Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	(1)
U.S. Offshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	74
U.S. Offshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 0
International [Member]
Capitalized Exploratory Well Costs [Line Items]
Projects with exploratory well costs capitalized for a period greater than one year after completion of drilling | Project	3
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 217
International [Member] | Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	11
International [Member] | Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	14
International [Member] | Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$ 192

Goodwill and Other Intangible_3

Goodwill and Other Intangible Assets - Goodwill (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 4,789,000,000	$ 4,789,000,000	$ 5,000,000,000
Goodwill impairment loss	0
Exploration and Production [Member]
Goodwill [Line Items]
Goodwill	4,300,000,000
WES Midstream [Member]
Goodwill [Line Items]
Goodwill	$ 446,000,000

Goodwill and Other Intangible_4

Goodwill and Other Intangible Assets - Other Intangible Assets and Amortization Expense Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Gross carrying amount	$ 980	$ 1,013
Accumulated amortization	(139)	(140)
Net carrying amount	841	873
Amortization expense	$ 32	$ 31

Goodwill and Other Intangible_5

Goodwill and Other Intangible Assets - Other Intangible Assets (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Finite-Lived Intangible Assets [Line Items]
Expected aggregate amortization expense for intangible assets in 2019	$ 32
Expected aggregate amortization expense for intangible assets in 2020	32
Expected aggregate amortization expense for intangible assets in 2021	32
Expected aggregate amortization expense for intangible assets in 2022	32
Expected aggregate amortization expense for intangible assets in 2023	$ 32
Customer Contracts [Member] | Gathering and Processing Assets in the Delaware basin [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired intangible assets, useful life	30 years

Equity-Method Investments (Deta

Equity-Method Investments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2007
Schedule of Equity Method Investments [Line Items]
Other long-term liabilities - other	$ 4,021	$ 4,109
Other assets	$ 2,336	2,211
Equity-method investments [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest of investee entities	95.00%
Carrying amount of notes payable to affiliates	$ 2,900			$ 2,900
Carrying amount of investments	$ 2,800
Anadarko's noncontrolling interest optional redemption	2022
Anadarko's noncontrolling interest mandatory redemption	2037
Other long-term liabilities - other	$ 41	46
Other assets	$ 4	$ 4
Applicable interest rate	3.79%	2.59%
Interest expense on the notes payable	$ 91	$ 64	$ 49
Equity (earnings) losses from investments in the investee entities	$ (87)	$ (56)	$ (33)
Equity-method investments [Member] | Equity-method investee 1 [Member]
Schedule of Equity Method Investments [Line Items]
Debt instrument, term	35 years
Equity-method investments [Member] | Equity-method investee 2 [Member]
Schedule of Equity Method Investments [Line Items]
Debt instrument, term	35 years
Equity-method investments [Member] | Maximum [Member]
Schedule of Equity Method Investments [Line Items]
Debt-to-capital ratio covenant	0.67
Equity-method investments [Member] | Contributed Property to Investees [Member]
Schedule of Equity Method Investments [Line Items]
Fair value of oil and gas properties and gathering and processing assets contributed by Anadarko				$ 2,900

Current Liabilities (Detail)

Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Outstanding checks in excess of bank account balances	$ 180	$ 219
Other Current Liabilities
Accrued income taxes	167	71
Interest payable	267	246
Production, property, and other taxes payable	309	216
Accrued employee benefits	319	210
Derivatives	89	384
Other	144	183
Total other current liabilities	$ 1,295	$ 1,310

Derivative Instruments - Oil an

Derivative Instruments - Oil and Natural-Gas Production/Processing Derivative Activities Table (Detail) - Not Designated as Hedging Instrument [Member] - Three Way Collars Oil 2019 [Member] MBbls / d in Thousands	12 Months Ended
	Dec. 31, 2018MBbls / d$ / bbl
Derivative [Line Items]
Oil derivative nonmonetary notional amount per day | MBbls / d	87
Call Option [Member] | Short [Member]
Average price per barrel or MMBtu
Ceiling sold price	72.98
Put Option [Member] | Short [Member]
Average price per barrel or MMBtu
Floor price	46.72
Put Option [Member] | Long [Member]
Average price per barrel or MMBtu
Floor price	56.72

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Amount of collateral posted related to derivative instruments with credit-risk-related contingent features		$ 66	$ 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		1,100	1,400
Not Designated as Hedging Instrument [Member] | Cash Payments Related To Interest Rate Swap Agreements [Member]
Derivative [Line Items]
Total cash payments for settled interest-rate swaps		92	$ 112
Not Designated as Hedging Instrument [Member] | Interest-Rate Swap 3 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 200	100
Not Designated as Hedging Instrument [Member] | Interest-Rate Swap 3 [Member] | Cash Payments To Amend Interest Rate Swap Agreements [Member]
Derivative [Line Items]
Total cash payments for settled interest-rate swaps	$ 10
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps 1 Through 5 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap		1,600
Western Gas Partners LP [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Swaps 6 Through 8 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap		$ 750

Derivative Instruments - Intere

Derivative Instruments - Interest-Rate Derivatives Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Aug. 31, 2018
Interest-Rate Swap 1 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 550
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 1, 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. 1, 2022
Weighted-average interest rate for interest-rate swap	6.809%
Interest-Rate Swap 3 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 100	$ 200
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 1, 2020
Weighted-average interest rate for interest-rate swap	6.891%
Interest-Rate Swap 4 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 1, 2021
Weighted-average interest rate for interest-rate swap	6.57%
Interest-Rate Swap 5 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 450
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 1, 2023
Weighted-average interest rate for interest-rate swap	6.445%
Western Gas Partners LP [Member] | Interest-Rate Swap 6 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250
Reference period start date for interest-rate swap	Dec. 31, 2019
Reference period end date for interest-rate swap	Dec. 31, 2024
Mandatory termination date for interest-rate swap	Dec. 31, 2019
Weighted-average interest rate for interest-rate swap	2.73%
Western Gas Partners LP [Member] | Interest-Rate Swap 7 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250
Reference period start date for interest-rate swap	Dec. 31, 2019
Reference period end date for interest-rate swap	Dec. 31, 2029
Mandatory termination date for interest-rate swap	Dec. 31, 2019
Weighted-average interest rate for interest-rate swap	2.856%
Western Gas Partners LP [Member] | Interest Rate Swap 8 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250
Reference period start date for interest-rate swap	Dec. 31, 2019
Reference period end date for interest-rate swap	Dec. 31, 2049
Mandatory termination date for interest-rate swap	Dec. 31, 2019
Weighted-average interest rate for interest-rate swap	2.905%

Derivative Instruments - Effect

Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Gross derivative assets		$ 357	$ 108
Gross derivative liabilities		(1,378)	(1,628)
Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	301	54
Gross derivative liabilities	[1]	(132)	(209)
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	300	7
Gross derivative liabilities	[1]	(126)	(1)
Commodity Derivatives [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	0	2
Gross derivative liabilities	[1]	0	0
Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	1	45
Gross derivative liabilities	[1]	(6)	(206)
Commodity Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	0	0
Gross derivative liabilities	[1]	0	(2)
Interest Rate Swap [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	56	54
Gross derivative liabilities	[1]	(1,238)	(1,419)
Interest Rate Swap [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	22	14
Gross derivative liabilities	[1]	0	0
Interest Rate Swap [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	34	40
Gross derivative liabilities	[1]	0	0
Interest Rate Swap [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	0	0
Gross derivative liabilities	[1]	(82)	(236)
Interest Rate Swap [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	[1]	0	0
Gross derivative liabilities	[1]	(1,156)	(1,183)
Western Gas Partners LP [Member] | Interest Rate Swap [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets		0	0
Gross derivative liabilities		$ (8)	$ 0
[1]	Excludes amounts related to WES interest-rate swap agreements.

Derivative Instruments - Effe_2

Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ 138		$ 131		$ 292
Commodity Derivatives [Member] | Gathering, processing, and marketing sales [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	[1]	8		(4)		6
Commodity Derivatives [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		213	[1]	3	[1]	147
Interest Rate Swap [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	[1]	(91)		132		139
Western Gas Partners LP [Member] | Interest Rate Swap [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ 8		$ 0		$ 0
[1]	Excludes amounts related to WES interest-rate swap agreements.

Derivative Instruments - Fair V

Derivative Instruments - Fair Value Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		$ 357	$ 108
Gross derivative liabilities		(1,378)	(1,628)
Derivative assets netting	[1]	(127)	(46)
Derivative liabilities netting	[1]	127	46
Cash collateral from counterparties		0	(1)
Cash collateral held by counterparties		68	173
Derivative assets		230	61
Derivative liabilities		(1,183)	(1,409)
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[2]	301	54
Gross derivative liabilities	[2]	(132)	(209)
Derivative assets netting	[1],[3]	(127)	(46)
Derivative liabilities netting	[1],[3]	127	46
Cash collateral from counterparties	[3]	0	(1)
Cash collateral held by counterparties	[3]	2	3
Derivative assets	[3]	174	7
Derivative liabilities	[3]	(3)	(160)
Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[2]	56	54
Gross derivative liabilities	[2]	(1,238)	(1,419)
Derivative assets netting	[1],[3]	0	0
Derivative liabilities netting	[1],[3]	0	0
Cash collateral from counterparties	[3]	0	0
Cash collateral held by counterparties	[3]	66	170
Derivative assets	[3]	56	54
Derivative liabilities	[3]	(1,172)	(1,249)
Fair Value, Inputs, Level 1 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		1	1
Gross derivative liabilities		(2)	(1)
Fair Value, Inputs, Level 1 [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[3]	1	1
Gross derivative liabilities	[3]	(2)	(1)
Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[3]	0	0
Gross derivative liabilities	[3]	0	0
Fair Value, Inputs, Level 2 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		356	107
Gross derivative liabilities		(1,376)	(1,627)
Fair Value, Inputs, Level 2 [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[3]	300	53
Gross derivative liabilities	[3]	(130)	(208)
Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[3]	56	54
Gross derivative liabilities	[3]	(1,238)	(1,419)
Fair Value, Inputs, Level 3 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		0	0
Gross derivative liabilities		0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[3]	0	0
Gross derivative liabilities	[3]	0	0
Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	[3]	0	0
Gross derivative liabilities	[3]	0	$ 0
Western Gas Partners LP [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities netting	[1]	0
Cash collateral held by counterparties		0
Derivative liabilities		(8)
Western Gas Partners LP [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities		0
Western Gas Partners LP [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities		(8)
Western Gas Partners LP [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities		$ 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.
[2]	Excludes amounts related to WES interest-rate swap agreements.
[3]	Excludes amounts related to WES interest-rate swap agreements.

Tangible Equity Units - Additi

Tangible Equity Units - Additional Information (Detail) shares in Millions, $ in Millions	Jun. 07, 2018USD ($)$ / unitshares	Jun. 30, 2015USD ($)$ / unitshares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
TEUs - senior amortizing notes due 2018 [Member]
Tangible Equity Units [Line Items]
Principal amount per amortizing note | $ / unit	10.95
Debt instrument, stated interest rate	1.50%
Final payment | $	$ 9		$ 17	$ 34
Debt instrument, maturity date	Jun. 7, 2018
7.50% Tangible Equity Units [Member]
Tangible Equity Units [Line Items]
Number of tangible equity units issued (in units)		9.2
Tangible equity unit rate		7.50%
Stated amount per tangible equity unit (in usd per unit) | $ / unit		50
Total net proceeds | $		$ 445
Equity Component of 7.5% Tangible Equity Units [Member] | Settled In Wgp Common Units [Member]
Tangible Equity Units [Line Items]
Purchase contract, mandatory settlement date	Jun. 7, 2018
Number of tangible equity units settled (in units)	9.2
Shares issued (in units)	8.2
Settlement rate	0.8921

Debt and Interest Expense - De

Debt and Interest Expense - Debt Activity Table (Detail) - USD ($) $ in Millions		Jun. 07, 2018	Dec. 31, 2018	May 31, 2018	Dec. 31, 2018		Dec. 31, 2017		Aug. 31, 2018	Mar. 31, 2018
Debt Instrument [Line Items]
Carrying value, beginning balance					$ 15,458	[1]	$ 15,078
Other, net					56		54
Carrying value, ending balance			$ 16,169		16,169		15,458	[1]
Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Carrying value, beginning balance					3,465	[1]	3,091
Other, net					3		4
Carrying value, ending balance			4,787		4,787		3,465	[1]
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Carrying value, beginning balance	[2]				28	[1],[3]	28
Other, net	[2]				0
Carrying value, ending balance	[1],[2]		28		28		28	[3]
Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Carrying value, beginning balance	[4]				11,965	[1],[5]	11,959
Other, net					53	[5]	50	[4]
Carrying value, ending balance	[1],[4],[5]		$ 11,354		11,354		11,965
WES RCF [Member]
Debt Instrument [Line Items]
Borrowings, credit facilities					540		370
Repayments of credit facilities					(690)
WES RCF [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Borrowings, credit facilities					540		370
Repayments of credit facilities					(690)
4.850% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Repayments of debt					$ (123)
Debt instrument, stated interest rate			4.85%		4.85%
4.850% Senior Notes due 2021 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt			$ (123)		$ (123)	[5]
3.450% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Repayments of debt					$ (375)
Debt instrument, stated interest rate			3.45%		3.45%
3.450% Senior Notes due 2024 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt			$ (377)		$ (375)	[5]
Senior Notes Zero Coupon [Member]
Debt Instrument [Line Items]
Repayments of debt					(35)
Senior Notes Zero Coupon [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt			$ (36)		$ (35)	[5]
5.550% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate			5.55%		5.55%
6.600% Senior Notes due 2046 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate			6.60%		6.60%
WES 4.650% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate			4.65%		4.65%
WES 5.450% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate			5.45%		5.45%
TEUs - senior amortizing notes due 2018 [Member]
Debt Instrument [Line Items]
Repayments of debt		$ (9)			$ (17)		(34)
Debt instrument, stated interest rate		1.50%
Debt instrument, maturity date		Jun. 7, 2018
TEUs - senior amortizing notes due 2018 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt					$ (17)	[5]	(34)	[4]
4.500% Senior Notes due March 2028 [Member]
Debt Instrument [Line Items]
Issuance					$ 394
Debt instrument, stated interest rate			4.50%		4.50%
4.500% Senior Notes due March 2028 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Issuance					$ 394
Debt instrument, stated interest rate										4.50%
5.300% Senior Notes due March 2048 [Member]
Debt Instrument [Line Items]
Issuance					$ 687
Debt instrument, stated interest rate			5.30%		5.30%
5.300% Senior Notes due March 2048 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Issuance					$ 687
Debt instrument, stated interest rate										5.30%
7.000% Debentures due 2027 [Member]
Debt Instrument [Line Items]
Repayments of debt							(6)
Debt instrument, stated interest rate			7.00%		7.00%
7.000% Debentures due 2027 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt	[5]						(6)
6.625% Debentures due 2028 [Member]
Debt Instrument [Line Items]
Repayments of debt							(3)
Debt instrument, stated interest rate			6.625%		6.625%
6.625% Debentures due 2028 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt	[4]						(3)
7.950% Debentures due 2029 [Member]
Debt Instrument [Line Items]
Repayments of debt							(1)
Debt instrument, stated interest rate			7.95%		7.95%
7.950% Debentures due 2029 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt	[4]						$ (1)
4.750% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Issuance					$ 396
Debt instrument, stated interest rate			4.75%		4.75%
4.750% Senior Notes due August 2028 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Issuance					$ 396
Debt instrument, stated interest rate									4.75%
5.500% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Issuance					$ 342
Debt instrument, stated interest rate			5.50%		5.50%
5.500% Senior Notes due August 2028 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Issuance					$ 342
Debt instrument, stated interest rate									5.50%
7.050% Debentures due 2018 [Member]
Debt Instrument [Line Items]
Repayments of debt					$ (114)
Debt instrument, stated interest rate
Debt instrument, maturity date
7.050% Debentures due 2018 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments of debt	[5]			$ (114)	$ (114)
Debt instrument, stated interest rate				7.05%
WES 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Repayments of credit facilities					$ (350)
Debt instrument, stated interest rate
Debt instrument, maturity date
WES 2.600% Senior Notes due 2018 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Repayments of credit facilities					$ (350)
Debt instrument, stated interest rate			2.60%		2.60%
[1]	The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.
[2]	Excludes WES.
[3]	Excludes WES.
[4]	Excludes WES and WGP
[5]	Excludes WES and WGP.

Debt and Interest Expense - Ou

Debt and Interest Expense - Outstanding Debt Table (Detail) - USD ($)		Jun. 07, 2018	Dec. 31, 2018		Nov. 30, 2018	Aug. 31, 2018	May 31, 2018	Mar. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 17,661,000,000						$ 17,032,000,000
Net unamortized discounts, premiums, and debt issuance costs (3)			(1,492,000,000)						(1,574,000,000)	[1]
Total borrowings			16,169,000,000						15,458,000,000	[2]	$ 15,078,000,000
Capital lease obligations			248,000,000						231,000,000
Less short-term debt			947,000,000						142,000,000
Total long-term debt			15,470,000,000						15,547,000,000
Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			4,840,000,000						3,490,000,000
Net unamortized discounts, premiums, and debt issuance costs (3)			(53,000,000)						(25,000,000)	[1]
Total borrowings			4,787,000,000						3,465,000,000	[2]	3,091,000,000
Capital lease obligations			0						0
Less short-term debt			0						0
Total long-term debt			4,787,000,000						3,465,000,000
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			28,000,000	[3]					28,000,000	[4]
Net unamortized discounts, premiums, and debt issuance costs (3)	[1]		0	[3]					0	[4]
Total borrowings	[3]		28,000,000	[2]					28,000,000	[2],[4]	28,000,000
Capital lease obligations			0	[3]					0	[4]
Less short-term debt			28,000,000	[3]					0	[4]
Total long-term debt			0	[3]					28,000,000	[4]
Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		12,793,000,000						13,514,000,000
Net unamortized discounts, premiums, and debt issuance costs (3)	[1],[5]		(1,439,000,000)						(1,549,000,000)
Total borrowings	[5]		11,354,000,000	[2],[6]					11,965,000,000	[2],[6]	$ 11,959,000,000
Capital lease obligations	[5]		248,000,000						231,000,000
Less short-term debt	[5]		919,000,000						142,000,000
Total long-term debt	[5]		$ 10,683,000,000						12,054,000,000
7.050% Debentures due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount									114,000,000
Debt instrument, stated interest rate
Debt instrument, maturity date
7.050% Debentures due 2018 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]								114,000,000
Debt instrument, stated interest rate							7.05%
TEUs - senior amortizing notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount									17,000,000
Debt instrument, stated interest rate		1.50%
Debt instrument, maturity date		Jun. 7, 2018
TEUs - senior amortizing notes due 2018 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]								17,000,000
WES 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount									350,000,000
Debt instrument, stated interest rate
Debt instrument, maturity date
WES 2.600% Senior Notes due 2018 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 350,000,000						350,000,000
Debt instrument, stated interest rate			2.60%
6.950% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 300,000,000						300,000,000
Debt instrument, stated interest rate			6.95%
6.950% Senior Notes due 2019 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 300,000,000						300,000,000
8.700% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 600,000,000						600,000,000
Debt instrument, stated interest rate			8.70%
8.700% Senior Notes due 2019 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 600,000,000						600,000,000
4.850% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 677,000,000						800,000,000
Debt instrument, stated interest rate			4.85%
4.850% Senior Notes due 2021 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 677,000,000	[5]	$ 800,000,000				800,000,000	[5]
WES 5.375% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 500,000,000						500,000,000
Debt instrument, stated interest rate			5.375%
WES 5.375% Senior Notes due 2021 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 500,000,000						500,000,000
WES 4.000% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 670,000,000						670,000,000
Debt instrument, stated interest rate			4.00%
WES 4.000% Senior Notes due 2022 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 670,000,000						670,000,000
3.450% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 248,000,000						625,000,000
Debt instrument, stated interest rate			3.45%
3.450% Senior Notes due 2024 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 248,000,000	[5]	625,000,000				625,000,000	[5]
6.950% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 650,000,000						650,000,000
Debt instrument, stated interest rate			6.95%
6.950% Senior Notes due 2024 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 650,000,000						650,000,000
WES 3.950% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 500,000,000						500,000,000
Debt instrument, stated interest rate			3.95%
WES 3.950% Senior Notes due 2025 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 500,000,000						500,000,000
WES 4.650% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 500,000,000						500,000,000
Debt instrument, stated interest rate			4.65%
WES 4.650% Senior Notes due 2026 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 500,000,000						500,000,000
5.550% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 1,100,000,000						1,100,000,000
Debt instrument, stated interest rate			5.55%
5.550% Senior Notes due 2026 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 1,100,000,000						1,100,000,000
7.500% Debentures due 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 112,000,000						112,000,000
Debt instrument, stated interest rate			7.50%
7.500% Debentures due 2026 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 112,000,000						112,000,000
7.000% Debentures due 2027 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 48,000,000						48,000,000
Debt instrument, stated interest rate			7.00%
7.000% Debentures due 2027 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 48,000,000						48,000,000
7.125% Debentures due 2027 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 150,000,000						150,000,000
Debt instrument, stated interest rate			7.125%
7.125% Debentures due 2027 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 150,000,000						150,000,000
4.500% Senior Notes due March 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 400,000,000
Debt instrument, stated interest rate			4.50%
4.500% Senior Notes due March 2028 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount								$ 400,000,000
Debt instrument, stated interest rate								4.50%
4.750% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 400,000,000
Debt instrument, stated interest rate			4.75%
4.750% Senior Notes due August 2028 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount						$ 400,000,000
Debt instrument, stated interest rate						4.75%
6.625% Debentures due 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 14,000,000						14,000,000
Debt instrument, stated interest rate			6.625%
6.625% Debentures due 2028 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 14,000,000						14,000,000
7.150% Debentures due 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 235,000,000						235,000,000
Debt instrument, stated interest rate			7.15%
7.150% Debentures due 2028 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 235,000,000						235,000,000
7.200% Debentures due 2029 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 135,000,000						135,000,000
Debt instrument, stated interest rate			7.20%
7.200% Debentures due 2029 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 135,000,000						135,000,000
7.950% Debentures due 2029 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 116,000,000						116,000,000
Debt instrument, stated interest rate			7.95%
7.950% Debentures due 2029 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 116,000,000						116,000,000
7.500% Senior Notes due 2031 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 900,000,000						900,000,000
Debt instrument, stated interest rate			7.50%
7.500% Senior Notes due 2031 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 900,000,000						900,000,000
7.875% Senior Notes due 2031 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 500,000,000						500,000,000
Debt instrument, stated interest rate			7.875%
7.875% Senior Notes due 2031 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 500,000,000						500,000,000
Zero Coupon Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			2,270,000,000						2,360,000,000
Zero Coupon Senior Notes due 2036 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			2,270,000,000	[5]	$ 2,400,000,000				2,360,000,000	[5]
6.450% Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 1,750,000,000						1,750,000,000
Debt instrument, stated interest rate			6.45%
6.450% Senior Notes due 2036 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 1,750,000,000						1,750,000,000
7.950% Senior Notes due 2039 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 325,000,000						325,000,000
Debt instrument, stated interest rate			7.95%
7.950% Senior Notes due 2039 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 325,000,000						325,000,000
6.200% Senior Notes due 2040 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 750,000,000						750,000,000
Debt instrument, stated interest rate			6.20%
6.200% Senior Notes due 2040 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 750,000,000						750,000,000
4.500% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 625,000,000						625,000,000
Debt instrument, stated interest rate			4.50%
4.500% Senior Notes due 2044 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 625,000,000						625,000,000
WES 5.450% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 600,000,000						600,000,000
Debt instrument, stated interest rate			5.45%
WES 5.450% Senior Notes due 2044 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 600,000,000						600,000,000
6.600% Senior Notes due 2046 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 1,100,000,000						1,100,000,000
Debt instrument, stated interest rate			6.60%
6.600% Senior Notes due 2046 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 1,100,000,000						1,100,000,000
5.300% Senior Notes due March 2048 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 700,000,000
Debt instrument, stated interest rate			5.30%
5.300% Senior Notes due March 2048 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount								$ 700,000,000
Debt instrument, stated interest rate								5.30%
5.500% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 350,000,000
Debt instrument, stated interest rate			5.50%
5.500% Senior Notes due August 2028 [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount						$ 350,000,000
Debt instrument, stated interest rate						5.50%
7.730% Debentures due 2096 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 61,000,000						61,000,000
Debt instrument, stated interest rate			7.73%
7.730% Debentures due 2096 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 61,000,000						61,000,000
7.500% Debentures due 2096 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 78,000,000						78,000,000
Debt instrument, stated interest rate			7.50%
7.500% Debentures due 2096 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 78,000,000						78,000,000
7.250% Debentures due 2096 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 49,000,000						49,000,000
Debt instrument, stated interest rate			7.25%
7.250% Debentures due 2096 [Member] | Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[5]		$ 49,000,000						49,000,000
WES RCF [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			220,000,000						370,000,000
WES RCF [Member] | Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			220,000,000						370,000,000
WGP RCF [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			28,000,000						28,000,000
WGP RCF [Member] | Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[3]		$ 28,000,000						$ 28,000,000
[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.
[5]	Excludes WES and WGP
[6]	Excludes WES and WGP.

Debt and Interest Expense - Sc

Debt and Interest Expense - Scheduled Maturities Table (Detail) $ in Millions	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
2019	$ 928
2020	0
2021	1,177
2022	670
2023	220
Western Gas Partners LP [Member]
Debt Instrument [Line Items]
2019	0
2020	0
2021	500
2022	670
2023	220
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
2019	28	[1]
2020	0	[1]
2021	0	[1]
2022	0	[1]
2023	0	[1]
Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
2019	900	[2]
2020	0	[2]
2021	677	[2]
2022	0	[2]
2023	$ 0	[2]
[1]	Excludes WES.
[2]	Excludes WES and WGP

Debt and Interest Expense - Ad

Debt and Interest Expense - Additional Information (Detail) - USD ($)		Nov. 30, 2018	Jan. 31, 2018	Jan. 31, 2019	Dec. 31, 2018		May 31, 2018	Feb. 28, 2018	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2006	Aug. 31, 2018	Mar. 31, 2018
Debt Instrument [Line Items]
Debt instrument, principal amount					$ 17,661,000,000				$ 17,661,000,000		$ 17,032,000,000
Gain (loss) on extinguishment of debt									2,000,000		(2,000,000)		$ (155,000,000)
FPSO capital lease obligation					248,000,000				248,000,000		231,000,000
FPSO capital lease accumulated depreciation					72,000,000				$ 72,000,000		41,000,000
Five-Year Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity			$ 3,000,000,000
Line of credit, expiration date									Jan. 23, 2023
Line of credit, outstanding borrowings					$ 0				$ 0
Five-Year Credit Facility [Member] | Minimum [Member] | Euro Interbank Offered Rate or Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									0.00%
Five-Year Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capital					0.65				0.65
Five-Year Credit Facility [Member] | Maximum [Member] | Euro Interbank Offered Rate or Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									1.65%
364-Day Facility [Member]
Debt Instrument [Line Items]
Line of credit, outstanding borrowings					$ 0				$ 0
364-Day Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capital					0.65				0.65
Commercial Paper [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity					$ 3,000,000,000				$ 3,000,000,000
Commercial paper, outstanding borrowings					0				$ 0
Commercial Paper [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, term									397 days
WES RCF [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					220,000,000				$ 220,000,000		370,000,000
Borrowings, credit facilities									540,000,000		370,000,000
Repayments of credit facilities									690,000,000
WGP RCF [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					28,000,000				$ 28,000,000		28,000,000
WGP RCF [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Line of credit, variable rate floor									0.00%
WGP RCF [Member] | London Interbank Offered Rate (LIBOR) [Member] | Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									1.00%
WGP RCF [Member] | Percentage Above Federal Funds Effective Rate [Member] | Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									0.50%
WGP RCF [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added									2.00%
WGP RCF [Member] | Minimum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									1.00%
WGP RCF [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added									2.75%
WGP RCF [Member] | Maximum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									1.75%
Fair Value, Inputs, Level 2 [Member] | Valuation, Market Approach [Member]
Debt Instrument [Line Items]
Estimated fair value of total borrowings					16,800,000,000				$ 16,800,000,000		17,700,000,000
3.450% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Repayments of debt									375,000,000
Debt instrument, principal amount					$ 248,000,000				$ 248,000,000		625,000,000
Debt instrument, stated interest rate					3.45%				3.45%
4.850% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Repayments of debt									$ 123,000,000
Debt instrument, principal amount					$ 677,000,000				$ 677,000,000		800,000,000
Debt instrument, stated interest rate					4.85%				4.85%
7.050% Debentures due 2018 [Member]
Debt Instrument [Line Items]
Repayments of debt									$ 114,000,000
Debt instrument, principal amount											114,000,000
Debt instrument, stated interest rate
Zero Coupon Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Repayments of debt									$ 35,000,000
Debt instrument, principal amount					$ 2,270,000,000				$ 2,270,000,000		2,360,000,000
Loan proceeds upon issuing debt														$ 500,000,000
Yield to maturity					5.24%				5.24%
Debt instrument, accreted value					$ 905,000,000				$ 905,000,000
Debt instrument, earliest call date									Oct. 10, 2019
4.500% Senior Notes due March 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					$ 400,000,000				$ 400,000,000
Debt instrument, stated interest rate					4.50%				4.50%
5.300% Senior Notes due March 2048 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					$ 700,000,000				$ 700,000,000
Debt instrument, stated interest rate					5.30%				5.30%
4.750% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					$ 400,000,000				$ 400,000,000
Debt instrument, stated interest rate					4.75%				4.75%
5.500% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					$ 350,000,000				$ 350,000,000
Debt instrument, stated interest rate					5.50%				5.50%
WES 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount											350,000,000
Debt instrument, stated interest rate
Repayments of credit facilities									$ 350,000,000
FPSO Capital Lease [Member]
Debt Instrument [Line Items]
Anadarko's nonoperated interest					19.00%				19.00%
FPSO capital lease obligation					$ 225,000,000				$ 225,000,000
FPSO capital lease asset					225,000,000				$ 225,000,000
FPSO capital lease initial term									10 years
FPSO capital lease additional term									10 years
Capital lease payments made									$ 46,000,000		44,000,000
Anadarko Excluding WES and WGP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[1]				12,793,000,000				12,793,000,000		13,514,000,000
FPSO capital lease obligation	[1]				248,000,000				$ 248,000,000		231,000,000
Anadarko Excluding WES and WGP [Member] | 364-Day Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity			$ 2,000,000,000
Debt instrument, term									364 days
Anadarko Excluding WES and WGP [Member] | 364-Day Facility [Member] | Minimum [Member] | London Interbank Offered Rate or Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									0.00%
Anadarko Excluding WES and WGP [Member] | 364-Day Facility [Member] | Maximum [Member] | London Interbank Offered Rate or Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									1.675%
Anadarko Excluding WES and WGP [Member] | 3.450% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Repayments of debt					377,000,000				$ 375,000,000	[2]
Debt instrument, principal amount		$ 625,000,000			248,000,000	[1]			248,000,000	[1]	625,000,000	[1]
Anadarko Excluding WES and WGP [Member] | 4.850% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Repayments of debt					123,000,000				123,000,000	[2]
Debt instrument, principal amount		800,000,000			677,000,000	[1]			677,000,000	[1]	800,000,000	[1]
Anadarko Excluding WES and WGP [Member] | 3.450% Senior Notes Due 2024 and 4.850% Senior Notes due 2021
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt					7,000,000
Anadarko Excluding WES and WGP [Member] | 7.050% Debentures due 2018 [Member]
Debt Instrument [Line Items]
Repayments of debt	[2]						$ 114,000,000		114,000,000
Debt instrument, principal amount	[1]										114,000,000
Debt instrument, stated interest rate							7.05%
Anadarko Excluding WES and WGP [Member] | Zero Coupon Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Repayments of debt					36,000,000				35,000,000	[2]
Debt instrument, principal amount		$ 2,400,000,000			2,270,000,000	[1]			2,270,000,000	[1]	2,360,000,000	[1]
Gain (loss) on extinguishment of debt					3,000,000
Extinguishment of debt					90,000,000
Western Gas Partners LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					4,840,000,000				4,840,000,000		3,490,000,000
FPSO capital lease obligation					0				0		0
Western Gas Partners LP [Member] | WES RCF [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					220,000,000				220,000,000		370,000,000
Line of credit, maximum capacity					$ 2,000,000,000			$ 1,500,000,000	2,000,000,000
Line of credit, expiration date		Feb. 26, 2023	Feb. 26, 2020		Feb. 26, 2024			Feb. 26, 2023
Line of credit, outstanding borrowings					$ 220,000,000				220,000,000
Line of credit, expandable maximum capacity								$ 2,000,000,000
Line of credit, increase limit								500,000,000
Borrowings, credit facilities									540,000,000		370,000,000
Repayments of credit facilities									$ 690,000,000
Line of credit, interest rate					3.74%				3.74%
Outstanding letters of credit					$ 5,000,000				$ 5,000,000
Line of credit, available borrowing capacity					1,300,000,000				$ 1,300,000,000
Western Gas Partners LP [Member] | WES RCF [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added									0.975%
Western Gas Partners LP [Member] | WES RCF [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added									1.45%
Western Gas Partners LP [Member] | WES 364-Day Facility
Debt Instrument [Line Items]
Line of credit, maximum capacity					$ 2,000,000,000				$ 2,000,000,000
Debt instrument, term									364 days
Line of credit, ticking fee					0.175%
Western Gas Partners LP [Member] | WES 364-Day Facility | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added									1.00%
Western Gas Partners LP [Member] | WES 364-Day Facility | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added									1.625%
Western Gas Partners LP [Member] | 4.500% Senior Notes due March 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount																$ 400,000,000
Debt instrument, stated interest rate																4.50%
Western Gas Partners LP [Member] | 5.300% Senior Notes due March 2048 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount																$ 700,000,000
Debt instrument, stated interest rate																5.30%
Western Gas Partners LP [Member] | 4.750% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount															$ 400,000,000
Debt instrument, stated interest rate															4.75%
Western Gas Partners LP [Member] | 5.500% Senior Notes due August 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount															$ 350,000,000
Debt instrument, stated interest rate															5.50%
Western Gas Partners LP [Member] | WES 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					$ 350,000,000				$ 350,000,000		350,000,000
Debt instrument, stated interest rate					2.60%				2.60%
Repayments of credit facilities									$ 350,000,000
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount					$ 28,000,000	[3]			28,000,000	[3]	28,000,000	[4]
FPSO capital lease obligation					0	[3]			0	[3]	0	[4]
Western Gas Equity Partners, LP excluding WES [Member] | WGP RCF [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	[3]				28,000,000				28,000,000		$ 28,000,000
Line of credit, maximum capacity			$ 250,000,000					$ 35,000,000
Line of credit, expiration date								Mar. 14, 2019
Line of credit, outstanding borrowings					28,000,000				28,000,000
Line of credit, expandable maximum capacity					$ 500,000,000				$ 500,000,000
Line of credit, interest rate					4.53%				4.53%
Line of credit, available borrowing capacity					$ 7,000,000				$ 7,000,000
Accreted Value At Next Potential Put Date [Member] | Zero Coupon Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Debt instrument, accreted value					$ 942,000,000				$ 942,000,000
Variable Rate Component 1 [Member] | Western Gas Partners LP [Member] | WES 364-Day Facility | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Applicable margin added									0.50%
Variable Rate Component 2 [Member] | Western Gas Partners LP [Member] | WES 364-Day Facility | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added									1.00%
Variable Rate Component 2 [Member] | Western Gas Partners LP [Member] | WES 364-Day Facility | Minimum [Member] | Unsecured Debt Rating [Member]
Debt Instrument [Line Items]
Applicable margin added									0.00%
Variable Rate Component 2 [Member] | Western Gas Partners LP [Member] | WES 364-Day Facility | Maximum [Member] | Unsecured Debt Rating [Member]
Debt Instrument [Line Items]
Applicable margin added									0.625%
Subsequent Event [Member] | Anadarko Excluding WES and WGP [Member] | 364-Day Facility [Member]
Debt Instrument [Line Items]
Debt instrument, term				364 days
Line of credit, expiration date				Jan. 12, 2019
[1]	Excludes WES and WGP
[2]	Excludes WES and WGP.
[3]	Excludes WES.
[4]	Excludes WES.

Debt and Interest Expense - Ca

Debt and Interest Expense - Capital Lease Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
2019	$ 58
2020	50
2021	48
2022	45
2023	43
Thereafter	323
Total future minimum lease payments	567
Less portion representing imputed interest	319
Capital lease obligations	$ 248	$ 231

Debt and Interest Expense - In

Debt and Interest Expense - Interest Expense Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt and other	$ 1,028	$ 1,003	$ 1,022
Capitalized interest	(81)	(71)	(132)
Total interest expense	$ 947	$ 932	$ 890

Income Taxes - Additional Info

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended			48 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2015
Income Tax Disclosure [Line Items]
One-time deferred tax expense (benefit) due to tax reform legislation	$ 95	$ (1,168)	$ 0
Tax reform legislation, measurement period adjustment, current tax benefit	26
Tax reform legislation, measurement period adjustment, deferred tax expense	121
Unrecognized tax benefits	1,287	1,317	1,456	$ 1,317	$ 1,780
Total income tax benefit recorded related to the Tronox-related contingent liability	(733)	1,477	1,021
Income taxes receivable	97	154		154
Unrecognized tax benefits that would affect the effective tax rate on income if recognized	1,260
Accrued interest related to uncertain tax positions	95	86		86
Interest and penalties recognized in income tax expense (benefit)	9	55
Minimum [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits expected to reverse within the next 12 months due to expiration of statutes of limitation and audit settlements	70
Maximum [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits expected to reverse within the next 12 months due to expiration of statutes of limitation and audit settlements	90
Portion Of Unrecognized Tax Benefits With Highly Certain Deductibility [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits	1,240
Portion Of Unrecognized Tax Benefits With Highly Certain Deductibility And Uncertain Timing [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits	43
Tronox Litigation [Member] | Judicial Ruling [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits	1,200
Tentative tax refund received			$ 881
Total income tax benefit recorded related to the Tronox-related contingent liability	$ 346			$ 346
Foreign Tax Credits [Member]
Income Tax Disclosure [Line Items]
Increase in valuation allowance		$ 236

Income Taxes - Components of I

Income Taxes - Components of Income Tax Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current [Abstract]
Federal	$ 14	$ 236	$ (140)
State	(1)	48	(1)
Foreign	595	414	378
Total current tax expense (benefit)	608	698	237
Deferred [Abstract]
Federal	150	(2,082)	(1,020)
State	(26)	(17)	(148)
Foreign	1	(76)	(90)
Total deferred tax expense (benefit)	125	(2,175)	(1,258)
Total income tax expense (benefit)	$ 733	$ (1,477)	$ (1,021)

Income Taxes - Reconciliation

Income Taxes - Reconciliation of Tax Computed at the U.S. Federal Statutory Rate to Income Tax Expense (Benefit) Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income (loss) before income taxes
Domestic	$ 492	$ (1,322)	$ (3,728)
Foreign	993	(366)	(101)
Income (Loss) Before Income Taxes	$ 1,485	$ (1,688)	$ (3,829)
U.S. federal statutory tax rate	21.00%	35.00%	35.00%
Tax computed at the U.S. federal statutory rate	$ 312	$ (591)	$ (1,340)
(Income) loss attributable to noncontrolling interests	(29)	(85)	(92)
Adjustments resulting from
State income taxes (net of federal income tax benefit)	(18)	25	(108)
U.S. federal tax reform	95	(1,168)	0
Tax impact from foreign operations	181	166	80
Non-deductible Algerian exceptional profits tax	154	110	106
Net changes in uncertain tax positions	(29)	90	90
Dispositions of non-deductible goodwill	0	6	205
Other, net	67	(30)	38
Total income tax expense (benefit)	$ 733	$ (1,477)	$ (1,021)
Effective tax rate	49.00%	88.00%	27.00%

Income Taxes - Components of T

Income Taxes - Components of Total Deferred Taxes Table (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes	[1]	$ (2,403)	$ (2,213)
Federal [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes		(1,972)	(1,758)
State, net of federal [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes		(176)	(200)
Foreign [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes		(255)	(255)
ALGERIA
Deferred Tax Assets (Liabilities), Net [Line Items]
Deferred Income Tax Assets, Net		$ 34	$ 21
[1]	Net deferred tax assets related to Algeria of $34 million in 2018 and $21 million in 2017 are presented in other assets on the Company’s Consolidated Balance Sheet.

Income Taxes - Deferred Tax As

Income Taxes - Deferred Tax Assets (Liabilities) Table (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred tax liabilities
Oil and gas exploration and development operations		$ (2,403)	$ (2,622)
Midstream and other depreciable properties		(662)	(543)
Mineral operations		(238)	(312)
Other		(134)	(53)
Gross long-term deferred tax liabilities		(3,437)	(3,530)
Deferred tax assets
Oil and gas exploration and development costs		303	309
Foreign and state net operating loss carryforwards		445	562
U.S. foreign tax credit carryforwards		2,665	2,685
Compensation and benefit plans		301	365
Other		308	420
Gross long-term deferred tax assets		4,022	4,341
Valuation allowances on deferred tax assets not expected to be realized		(2,988)	(3,024)	$ (1,755)	$ (1,403)
Net long-term deferred tax assets		1,034	1,317
Total deferred taxes	[1]	$ (2,403)	$ (2,213)
[1]	Net deferred tax assets related to Algeria of $34 million in 2018 and $21 million in 2017 are presented in other assets on the Company’s Consolidated Balance Sheet.

Income Taxes - Valuation Allow

Income Taxes - Valuation Allowances Rollforward (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Balance at January 1	$ (3,024)	$ (1,755)	$ (1,403)
Valuation Allowance [Line Items]
Balance at December 31	(2,988)	(3,024)	(1,755)
U.S. Foreign Tax Credits [Member]
Valuation Allowance [Line Items]
Change in valuation allowances	(50)	(1,287)	(477)
Foreign and State Net Operating Loss Carryforwards [Member]
Valuation Allowance [Line Items]
Change in valuation allowances	72	75	13
Foreign Capitalized Costs [Member]
Valuation Allowance [Line Items]
Change in valuation allowances	$ 14	$ (57)	$ 112

Income Taxes - Net Operating L

Income Taxes - Net Operating Loss Carryforward Table (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Uncertain tax positions		$ 1,287	$ 1,317	$ 1,456	$ 1,780
Foreign [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward		820
Uncertain tax positions		$ 378
Foreign [Member] | Earliest Tax Year [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, expiration date		Dec. 31, 2019
State [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	[1]	$ 4,250
Uncertain tax positions		$ 711
State [Member] | Earliest Tax Year [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, expiration date		Dec. 31, 2019
State [Member] | Latest Tax Year [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, expiration date		Dec. 31, 2038
[1]	Net of $711 million uncertain tax position at December 31, 2018.

Income Taxes - Tax Credit Carr

Income Taxes - Tax Credit Carryforward Table (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Tax Credit Carryforward [Line Items]
Uncertain tax positions		$ 1,287	$ 1,317	$ 1,456	$ 1,780
Foreign Tax Credits [Member]
Tax Credit Carryforward [Line Items]
Tax credit carryforward	[1]	$ 2,665
Foreign Tax Credits [Member] | Earliest Tax Year [Member]
Tax Credit Carryforward [Line Items]
Tax credit carryforward, expiration date		Dec. 31, 2023
Foreign Tax Credits [Member] | Latest Tax Year [Member]
Tax Credit Carryforward [Line Items]
Tax credit carryforward, expiration date		Dec. 31, 2028
Texas Margins Tax Credit [Member]
Tax Credit Carryforward [Line Items]
Tax credit carryforward		$ 27
Tax credit carryforward, expiration date		Dec. 31, 2026
[1]	Net of $378 million uncertain tax position at December 31, 2018.

Income Taxes - Taxes Receivabl

Income Taxes - Taxes Receivable (Payable) Table (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes receivable	$ 97	$ 154
Income taxes (payable)	(167)	(71)
Total net income taxes receivable (payable)	(70)	83
Accounts Receivable - Other [Member]
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes receivable	46	53
Other Assets [Member]
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes receivable, noncurrent	51	101
Accrued Expense [Member]
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes (payable)	$ (167)	$ (71)

Income Taxes - Unrecognized Ta

Income Taxes - Unrecognized Tax Benefits Rollforward (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1	$ (1,317)	$ (1,456)	$ (1,780)
Increases related to prior-year tax positions	(21)	(15)	(86)
Decreases related to prior-year tax positions	48	214	436
Increases related to current-year tax positions	0	(72)	(26)
Settlements	1	12	0
Lapse of statute of limitations	2	0	0
Balance at December 31	$ (1,287)	$ (1,317)	$ (1,456)

Income Taxes - Tax Years Subje

Income Taxes - Tax Years Subject to Examination by Major Jurisdiction Table (Detail)	12 Months Ended
	Dec. 31, 2018
United States [Member] | Earliest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2013
United States [Member] | Latest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2018
Algeria [Member] | Earliest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2015
Algeria [Member] | Latest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2018
Ghana [Member] | Earliest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2015
Ghana [Member] | Latest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2018

Asset Retirement Obligations (D

Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Carrying amount at January 1	$ 2,794	$ 2,931
Liabilities acquired	0	4
Liabilities incurred	153	191
Property dispositions	(99)	(154)
Liabilities settled	(274)	(135)
Accretion expense	130	144
Revisions in estimated liabilities	395	(187)
Carrying amount at December 31	$ 3,099	$ 2,794

Conveyance of Future Hard Min_3

Conveyance of Future Hard Minerals Royalty Revenues - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Deferred Revenue Disclosure [Abstract]
Other financing activities	$ 413	$ (6)	$ (18)	$ 0
Maximum amount of total future royalty revenue third-party is entitled to	$ 553	428
Deferred Revenue Arrangement [Line Items]
Amount of deferred revenue amortized in period		36	38	37
Payments of future hard minerals royalty revenues conveyed		$ 50	$ 50	$ 25
Royalties Between $800 and $900 Million During the First 10 Years [Member]
Deferred Revenue Arrangement [Line Items]
Percentage of excess royalties	3.00%
Baseline amount of excess royalties	$ 800
Royalties In Excess Of $900 Million During the First 10 Years [Member]
Deferred Revenue Arrangement [Line Items]
Percentage of excess royalties	4.00%
Baseline amount of excess royalties	$ 900
Minimum [Member]
Deferred Revenue Arrangement [Line Items]
Term of conveyance	10 years
Maximum [Member]
Deferred Revenue Arrangement [Line Items]
Term of conveyance	15 years

Conveyance of Future Hard Min_4

Conveyance of Future Hard Minerals Royalty Revenues - Schedule of Future Royalty Payments (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Mar. 31, 2016
Deferred Revenue Disclosure [Abstract]
2019	$ 52
2020	57
2021	57
2022	58
2023	60
Thereafter	144
Total	$ 428	$ 553

Commitments - Operating Leases

Commitments - Operating Leases (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	$ 654
Operating leases, residual value guarantees	73
Total rent expense, net of sublease income and amounts capitalized	74	$ 55	$ 73
Contingent rent expense related to transportation and processing fees	4	$ 3	$ 6
Operating leases, residual value guarantees accrued	$ 5
Maximum [Member]
Operating Leased Assets [Line Items]
Operating leases, expiration date	Dec. 31, 2033
Drilling Rigs [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	$ 262
Other Operating Lease Agreements [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	392
Offshore Drilling Rig Commitments [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	$ 209
Number of offshore drilling vessels related to operating leases	3
Onshore Drilling Rig Commitments [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	$ 41
International Drilling Rig Commitments [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	$ 12
Number of offshore drilling vessels related to operating leases	2

Commitments - Future Minimum L

Commitments - Future Minimum Lease Payments Table (Detail) $ in Millions	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
2019	$ 264
2020	139
2021	57
2022	35
2023	24
Thereafter	135
Total future minimum lease payments	$ 654

Commitments - Other Commitment

Commitments - Other Commitments Lease Payments Table (Detail) $ in Millions	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
2019	$ 1,147
2020	1,155
2021	993
2022	786
2023	646
Thereafter	1,498
Total	$ 6,225	[1]
[1]	Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.

Contingencies (Detail)

Contingencies (Detail) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Loss Contingencies [Line Items]
Loss contingency accrual	$ 33,000,000
Other assets	2,336,000,000	$ 2,211,000,000
Liability for remediation and reclamation obligations	109,000,000	$ 113,000,000
Pending Litigation [Member] | Peregrino Litigation [Member]
Loss Contingencies [Line Items]
Loss contingency accrual	0
Pending Litigation [Member] | Amount Of Tax Originally In Dispute [Member] | Peregrino Litigation [Member]
Loss Contingencies [Line Items]
Other assets	$ 88,000,000

Restructuring Charges (Detail)

Restructuring Charges (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ 53	$ 21	$ 389
General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges			192
Other Income (Expense) [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges			$ 197
Retirement Benefits [Member] | General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges		$ 21

Pension Plans, Other Postreti_3

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Change in Benefit Obligation Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Pension Plans, Defined Benefit [Member]
Change in benefit obligation
Benefit obligation at beginning of year	$ 2,218	[1]	$ 2,301
Service cost	90		87		$ 99
Interest cost	77		84		95
Actuarial (gain) loss	(176)		107
Curtailments, settlements, and special termination benefits expense	15		23
Participant contributions	0		0
Benefit payments	(268)		(396)
Foreign-currency exchange-rate changes	(8)		12
Benefit obligation at end of year	1,948	[1]	2,218	[1]	2,301
Accumulated benefit obligation for all defined-benefit pension plans	1,600		1,900
Other Postretirement Benefits Plan [Member]
Change in benefit obligation
Benefit obligation at beginning of year	302	[1]	296
Service cost	1		2		3
Interest cost	11		12		12
Actuarial (gain) loss	(23)		15
Curtailments, settlements, and special termination benefits expense	0		(1)
Participant contributions	7		5
Benefit payments	(25)		(27)
Foreign-currency exchange-rate changes	0		0
Benefit obligation at end of year	$ 273	[1]	$ 302	[1]	$ 296
[1]	The accumulated benefit obligation for all defined-benefit pension plans was $1.6 billion at December 31, 2018 and $1.9 billion at December 31, 2017.

Pension Plans, Other Postreti_4

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Change in Plan Assets, Funded Status of the Plans, and Amounts Recognized in the Financial Statements Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Change in plan assets
Employer contributions	$ 244
Pension Plans, Defined Benefit [Member]
Change in plan assets
Fair value of plan assets at beginning of year	1,424	$ 1,340
Actual return on plan assets	(57)	209
Employer contributions	225	254
Participant contributions	0	0
Benefits paid related to plan settlements	(212)	(337)
Benefit payments, other	(56)	(59)
Foreign-currency exchange-rate changes	(10)	17
Fair value of plan assets at end of year	1,314	1,424
Funded status of the plans at end of year	(634)	(794)
Total recognized amounts in the balance sheet consist of
Other assets	63	58
Accrued expenses	(42)	(16)
Other long-term liabilities—other	(655)	(836)
Total	(634)	(794)
Total recognized amounts in accumulated other comprehensive income consist of
Prior service (credit) cost	1	0
Net actuarial (gain) loss	399	501
Total	400	501
Other Postretirement Benefits Plan [Member]
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	19	22
Participant contributions	7	5
Benefits paid related to plan settlements	(1)	(3)
Benefit payments, other	(25)	(24)
Foreign-currency exchange-rate changes	0	0
Fair value of plan assets at end of year	0	0
Funded status of the plans at end of year	(273)	(302)
Total recognized amounts in the balance sheet consist of
Other assets	0	0
Accrued expenses	(21)	(21)
Other long-term liabilities—other	(252)	(281)
Total	(273)	(302)
Total recognized amounts in accumulated other comprehensive income consist of
Prior service (credit) cost	(2)	(26)
Net actuarial (gain) loss	(9)	14
Total	$ (11)	$ (12)

Pension Plans, Other Postreti_5

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Accumulated Benefit Obligations in Excess of Plan Assets Table (Detail) - Pension Plans, Defined Benefit [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 1,828	$ 2,079
Accumulated benefit obligation	1,527	1,749
Fair value of plan assets	$ 1,131	$ 1,227

Pension Plans, Other Postreti_6

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Components of Net Periodic Benefit Cost Table (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost		$ 90	$ 87	$ 99
Interest cost		77	84	95
Expected (return) loss on plan assets		(83)	(84)	(97)
Amortization of net actuarial (gain) loss		25	25	42
Amortization of net prior service (credit) cost		0	(1)	0
Settlement expense	[1]	49	91	146
Termination benefits expense	[1]	7	4	44
Curtailment expense	[1]	(1)	0	8
Net periodic benefit cost	[2]	164	206	337
Other Postretirement Benefits Plan [Member]
Components of net periodic benefit cost
Service cost		1	2	3
Interest cost		11	12	12
Expected (return) loss on plan assets		0	0	0
Amortization of net actuarial (gain) loss		0	0	0
Amortization of net prior service (credit) cost		(24)	(24)	(25)
Settlement expense	[1]	0	0	0
Termination benefits expense	[1]	0	0	0
Curtailment expense	[1]	0	0	0
Net periodic benefit cost	[2]	$ (12)	$ (10)	$ (10)
[1]	Settlement expense, termination benefits expense, and curtailment expense for 2016 relate to the workforce reduction program initiated in the first quarter of 2016. See Note 19—Restructuring Charges.
[2]	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.

Pension Plans, Other Postreti_7

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Amounts Recognized in Other Comprehensive Income (Expense) Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Amounts recognized in other comprehensive income (expense)
Net actuarial gain (loss)	$ 50	$ (14)	$ (175)
Amortization of net actuarial (gain) loss	74	116	188
Amortization of net prior service cost (credit)	(24)	(25)	(34)
Pension Plans, Defined Benefit [Member]
Amounts recognized in other comprehensive income (expense)
Net actuarial gain (loss)	27	0	(150)
Amortization of net actuarial (gain) loss	74	116	188
Amortization of net prior service cost (credit)	0	(1)	0
Total amounts recognized in other comprehensive income (expense)	101	115	38
Other Postretirement Benefits Plan [Member]
Amounts recognized in other comprehensive income (expense)
Net actuarial gain (loss)	23	(14)	(25)
Amortization of net actuarial (gain) loss	0	0	0
Amortization of net prior service cost (credit)	(24)	(24)	(34)
Total amounts recognized in other comprehensive income (expense)	$ (1)	$ (38)	$ (59)

Pension Plans, Other Postreti_8

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Retirement Benefits [Abstract]
Defined-benefit plan, amortization of net actuarial loss in 2019	$ 12,000,000
Defined benefit plan, amortization of prior service credit in 2019	$ 2,000,000
Defined benefit plan, annual rate of increase assumed for next fiscal year	1.70%	2.00%	2.00%
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amount of employer securities included in plan assets	$ 0
Defined-contribution plans, recognized expense	$ 63,000,000	$ 63,000,000	$ 64,000,000
Maximum [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target asset-allocation percentages	0.5
Maximum [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target asset-allocation percentages	0.25
Maximum [Member] | Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target asset-allocation percentages	0.25

Pension Plans, Other Postreti_9

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Weighted-Average Assumptions for Benefit Obligations and Net Periodic Benefit Cost Table (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.30%	3.62%	4.06%
Rates of increase in compensation levels	5.33%	5.36%	5.40%
Discount rate	3.62%	4.06%	4.62%
Long-term rate of return on plan assets	6.09%	6.12%	6.77%
Rates of increase in compensation levels	5.36%	5.40%	5.34%
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.43%	3.75%	4.26%
Rates of increase in compensation levels	5.43%	5.46%	5.48%
Discount rate	3.75%	4.26%	5.00%
Rates of increase in compensation levels	5.46%	5.48%	5.41%

Pension Plans, Other Postret_10

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Fair Value of Pension Plan Assets by Asset Class and Input Level Table (Detail) - Investments [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	$ 1,314	$ 1,424
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	260	241
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	77	84
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1],[2]	13	13
Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments measured at net asset value	[3]	964	1,086
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		28	1
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		28	1
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	0	0
Fixed-Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		71	86
Fixed-Income [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		43	55
Fixed-Income [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		28	31
Fixed-Income [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	0	0
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		189	185
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		189	185
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	0	0
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		13	13
Real Estate [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Real Estate [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Real Estate [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	13	13
Total change in level 3 investments attributable to the actual return on plan assets still held at the reporting period		0	3
Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		49	53
Other [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Other [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		49	53
Other [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	$ 0	$ 0
[1]	Amount excludes receivables and payables, primarily related to Level 1 investments.
[2]	There were no changes in Level 3 investments for the year ended December 31, 2018. The changes in Level 3 investments of $3 million for the year ended December 31, 2017, were attributable to the actual return on plan assets still held at the reporting date.
[3]	Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.

Pension Plans, Other Postret_11

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Estimated Future Contributions and Current Year Contributions Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected employer contributions in 2019	$ 155
Employer contributions	244
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	225	$ 254
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	19	$ 22
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected employer contributions in 2019	90
Employer contributions	161
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected employer contributions in 2019	43
Employer contributions	64
Unfunded Plans [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected employer contributions in 2019	22
Employer contributions	$ 19

Pension Plans, Other Postret_12

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Estimated Benefit Payments Table (Detail) $ in Millions	Dec. 31, 2018USD ($)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2019	$ 223
2020	148
2021	150
2022	190
2023	181
2024-2028	839
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2019	22
2020	21
2021	20
2022	20
2023	20
2024-2028	$ 86

Stockholders' Equity - Additio

Stockholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended							12 Months Ended			13 Months Ended	15 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Aug. 31, 2018	Jun. 30, 2018	Feb. 28, 2018	Dec. 31, 2017	Sep. 30, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2018	Sep. 30, 2017
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program amount authorized	$ 5,000							$ 5,000			$ 5,000	$ 5,000	$ 2,500
Total Shares Delivered (in shares)											65
Average Price per Share (in usd per share)											$ 57.69
Purchase of treasury stock (in shares)								43	22	0
Amount of share repurchase program completed											$ 3,750	3,750
Issuance of common stock during the period (in shares)							40.5	0	0	41
Price per share of common stock issued during the period							$ 53.23
Proceeds from issuance of common stock							$ 2,160	$ 7	$ 0	$ 2,188
Accelerated Stock Repurchase Program, [Member]
Equity, Class of Treasury Stock [Line Items]
Payment under share repurchase program	2,941			$ 1,441	$ 500	$ 1,000		$ 2,941	$ 1,000		$ 2,941	$ 2,941
Price paid per share under ASR (in usd per share)				$ 65.28	$ 58.82	$ 48.13
Initial Shares Delivered (in shares)				19.1	7	15.7					41.8
Additional Shares Delivered (in shares)				3	1.5	5.1					9.6
Total Shares Delivered (in shares)				22.1	8.5	20.8					51.4
Open-market Stock Purchases [Member]
Equity, Class of Treasury Stock [Line Items]
Amount (in shares)	$ 250	$ 250	$ 250			$ 59					$ 809
Average Price per Share (in usd per share)	$ 52.34	$ 63.11	$ 66.14			$ 52
Purchase of treasury stock (in shares)	4.8	3.9	3.8			1.1					13.6

Stockholders' Equity - Common

Stockholders' Equity - Common Stock Rollforward (Detail) shares in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2016shares	Dec. 31, 2018shares		Dec. 31, 2017shares	Dec. 31, 2016shares
Shares of common stock issued
Shares at January 1 (in shares)		574,200		572,000	528,000
Exercise of stock options (in shares)		100	[1]	0	1,000
Issuance of common stock (in shares)	40,500	0		0	41,000
Issuance of restricted stock (in shares)		3,000		2,000	2,000
Shares at December 31 (in shares)		576,600		574,200	572,000
Shares of common stock held in treasury
Shares at January 1 (in shares)		43,400		21,000	20,000
Purchase of treasury stock (in shares)		43,000		22,000	0
Shares received for restricted stock vested and stock options exercised (in shares)		1,000		0	1,000
Shares at December 31 (in shares)		87,200		43,400	21,000
Shares of common stock outstanding at December 31 (in shares)		490,000		531,000	551,000
[1]	The total intrinsic value of stock options exercised was $1 million during 2018, zero during 2017, and $7 million during 2016, based on the difference between the market price at the exercise date and the exercise price.

Stockholders' Equity - Reconci

Stockholders' Equity - Reconciliation between Basic and Diluted EPS Table (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income (loss)
Net income (loss) attributable to common stockholders	$ 615	$ (456)	$ (3,071)
Income (loss) effect of TEUs	(4)	(7)	(6)
Less distributions on participating securities	5	1	1
Basic	606	(464)	(3,078)
Income (loss) effect of TEUs	(1)	(2)	(1)
Diluted	$ 605	$ (466)	$ (3,079)
Shares
Average number of common shares outstanding—basic (in shares)	504	548	522
Average number of common shares outstanding—diluted (in shares)	504	548	522
Excluded due to anti-dilutive effect (in shares)	9	11	11
Net income (loss) per common share
Basic (in usd per share)	$ 1.20	$ (0.85)	$ (5.90)
Diluted (in usd per share)	1.20	(0.85)	(5.90)
Dividends per common share (in USD per share)	$ 1.05	$ 0.2	$ 0.2

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018	Jan. 01, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance		$ 13,790	$ 15,497	$ 15,457
Other comprehensive income (loss), before reclassifications		39	(10)	(107)
Reclassifications to Consolidated Statement of Income		37	63	99
Cumulative effect of accounting change					$ (47)	$ (31)
Net other comprehensive income (loss)		3	53	(8)
Balance		10,943	13,790	15,497
Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance		(35)	(37)	(42)
Other comprehensive income (loss), before reclassifications		0	0	0
Reclassifications to Consolidated Statement of Income		2	2	5
Net other comprehensive income (loss)		(5)	2	5
Balance		(40)	(35)	(37)
Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance		(303)	(354)	(341)
Other comprehensive income (loss), before reclassifications		39	(10)	(107)
Reclassifications to Consolidated Statement of Income		35	61	94
Net other comprehensive income (loss)		8	51	(13)
Balance		(295)	(303)	(354)
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance		(338)	(391)	(383)
Cumulative effect of accounting change					(73)
Balance		$ (335)	$ (338)	$ (391)
Accounting Standards Update 2018-02 [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Cumulative effect of accounting change	[1]				(73)
Accounting Standards Update 2018-02 [Member] | Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Cumulative effect of accounting change	[1]				(7)
Accounting Standards Update 2018-02 [Member] | Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Cumulative effect of accounting change	[1]				$ (66)
[1]	Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

Share-Based Compensation - Add

Share-Based Compensation - Additional Information (Detail) - USD ($) shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Shares available for future issuance under active share-based compensation plans (in shares)	20
Shares authorized for awards under active share-based compensation plans (in shares)	41
Cash received from stock option exercises	$ 7,000,000	$ 0	$ 30,000,000
Tax benefit from exercise of stock options	$ 0	$ 0	$ 2,000,000

Share-Based Compensation - Com

Share-Based Compensation - Compensation Expense Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	$ 188		$ 150	$ 235
Income tax benefit	43		35	86
Restricted stock [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	147	[1]	145	175
Restricted stock [Member] | Share Based Compensation [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense				31
Stock options [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	21	[1]	17	20
Stock options [Member] | Share Based Compensation [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense				1
Other equity-classified awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	1		1	2
Performance-based unit awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	$ 19	[1]	(13)	38
Performance-based unit awards [Member] | Share Based Compensation [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense			$ (7)	$ 7
[1]	Includes restructuring charges of $(7) million for performance-based unit awards in 2017 and $31 million for restricted stock, $1 million for stock options, and $7 million for performance-based unit awards in 2016. See Note 19—Restructuring Charges for additional information.

Share-Based Compensation - Equ

Share-Based Compensation - Equity-Classified Awards (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted stock [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Weighted-average grant-date fair value (in usd per share)	$ 58.30	$ 59.92	$ 52.03
Total fair value	$ 142	$ 132	$ 114
Total unrecognized compensation cost	$ 172
Unrecognized compensation cost, remaining weighted-average remaining service period	1 year 6 months
Restricted stock [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years
Stock options [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years
Total unrecognized compensation cost related to stock options	$ 25
Stock options [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Expiration date	7 years

Share-Based Compensation - Res

Share-Based Compensation - Restricted Stock Activity Table (Detail) - Restricted stock [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock Shares [Roll Forward]
Non-vested at January 1, 2018 (in shares)	4,690
Granted (in shares)	2,720
Vested (in shares)	(2,300)
Forfeited (in shares)	(420)
Non-vested at December 31, 2018 (in shares)	4,690	4,690
Restricted Stock Weighted-Average Grant-Date Fair Value [Abstract]
Non-vested at January 1, 2018 (in usd per share)	$ 59.24
Granted (in usd per share)	58.30	$ 59.92	$ 52.03
Vested (in usd per share)	61.19
Forfeited (in usd per share)	58.07
Non-vested at December 31, 2018 (in usd per share)	$ 57.88	$ 59.24

Share-Based Compensation - Sto

Share-Based Compensation - Stock Options Assumptions Table (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted-average grant-date fair value (in usd per share)	$ 15.36	$ 14.77	$ 15.92
Assumptions
Expected option life—years	4 years 9 months 18 days	4 years 9 months 18 days	4 years 1 month 6 days
Volatility	33.50%	33.60%	38.20%
Risk-free interest rate	2.90%	2.00%	1.30%
Dividend yield	1.90%	0.40%	0.60%

Share-Based Compensation - S_2

Share-Based Compensation - Stock Option Activity Table (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Outstanding [Roll Forward]
Shares outstanding at January 1, 2018 (in shares)		6,570
Shares granted (in shares)		1,190
Shares exercised (in shares)		(100)	[1]	0	(1,000)
Shares forfeited or expired (in shares)		(1,300)
Shares outstanding at December 31, 2018 (in shares)		6,360		6,570
Shares vested or expected to vest at December 31, 2018 (in shares)		6,360
Shares exercisable at December 31, 2018 (in shares)		4,120
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Weighted-average exercise price, outstanding at January 1, 2018 (in usd per share)		$ 71.44
Granted weighted-average exercise price (in usd per share)		55.47
Exercised weighted-average exercise price (in usd per share)	[1]	65.03
Forfeited or expired weighted-average exercise price (in usd per share)		79.55
Weighted-average exercise price, outstanding at December 31, 2018 (in usd per share)		67		$ 71.44
Weighted-average exercise price, vested or expected to vest at December 31, 2018 (in usd per share)		67
Weighted-average exercise price, exercisable at December 31, 2018 (in usd per share)		$ 74.19
Weighted-average remaining contractual term, outstanding at December 31, 2018		3 years 11 months 1 day
Weighted-average remaining contractual term, vested or expected to vest at December 31, 2018		3 years 11 months 1 day
Weighted-average remaining contractual term, exercisable at December 31, 2018		2 years 7 months 28 days
Aggregate intrinsic value, outstanding at December 31, 2018		$ 0
Aggregate intrinsic value, vested or expected to vest at December 31, 2018		0
Aggregate intrinsic value, exercisable at December 31, 2018		0
Total intrinsic value of stock options exercised during the period		$ 1		$ 0	$ 7
[1]	The total intrinsic value of stock options exercised was $1 million during 2018, zero during 2017, and $7 million during 2016, based on the difference between the market price at the exercise date and the exercise price.

Share-Based Compensation - Lia

Share-Based Compensation - Liability-Classified Awards (Detail) - Performance-based unit awards [Member] - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Liability paid	$ 0	$ 10,000,000	$ 6,000,000
Outstanding liability	$ 46,000,000
Number of shares of common stock represented by each performance unit	1
Total unrecognized compensation cost	$ 28,000,000
Unrecognized compensation cost, remaining weighted-average remaining service period	2 years 6 months
Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years

Noncontrolling Interests (Detai

Noncontrolling Interests (Detail) - USD ($) shares in Thousands, $ in Millions	Mar. 01, 2017	Jun. 30, 2015	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 07, 2018
Scenario, Forecast [Member]
Noncontrolling Interest [Line Items]
Sale of assets, consideration			$ 4,000
Cash proceeds from sale of assets			$ 2,000
7.50% Tangible Equity Units [Member]
Noncontrolling Interest [Line Items]
Number of tangible equity units issued (in units)		9,200
Western Gas Partners LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement					1,300
Western Gas Partners LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Public ownership interest in subsidiary				59.20%
Western Gas Partners LP [Member] | Limited Partner [Member] | Scenario, Forecast [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary			55.50%
Western Gas Equity Partners LP [Member]
Noncontrolling Interest [Line Items]
Units issued to the public					12,500
Net proceeds raised from public offering					$ 476
Western Gas Equity Partners LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary				77.80%
Public ownership interest in subsidiary				22.20%
Convertible Preferred Units [Member] | Western Gas Partners LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement					22,000
Percentage of preferred units converted	50.00%
Proceeds from issuance of private placement					$ 687
Class C Units [Member] | Western Gas Partners LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement				1,100	886	946
WES LP [Member] | Western Gas Partners LP [Member] | Limited Partner [Member] | Scenario, Forecast [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary			2.00%
Anadarko Limited Partner Interest In WES Owned Through Other Subsidiaries [Member] | Western Gas Partners LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary				9.70%
Western Gas Equity Partners, LP Ownership Interest in Western Gas Partners, LP [Member] | Western Gas Partners LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary				29.60%
Western Gas Equity Partners, LP Ownership Interest in Western Gas Partners, LP [Member] | Western Gas Partners LP [Member] | Limited Partner [Member] | Scenario, Forecast [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary			98.00%
Western Gas Equity Partners, LP Ownership Interest in Western Gas Partners, LP [Member] | Western Gas Partners LP [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary				1.50%
Settled In Wgp Common Units [Member] | Equity Component of 7.5% Tangible Equity Units [Member]
Noncontrolling Interest [Line Items]
Shares issued (in shares)							8,200

Variable Interest Entities - Fi

Variable Interest Entities - Financial Data of WGP (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Statement of Operations Data
Total revenues and other		$ 13,382		$ 11,908		$ 7,869
Operating income (loss)		2,619		(565)		(2,372)
Net Income (Loss)		752		(211)		(2,808)
Statement of Cash Flows Data
Net cash provided by (used in) operating activities		5,929		4,009		3,000
Net cash provided by (used in) investing activities		(5,982)		(1,030)		(2,742)
Net cash provided by (used in) financing activities		(3,177)		(1,613)		2,008
Balance Sheet Data
Net property, plant, and equipment		28,615		27,451		32,168
Total assets		40,376		42,086
Long-term debt		15,470		15,547
Total equity and partners’ capital		10,943		13,790		15,497	$ 15,457
Variable Interest Entity, Primary Beneficiary [Member]
Balance Sheet Data
Net property, plant, and equipment		6,612		5,731
WGP [Member]
Balance Sheet Data
Long-term debt		0	[1]	28	[2]
WGP [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Statement of Operations Data
Total revenues and other		1,990		2,248		1,804
Operating income (loss)		625		704		705
Net Income (Loss)		449		573		597
Statement of Cash Flows Data
Net cash provided by (used in) operating activities		1,017		897		913
Net cash provided by (used in) investing activities		(1,460)		(764)		(1,106)
Net cash provided by (used in) financing activities		456		(413)		452
Balance Sheet Data
Net property, plant, and equipment		6,612		5,731
Total assets		9,239		8,016
Long-term debt		4,787		3,493
Total liabilities		5,734		4,071
Total equity and partners’ capital		3,505		3,945
WGP distributions to Anadarko	[3]	408		368		321
WGP distributions to third parties		$ 494		$ 443		$ 362
[1]	Excludes WES.
[2]	Excludes WES.
[3]	WGP distributions to Anadarko are eliminated upon consolidation.

Variable Interest Entities (Det

Variable Interest Entities (Detail) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	May 31, 2017	May 31, 2008	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Variable Interest Entity [Line Items]
Interest income for WES			$ 1,028	$ 1,003	$ 1,022
Western Gas Partners LP [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Note receivable for WES		$ 260
Debt instrument, term		30 years
Fixed annual rate		6.50%
Interest income for WES			17	17	17
Cash payment received	$ 37
Above-market component of swap extensions with Anadarko			$ 52	$ 59	$ 46

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash paid (received)
Interest, net of amounts capitalized		$ 982	$ 906	$ 856
Income taxes, net of refunds	[1]	51	64	(882)
Non-cash investing activities
Fair value of properties and equipment acquired		22	640	3
Asset retirement cost additions		523	66	298
Accruals of property, plant, and equipment		822	824	549
Net liabilities assumed (divested) in acquisitions and divestitures		(111)	(158)	723
Non-cash investing and financing activities
Acquisition contingent consideration		0	0	103
Settlement of tangible equity units		$ 300	$ 0	0
Net Operating Loss Carryback [Member]
Cash paid (received)
Income taxes, net of refunds				$ 881
[1]	Includes $881 million from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$ 1,429	$ 4,674	$ 3,308	$ 1,025
Cash and Cash Equivalents [Member]
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	1,295	4,553
Restricted cash and restricted cash equivalents	139	255
Restricted cash and restricted cash equivalents included in Other Assets [Member]
Cash and Cash Equivalents [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$ 134	$ 121

Segment Information - Addition

Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018USD ($)Segment	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Segment Reporting [Abstract]
Number of reporting segments | Segment	2
Segment Reporting Information [Line Items]
Sales revenues	$ (14,044,000,000)		$ (8,447,000,000)
Customer Concentration [Member] | Sales revenues [Member]
Segment Reporting Information [Line Items]
Sales revenues			$ 0
Royal Dutch Shell PLC [Member] | Customer Concentration [Member] | Sales revenues [Member] | Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	1,400,000,000
BP PLC [Member] | Customer Concentration [Member] | Sales revenues [Member] | Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Sales revenues	$ 1,300,000,000	$ (1,100,000,000)

Segment Information - Reconcil

Segment Information - Reconciliation of Income (Loss) before Income Taxes to Consolidated Adjusted EBITDAX Table (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Income (loss) before income taxes		$ 1,485	$ (1,688)	$ (3,829)
(Gains) losses on divestitures, net	[1],[2]	(20)	(674)	757
Exploration expense	[3]	459	2,535	944
DD&A		4,254	4,279	4,301
Impairments		800	408	227
Interest expense		947	932	890
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives		(407)	156	559
(Gains) losses on early extinguishment of debt		(2)	2	155
Restructuring and reorganization-related charges		(53)	(21)	(389)
Less net income (loss) attributable to noncontrolling interests		137	245	263
Adjusted EBITDAX		7,432	5,726	4,073
Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Certain other nonoperating items		0	0	(58)
Deepwater Horizon [Member] | Judicial Ruling [Member]
Segment Reporting Information [Line Items]
Other operating expense		0
Deepwater Horizon [Member] | Pending Litigation [Member]
Segment Reporting Information [Line Items]
Other operating expense			$ 0	$ 1
Exploration Expense [Member]
Segment Reporting Information [Line Items]
Restructuring and reorganization-related charges		$ (20)
[1]	Includes gain of $126 million related to the 2017 property exchange discussed below.
[2]	Includes goodwill allocated to divestitures of $209 million in 2017 and $397 million in 2016.
[3]	Includes reorganization-related charges of $20 million for the year ended December 31, 2018.

Segment Information - Selected

Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Segment Reporting Information [Line Items]
Sales revenues	$ 14,044				$ 8,447
Other	292		$ 265		179
Total revenues and other	13,382		11,908		7,869
Operating costs and expenses	10,763		12,473		10,241
Net cash from settlement of commodity derivatives	545		(25)		(267)
Other (income) expense, net	59		54		126
Net income (loss) attributable to noncontrolling interests	137		245		263
Total expenses and other	5,938		5,502		4,561
Adjusted EBITDAX	7,432		5,726		4,073
Net properties and equipment	28,615		27,451		32,168
Capital expenditures	6,185		5,300		3,314
Goodwill	4,789		4,789		5,000
(Gains) Losses on Derivatives, net [Member] | Commodity Derivatives [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives	545		(27)		(265)
Gathering, processing, and marketing sales [Member] | Commodity Derivatives [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	8		(6)		8
Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	13,362	[1]	11,234	[2]	8,626	[2]
Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	5,243	[3]	5,258	[4]	4,576	[4]
Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	13	[5]	26		(13)	[6]
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Sales revenues	224				149
Other	85		61		30
Total revenues and other	(630)
Net income (loss) attributable to noncontrolling interests	137		245		263
Total expenses and other	1,031		562		121
Adjusted EBITDAX	(1,653)		(941)		(733)
Net properties and equipment	1,929		1,956		2,119
Capital expenditures	170		106		74
Goodwill	0		0		0
Other and Intersegment Eliminations [Member] | (Gains) Losses on Derivatives, net [Member] | Commodity Derivatives [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives	545		(27)		(265)
Other and Intersegment Eliminations [Member] | Gathering, processing, and marketing sales [Member] | Commodity Derivatives [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	8		(6)		8
Other and Intersegment Eliminations [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	(630)	[1]	(373)	[2]	(620)	[2]
Other and Intersegment Eliminations [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	328	[3]	318	[4]	136	[4]
Other and Intersegment Eliminations [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	21	[5]	26	[6]	(13)	[6]
Other and Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Sales revenues	(771)		(627)		(799)
Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Goodwill	4,300
Exploration and Production Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales revenues	11,515				7,152
Other	(4)		15		(5)
Total revenues and other	11,501
Net income (loss) attributable to noncontrolling interests	0		0		0
Total expenses and other	3,896		3,517		3,485
Adjusted EBITDAX	7,585		5,471		3,666
Net properties and equipment	18,276		18,729		24,391
Capital expenditures	4,103		3,785		2,689
Goodwill	4,343		4,343		4,550
Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | (Gains) Losses on Derivatives, net [Member] | Commodity Derivatives [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives	0		0		0
Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Gathering, processing, and marketing sales [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	0		0		0
Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	11,481	[1]	8,988	[2]	7,151	[2]
Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	3,896	[3]	3,517	[4]	3,485	[4]
Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	0	[5]	0	[6]	0	[6]
Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Sales revenues	81		21		4
WES Midstream [Member]
Segment Reporting Information [Line Items]
Goodwill	446
WES Midstream [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales revenues	2,305				1,146
Other	211		189		154
Total revenues and other	2,511
Net income (loss) attributable to noncontrolling interests	0		0		0
Total expenses and other	1,011		1,423		955
Adjusted EBITDAX	1,500		1,196		1,140
Net properties and equipment	8,410		6,766		5,658
Capital expenditures	1,912		1,409		551
Goodwill	446		446		450
WES Midstream [Member] | Operating Segments [Member] | (Gains) Losses on Derivatives, net [Member] | Commodity Derivatives [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives	0		0		0
WES Midstream [Member] | Operating Segments [Member] | Gathering, processing, and marketing sales [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	0		0		0
WES Midstream [Member] | Operating Segments [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other	2,511	[1]	2,619	[2]	2,095	[2]
WES Midstream [Member] | Operating Segments [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses	1,019	[3]	1,423	[4]	955	[4]
WES Midstream [Member] | Operating Segments [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	(8)	[5]	0	[6]	0	[6]
WES Midstream [Member] | Operating Segments [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Sales revenues	690		606		795
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Sales revenues	13,070		10,969		$ 8,447
Oil and Gas [Member] | Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Sales revenues	56		193
Oil and Gas [Member] | Exploration and Production Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales revenues	11,404		8,952
Oil and Gas [Member] | WES Midstream [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales revenues	$ 1,610		$ 1,824
[1]	Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
[2]	Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
[3]	Operating costs and expenses excludes exploration expense, DD&A, impairments, reorganization-related charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.
[4]	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.
[5]	Other (income) expense, net excludes reorganization-related charges since these expenses are excluded from Adjusted EBITDAX.
[6]	Other (income) expense, net excludes certain other nonoperating items and restructuring charges since these items are excluded from Adjusted EBITDAX.

Segment Information - Sales Re

Segment Information - Sales Revenues by Geographic Area Table (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue from External Customer [Line Items]
Sales revenues	$ 14,044		$ 8,447
Oil and Gas [Member]
Revenue from External Customer [Line Items]
Sales revenues	13,070	$ 10,969	8,447
Oil and Gas [Member] | United States [Member]
Revenue from External Customer [Line Items]
Sales revenues	10,659	9,176	7,049
Oil and Gas [Member] | Algeria [Member]
Revenue from External Customer [Line Items]
Sales revenues	1,596	1,249	1,103
Oil and Gas [Member] | Other International [Member]
Revenue from External Customer [Line Items]
Sales revenues	$ 815	$ 544	$ 295

Segment Information - Net Prop

Segment Information - Net Properties and Equipment by Geographic Area Table (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment		$ 28,615	$ 27,451	$ 32,168
Capitalized costs		444	525	$ 1,230	$ 1,124
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment		25,891	24,382
Algeria [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment		808	965
Other International [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment	[1]	1,916	$ 2,104
Tubarao Tigre Discovery [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Capitalized costs		$ 519
[1]	Includes $519 million of capitalized costs related to the Mozambique LNG project at December 31, 2018.

Uncategorized Items - apc-20190

Label	Element	Value
Additional Paid-in Capital [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (3,000,000)
Noncontrolling Interest [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(23,000,000)
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(28,000,000)
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 49,000,000