Anadarko Petroleum 10-Q 26 Jul 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 15, 2016
Document And Entity Information [Abstract]
Trading Symbol	APC
Entity Registrant Name	ANADARKO PETROLEUM CORP
Entity Central Index Key	773,910
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		510,457,469

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues and Other
Oil and condensate sales	$ 1,125	$ 1,616	$ 1,975	$ 3,035
Natural-gas sales	320	487	686	1,128
Natural-gas liquids sales	235	229	413	461
Gathering, processing, and marketing sales	305	305	545	598
Gains (losses) on divestitures and other, net	(70)	(1)	(30)	(265)
Total	1,915	2,636	3,589	4,957
Costs and Expenses
Oil and gas operating	202	226	410	522
Oil and gas transportation	246	283	488	588
Exploration	76	103	202	1,186
Gathering, processing, and marketing	252	255	467	509
General and administrative	305	278	754	585
Depreciation, depletion, and amortization	984	1,214	2,133	2,470
Other taxes	157	151	274	333
Impairments	18	30	34	2,813
Other operating expense	7	6	23	69
Total	2,247	2,546	4,785	9,075
Operating Income (Loss)	(332)	90	(1,196)	(4,118)
Other (Income) Expense
Interest expense	217	201	437	417
Loss on early extinguishment of debt	124	0	124	0
(Gains) losses on derivatives, net	311	(310)	610	(158)
Other (income) expense, net	(55)	15	(55)	62
Total	593	(95)	1,110	325
Income (Loss) Before Income Taxes	(925)	185	(2,306)	(4,443)
Income tax expense (benefit)	(314)	77	(697)	(1,315)
Net Income (Loss)	(611)	108	(1,609)	(3,128)
Net income (loss) attributable to noncontrolling interests	81	47	117	79
Net Income (Loss) Attributable to Common Stockholders	$ (692)	$ 61	$ (1,726)	$ (3,207)
Per Common Share
Net income (loss) attributable to common stockholders—basic	$ (1.36)	$ 0.12	$ (3.39)	$ (6.32)
Net income (loss) attributable to common stockholders—diluted	$ (1.36)	$ 0.12	$ (3.39)	$ (6.32)
Average Number of Common Shares Outstanding—Basic	510	508	510	507
Average Number of Common Shares Outstanding—Diluted	510	509	510	507
Dividends (per common share)	$ 0.05	$ 0.27	$ 0.10	$ 0.54
Commodity Contract and Interest Rate Swap [Member]
Other (Income) Expense
(Gains) losses on derivatives, net	$ 307	$ (311)	$ 604	$ (159)
Tronox Litigation [Member] | Judicial Ruling [Member]
Other (Income) Expense
Tronox-related contingent loss	$ 0	$ 0	$ 0	$ 5

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ (611)	$ 108	$ (1,609)	$ (3,128)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2	3	5	5
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	(1)	(1)	(2)	(2)
Total adjustments for derivative instruments, net of taxes	1	2	3	3
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	(24)	0	(190)	0
Income taxes on net gain (loss) incurred during period	9	0	70	0
Prior service credit (cost) incurred during period	0	0	(1)	0
Income taxes on prior service credit (cost) incurred during period	0	0	1	0
Amortization of net actuarial (gain) loss to general and administrative expense	34	13	42	26
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	(13)	(5)	(16)	(9)
Amortization of net prior service (credit) cost to general and administrative expense	(6)	1	(21)	1
Income taxes on amortization of net prior service (credit) cost to general and administrative expense	3	0	8	0
Total adjustments for pension and other postretirement plans, net of taxes	3	9	(107)	18
Total	4	11	(104)	21
Comprehensive Income (Loss)	(607)	119	(1,713)	(3,107)
Comprehensive income (loss) attributable to noncontrolling interests	81	47	117	79
Comprehensive Income (Loss) Attributable to Common Stockholders	$ (688)	$ 72	$ (1,830)	$ (3,186)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents ($160 and $100 related to VIEs)	$ 1,394	$ 939
Accounts receivable (net of allowance of $13 and $11)
Customers ($67 and $81 related to VIEs)	770	652
Others ($76 and $84 related to VIEs)	730	1,817
Other current assets	318	573
Total	3,212	3,981
Properties and Equipment
Cost	69,610	70,683
Less accumulated depreciation, depletion, and amortization	37,265	36,932
Net properties and equipment ($5,002 and $4,859 related to VIEs)	32,345	33,751
Other Assets ($621 and $644 related to VIEs)	2,239	2,268
Goodwill and Other Intangible Assets ($1,237 and $1,220 related to VIEs)	6,237	6,331
Total Assets	44,033	46,331
Current Liabilities
Accounts payable ($172 and $179 related to VIEs)	2,200	2,850
Current asset retirement obligations	221	309
Interest payable	242	247
Other taxes payable ($21 and $18 related to VIEs)	282	318
Accrued expenses	267	424
Short-term debt	32	32
Total	3,244	4,180
Long-term Debt	15,641	15,636
Other Long-term Liabilities
Deferred income taxes	4,686	5,400
Asset retirement obligations ($135 and $127 related to VIEs)	1,726	1,750
Other	4,136	3,908
Total	10,548	11,058
Stockholders' equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 531.2 million and 528.3 million shares issued)	53	52
Paid-in capital	9,638	9,265
Retained earnings	3,103	4,880
Treasury stock (20.7 million and 20.0 million shares)	(1,026)	(995)
Accumulated other comprehensive income (loss)	(487)	(383)
Total Stockholders’ Equity	11,281	12,819
Noncontrolling interests	3,319	2,638
Total Equity	14,600	15,457
Total Liabilities and Equity	$ 44,033	$ 46,331

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Cash and cash equivalents ($160 and $100 related to VIEs)	$ 1,394	$ 939
Allowance for uncollectible accounts	13	11
Customers ($67 and $81 related to VIEs)	770	652
Others ($76 and $84 related to VIEs)	730	1,817
Net properties and equipment ($5,002 and $4,859 related to VIEs)	32,345	33,751
Other Assets ($621 and $644 related to VIEs)	2,239	2,268
Goodwill and Other Intangible Assets ($1,237 and $1,220 related to VIEs)	6,237	6,331
Accounts payable ($172 and $179 related to VIEs)	2,200	2,850
Other taxes payable ($21 and $18 related to VIEs)	282	318
Asset retirement obligations ($135 and $127 related to VIEs)	$ 1,726	$ 1,750
Common stock, par value per share	$ 0.1	$ 0.1
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	531,200,000	528,300,000
Treasury stock, shares	20,700,000	20,000,000
Variable Interest Entity, Primary Beneficiary [Member]
Cash and cash equivalents ($160 and $100 related to VIEs)	$ 160	$ 100
Customers ($67 and $81 related to VIEs)	67	81
Others ($76 and $84 related to VIEs)	76	84
Net properties and equipment ($5,002 and $4,859 related to VIEs)	5,002	4,859
Other Assets ($621 and $644 related to VIEs)	621	644
Goodwill and Other Intangible Assets ($1,237 and $1,220 related to VIEs)	1,237	1,220
Accounts payable ($172 and $179 related to VIEs)	172	179
Other taxes payable ($21 and $18 related to VIEs)	21	18
Asset retirement obligations ($135 and $127 related to VIEs)	$ 135	$ 127

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY - 6 months ended Jun. 30, 2016 - USD ($) $ in Millions	Total	Subsidiary Equity Transactions [Member]	Common Stock [Member]	Paid-in Capital [Member]	Paid-in Capital [Member]Subsidiary Equity Transactions [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member]Subsidiary Equity Transactions [Member]
Balance at Dec. 31, 2015	$ 15,457		$ 52	$ 9,265		$ 4,880	$ (995)	$ (383)	$ 2,638
Net income (loss)	(1,609)					(1,726)			117
Common stock issued	109		1	108
Dividends—common stock	(51)					(51)
Repurchase of common stock	(31)						(31)
Subsidiary equity transactions		$ 988			$ 265					$ 723
Distributions to noncontrolling interest owners	(159)								(159)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	3							3
Adjustments for pension and other postretirement plans	(107)							(107)
Balance at Jun. 30, 2016	$ 14,600		$ 53	$ 9,638		$ 3,103	$ (1,026)	$ (487)	$ 3,319

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash Flows from Operating Activities
Net income (loss)	$ (1,609)	$ (3,128)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	2,133	2,470
Deferred income taxes	(820)	(1,187)
Dry hole expense and impairments of unproved properties	45	1,040
Impairments	34	2,813
(Gains) losses on divestitures, net	102	425
Loss on early extinguishment of debt	124	0
Total (gains) losses on derivatives, net	610	(158)
Operating portion of net cash received (paid) in settlement of derivative instruments	165	172
Other	203	74
Changes in assets and liabilities
(Increase) decrease in accounts receivable	922	(105)
Increase (decrease) in accounts payable and accrued expenses	(717)	(198)
Other items, net	(100)	(269)
Net cash provided by (used in) operating activities	1,092	(3,261)
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(1,879)	(3,501)
Divestitures of properties and equipment and other assets	900	700
Other, net	14	16
Net cash provided by (used in) investing activities	(965)	(2,785)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	5,275	4,787
Repayments of debt	(5,425)	(3,857)
Financing portion of net cash received (paid) for derivative instruments	(727)	(77)
Increase (decrease) in outstanding checks	(159)	(109)
Dividends paid	(51)	(277)
Repurchase of common stock	(31)	(37)
Issuance of common stock, including tax benefit on share-based compensation awards	30	19
Distributions to noncontrolling interest owners	(159)	(135)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs	413	0
Net cash provided by (used in) financing activities	329	849
Effect of Exchange Rate Changes on Cash	(1)	1
Net Increase (Decrease) in Cash and Cash Equivalents	455	(5,196)
Cash and Cash Equivalents at Beginning of Period	939	7,369
Cash and Cash Equivalents at End of Period	1,394	2,173
Subsidiary Equity Transactions [Member]
Cash Flows from Financing Activities
Sale of subsidiary units	1,163	187
Equity Component of 7.50% Tangible Equity Units [Member]
Cash Flows from Financing Activities
Sale of subsidiary units	0	348
Tronox Litigation [Member] | Judicial Ruling [Member]
Changes in assets and liabilities
Tronox-related contingent liability	$ 0	$ (5,210)

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2016
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 marketing of oil, condensate, natural gas, and natural gas liquids (NGLs), and in the marketing of anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of oil, condensate, natural gas, and NGLs. The Company also participates in the hard-minerals business through royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. Basis of Presentation The Consolidated Financial Statements have been prepared in conformity with generally accepted accounting principles in the United States (GAAP). Certain prior-period amounts have been reclassified to conform to the current-year presentation. These Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 . 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 variable interest entities (VIEs) for which Anadarko is the primary beneficiary. 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 over which 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. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Recently Issued Accounting Standards The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03, Interest—Imputation of Interest (Subtopic 835-30)—Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015. The FASB issued ASU 2015-02, Consolidation (Topic 810)—Amendments to the Consolidation Analysis. The Company adopted this ASU on January 1, 2016. In accordance with the new ASU, Western Gas Equity Partners, LP (WGP) and Western Gas Partners, LP (WES), publicly traded consolidated subsidiaries of the Company, are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model. After adoption, WGP and WES were consolidated by the Company under the variable interest model. While this ASU requires additional financial statement disclosure, it has no impact on the Company’s consolidated results of operations, cash flows, or financial position. See Note 17—Variable Interest Entities . The FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows, and accounting for forfeitures. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements. 1. Summary of Significant Accounting Policies (Continued) The FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires the lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements. The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which supersedes current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASUs and, as amended, 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 is required to adopt the new standard in the first quarter of 2018 using one of two retrospective application methods. The Company is continuing to evaluate the provisions of this ASU and has not determined the impact this standard may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.

Inventories

Inventories	6 Months Ended
	Jun. 30, 2016
Energy Related Inventory [Abstract]
Inventories	2. Inventories The following summarizes the major classes of inventories included in other current assets: millions June 30, December 31, Oil $ 111 $ 116 Natural gas 28 36 NGLs 77 64 Total inventories $ 216 $ 216

Divestitures and Assets Held fo

Divestitures and Assets Held for Sale	6 Months Ended
	Jun. 30, 2016
Property, Plant and Equipment [Abstract]
Divestitures and Assets Held for Sale	3. Divestitures and Assets Held for Sale For the six months ended June 30, 2016 , the Company received $900 million in net proceeds from divestitures and recognized net losses of $102 million from divestitures and assets held for sale. Divestitures The following divestitures primarily related to assets that were included in the oil and gas exploration and production reporting segment: • The Company sold certain U.S. onshore assets in East Texas/Louisiana with a sales price of $107 million , for net proceeds of $99 million , and recognized a gain of $13 million . • The Company sold certain U.S. onshore assets in West Texas for net proceeds of $138 million , with no gain or loss recognized. • The Company sold certain U.S. onshore assets in the Rockies for net proceeds of $593 million , and recognized a loss of $53 million . Assets Held for Sale Certain U.S. onshore assets included in the oil and gas exploration and production and midstream reporting segments satisfied criteria to be considered held for sale during the second quarter of 2016, at which time the Company remeasured them to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $50 million . The sale of these assets is expected to close in the third quarter of 2016. Gains and losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. At June 30, 2016, the balances of assets and liabilities associated with assets held for sale were not material.

Impairments

Impairments	6 Months Ended
	Jun. 30, 2016
Asset Impairment Charges [Abstract]
Impairments	4. Impairments Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment: Three Months Ended Six Months Ended millions Impairment Fair Value (1) Impairment Fair Value (1) June 30, 2016 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ — $ — $ 4 $ 585 Gulf of Mexico properties 1 — 2 — Cost-method investment (2) 1 32 2 32 Midstream Long-lived assets held for use 11 2 21 5 Other Long-lived assets held for use 5 1 5 1 Total $ 18 $ 35 $ 34 $ 623 June 30, 2015 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ 4 $ 12 $ 2,303 $ 1,303 Gulf of Mexico properties 17 — 25 — Cost-method investment (2) 1 32 1 32 Midstream Long-lived assets held for use 8 199 484 202 Total $ 30 $ 243 $ 2,813 $ 1,537 __________________________________________________________________ (1) Measured as of the impairment date using the income approach and Level 3 inputs. (2) Represents the after-tax net investment. Impairments during the six months ended June 30, 2015, were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, which were impaired due to lower forecasted commodity prices. In addition to the long-lived asset impairments above, the Company recognized a $935 million impairment of unproved Greater Natural Buttes properties during the six months ended June 30, 2015, as a result of lower commodity prices. Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. It is reasonably possible that prolonged low or further declines in commodity prices, changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in future impairments.

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	6 Months Ended
	Jun. 30, 2016
Capitalized Exploratory Well Costs [Abstract]
Suspended Exploratory Well Costs	5. Suspended Exploratory Well Costs The Company’s suspended exploratory well costs were $1.2 billion at June 30, 2016, and $1.1 billion at December 31, 2015 . The increase in suspended exploratory well costs during 2016 is primarily related to the capitalization of costs associated with appraisal activities in Côte d’Ivoire. There were no material charges to exploration expense during the six months ended June 30, 2016 , related to suspended exploratory well costs previously capitalized for a period greater than one year since the completion of drilling at December 31, 2015. Projects with suspended exploratory well costs are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development and where management is actively pursuing efforts to assess whether reserves can be attributed to these projects. 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.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	6. Derivative Instruments Objective and Strategy The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations such as Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities). Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. See Note 15—Accumulated Other Comprehensive Income (Loss) . 6. Derivative Instruments (Continued) Oil and Natural-Gas Production/Processing Derivative Activities The oil prices listed below are a combination of New York Mercantile Exchange (NYMEX) West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at June 30, 2016 : 2016 Settlement 2017 Settlement 2018 Settlement Oil Three-Way Collars (MBbls/d) 83 — — Average price per barrel Ceiling sold price (call) $ 63.82 $ — $ — Floor purchased price (put) $ 54.46 $ — $ — Floor sold price (put) $ 42.77 $ — $ — Natural Gas Three-Way Collars (thousand MMBtu/d) — 682 250 Average price per MMBtu Ceiling sold price (call) $ — $ 3.60 $ 3.54 Floor purchased price (put) $ — $ 2.75 $ 2.75 Floor sold price (put) $ — $ 2.00 $ 2.00 Fixed-Price Contracts (thousand MMBtu/d) 14 32 — Average price per MMBtu $ 2.38 $ 3.14 $ — NGLs Fixed-Price Contracts (MBbls/d) — 2 — Average price per barrel $ — $ 15.84 $ — __________________________________________________________________ MBbls/d—thousand barrels per day MMBtu/d—million British thermal units per day MMBtu—million British thermal units A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price. Marketing and Trading Derivative Activities The Company had financial derivative transactions with notional volumes of natural gas totaling 5 billion cubic feet (Bcf) at June 30, 2016 , and 8 Bcf at December 31, 2015 , that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity. 6. Derivative Instruments (Continued) Interest-Rate Derivatives Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month London Interbank Offered Rate (LIBOR). In February 2016, in exchange for amended terms with certain counterparties, the Company modified the mandatory termination dates from 2021 to 2018 and, in some cases, the related fixed interest rates on interest-rate swaps with an aggregate notional principal amount of $500 million . Additionally, an interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million . At June 30, 2016 , the Company had outstanding interest-rate swaps with a notional amount of $1.7 billion due prior to or at September 2021 that will manage interest-rate risk associated with the potential refinancing of the Company’s $900 million Senior Notes due 2019 and the Zero-Coupon Senior Notes due 2036 (Zero Coupons), should the Zero Coupons be put to the Company prior to the swap termination dates. At the next put date in October 2016 , the accreted value of the Zero Coupons will be $839 million . See Note 8—Debt and Interest Expense . 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. Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements or collateralization related to these extended interest-rate derivatives are classified as cash flows from financing activities. The Company had the following outstanding interest-rate swaps at June 30, 2016 : millions except percentages Mandatory Weighted-Average Notional Principal Amount Reference Period Termination Date Interest Rate $ 50 September 2016 – 2026 September 2016 5.910% $ 50 September 2016 – 2046 September 2016 6.290% $ 500 September 2016 – 2046 September 2018 6.559% $ 300 September 2016 – 2046 September 2020 6.509% $ 450 September 2017 – 2047 September 2018 6.445% $ 100 September 2017 – 2047 September 2020 6.891% $ 250 September 2017 – 2047 September 2021 6.570% 6. Derivative Instruments (Continued) Effect of Derivative Instruments — Balance Sheet The following summarizes the fair value of the Company’s derivative instruments: Gross Derivative Assets Gross Derivative Liabilities millions June 30, December 31, June 30, December 31, Balance Sheet Classification 2016 2015 2016 2015 Commodity derivatives Other current assets $ 111 $ 462 $ (29 ) $ (177 ) Other assets 10 8 — — Accrued expenses 4 — (30 ) (3 ) Other liabilities 2 — (15 ) — 127 470 (74 ) (180 ) Interest-rate derivatives Other current assets 3 2 — — Other assets 15 54 — — Accrued expenses — — (99 ) (54 ) Other liabilities — — (1,749 ) (1,488 ) 18 56 (1,848 ) (1,542 ) Total derivatives $ 145 $ 526 $ (1,922 ) $ (1,722 ) Effect of Derivative Instruments — Statement of Income The following summarizes gains and losses related to derivative instruments: millions Three Months Ended Six Months Ended Classification of (Gain) Loss Recognized 2016 2015 2016 2015 Commodity derivatives Gathering, processing, and marketing sales (1) $ 4 $ 1 $ 6 $ 1 (Gains) losses on derivatives, net 94 1 66 (52 ) Interest-rate derivatives (Gains) losses on derivatives, net 213 (312 ) 538 (107 ) Total (gains) losses on derivatives, net $ 311 $ (310 ) $ 610 $ (158 ) __________________________________________________________________ (1) Represents the effect of Marketing and Trading Derivative Activities. 6. Derivative Instruments (Continued) Credit-Risk Considerations The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure. The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types. At June 30, 2016 , $100 million of the Company’s $1.922 billion gross derivative liability balance, and at December 31, 2015 , $347 million of the Company’s $1.722 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle 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 may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to a level that is below investment grade. In February 2016, Moody’s Investors Service (Moody’s) downgraded the Company’s long-term debt credit rating from “Baa2” to “Ba1,” which is below investment grade. The downgrade triggered credit-risk-related features with certain derivative counterparties and required the Company to post collateral under its derivative instruments. The amount of cash posted as collateral pursuant to the contractual requirements applicable to derivative instruments with financial institutions was $599 million at June 30, 2016 , and $58 million at December 31, 2015 . No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.3 billion (net of collateral) at each of June 30, 2016 , and December 31, 2015 . 6. 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 June 30, 2016 Level 1 Level 2 Level 3 Netting (1) Collateral Total Assets Commodity derivatives $ 1 $ 126 $ — $ (35 ) $ — $ 92 Interest-rate derivatives — 18 — — — 18 Total derivative assets $ 1 $ 144 $ — $ (35 ) $ — $ 110 Liabilities Commodity derivatives $ (4 ) $ (70 ) $ — $ 35 $ 5 $ (34 ) Interest-rate derivatives — (1,848 ) — — 592 (1,256 ) Total derivative liabilities $ (4 ) $ (1,918 ) $ — $ 35 $ 597 $ (1,290 ) December 31, 2015 Assets Commodity derivatives $ 10 $ 460 $ — $ (178 ) $ (8 ) $ 284 Interest-rate derivatives — 56 — — — 56 Total derivative assets $ 10 $ 516 $ — $ (178 ) $ (8 ) $ 340 Liabilities Commodity derivatives $ (1 ) $ (179 ) $ — $ 178 $ — $ (2 ) Interest-rate derivatives — (1,542 ) — — 58 (1,484 ) Total derivative liabilities $ (1 ) $ (1,721 ) $ — $ 178 $ 58 $ (1,486 ) __________________________________________________________________ (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.

Tangible Equity Units

Tangible Equity Units	6 Months Ended
	Jun. 30, 2016
Tangible Equity Units [Abstract]
Tangible Equity Units	7. Tangible Equity Units In June 2015, the Company issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per TEU for net proceeds of $445 million . Each TEU is comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification. The prepaid equity purchase contracts are included in noncontrolling interests, net of issuance costs, and the senior amortizing notes are included in short-term debt and long-term debt on the Company’s Consolidated Balance Sheets. Equity Component Unless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018 . Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver not more than 0.8591 WGP common units and not less than 0.7159 WGP common units (or a computed number of APC shares) per TEU on the settlement date, subject to adjustment, at the settlement rate based upon the applicable market value of WGP common units (or APC shares). Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. On September 7, 2015 , Anadarko began paying equal quarterly cash installments of $0.9375 per amortizing note (except for the September 7, 2015 installment payment, which was $0.9063 per amortizing note). The payments constitute a payment of interest and partial repayment of principal, with the aggregate per-year payments of principal and interest equating to a 7.50% cash payment with respect to each TEU. The senior amortizing notes have a final installment payment date of June 7, 2018 , and are senior unsecured obligations of the Company.

Debt and Interest Expense

Debt and Interest Expense	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Debt and Interest Expense	8. Debt and Interest Expense Debt Activity The following summarizes the Company’s debt activity, after eliminating the effect of intercompany transactions, during the six months ended June 30, 2016 : Carrying Value millions WES WGP (1) Anadarko (2) Anadarko Consolidated Description Balance at December 31, 2015 $ 2,691 $ — $ 12,957 $ 15,648 Issuances — — 794 794 4.850% Senior Notes due 2021 — — 1,088 1,088 5.550% Senior Notes due 2026 — — 1,088 1,088 6.600% Senior Notes due 2046 Borrowings — — 1,750 1,750 364-Day Facility 530 — — 530 WES RCF — 28 — 28 WGP RCF Repayments — — (1,749 ) (1,749 ) 5.950% Senior Notes due 2016 — — (1,245 ) (1,245 ) 6.375% Senior Notes due 2017 — — (1,750 ) (1,750 ) 364-Day Facility (290 ) — — (290 ) WES RCF — — (250 ) (250 ) Commercial paper notes, net — — (17 ) (17 ) TEUs - senior amortizing notes Other, net 1 — 27 28 Amortization of discounts, premiums, and debt issuance costs Balance at June 30, 2016 $ 2,932 $ 28 $ 12,693 $ 15,653 __________________________________________________________________ (1) Excludes WES. (2) Excludes WES and WGP. 8. Debt and Interest Expense (Continued) Debt The Company’s outstanding debt, excluding the capital lease obligation and any borrowings under the WGP revolving credit facility, is senior unsecured. The following summarizes the Company’s outstanding debt after eliminating the effect of intercompany transactions: millions WES WGP (1) Anadarko (2) Anadarko Consolidated June 30, 2016 Total borrowings at face value $ 2,960 $ 28 $ 14,325 $ 17,313 Net unamortized discounts, premiums, and debt issuance costs (3) (28 ) — (1,632 ) (1,660 ) Total borrowings 2,932 28 12,693 15,653 Capital lease obligation — — 20 20 Less short-term debt — — 32 32 Total long-term debt $ 2,932 $ 28 $ 12,681 $ 15,641 December 31, 2015 Total borrowings at face value $ 2,720 $ — $ 14,592 $ 17,312 Net unamortized discounts, premiums, and debt issuance costs (3) (29 ) — (1,635 ) (1,664 ) Total borrowings 2,691 — 12,957 15,648 Capital lease obligation — — 20 20 Less short-term debt — — 32 32 Total long-term debt $ 2,691 $ — $ 12,945 $ 15,636 __________________________________________________________________ (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 revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets. During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016 . The Company recognized a loss of $124 million for the early retirement and redemption of these senior notes, which included $114 million of premiums paid. 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, which will be $839 million at the next put date in October 2016 . Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2016 , as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised. Fair Value The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.2 billion at June 30, 2016 , and $15.7 billion at December 31, 2015 . 8. Debt and Interest Expense (Continued) Anadarko Revolving Credit Facilities and Commercial Paper Program Anadarko has a $3.0 billion five -year senior unsecured revolving credit facility maturing in January 2021 (Five-Year Facility). In addition, in January 2016 the Company replaced its previous $2.0 billion 364 -day senior unsecured revolving credit facility with a new $2.0 billion 364 -day senior unsecured revolving credit facility ( 364 -Day Facility), on identical terms, that will mature in January 2017 . At June 30, 2016 , the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility and was in compliance with all related 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 and is supported by the Five-Year Facility. The maturities of the commercial paper notes may vary, but may not exceed 397 days . In February 2016, Moody’s downgraded the Company’s commercial paper program credit rating, which essentially eliminated the Company’s access to the commercial paper market. As a result, the Company has not issued commercial paper notes since the downgrade. At June 30, 2016 , the Company had no outstanding borrowings under the commercial paper program. WES and WGP Borrowings WES has a five -year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (WES RCF), which is expandable to $1.5 billion . At June 30, 2016 , WES had outstanding borrowings under its RCF of $540 million at an interest rate of 1.77% , had outstanding letters of credit of $5 million , and had available borrowing capacity of $655 million . At June 30, 2016 , WES was in compliance with all related covenants. In March 2016, WGP entered into a three -year $250 million senior secured revolving credit facility maturing in March 2019 (WGP RCF), which is expandable to $500 million , subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. 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 June 30, 2016 , WGP had outstanding borrowings under its RCF of $28 million at an interest rate of 2.72% , had available borrowing capacity of $222 million , and was in compliance with all related covenants. In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026 . Net proceeds were used to repay a portion of the amount outstanding under the WES RCF. Interest Expense The following summarizes interest expense: Three Months Ended Six Months Ended millions 2016 2015 2016 2015 Debt and other $ 259 $ 244 $ 517 $ 498 Capitalized interest (42 ) (43 ) (80 ) (81 ) Total interest expense $ 217 $ 201 $ 437 $ 417

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	9. Income Taxes The following summarizes income tax expense (benefit) and effective tax rates: Three Months Ended Six Months Ended millions except percentages 2016 2015 2016 2015 Income tax expense (benefit) $ (314 ) $ 77 $ (697 ) $ (1,315 ) Income (loss) before income taxes (925 ) 185 (2,306 ) (4,443 ) Effective tax rate 34 % 42 % 30 % 30 % The Company reported a loss before income taxes for the three and six months ended June 30, 2016, and the six months ended June 30, 2015 . As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The variance from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2016 and 2015 , was primarily attributable to the non-deductible Algerian exceptional profits tax for Algerian income tax purposes and the tax impact from foreign operations. In addition, the decrease from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2016, was attributable to non-deductible goodwill related to divestitures and net changes in uncertain tax positions. At June 30, 2016, the Company’s Consolidated Balance Sheet included a $192 million tax receivable included in accounts receivable—others.

Conveyance of Future Hard Miner

Conveyance of Future Hard Minerals Royalty Revenues	6 Months Ended
	Jun. 30, 2016
Deferred Revenue Disclosure [Abstract]
Conveyance Of Future Hard Minerals Royalty Revenues [Text Block]	10. 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 have been accounted for as deferred revenues and are included in accrued expenses and other long-term liabilities 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. During the six months ended June 30, 2016 , the Company amortized $19 million of deferred revenues as a result of this agreement. Proceeds from the transaction and payments to the third party are reported in financing activities in the Company’s Consolidated Statement of Cash Flows. The Company will make the first payment for royalties in September 2016. 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. The following summarizes the future amounts, prior to the 3% to 4% of any excess described above, that the Company expects to pay: millions 2016 $ 25 2017 50 2018 50 2019 52 2020 56 Later years 320 Total $ 553

Contingencies

Contingencies	6 Months Ended
	Jun. 30, 2016
Contingencies Disclosure [Abstract]
Contingencies	11. Contingencies Litigation The following is a discussion of any material developments in previously reported contingencies and any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 . Deepwater Horizon Events In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the Operating Agreement with BP. Numerous Deepwater Horizon event-related civil lawsuits were filed against BP and other parties, including the Company. Generally, the plaintiffs sought actual damages, punitive damages, declaratory judgment, and/or injunctive relief. This litigation was consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court). BP Consent Decree In July 2015, BP announced a settlement agreement in principle with the U.S. Department of Justice (DOJ) and certain states and local government entities regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event (BP Settlement) and, in October 2015, lodged a proposed consent decree with the Louisiana District Court. In April 2016, the Louisiana District Court approved the consent decree. As a result of the BP Settlement and approval of the consent decree, all liability relating to OPA-related environmental costs was resolved and all NRD claims and claims by the United States and the Gulf states impacted by the event relating to the MDL action were dismissed. For any remaining claims relating to the MDL action, the Company is fully indemnified by BP against any losses pursuant to the Settlement Agreement. For additional disclosure related to the Deepwater Horizon events, see Note 15 — Contingencies — Deepwater Horizon Events in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015. Penalties and Fines In December 2010, the DOJ, on behalf of the United States, filed a civil lawsuit in the Louisiana District Court against several parties, including the Company, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. After previously finding that Anadarko, as a nonoperating investor in the Macondo well, was not culpable with respect to the Deepwater Horizon events, the Louisiana District Court found Anadarko liable for civil penalties under Section 311 of the CWA as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. Neither party appealed the decision and the Company paid the penalty in the first quarter of 2016.

Restructuring Charges

Restructuring Charges	6 Months Ended
	Jun. 30, 2016
Restructuring and Related Activities [Abstract]
Restructuring Charges	12. Restructuring Charges In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of Anadarko’s workforce with the Company’s expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. All restructuring charges will be recognized in 2016, with the exception of approximately $10 million of expense for retirement benefits expected to be recognized in the first quarter of 2017. The following summarizes the total expected restructuring charges and the amounts expensed during the three and six months ended June 30, 2016, which are included in general and administrative expenses in the Company’s Consolidated Statements of Income: millions Total Expected Costs Three Months Ended Six Months Ended Costs by category Cash severance $ 153 $ 15 $ 146 Retirement benefits (1) 220 27 76 Share-based compensation 34 6 29 Total $ 407 $ 48 $ 251 __________________________________________________________________ (1) Includes termination benefits, curtailments, and settlements. See Note 13—Pension Plans and Other Postretirement Benefits . The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet: millions 2016 Balance at January 1 $ — Accruals 146 Payments (126 ) Balance at June 30 $ 20

Pension Plans and Other Postret

Pension Plans and Other Postretirement Benefits	6 Months Ended
	Jun. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Pension Plans and Other Postretirement Benefits	13. Pension Plans and Other Postretirement Benefits The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree and, in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost: Pension Benefits Other Benefits millions 2016 2015 2016 2015 Three Months Ended June 30 Service cost $ 23 $ 29 $ — $ 2 Interest cost 23 26 3 4 Expected return on plan assets (24 ) (28 ) — — Amortization of net actuarial loss (gain) 10 13 — — Amortization of net prior service cost (credit) — — (6 ) 1 Settlement expense 24 — — — Curtailment expense — — 3 — Net periodic benefit cost $ 56 $ 40 $ — $ 7 Six Months Ended June 30 Service cost $ 49 $ 59 $ 1 $ 5 Interest cost 49 51 6 8 Expected return on plan assets (51 ) (55 ) — — Amortization of net actuarial loss (gain) 18 26 — — Amortization of net prior service cost (credit) — — (12 ) 1 Settlement expense 24 — — — Termination benefits expense 44 — — — Curtailment expense 8 — — — Net periodic benefit cost $ 141 $ 81 $ (5 ) $ 14 The Company’s workforce reduction program resulted in remeasurements of its pension and other postretirement benefit obligations during 2016. The remeasurements resulted in increases in the benefit obligation of $171 million for the pension benefit plans and $23 million for the other postretirement benefit plans, with a corresponding decrease in other comprehensive income. At December 31, 2015, total expected contributions related to unfunded pension plans were $25 million for 2016. The Company expects to contribute an additional $82 million in 2016 and $23 million in 2017 to unfunded pension plans primarily related to the workforce reduction program. See Note 12—Restructuring Charges .

Stockholders' Equity

Stockholders' Equity	6 Months Ended
	Jun. 30, 2016
Stockholders' Equity Note [Abstract]
Stockholders' Equity	14. Stockholders’ Equity 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, TEUs, and WES Series A Preferred units, if the inclusion of these items is dilutive. The following provides a reconciliation between basic and diluted earnings per share attributable to common stockholders: Three Months Ended Six Months Ended millions except per-share amounts 2016 2015 2016 2015 Net income (loss) Net income (loss) attributable to common stockholders $ (692 ) $ 61 $ (1,726 ) $ (3,207 ) Income (loss) effect of TEUs (2 ) — (3 ) — Less distributions on participating securities — 1 — 2 Basic $ (694 ) $ 60 $ (1,729 ) $ (3,209 ) Income (loss) effect of TEUs (1 ) — (1 ) — Diluted $ (695 ) $ 60 $ (1,730 ) $ (3,209 ) Shares Average number of common shares outstanding—basic 510 508 510 507 Dilutive effect of stock options — 1 — — Average number of common shares outstanding—diluted 510 509 510 507 Excluded due to anti-dilutive effect 11 6 10 11 Net income (loss) per common share Basic $ (1.36 ) $ 0.12 $ (3.39 ) $ (6.32 ) Diluted $ (1.36 ) $ 0.12 $ (3.39 ) $ (6.32 )

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	6 Months Ended
	Jun. 30, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	15. 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 — (120 ) (120 ) Reclassifications to Consolidated Statement of Income 3 13 16 Balance at June 30, 2016 $ (39 ) $ (448 ) $ (487 )

Noncontrolling Interests

Noncontrolling Interests	6 Months Ended
	Jun. 30, 2016
Noncontrolling Interest Items [Abstract]
Noncontrolling Interests	16. Noncontrolling Interests WES, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During the first quarter of 2016 , WES issued 14 million Series A Preferred units to private investors for net proceeds of $440 million , and issued 1.3 million common units to the Company. Proceeds from these issuances were used to acquire interests in Springfield Pipeline LLC from the Company. During the second quarter of 2016 , WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and raised net proceeds of $247 million . Class C units issued to Anadarko will receive quarterly distributions in the form of additional Class C units until the end of 2017, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 534 thousand Class C units to Anadarko during the six months ended June 30, 2016 , and 498 thousand Class C units to Anadarko during 2015. During 2015, WES issued approximately 874 thousand common units to the public for net proceeds of $57 million . WGP, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own partnership interests in WES. During the three months ended June 30, 2016, Anadarko sold 12.5 million of its WGP common units to the public for net proceeds of $476 million . At June 30, 2016 , Anadarko’s ownership interest in WGP consisted of an 81.6% limited partner interest and the entire non-economic general partner interest. The remaining 18.4% limited partner interest in WGP was owned by the public. At June 30, 2016 , WGP’s ownership interest in WES consisted of a 30.0% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At June 30, 2016 , Anadarko also owned an 8.4% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 60.1% limited partner interest in WES was owned by the public.

Variable Interest Entities

Variable Interest Entities	6 Months Ended
	Jun. 30, 2016
Variable Interest Entities [Abstract]
Variable Interest Entity Disclosure [Text Block]	17. 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 and WES. See Note 16—Noncontrolling Interests for additional information on WGP and WES. Assets and Liabilities of VIEs The assets of WGP and WES cannot be used by Anadarko for general corporate purposes and are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP and WES for which the creditors do not have recourse to other assets of the Company are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. All outstanding debt for WES at June 30, 2016, and December 31, 2015 , 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 June 30, 2016, and December 31, 2015 , 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 8—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 8—Debt and Interest Expense and Note 16—Noncontrolling Interests for additional information on WGP and WES financing activity. 17. Variable Interest Entities (Continued) Financial Support Provided to VIEs Concurrent with the closing of its May 2008 initial public offering, WES loaned the Company $260 million in exchange for a 30 -year note bearing interest at a fixed annual rate of 6.50% , payable quarterly. The related interest income for WES was $4 million for each of the three months ended June 30, 2016 and 2015, and $8 million for each of the six months ended June 30, 2016 and 2015. The note receivable and related interest income are eliminated in consolidation. In March 2015, WES acquired the Company’s interest in Delaware Basin JV Gathering LLC. The acquisition was financed using a deferred purchase price obligation which requires a cash payment from WES to the Company due on March 31, 2020. The net present value of this obligation was $29 million at June 30, 2016, and $189 million at December 31, 2015 . In order to reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of their contracts, Anadarko has commodity price swap agreements in place with WES expiring in 2016. WES has recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for the amount by which the swap price exceeds the applicable market price. WES recorded a $16 million capital contribution from Anadarko for the six months ended June 30, 2016 , and a capital contribution of zero for the six months ended June 30, 2015 .

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended
	Jun. 30, 2016
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	18. Supplemental Cash Flow Information The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities: Six Months Ended millions 2016 2015 Cash paid (received) Interest, net of amounts capitalized (1) $ 427 $ 1,621 Income taxes, net of refunds (2) (883 ) 6 Non-cash investing activities Fair value of properties and equipment from non-cash transactions $ 3 $ 126 Asset retirement cost additions 49 90 Accruals of property, plant, and equipment 505 901 Net liabilities assumed (divested) in acquisitions and divestitures (36 ) (29 ) Non-cash investing and financing activities Floating production, storage, and offloading vessel construction period obligation $ 11 $ 43 __________________________________________________________________ (1) Includes $1.2 billion of interest related to the Tronox settlement payment in 2015. (2) Includes $881 million from a tax refund related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Segment Information	19. Segment Information Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces oil, condensate, natural gas, and NGLs and plans for the development and operation of the Company’s LNG project in Mozambique. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, condensate, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells much of Anadarko’s oil, condensate, natural-gas, and NGLs production as well as third-party purchased volumes. 19. Segment Information (Continued) 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; gains (losses) on divestitures, net; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; interest expense; 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 general and administrative expenses, Deepwater Horizon settlement and related costs included in other operating expenses, loss on early extinguishment of debt, Tronox-related contingent loss, 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. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, 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 that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. 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 or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes: Three Months Ended Six Months Ended millions 2016 2015 2016 2015 Income (loss) before income taxes $ (925 ) $ 185 $ (2,306 ) $ (4,443 ) (Gains) losses on divestitures, net 104 91 102 425 Exploration expense 76 103 202 1,186 DD&A 984 1,214 2,133 2,470 Impairments 18 30 34 2,813 Interest expense 217 201 437 417 Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives 371 (229 ) 775 14 Restructuring charges 48 — 251 — Other operating expense — — 1 4 Loss on early extinguishment of debt 124 — 124 — Tronox-related contingent loss — — — 5 Certain other nonoperating items (56 ) — (56 ) 22 Less net income (loss) attributable to noncontrolling interests 81 47 117 79 Consolidated Adjusted EBITDAX $ 880 $ 1,548 $ 1,580 $ 2,834 19. Segment Information (Continued) Information presented below as “Other and Intersegment Eliminations” includes corporate costs, results from hard-minerals royalties, and net cash from settlement of commodity derivatives. The following summarizes selected financial information for Anadarko’s reporting segments: millions Oil and Gas Exploration & Production Midstream Marketing Other and Intersegment Eliminations Total Three Months Ended June 30, 2016 Sales revenues $ 1,033 $ 141 $ 811 $ — $ 1,985 Intersegment revenues 567 340 (676 ) (231 ) — Other — — — 34 34 Total revenues and other (1) 1,600 481 135 (197 ) 2,019 Operating costs and expenses (2) 790 219 177 (65 ) 1,121 Net cash from settlement of commodity derivatives — — — (60 ) (60 ) Other (income) expense, net (3) — — — 1 1 Net income (loss) attributable to noncontrolling interests — 81 — — 81 Total expenses and other 790 300 177 (124 ) 1,143 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 4 — 4 Adjusted EBITDAX $ 810 $ 181 $ (38 ) $ (73 ) $ 880 Three Months Ended June 30, 2015 Sales revenues $ 1,356 $ 191 $ 1,090 $ — $ 2,637 Intersegment revenues 885 303 (954 ) (234 ) — Other — — — 90 90 Total revenues and other (1) 2,241 494 136 (144 ) 2,727 Operating costs and expenses (2) 832 234 192 (59 ) 1,199 Net cash from settlement of commodity derivatives — — — (82 ) (82 ) Other (income) expense, net — — — 15 15 Net income (loss) attributable to noncontrolling interests — 47 — — 47 Total expenses and other 832 281 192 (126 ) 1,179 Adjusted EBITDAX $ 1,409 $ 213 $ (56 ) $ (18 ) $ 1,548 __________________________________________________________________ (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 other operating expense since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX. 19. Segment Information (Continued) millions Oil and Gas Exploration & Production Midstream Marketing Other and Intersegment Eliminations Total Six Months Ended June 30, 2016 Sales revenues $ 1,744 $ 266 $ 1,609 $ — $ 3,619 Intersegment revenues 1,168 642 (1,339 ) (471 ) — Other — — — 72 72 Total revenues and other (1) 2,912 908 270 (399 ) 3,691 Operating costs and expenses (2) 1,563 402 353 (154 ) 2,164 Net cash from settlement of commodity derivatives — — — (163 ) (163 ) Other (income) expense, net (3) — — — 1 1 Net income (loss) attributable to noncontrolling interests — 117 — — 117 Total expenses and other 1,563 519 353 (316 ) 2,119 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 8 — 8 Adjusted EBITDAX $ 1,349 $ 389 $ (75 ) $ (83 ) $ 1,580 Six Months Ended June 30, 2015 Sales revenues $ 2,426 $ 365 $ 2,431 $ — $ 5,222 Intersegment revenues 2,002 605 (2,145 ) (462 ) — Other — — — 160 160 Total revenues and other (1) 4,428 970 286 (302 ) 5,382 Operating costs and expenses (2) 1,834 474 390 (96 ) 2,602 Net cash from settlement of commodity derivatives — — — (172 ) (172 ) Other (income) expense, net (3) — — — 40 40 Net income (loss) attributable to noncontrolling interests — 79 — — 79 Total expenses and other 1,834 553 390 (228 ) 2,549 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 1 — 1 Adjusted EBITDAX $ 2,594 $ 417 $ (103 ) $ (74 ) $ 2,834 __________________________________________________________________ (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 other operating expense since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Recently Issued Accounting Standards	Recently Issued Accounting Standards The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03, Interest—Imputation of Interest (Subtopic 835-30)—Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015. The FASB issued ASU 2015-02, Consolidation (Topic 810)—Amendments to the Consolidation Analysis. The Company adopted this ASU on January 1, 2016. In accordance with the new ASU, Western Gas Equity Partners, LP (WGP) and Western Gas Partners, LP (WES), publicly traded consolidated subsidiaries of the Company, are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model. After adoption, WGP and WES were consolidated by the Company under the variable interest model. While this ASU requires additional financial statement disclosure, it has no impact on the Company’s consolidated results of operations, cash flows, or financial position. See Note 17—Variable Interest Entities . The FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows, and accounting for forfeitures. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements. 1. Summary of Significant Accounting Policies (Continued) The FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires the lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements. The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which supersedes current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASUs and, as amended, 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 is required to adopt the new standard in the first quarter of 2018 using one of two retrospective application methods. The Company is continuing to evaluate the provisions of this ASU and has not determined the impact this standard may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2016
Energy Related Inventory [Abstract]
Inventory Disclosure Table	The following summarizes the major classes of inventories included in other current assets: millions June 30, December 31, Oil $ 111 $ 116 Natural gas 28 36 NGLs 77 64 Total inventories $ 216 $ 216

Impairments (Tables)

Impairments (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Impairment Charges [Abstract]
Schedule of Impairment Expense	The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment: Three Months Ended Six Months Ended millions Impairment Fair Value (1) Impairment Fair Value (1) June 30, 2016 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ — $ — $ 4 $ 585 Gulf of Mexico properties 1 — 2 — Cost-method investment (2) 1 32 2 32 Midstream Long-lived assets held for use 11 2 21 5 Other Long-lived assets held for use 5 1 5 1 Total $ 18 $ 35 $ 34 $ 623 June 30, 2015 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ 4 $ 12 $ 2,303 $ 1,303 Gulf of Mexico properties 17 — 25 — Cost-method investment (2) 1 32 1 32 Midstream Long-lived assets held for use 8 199 484 202 Total $ 30 $ 243 $ 2,813 $ 1,537 __________________________________________________________________ (1) Measured as of the impairment date using the income approach and Level 3 inputs. (2) Represents the after-tax net investment.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at June 30, 2016 : 2016 Settlement 2017 Settlement 2018 Settlement Oil Three-Way Collars (MBbls/d) 83 — — Average price per barrel Ceiling sold price (call) $ 63.82 $ — $ — Floor purchased price (put) $ 54.46 $ — $ — Floor sold price (put) $ 42.77 $ — $ — Natural Gas Three-Way Collars (thousand MMBtu/d) — 682 250 Average price per MMBtu Ceiling sold price (call) $ — $ 3.60 $ 3.54 Floor purchased price (put) $ — $ 2.75 $ 2.75 Floor sold price (put) $ — $ 2.00 $ 2.00 Fixed-Price Contracts (thousand MMBtu/d) 14 32 — Average price per MMBtu $ 2.38 $ 3.14 $ — NGLs Fixed-Price Contracts (MBbls/d) — 2 — Average price per barrel $ — $ 15.84 $ — __________________________________________________________________ MBbls/d—thousand barrels per day MMBtu/d—million British thermal units per day MMBtu—million British thermal units The Company had the following outstanding interest-rate swaps at June 30, 2016 : millions except percentages Mandatory Weighted-Average Notional Principal Amount Reference Period Termination Date Interest Rate $ 50 September 2016 – 2026 September 2016 5.910% $ 50 September 2016 – 2046 September 2016 6.290% $ 500 September 2016 – 2046 September 2018 6.559% $ 300 September 2016 – 2046 September 2020 6.509% $ 450 September 2017 – 2047 September 2018 6.445% $ 100 September 2017 – 2047 September 2020 6.891% $ 250 September 2017 – 2047 September 2021 6.570%
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	The following summarizes the fair value of the Company’s derivative instruments: Gross Derivative Assets Gross Derivative Liabilities millions June 30, December 31, June 30, December 31, Balance Sheet Classification 2016 2015 2016 2015 Commodity derivatives Other current assets $ 111 $ 462 $ (29 ) $ (177 ) Other assets 10 8 — — Accrued expenses 4 — (30 ) (3 ) Other liabilities 2 — (15 ) — 127 470 (74 ) (180 ) Interest-rate derivatives Other current assets 3 2 — — Other assets 15 54 — — Accrued expenses — — (99 ) (54 ) Other liabilities — — (1,749 ) (1,488 ) 18 56 (1,848 ) (1,542 ) Total derivatives $ 145 $ 526 $ (1,922 ) $ (1,722 ) The following summarizes gains and losses related to derivative instruments: millions Three Months Ended Six Months Ended Classification of (Gain) Loss Recognized 2016 2015 2016 2015 Commodity derivatives Gathering, processing, and marketing sales (1) $ 4 $ 1 $ 6 $ 1 (Gains) losses on derivatives, net 94 1 66 (52 ) Interest-rate derivatives (Gains) losses on derivatives, net 213 (312 ) 538 (107 ) Total (gains) losses on derivatives, net $ 311 $ (310 ) $ 610 $ (158 ) __________________________________________________________________ (1) Represents the effect of Marketing and Trading Derivative Activities.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy: millions June 30, 2016 Level 1 Level 2 Level 3 Netting (1) Collateral Total Assets Commodity derivatives $ 1 $ 126 $ — $ (35 ) $ — $ 92 Interest-rate derivatives — 18 — — — 18 Total derivative assets $ 1 $ 144 $ — $ (35 ) $ — $ 110 Liabilities Commodity derivatives $ (4 ) $ (70 ) $ — $ 35 $ 5 $ (34 ) Interest-rate derivatives — (1,848 ) — — 592 (1,256 ) Total derivative liabilities $ (4 ) $ (1,918 ) $ — $ 35 $ 597 $ (1,290 ) December 31, 2015 Assets Commodity derivatives $ 10 $ 460 $ — $ (178 ) $ (8 ) $ 284 Interest-rate derivatives — 56 — — — 56 Total derivative assets $ 10 $ 516 $ — $ (178 ) $ (8 ) $ 340 Liabilities Commodity derivatives $ (1 ) $ (179 ) $ — $ 178 $ — $ (2 ) Interest-rate derivatives — (1,542 ) — — 58 (1,484 ) Total derivative liabilities $ (1 ) $ (1,721 ) $ — $ 178 $ 58 $ (1,486 ) __________________________________________________________________ (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.

Debt and Interest Expense (Tabl

Debt and Interest Expense (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Debt Outstanding and Debt Activity Tables	The following summarizes the Company’s debt activity, after eliminating the effect of intercompany transactions, during the six months ended June 30, 2016 : Carrying Value millions WES WGP (1) Anadarko (2) Anadarko Consolidated Description Balance at December 31, 2015 $ 2,691 $ — $ 12,957 $ 15,648 Issuances — — 794 794 4.850% Senior Notes due 2021 — — 1,088 1,088 5.550% Senior Notes due 2026 — — 1,088 1,088 6.600% Senior Notes due 2046 Borrowings — — 1,750 1,750 364-Day Facility 530 — — 530 WES RCF — 28 — 28 WGP RCF Repayments — — (1,749 ) (1,749 ) 5.950% Senior Notes due 2016 — — (1,245 ) (1,245 ) 6.375% Senior Notes due 2017 — — (1,750 ) (1,750 ) 364-Day Facility (290 ) — — (290 ) WES RCF — — (250 ) (250 ) Commercial paper notes, net — — (17 ) (17 ) TEUs - senior amortizing notes Other, net 1 — 27 28 Amortization of discounts, premiums, and debt issuance costs Balance at June 30, 2016 $ 2,932 $ 28 $ 12,693 $ 15,653 __________________________________________________________________ (1) Excludes WES. (2) Excludes WES and WGP. The following summarizes the Company’s outstanding debt after eliminating the effect of intercompany transactions: millions WES WGP (1) Anadarko (2) Anadarko Consolidated June 30, 2016 Total borrowings at face value $ 2,960 $ 28 $ 14,325 $ 17,313 Net unamortized discounts, premiums, and debt issuance costs (3) (28 ) — (1,632 ) (1,660 ) Total borrowings 2,932 28 12,693 15,653 Capital lease obligation — — 20 20 Less short-term debt — — 32 32 Total long-term debt $ 2,932 $ 28 $ 12,681 $ 15,641 December 31, 2015 Total borrowings at face value $ 2,720 $ — $ 14,592 $ 17,312 Net unamortized discounts, premiums, and debt issuance costs (3) (29 ) — (1,635 ) (1,664 ) Total borrowings 2,691 — 12,957 15,648 Capital lease obligation — — 20 20 Less short-term debt — — 32 32 Total long-term debt $ 2,691 $ — $ 12,945 $ 15,636 __________________________________________________________________ (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 revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.
Interest Expense Table	The following summarizes interest expense: Three Months Ended Six Months Ended millions 2016 2015 2016 2015 Debt and other $ 259 $ 244 $ 517 $ 498 Capitalized interest (42 ) (43 ) (80 ) (81 ) Total interest expense $ 217 $ 201 $ 437 $ 417

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Schedule of Income Taxes and Effective Tax Rate	The following summarizes income tax expense (benefit) and effective tax rates: Three Months Ended Six Months Ended millions except percentages 2016 2015 2016 2015 Income tax expense (benefit) $ (314 ) $ 77 $ (697 ) $ (1,315 ) Income (loss) before income taxes (925 ) 185 (2,306 ) (4,443 ) Effective tax rate 34 % 42 % 30 % 30 %

Conveyance of Future Hard Min33

Conveyance of Future Hard Minerals Royalty Revenues (Tables)	6 Months Ended
	Jun. 30, 2016
Deferred Revenue Disclosure [Abstract]
Other Commitments [Table Text Block]	The following summarizes the future amounts, prior to the 3% to 4% of any excess described above, that the Company expects to pay: millions 2016 $ 25 2017 50 2018 50 2019 52 2020 56 Later years 320 Total $ 553

Restructuring Charges (Tables)

Restructuring Charges (Tables)	6 Months Ended
	Jun. 30, 2016
Restructuring and Related Activities [Abstract]
Schedule of Restructuring Charges	The following summarizes the total expected restructuring charges and the amounts expensed during the three and six months ended June 30, 2016, which are included in general and administrative expenses in the Company’s Consolidated Statements of Income: millions Total Expected Costs Three Months Ended Six Months Ended Costs by category Cash severance $ 153 $ 15 $ 146 Retirement benefits (1) 220 27 76 Share-based compensation 34 6 29 Total $ 407 $ 48 $ 251 __________________________________________________________________ (1) Includes termination benefits, curtailments, and settlements. See Note 13—Pension Plans and Other Postretirement Benefits . The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet: millions 2016 Balance at January 1 $ — Accruals 146 Payments (126 ) Balance at June 30 $ 20

Pension Plans and Other Postr35

Pension Plans and Other Postretirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Cost Table	The following summarizes the Company’s pension and other postretirement benefit cost: Pension Benefits Other Benefits millions 2016 2015 2016 2015 Three Months Ended June 30 Service cost $ 23 $ 29 $ — $ 2 Interest cost 23 26 3 4 Expected return on plan assets (24 ) (28 ) — — Amortization of net actuarial loss (gain) 10 13 — — Amortization of net prior service cost (credit) — — (6 ) 1 Settlement expense 24 — — — Curtailment expense — — 3 — Net periodic benefit cost $ 56 $ 40 $ — $ 7 Six Months Ended June 30 Service cost $ 49 $ 59 $ 1 $ 5 Interest cost 49 51 6 8 Expected return on plan assets (51 ) (55 ) — — Amortization of net actuarial loss (gain) 18 26 — — Amortization of net prior service cost (credit) — — (12 ) 1 Settlement expense 24 — — — Termination benefits expense 44 — — — Curtailment expense 8 — — — Net periodic benefit cost $ 141 $ 81 $ (5 ) $ 14

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	6 Months Ended
	Jun. 30, 2016
Stockholders' Equity Note [Abstract]
Earnings Per Share Table	The following provides a reconciliation between basic and diluted earnings per share attributable to common stockholders: Three Months Ended Six Months Ended millions except per-share amounts 2016 2015 2016 2015 Net income (loss) Net income (loss) attributable to common stockholders $ (692 ) $ 61 $ (1,726 ) $ (3,207 ) Income (loss) effect of TEUs (2 ) — (3 ) — Less distributions on participating securities — 1 — 2 Basic $ (694 ) $ 60 $ (1,729 ) $ (3,209 ) Income (loss) effect of TEUs (1 ) — (1 ) — Diluted $ (695 ) $ 60 $ (1,730 ) $ (3,209 ) Shares Average number of common shares outstanding—basic 510 508 510 507 Dilutive effect of stock options — 1 — — Average number of common shares outstanding—diluted 510 509 510 507 Excluded due to anti-dilutive effect 11 6 10 11 Net income (loss) per common share Basic $ (1.36 ) $ 0.12 $ (3.39 ) $ (6.32 ) Diluted $ (1.36 ) $ 0.12 $ (3.39 ) $ (6.32 )

Accumulated Other Comprehensi37

Accumulated Other Comprehensive Income (Loss) (Tables)	6 Months Ended
	Jun. 30, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule Of 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 — (120 ) (120 ) Reclassifications to Consolidated Statement of Income 3 13 16 Balance at June 30, 2016 $ (39 ) $ (448 ) $ (487 )

Supplemental Cash Flow Inform38

Supplemental Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2016
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: Six Months Ended millions 2016 2015 Cash paid (received) Interest, net of amounts capitalized (1) $ 427 $ 1,621 Income taxes, net of refunds (2) (883 ) 6 Non-cash investing activities Fair value of properties and equipment from non-cash transactions $ 3 $ 126 Asset retirement cost additions 49 90 Accruals of property, plant, and equipment 505 901 Net liabilities assumed (divested) in acquisitions and divestitures (36 ) (29 ) Non-cash investing and financing activities Floating production, storage, and offloading vessel construction period obligation $ 11 $ 43 __________________________________________________________________ (1) Includes $1.2 billion of interest related to the Tronox settlement payment in 2015. (2) Includes $881 million from a tax refund related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) Before Income Taxes	Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes: Three Months Ended Six Months Ended millions 2016 2015 2016 2015 Income (loss) before income taxes $ (925 ) $ 185 $ (2,306 ) $ (4,443 ) (Gains) losses on divestitures, net 104 91 102 425 Exploration expense 76 103 202 1,186 DD&A 984 1,214 2,133 2,470 Impairments 18 30 34 2,813 Interest expense 217 201 437 417 Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives 371 (229 ) 775 14 Restructuring charges 48 — 251 — Other operating expense — — 1 4 Loss on early extinguishment of debt 124 — 124 — Tronox-related contingent loss — — — 5 Certain other nonoperating items (56 ) — (56 ) 22 Less net income (loss) attributable to noncontrolling interests 81 47 117 79 Consolidated Adjusted EBITDAX $ 880 $ 1,548 $ 1,580 $ 2,834
Schedule of Segment Reporting Information, by Segment	The following summarizes selected financial information for Anadarko’s reporting segments: millions Oil and Gas Exploration & Production Midstream Marketing Other and Intersegment Eliminations Total Three Months Ended June 30, 2016 Sales revenues $ 1,033 $ 141 $ 811 $ — $ 1,985 Intersegment revenues 567 340 (676 ) (231 ) — Other — — — 34 34 Total revenues and other (1) 1,600 481 135 (197 ) 2,019 Operating costs and expenses (2) 790 219 177 (65 ) 1,121 Net cash from settlement of commodity derivatives — — — (60 ) (60 ) Other (income) expense, net (3) — — — 1 1 Net income (loss) attributable to noncontrolling interests — 81 — — 81 Total expenses and other 790 300 177 (124 ) 1,143 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 4 — 4 Adjusted EBITDAX $ 810 $ 181 $ (38 ) $ (73 ) $ 880 Three Months Ended June 30, 2015 Sales revenues $ 1,356 $ 191 $ 1,090 $ — $ 2,637 Intersegment revenues 885 303 (954 ) (234 ) — Other — — — 90 90 Total revenues and other (1) 2,241 494 136 (144 ) 2,727 Operating costs and expenses (2) 832 234 192 (59 ) 1,199 Net cash from settlement of commodity derivatives — — — (82 ) (82 ) Other (income) expense, net — — — 15 15 Net income (loss) attributable to noncontrolling interests — 47 — — 47 Total expenses and other 832 281 192 (126 ) 1,179 Adjusted EBITDAX $ 1,409 $ 213 $ (56 ) $ (18 ) $ 1,548 __________________________________________________________________ (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 other operating expense since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX. 19. Segment Information (Continued) millions Oil and Gas Exploration & Production Midstream Marketing Other and Intersegment Eliminations Total Six Months Ended June 30, 2016 Sales revenues $ 1,744 $ 266 $ 1,609 $ — $ 3,619 Intersegment revenues 1,168 642 (1,339 ) (471 ) — Other — — — 72 72 Total revenues and other (1) 2,912 908 270 (399 ) 3,691 Operating costs and expenses (2) 1,563 402 353 (154 ) 2,164 Net cash from settlement of commodity derivatives — — — (163 ) (163 ) Other (income) expense, net (3) — — — 1 1 Net income (loss) attributable to noncontrolling interests — 117 — — 117 Total expenses and other 1,563 519 353 (316 ) 2,119 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 8 — 8 Adjusted EBITDAX $ 1,349 $ 389 $ (75 ) $ (83 ) $ 1,580 Six Months Ended June 30, 2015 Sales revenues $ 2,426 $ 365 $ 2,431 $ — $ 5,222 Intersegment revenues 2,002 605 (2,145 ) (462 ) — Other — — — 160 160 Total revenues and other (1) 4,428 970 286 (302 ) 5,382 Operating costs and expenses (2) 1,834 474 390 (96 ) 2,602 Net cash from settlement of commodity derivatives — — — (172 ) (172 ) Other (income) expense, net (3) — — — 40 40 Net income (loss) attributable to noncontrolling interests — 79 — — 79 Total expenses and other 1,834 553 390 (228 ) 2,549 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 1 — 1 Adjusted EBITDAX $ 2,594 $ 417 $ (103 ) $ (74 ) $ 2,834 __________________________________________________________________ (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 other operating expense since these expenses are excluded from Adjusted EBITDAX. (3) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

Summary of Significant Accoun40

Summary of Significant Accounting Policies (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reduction in other current assets	$ (318)	$ (573)
Reduction in short-term debt	(32)	(32)
Reduction in other assets	(2,239)	(2,268)
Reduction in long-term debt	$ (15,641)	(15,636)
Accounting Standards Update 2015-03 [Member] | Restatement Adjustment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reduction in other current assets		1
Reduction in short-term debt		1
Reduction in other assets		82
Reduction in long-term debt		$ 82

Inventories (Detail)

Inventories (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Energy Related Inventory [Abstract]
Oil	$ 111	$ 116
Natural gas	28	36
NGLs	77	64
Total inventories	$ 216	$ 216

Divestitures and Assets Held 42

Divestitures and Assets Held for Sale (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures			$ 900,000,000	$ 700,000,000
Net losses from divestitures and assets held for sale	$ (104,000,000)	$ (91,000,000)	102,000,000	$ 425,000,000
Held for Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets associated with assets held for sale were not material
Liabilities associated with assets held for sale were not material
Oil and Gas Exploration and Production Reporting Segment [Member] | Certain U.S. Onshore East Texas/Louisiana Assets [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures			99,000,000
Original sales price			107,000,000
Gain (loss) on divestitures			13,000,000
Oil and Gas Exploration and Production Reporting Segment [Member] | Certain U.S. Onshore West Texas Assets [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures			138,000,000
Gain (loss) on divestitures			0
Oil and Gas Exploration and Production Reporting Segment [Member] | Certain U.S. Onshore Assets in the Rockies [Member] | Asset Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from divestitures			593,000,000
Gain (loss) on divestitures			$ (53,000,000)
Oil And Gas Exploration And Production And Midstream Reporting Segment [Member] | Certain U.S. Onshore Assets [Member] | Held for Sale [Member] | Fair Value, Inputs, Level 2 [Member] | Market Approach Valuation Technique [Member] | Fair Value, Measurements, Nonrecurring [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on asset held for sale	$ 50,000,000

Impairments - Impairments and F

Impairments - Impairments and Fair Values by Segment Table (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Impaired Long Lived Assets Held and Used [Line Items]
Total impairments		$ 18	$ 30	$ 34	$ 2,813
Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total fair value	[1]	623	1,537	623	1,537
Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 2nd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total fair value	[1]	35	243	35	243
Oil and Gas Exploration and Production Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of cost-method investment		1	1	2	1
Oil and Gas Exploration and Production Reporting Segment [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of cost-method investment	[1],[2]	32	32	32	32
Oil and Gas Exploration and Production Reporting Segment [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 2nd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of cost-method investment	[1],[2]	32	32	32	32
Oil and Gas Exploration and Production Reporting Segment [Member] | U.S. Onshore Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		0	4	4	2,303
Oil and Gas Exploration and Production Reporting Segment [Member] | U.S. Onshore Properties [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	585	1,303	585	1,303
Oil and Gas Exploration and Production Reporting Segment [Member] | U.S. Onshore Properties [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 2nd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	0	12	0	12
Oil and Gas Exploration and Production Reporting Segment [Member] | Gulf of Mexico [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		1	17	2	25
Oil and Gas Exploration and Production Reporting Segment [Member] | Gulf of Mexico [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	0	0	0	0
Oil and Gas Exploration and Production Reporting Segment [Member] | Gulf of Mexico [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 2nd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	0	0	0	0
Midstream Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		11	8	21	484
Midstream Reporting Segment [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	5	202	5	202
Midstream Reporting Segment [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 2nd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	2	$ 199	2	$ 199
Other and Intersegment Eliminations [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		5		5
Other and Intersegment Eliminations [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	1		1
Other and Intersegment Eliminations [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 2nd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	$ 1		$ 1
[1]	Measured as of the impairment date using the income approach and Level 3 inputs.
[2]	Represents the after-tax net investment.

Impairments - Additional Inform

Impairments - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties	$ 45	$ 1,040
Unproved Greater Natural Buttes Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties		$ 935

Suspended Exploratory Well Co45

Suspended Exploratory Well Costs (Detail) - USD ($) $ in Billions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Capitalized Exploratory Well Costs [Abstract]
Suspended exploratory well costs	$ 1.2	$ 1.1
Suspended exploratory well costs previously capitalized for a period greater than one year since the completion of drilling at December 31, 2015, charged to exploration expense were not material

Derivative Instruments - Oil an

Derivative Instruments - Oil and Natural-Gas Production/Processing Derivative Activities Table (Detail) - Not Designated as Hedging Instrument [Member] MMBTU / d in Thousands	6 Months Ended
	Jun. 30, 2016MMBTU / dMBbls / d$ / bbl$ / MMBTU
Three Way Collars Oil 2016 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	83
Three Way Collars Oil 2016 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price | $ / bbl	63.82
Three Way Collars Oil 2016 [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average floor price | $ / bbl	42.77
Three Way Collars Oil 2016 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price | $ / bbl	54.46
Three Way Collars Natural Gas 2017 [Member]
Average price per MMBtu or barrel
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	682
Three Way Collars Natural Gas 2017 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price	3.60
Three Way Collars Natural Gas 2017 [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average floor price	2
Three Way Collars Natural Gas 2017 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price	2.75
Three Way Collars Natural Gas 2018 [Member]
Average price per MMBtu or barrel
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	250
Three Way Collars Natural Gas 2018 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price	3.54
Three Way Collars Natural Gas 2018 [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average floor price	2
Three Way Collars Natural Gas 2018 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price	2.75
Forward Contracts Natural Gas 2016 [Member]
Average price per MMBtu or barrel
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	14
Average price per MMBtu or barrel	2.38
Forward Contracts Natural Gas 2017 [Member]
Average price per MMBtu or barrel
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	32
Average price per MMBtu or barrel	3.14
Forward Contracts Natural Gas Liquids 2017 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	2
Average price per MMBtu or barrel
Average price per MMBtu or barrel | $ / bbl	15.84

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) Mcf in Millions, $ in Millions	2 Months Ended	6 Months Ended		12 Months Ended
	Feb. 29, 2016	Jun. 30, 2016USD ($)Mcf	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)Mcf
Derivative [Line Items]
Cash payment for settled interest-rate swap		$ 727	$ 77
Debt instrument, principal amount		17,313		$ 17,312
Total Amount of Senior Notes Due in 2019 [Member]
Derivative [Line Items]
Debt instrument, principal amount		$ 900
Zero-Coupon Senior Notes [Member]
Derivative [Line Items]
Debt instrument, maturity date		Oct. 10, 2036
Debt Instrument, earliest call date		Oct. 10, 2016
Zero-Coupon Senior Notes [Member] | Accreted Value at Next Potential Put Date [Member]
Derivative [Line Items]
Debt instrument, accreted value		$ 839
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross derivative liabilities		1,922		1,722
Amount of cash posted as collateral		599		58
Aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed (net of collateral)		1,300		1,300
Not Designated as Hedging Instrument [Member] | Settled Interest Rate Swap [Member]
Derivative [Line Items]
Cash payment for settled interest-rate swap		193
Not Designated as Hedging Instrument [Member] | Interest-Rate Swaps 3 and 5 [Member] | Modified Interest-Rate Swaps for Mandatory Termination Dates [Member]
Derivative [Line Items]
Mandatory termination date for interest-rate swap prior to modification	Sep. 15, 2021
Notional principal amount of interest-rate swap		500
Not Designated as Hedging Instrument [Member] | Interest-Rate Swaps 1 Through 7 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap		1,700
Not Designated as Hedging Instrument [Member] | Permitted to Offset Gross Derivative Asset with Financial Institutions [Member]
Derivative [Line Items]
Gross derivative liabilities		$ 100		$ 347
Natural Gas [Member] | Commodity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Financial derivative transactions | Mcf		5		8

Derivative Instruments - Intere

Derivative Instruments - Interest-Rate Derivatives Table (Detail) - Not Designated as Hedging Instrument [Member] $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Interest-Rate Swap 1 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 50
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2026
Mandatory termination date for interest-rate swap	Sep. 15, 2016
Weighted-average interest rate for interest-rate swap	5.91%
Interest-Rate Swap 2 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 50
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 15, 2016
Weighted-average interest rate for interest-rate swap	6.29%
Interest-Rate Swap 3 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 500
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 15, 2018
Weighted-average interest rate for interest-rate swap	6.559%
Interest-Rate Swap 4 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 300
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 15, 2020
Weighted-average interest rate for interest-rate swap	6.509%
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. 15, 2018
Weighted-average interest rate for interest-rate swap	6.445%
Interest-Rate Swap 6 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 100
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 15, 2020
Weighted-average interest rate for interest-rate swap	6.891%
Interest Rate Swap 7 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 250
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 15, 2021
Weighted-average interest rate for interest-rate swap	6.57%

Derivative Instruments - Effect

Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 145	$ 526
Gross derivative liabilities	(1,922)	(1,722)
Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	127	470
Gross derivative liabilities	(74)	(180)
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	111	462
Gross derivative liabilities	(29)	(177)
Commodity Derivatives [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	10	8
Gross derivative liabilities	0	0
Commodity Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	4	0
Gross derivative liabilities	(30)	(3)
Commodity Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	2	0
Gross derivative liabilities	(15)	0
Interest-Rate Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	18	56
Gross derivative liabilities	(1,848)	(1,542)
Interest-Rate Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	3	2
Gross derivative liabilities	0	0
Interest-Rate Derivatives [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	15	54
Gross derivative liabilities	0	0
Interest-Rate Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	(99)	(54)
Interest-Rate Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	$ (1,749)	$ (1,488)

Derivative Instruments - Effe50

Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ 311	$ (310)	$ 610	$ (158)
Commodity Derivatives [Member] | Gathering, Processing, and Marketing Sales [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	[1]	4	1	6	1
Commodity Derivatives [Member] | (Gains) Losses on Derivatives, Net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		94	1	66	(52)
Interest-Rate Derivatives [Member] | (Gains) Losses on Derivatives, Net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ 213	$ (312)	$ 538	$ (107)
[1]	Represents the effect of Marketing and Trading Derivative Activities.

Derivative Instruments - Fair V

Derivative Instruments - Fair Value Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		$ 145	$ 526
Gross derivative liabilities		(1,922)	(1,722)
Derivative assets netting	[1]	(35)	(178)
Derivative liabilities netting	[1]	35	178
Cash collateral from counterparties		0	(8)
Cash collateral held by counterparties		597	58
Derivative assets		110	340
Derivative liabilities		(1,290)	(1,486)
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		127	470
Gross derivative liabilities		(74)	(180)
Derivative assets netting	[1]	(35)	(178)
Derivative liabilities netting	[1]	35	178
Cash collateral from counterparties		0	(8)
Cash collateral held by counterparties		5	0
Derivative assets		92	284
Derivative liabilities		(34)	(2)
Interest-Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		18	56
Gross derivative liabilities		(1,848)	(1,542)
Derivative assets netting	[1]	0	0
Derivative liabilities netting	[1]	0	0
Cash collateral from counterparties		0	0
Cash collateral held by counterparties		592	58
Derivative assets		18	56
Derivative liabilities		(1,256)	(1,484)
Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		1	10
Gross derivative liabilities		(4)	(1)
Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		144	516
Gross derivative liabilities		(1,918)	(1,721)
Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		0	0
Gross derivative liabilities		0	0
Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		1	10
Gross derivative liabilities		(4)	(1)
Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		126	460
Gross derivative liabilities		(70)	(179)
Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		0	0
Gross derivative liabilities		0	0
Recurring [Member] | Interest-Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		0	0
Gross derivative liabilities		0	0
Recurring [Member] | Interest-Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		18	56
Gross derivative liabilities		(1,848)	(1,542)
Recurring [Member] | Interest-Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		0	0
Gross derivative liabilities		$ 0	$ 0
[1]	Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

Tangible Equity Units (Detail)

Tangible Equity Units (Detail) shares in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2016unit$ / unit	Jun. 30, 2015USD ($)$ / unitshares
Senior Note Component of 7.50% Tangible Equity Units [Member]
Tangible Equity Units [Line Items]
Tangible equity unit rate	7.50%
Principal amount per amortizing note	10.95
Debt instrument, stated interest rate	1.50%
Beginning date of quarterly cash installment payments	Sep. 7, 2015
Quarterly cash installment payment per amortizing note	0.9375
First quarterly cash installment payment per amortizing note	0.9063
Final installment payment date	Jun. 7, 2018
7.50% Tangible Equity Units [Member]
Tangible Equity Units [Line Items]
Number of tangible equity units issued | shares		9.2
Tangible equity unit rate		7.50%
Stated amount per tangible equity unit		50
Total net proceeds | $		$ 445
Equity Component of 7.50% Tangible Equity Units [Member]
Tangible Equity Units [Line Items]
Purchase contract, mandatory settlement date	Jun. 7, 2018
Equity Component of 7.50% Tangible Equity Units [Member] | Settled In WGP Common Units [Member]
Tangible Equity Units [Line Items]
Maximum settlement rate | unit	0.8591
Minimum settlement rate | unit	0.7159

Debt and Interest Expense - Deb

Debt and Interest Expense - Debt Activity Table (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Debt Instrument [Line Items]
Balance at December 31, 2015	$ 15,648
Other, net	28
Balance at June 30, 2016	15,653
Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Balance at December 31, 2015	2,691
Other, net	1
Balance at June 30, 2016	2,932
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Balance at December 31, 2015	0	[1]
Other, net	0	[1]
Balance at June 30, 2016	28	[1]
Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Balance at December 31, 2015	12,957	[2]
Other, net	27	[2]
Balance at June 30, 2016	12,693	[2]
7.50% Tangible Equity Units [Member]
Debt Instrument [Line Items]
Repayments, senior notes	(17)
7.50% Tangible Equity Units [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments, senior notes	(17)	[2]
Commercial Paper [Member]
Debt Instrument [Line Items]
Repayments, commercial paper	(250)
Commercial Paper [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments, commercial paper	(250)	[2]
4.850% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Issuances	$ 794
Debt instrument, stated interest rate	4.85%
Debt instrument, maturity date	Mar. 15, 2021
4.850% Senior Notes Due 2021 [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Issuances	$ 794	[2]
5.550% Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Issuances	$ 1,088
Debt instrument, stated interest rate	5.55%
Debt instrument, maturity date	Mar. 15, 2026
5.550% Senior Notes Due 2026 [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Issuances	$ 1,088	[2]
6.600% Senior Notes Due 2046 [Member]
Debt Instrument [Line Items]
Issuances	$ 1,088
Debt instrument, stated interest rate	6.60%
Debt instrument, maturity date	Mar. 15, 2046
6.600% Senior Notes Due 2046 [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Issuances	$ 1,088	[2]
364-Day Credit Facility Due 2017 [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	1,750
Repayments, credit facility	(1,750)
364-Day Credit Facility Due 2017 [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	1,750	[2]
Repayments, credit facility	(1,750)	[2]
WES RCF [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	530
Repayments, credit facility	(290)
WES RCF [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	530
Repayments, credit facility	(290)
WGP RCF [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	28
WGP RCF [Member] | Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	28	[1]
5.950% Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Repayments, senior notes	$ (1,749)
Debt instrument, stated interest rate	5.95%
Debt instrument, maturity date	Sep. 15, 2016
5.950% Senior Notes Due 2016 [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments, senior notes	$ (1,749)	[2]
Portion of 6.375% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Repayments, senior notes	(1,245)
Portion of 6.375% Senior Notes Due 2017 [Member] | Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Repayments, senior notes	$ (1,245)	[2]
6.375% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	6.375%
Debt instrument, maturity date	Sep. 15, 2017
[1]	Excludes WES.
[2]	Excludes WES and WGP.

Debt and Interest Expense - Out

Debt and Interest Expense - Outstanding Debt Table (Detail) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total borrowings at face value		$ 17,313	$ 17,312
Net unamortized discounts, premiums, and debt issuance costs (3)	[1]	(1,660)	(1,664)
Total borrowings		15,653	15,648
Capital lease obligation		20	20
Less short-term debt		32	32
Total long-term debt		15,641	15,636
Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Total borrowings at face value		2,960	2,720
Net unamortized discounts, premiums, and debt issuance costs (3)	[1]	(28)	(29)
Total borrowings		2,932	2,691
Capital lease obligation		0	0
Less short-term debt		0	0
Total long-term debt		2,932	2,691
Western Gas Equity Partners, LP excluding WES [Member]
Debt Instrument [Line Items]
Total borrowings at face value	[2]	28	0
Net unamortized discounts, premiums, and debt issuance costs (3)	[1],[2]	0	0
Total borrowings	[2]	28	0
Capital lease obligation	[2]	0	0
Less short-term debt	[2]	0	0
Total long-term debt	[2]	28	0
Anadarko excluding WES and WGP [Member]
Debt Instrument [Line Items]
Total borrowings at face value	[3]	14,325	14,592
Net unamortized discounts, premiums, and debt issuance costs (3)	[1],[3]	(1,632)	(1,635)
Total borrowings	[3]	12,693	12,957
Capital lease obligation	[3]	20	20
Less short-term debt	[3]	32	32
Total long-term debt	[3]	$ 12,681	$ 12,945
[1]	Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.
[2]	Excludes WES.
[3]	Excludes WES and WGP.

Debt and Interest Expense - Add

Debt and Interest Expense - Additional Information (Detail) - USD ($)	Jul. 12, 2016	Jan. 19, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 17,313,000,000		$ 17,313,000,000		$ 17,312,000,000
Loss on early extinguishment of debt			124,000,000	$ 0	124,000,000	$ 0
Premiums for early retirement and redemption of senior notes			114,000,000
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
Fair Value, Inputs, Level 2 [Member] | Market Approach Valuation Technique [Member]
Debt Instrument [Line Items]
Estimated fair value of total borrowings			17,200,000,000		$ 17,200,000,000		$ 15,700,000,000
Senior Notes 1 Through 3 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			3,000,000,000		3,000,000,000
Portion of 6.375% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Amount of debt extinguished					1,250,000,000
6.375% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount			$ 2,000,000,000		$ 2,000,000,000
Debt instrument, stated interest rate			6.375%		6.375%
Debt instrument, maturity date					Sep. 15, 2017
5.950% Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Amount of debt extinguished					$ 1,750,000,000
Debt instrument, stated interest rate			5.95%		5.95%
Debt instrument, maturity date					Sep. 15, 2016
Zero-Coupon Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date					Oct. 10, 2036
Debt Instrument, earliest call date					Oct. 10, 2016
Amount of Zero Coupon Notes classified as long-term debt on the Company's Consolidated Balance Sheet					$ 839,000,000
Zero-Coupon Senior Notes [Member] | Accreted Value at Next Potential Put Date [Member]
Debt Instrument [Line Items]
Debt instrument, accreted value			$ 839,000,000		839,000,000
Five-Year Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity			3,000,000,000		$ 3,000,000,000
Debt instrument, term					5 years
Line of credit, expiration date					Jan. 23, 2021
Line of credit, outstanding borrowings			0		$ 0
364-Day Credit Facility Due 2016 [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity		$ 2,000,000,000
Debt instrument, term		364 days
364-Day Credit Facility Due 2017 [Member]
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, expiration date					Jan. 15, 2017
Line of credit, outstanding borrowings			0		$ 0
WES 4.650% Senior Notes Due 2026 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	$ 500,000,000
Debt instrument, stated interest rate	4.65%
Debt instrument, maturity date	Jul. 12, 2026
WES RCF [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity			1,200,000,000		$ 1,200,000,000
Debt instrument, term					5 years
Line of credit, expiration date					Feb. 26, 2019
Line of credit, outstanding borrowings			$ 540,000,000		$ 540,000,000
Line of credit, interest rate			1.77%		1.77%
Line of credit, available borrowing capacity			$ 655,000,000		$ 655,000,000
Line of credit, expandable maximum capacity			1,500,000,000		1,500,000,000
Letters of credit, outstanding			5,000,000		5,000,000
WGP RCF [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity			250,000,000		$ 250,000,000
Debt instrument, term					3 years
Line of credit, expiration date					Mar. 14, 2019
Line of credit, outstanding borrowings			$ 28,000,000		$ 28,000,000
Line of credit, interest rate			2.72%		2.72%
Line of credit, available borrowing capacity			$ 222,000,000		$ 222,000,000
Line of credit, expandable maximum capacity			$ 500,000,000		$ 500,000,000
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%

Debt and Interest Expense - Int

Debt and Interest Expense - Interest Expense Table (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Debt Disclosure [Abstract]
Debt and other	$ 259	$ 244	$ 517	$ 498
Capitalized interest	(42)	(43)	(80)	(81)
Total interest expense	$ 217	$ 201	$ 437	$ 417

Income Taxes - Income Tax Expen

Income Taxes - Income Tax Expense (Benefit) Table (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ (314)	$ 77	$ (697)	$ (1,315)
Income (loss) before income taxes	$ (925)	$ 185	$ (2,306)	$ (4,443)
Effective tax rate	34.00%	42.00%	30.00%	30.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
U.S. federal statutory rate	35.00%	35.00%	35.00%	35.00%
Accounts Receivable Other [Member]
Income Tax Disclosure [Line Items]
Income taxes receivable	$ 192		$ 192

Conveyance of Future Hard Min59

Conveyance of Future Hard Minerals Royalty Revenues - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Deferred Revenue Disclosure [Abstract]
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs	$ 413	$ 0
Maximum amount of total future royalty revenue third-party is entitled to	553
Deferred Revenue Arrangement [Line Items]
Amount of deferred revenue amortized in period	$ 19
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 Min60

Conveyance of Future Hard Minerals Royalty Revenues - Schedule of Future Royalty Payments (Detail) $ in Millions	Jun. 30, 2016USD ($)
Deferred Revenue Disclosure [Abstract]
2,016	$ 25
2,017	50
2,018	50
2,019	52
2,020	56
Later years	320
Total	$ 553

Contingencies (Detail)

Contingencies (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2011
Macondo Exploration Well [Member]
Loss Contingencies [Line Items]
Nonoperated interest			25.00%
Deepwater Horizon [Member] | Judicial Ruling [Member] | Clean Water Act [Member]
Loss Contingencies [Line Items]
CWA penalty		$ 159.5
Amount of penalty paid	$ 159.5

Restructuring Charges - Schedul

Restructuring Charges - Schedule of Resctucturing Charges (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Restructuring Cost and Reserve [Line Items]
Total expected restructuring charges		$ 407		$ 407
Restructuring charges		48	$ 0	251	$ 0
General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges		48		251
Cash Severance [Member]
Restructuring Cost and Reserve [Line Items]
Total expected restructuring charges		153		153
Cash Severance [Member] | General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges		15		146
Retirement Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Total expected restructuring charges	[1]	220		220
Retirement Benefits [Member] | General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges	[1]	27		76
Share-based Compensation [Member]
Restructuring Cost and Reserve [Line Items]
Total expected restructuring charges		34		34
Share-based Compensation [Member] | General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges		6		29
Amount to be Recognized in 2017 [Member] | Retirement Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Total expected restructuring charges		$ 10		$ 10
[1]	Includes termination benefits, curtailments, and settlements. See Note 13—Pension Plans and Other Postretirement Benefits.

Restructuring Charges - Rollfor

Restructuring Charges - Rollforward of Severance-related Liability (Detail) - Cash Severance [Member] $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Restructuring Cost and Reserve [Line Items]
Accruals	$ 146
Payments	(126)
Accounts Payable [Member]
Restructuring Cost and Reserve [Line Items]
Balance at January 1	0
Balance at June 30	$ 20

Pension Plans and Other Postr64

Pension Plans and Other Postretirement Benefits - Components of Net Periodic Benefit Cost Table (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Plan [Member]
Components of net periodic benefit cost
Service cost	$ 23	$ 29	$ 49	$ 59
Interest cost	23	26	49	51
Expected return on plan assets	(24)	(28)	(51)	(55)
Amortization of net actuarial loss (gain)	10	13	18	26
Amortization of net prior service cost (credit)	0	0	0	0
Settlement expense	24	0	24	0
Termination benefits expense			44	0
Curtailment expense	0	0	8	0
Net periodic benefit cost	56	40	141	81
Other Postretirement Benefit Plans [Member]
Components of net periodic benefit cost
Service cost	0	2	1	5
Interest cost	3	4	6	8
Expected return on plan assets	0	0	0	0
Amortization of net actuarial loss (gain)	0	0	0	0
Amortization of net prior service cost (credit)	(6)	1	(12)	1
Settlement expense	0	0	0	0
Termination benefits expense			0	0
Curtailment expense	3	0	0	0
Net periodic benefit cost	$ 0	$ 7	$ (5)	$ 14

Pension Plans and Other Postr65

Pension Plans and Other Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Corresponding decrease in other comprehensive income related to the benefit obligation increase	$ 24	$ 0	$ 190	$ 0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation increase for the period			171
Corresponding decrease in other comprehensive income related to the benefit obligation increase			171
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation increase for the period			23
Corresponding decrease in other comprehensive income related to the benefit obligation increase			23
Unfunded Plans Defined Benefit [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected future employer contributions in 2016					$ 25
Unfunded Plans Defined Benefit [Member] | Pension Plan [Member] | Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected future employer contributions in 2016			82
Expected future employer contributions in 2017			$ 23

Stockholders' Equity (Detail)

Stockholders' Equity (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Net income (loss)
Net income (loss) attributable to common stockholders	$ (692)	$ 61	$ (1,726)	$ (3,207)
Income (loss) effect of TEUs	(2)	0	(3)	0
Less distributions on participating securities	0	1	0	2
Basic	(694)	60	(1,729)	(3,209)
Income (loss) effect of TEUs	(1)	0	(1)	0
Diluted	$ (695)	$ 60	$ (1,730)	$ (3,209)
Shares
Average number of common shares outstanding—basic	510	508	510	507
Dilutive effect of stock options	0	1	0	0
Average number of common shares outstanding—diluted	510	509	510	507
Excluded due to anti-dilutive effect	11	6	10	11
Net income (loss) per common share
Basic	$ (1.36)	$ 0.12	$ (3.39)	$ (6.32)
Diluted	$ (1.36)	$ 0.12	$ (3.39)	$ (6.32)

Accumulated Other Comprehensi67

Accumulated Other Comprehensive Income (Loss) (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	$ 15,457
Other comprehensive income (loss), before reclassifications	(120)
Reclassifications to Consolidated Statement of Income	16
Balance	14,600
Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	(42)
Other comprehensive income (loss), before reclassifications	0
Reclassifications to Consolidated Statement of Income	3
Balance	(39)
Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	(341)
Other comprehensive income (loss), before reclassifications	(120)
Reclassifications to Consolidated Statement of Income	13
Balance	(448)
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	(383)
Balance	$ (487)

Noncontrolling Interests (Detai

Noncontrolling Interests (Detail) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended	12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Western Gas Equity Partners, LP [Member]
Noncontrolling Interest [Line Items]
Common units issued to the public	12,500
Net proceeds from common units	$ 476
Western Gas Equity Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	81.60%		81.60%
Public ownership interest in subsidiary	18.40%		18.40%
Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement		1,300
Common units issued to the public				874
Net proceeds from common units				$ 57
Western Gas Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Public ownership interest in subsidiary	60.10%		60.10%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Western Gas Equity Partners, LP Ownership Interest in Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	30.00%		30.00%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Anadarko Limited Partner Interest In WES Owned Through Other Subsidiaries [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	8.40%		8.40%
Western Gas Partners, LP [Member] | General Partner [Member] | Western Gas Equity Partners, LP Ownership Interest in Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	1.50%		1.50%
Series A Preferred Units [Member] | Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement	8,000	14,000
Net proceeds from Series A preferred units	$ 247	$ 440
Class C Units [Member] | Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement			534	498

Variable Interest Entities (Det

Variable Interest Entities (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Variable Interest Entity [Line Items]
Interest income for WES	$ 259	$ 244	$ 517	$ 498
Variable Interest Entity, Primary Beneficiary [Member] | Western Gas Partners, LP [Member]
Variable Interest Entity [Line Items]
Note receivable for WES	$ 260		$ 260
Debt instrument, term			30 years
Fixed annual rate	6.50%		6.50%
Interest income for WES	$ 4	$ 4	$ 8	8
Deferred purchase price obligation - Anadarko	$ 29		29		$ 189
Above-market component of swap extensions with Anadarko			$ 16	$ 0

Supplemental Cash Flow Inform70

Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015
Cash (paid) received
Interest, net of amounts capitalized (1)	$ 427		$ 1,621	[1]
Income taxes, net of refunds (2)	(883)	[2]	6
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	3		126
Asset retirement cost additions	49		90
Accruals of property, plant, and equipment	505		901
Net liabilities assumed (divested) in acquisitions and divestitures	(36)		(29)
Non-cash investing and financing activities
Floating production, storage, and offloading vessel construction period obligation	11		43
Related to Net Operating Loss Carryback [Member]
Cash (paid) received
Income taxes, net of refunds (2)	$ 881
Tronox Litigation [Member] | Judicial Ruling [Member]
Cash (paid) received
Interest, net of amounts capitalized (1)			$ 1,200
[1]	Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.
[2]	Includes $881 million from a tax refund related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.

Segment Information - Additiona

Segment Information - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2016Segment
Segment Reporting [Abstract]
Number of reporting segments	3
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Number of operating segments	2

Segment Information - Reconcili

Segment Information - Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) Before Income Taxes (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting [Abstract]
Income (loss) before income taxes	$ (925)	$ 185	$ (2,306)	$ (4,443)
(Gains) losses on divestitures, net	(104)	(91)	102	425
Exploration expense	76	103	202	1,186
DD&A	984	1,214	2,133	2,470
Impairments	18	30	34	2,813
Interest expense	217	201	437	417
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	371	(229)	775	14
Restructuring charges	48	0	251	0
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Loss on early extinguishment of debt	124	0	124	0
Net income (loss) attributable to noncontrolling interests	81	47	117	79
Consolidated Adjusted EBITDAX	880	1,548	1,580	2,834
Certain Other Nonoperating Items [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Certain other nonoperating items	(56)	0	(56)	22
Deepwater Horizon [Member] | Pending Litigation [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other operating expense		0		4
Deepwater Horizon [Member] | Judicial Ruling [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other operating expense	0		1
Tronox Litigation [Member] | Judicial Ruling [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other operating expense	$ 0	$ 0	0	5
Certain other nonoperating items			$ 0	$ (5,210)

Segment Information - Selected

Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Revenues		$ 1,985	$ 2,637		$ 3,619	$ 5,222
Other		34	90		72	160
Total revenues and other (1)		1,915	2,636		3,589	4,957
Operating costs and expenses (2)		2,247	2,546		4,785	9,075
Net cash from settlement of commodity derivatives					(165)	(172)
Other (income) expense, net		(55)	15		(55)	62
Net income (loss) attributable to noncontrolling interests		81	47		117	79
Total expenses and other		1,143	1,179		2,119	2,549
Consolidated Adjusted EBITDAX		880	1,548		1,580	2,834
(Gains) Losses on Derivatives, Net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		(60)	(82)		(163)	(172)
Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		4			8	1
Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other (1)	[1]	2,019	2,727		3,691	5,382
Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses (2)	[2]	1,121	1,199		2,164	2,602
Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		1	15	[3]	1	40	[3]
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues		0	0		0	0
Other		34	90		72	160
Total expenses and other		(124)	(126)		(316)	(228)
Consolidated Adjusted EBITDAX		(73)	(18)		(83)	(74)
Other and Intersegment Eliminations [Member] | (Gains) Losses on Derivatives, Net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		(60)	(82)		(163)	(172)
Other and Intersegment Eliminations [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other (1)	[1]	(197)	(144)		(399)	(302)
Other and Intersegment Eliminations [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses (2)	[2]	(65)	(59)		(154)	(96)
Other and Intersegment Eliminations [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net		1	15	[3]	1	40	[3]
Other and Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		(231)	(234)		(471)	(462)
Oil and Gas Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues		1,033	1,356		1,744	2,426
Oil and Gas Exploration and Production Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		567	885		1,168	2,002
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total expenses and other		790	832		1,563	1,834
Consolidated Adjusted EBITDAX		810	1,409		1,349	2,594
Oil and Gas 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 (1)	[1]	1,600	2,241		2,912	4,428
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses (2)	[2]	790	832		1,563	1,834
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues		141	191		266	365
Midstream Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		340	303		642	605
Midstream Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income (loss) attributable to noncontrolling interests		81	47		117	79
Total expenses and other		300	281		519	553
Consolidated Adjusted EBITDAX		181	213		389	417
Midstream Reporting Segment [Member] | Operating Segments [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other (1)	[1]	481	494		908	970
Midstream Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses (2)	[2]	219	234		402	474
Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues		811	1,090		1,609	2,431
Marketing Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		(676)	(954)		(1,339)	(2,145)
Marketing Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total expenses and other		177	192		353	390
Consolidated Adjusted EBITDAX		(38)	(56)		(75)	(103)
Marketing Reporting Segment [Member] | Operating Segments [Member] | Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		4			8	1
Marketing Reporting Segment [Member] | Operating Segments [Member] | Excluding Gains Losses On Divestitures Net [Member]
Segment Reporting Information [Line Items]
Total revenues and other (1)	[1]	135	136		270	286
Marketing Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Items [Member]
Segment Reporting Information [Line Items]
Operating costs and expenses (2)	[2]	$ 177	$ 192		$ 353	$ 390
[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 other operating expense since these expenses are excluded from Adjusted EBITDAX.
[3]	Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.