Anadarko Petroleum 10-Q 27 Oct 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 19, 2015
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	Sep. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		508,142,751

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues and Other
Natural-gas sales	$ 484	$ 830	$ 1,612	$ 3,038
Oil and condensate sales	1,229	2,637	4,264	7,766
Natural-gas liquids sales	183	424	644	1,221
Gathering, processing, and marketing sales	334	339	932	928
Gains (losses) on divestitures and other, net	(542)	780	(807)	2,340
Total	1,688	5,010	6,645	15,293
Costs and Expenses
Oil and gas operating	262	275	784	861
Oil and gas transportation and other	271	322	921	869
Exploration	1,074	199	2,260	1,000
Gathering, processing, and marketing	289	269	798	771
General and administrative	345	381	933	984
Depreciation, depletion, and amortization	1,111	1,163	3,581	3,335
Other taxes	127	306	460	981
Impairments	758	394	3,571	514
Total	4,237	3,312	13,312	9,411
Operating Income (Loss)	(2,549)	1,698	(6,667)	5,882
Other (Income) Expense
Interest expense	199	204	616	573
(Gains) losses on derivatives, net	281	(324)	123	462
Other (income) expense, net	47	24	109	12
Total	528	(76)	853	5,376
Income (Loss) Before Income Taxes	(3,077)	1,774	(7,520)	506
Income tax expense (benefit)	(917)	627	(2,232)	1,719
Net Income (Loss)	(2,160)	1,147	(5,288)	(1,213)
Net income attributable to noncontrolling interests	75	60	154	142
Net Income (Loss) Attributable to Common Stockholders	$ (2,235)	$ 1,087	$ (5,442)	$ (1,355)
Per Common Share
Net income (loss) attributable to common stockholders—basic	$ (4.41)	$ 2.13	$ (10.73)	$ (2.69)
Net income (loss) attributable to common stockholders—diluted	$ (4.41)	$ 2.12	$ (10.73)	$ (2.69)
Average Number of Common Shares Outstanding—Basic	508	506	508	505
Average Number of Common Shares Outstanding—Diluted	508	508	508	505
Dividends (per common share)	$ 0.27	$ 0.27	$ 0.81	$ 0.72
Commodity Contract and Interest Rate Swap [Member]
Other (Income) Expense
(Gains) losses on derivatives, net	$ 282	$ (323)	$ 123	$ 453
Deepwater Horizon [Member] | Pending Litigation [Member]
Costs and Expenses
Litigation-related contingent loss	0	3	4	96
Tronox Litigation [Member] | Judicial Ruling [Member]
Costs and Expenses
Litigation-related contingent loss	$ 0	$ 19	$ 5	$ 4,338

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ (2,160)	$ 1,147	$ (5,288)	$ (1,213)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2	2	7	7
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	(1)	(1)	(3)	(3)
Total adjustments for derivative instruments, net of taxes	1	1	4	4
Adjustments for pension and other postretirement plans
Amortization of net actuarial (gain) loss to general and administrative expense	13	7	39	21
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	(5)	(2)	(14)	(7)
Amortization of net prior service (credit) cost to general and administrative expense	1	0	2	0
Income taxes on amortization of net prior service (credit) cost to general and administrative expense	(1)	0	(1)	0
Total adjustments for pension and other postretirement plans, net of taxes	8	5	26	14
Total	9	6	30	18
Comprehensive Income (Loss)	(2,151)	1,153	(5,258)	(1,195)
Comprehensive income attributable to noncontrolling interests	75	60	154	142
Comprehensive Income (Loss) Attributable to Common Stockholders	$ (2,226)	$ 1,093	$ (5,412)	$ (1,337)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents		$ 2,072	$ 7,369
Accounts receivable (net of allowance of $8 million and $7 million)
Customers		833	1,118
Others		1,636	1,409
Other current assets		646	1,325
Total		5,187	11,221
Properties and Equipment
Cost		70,387	75,107
Less accumulated depreciation, depletion, and amortization		35,006	33,518
Net properties and equipment		35,381	41,589
Other Assets		2,271	2,310
Goodwill and Other Intangible Assets		6,343	6,569
Total Assets		49,182	61,689
Current Liabilities
Accounts payable		3,074	3,683
Current asset retirement obligations		334	257
Accrued expenses		907	994
Short-term debt		33	0
Total		4,438	10,234
Long-term Debt	[1]	15,892	15,092
Other Long-term Liabilities
Deferred income taxes		6,090	9,249
Asset retirement obligations		1,670	1,796
Other		4,040	3,000
Total		11,800	14,045
Stockholders' equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 527.8 million and 525.9 million shares issued)		52	52
Paid-in capital		9,224	9,005
Retained earnings		6,268	12,125
Treasury stock (19.7 million and 19.3 million shares)		(978)	(940)
Accumulated other comprehensive income (loss)		(487)	(517)
Total Stockholders’ Equity		14,079	19,725
Noncontrolling interests		2,973	2,593
Total Equity		17,052	22,318
Total Liabilities and Equity		49,182	61,689
Pending Litigation [Member] | Deepwater Horizon [Member]
Current Liabilities
Litigation-related contingent liability		90	90
Judicial Ruling [Member] | Tronox Litigation [Member]
Current Liabilities
Litigation-related contingent liability		$ 0	$ 5,210
[1]	Includes WES debt of $2.6 billion at September 30, 2015, and $2.4 billion at December 31, 2014.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 8	$ 7
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	527,800,000	525,900,000
Treasury stock, shares	19,700,000	19,300,000

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY - 9 months ended Sep. 30, 2015 - USD ($) $ in Millions	Total	Common Stock [Member]	Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Subsidiary Equity Transactions [Member]	Subsidiary Equity Transactions [Member]Paid-in Capital [Member]	Subsidiary Equity Transactions [Member]Noncontrolling Interests [Member]	7.50% Tangible Equity Units [Member]	7.50% Tangible Equity Units [Member]Noncontrolling Interests [Member]
Balance at Dec. 31, 2014	$ 22,318	$ 52	$ 9,005	$ 12,125	$ (940)	$ (517)	$ 2,593
Net income (loss)	(5,288)			(5,442)			154
Common stock issued	154		154
Dividends—common stock	(415)			(415)
Repurchase of common stock	(38)				(38)
Subsidiary equity transactions								$ 151	$ 65	$ 86	$ 348	$ 348
Distributions to noncontrolling interest owners	(208)						(208)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	4					4
Adjustments for pension and other postretirement plans	26					26
Balance at Sep. 30, 2015	$ 17,052	$ 52	$ 9,224	$ 6,268	$ (978)	$ (487)	$ 2,973

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash Flows from Operating Activities
Net income (loss)	$ (5,288)	$ (1,213)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	3,581	3,335
Dry hole expense and impairments of unproved properties	1,993	743
Impairments	3,571	514
(Gains) losses on divestitures, net	1,003	(2,194)
Total (gains) losses on derivatives, net	123	462
Operating portion of net cash received (paid) in settlement of derivative instruments	251	(138)
Other	219	195
Changes in assets and liabilities
(Increase) decrease in accounts receivable	23	104
Increase (decrease) in accounts payable and accrued expenses	(573)	710
Other items—net	800	(225)
Net cash provided by (used in) operating activities	(2,134)	6,514
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(4,861)	(7,289)
Divestitures of properties and equipment and other assets	1,248	4,770
Other—net	(83)	(376)
Net cash provided by (used in) investing activities	(3,696)	(2,895)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	4,810	2,370
Repayments of debt	(4,024)	(1,255)
Financing portion of net cash received (paid) for derivative instruments	(44)	(222)
Increase (decrease) in outstanding checks	(103)	134
Dividends paid	(415)	(368)
Repurchase of common stock	(38)	(36)
Issuance of common stock, including tax benefit on share-based compensation awards	21	117
Distributions to noncontrolling interest owners	(208)	(157)
Net cash provided by (used in) financing activities	534	1,017
Effect of Exchange Rate Changes on Cash	(1)	1
Net Increase (Decrease) in Cash and Cash Equivalents	(5,297)	4,637
Cash and Cash Equivalents at Beginning of Period	7,369	3,698
Cash and Cash Equivalents at End of Period	2,072	8,335
Subsidiary Equity Transactions [Member]
Cash Flows from Financing Activities
Proceeds from equity issuances	187	434
7.50% Tangible Equity Units [Member]
Cash Flows from Financing Activities
Borrowings, net of issuance costs	97
Proceeds from equity issuances	348	0
Deepwater Horizon [Member] | Pending Litigation [Member]
Changes in assets and liabilities
Litigation-related contingent costs	0	93
Tronox Litigation [Member] | Judicial Ruling [Member]
Changes in assets and liabilities
Litigation-related contingent costs	(5,210)	4,338
Excluding Certain International Locations [Member]
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Deferred income taxes	$ (2,627)	$ (210)

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
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 natural gas, oil, condensate, natural gas liquids (NGLs), and the anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, oil, 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 information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; asset retirement obligations; litigation liabilities; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. 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 will simplify the presentation of debt issuance costs by requiring such 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. These ASUs are effective for annual and interim periods beginning in 2016 and are required to be adopted using a retrospective approach, with early adoption permitted. The Company does not expect the adoption to have a material impact on its consolidated financial statements. The FASB issued ASU 2015-02, Consolidation—Amendments to the Consolidation Analysis . This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. 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 . This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition , and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition , and 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 effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers—Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using one of two retrospective application methods, with early adoption permitted in 2017. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

Acquisitions, Divestitures, and

Acquisitions, Divestitures, and Assets Held for Sale	9 Months Ended
	Sep. 30, 2015
Property, Plant and Equipment [Abstract]
Acquisitions, Divestitures, and Assets Held for Sale	2. Acquisitions, Divestitures, and Assets Held for Sale Acquisitions In November 2014, Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, acquired Nuevo Midstream, LLC (Nuevo) for $1.554 billion . Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). The acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. The fair-value measurements of the assets acquired and liabilities assumed at the acquisition date were preliminary as of September 30, 2015, pending final review of certain support related to the entity’s assets and liabilities. There were no material changes to the fair value of assets acquired and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2014. Divestitures and Assets Held for Sale For the nine months ended September 30, 2015 , the Company received $1.2 billion in proceeds from divestitures and recognized net losses of $1.0 billion . Divestitures During the third quarter of 2015, the Company sold certain coalbed methane properties in the Rocky Mountains Region (Rockies) for net proceeds of $107 million , after closing adjustments, and recognized a loss of $440 million . These properties were included in the oil and gas exploration and production reporting segment. The sale of certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas, with an original sales price of $440 million , closed in July 2015 for net proceeds of $426 million after closing adjustments. During the nine months ended September 30, 2015 , the Company recognized a loss of $110 million . The sale of certain enhanced oil recovery (EOR) assets in the Rockies included in the oil and gas exploration and reporting segment, with an original sales price of $703 million , closed in April 2015 for net proceeds of $686 million after closing adjustments. During the nine months ended September 30, 2015 , the Company recognized a loss of $344 million . Assets Held for Sale Certain coalbed methane midstream assets in the Rockies satisfied criteria to be considered held for sale during the third quarter of 2015, 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 $100 million . The sale of these assets is expected to close in the fourth quarter of 2015 for a sales price of $80 million , subject to closing adjustments. 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 September 30, 2015, the balances of assets and liabilities associated with assets held for sale were not material.

Inventories

Inventories	9 Months Ended
	Sep. 30, 2015
Energy Related Inventory [Abstract]
Inventories	3. Inventories The following summarizes the major classes of inventories included in other current assets: millions September 30, December 31, Oil $ 108 $ 133 Natural gas 37 27 NGLs 57 83 Total inventories $ 202 $ 243

Impairments

Impairments	9 Months Ended
	Sep. 30, 2015
Asset Impairment Charges [Abstract]
Impairments	4. Impairments The following summarizes impairments of proved properties and the related post-impairment fair values by segment: Three Months Ended Nine Months Ended millions Impairment Fair Value (1) Impairment Fair Value (1) September 30, 2015 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ 641 $ 634 $ 2,944 $ 1,904 Gulf of Mexico properties 101 94 126 94 Cost-method investment (2) 1 32 2 32 Midstream Long-lived assets held for use 15 7 499 209 Total $ 758 $ 767 $ 3,571 $ 2,239 September 30, 2014 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ 387 $ 385 $ 387 $ 385 Gulf of Mexico properties — — 115 327 Cost-method investment (2) — — 2 32 Midstream Long-lived assets held for use 7 — 10 — Total $ 394 $ 385 $ 514 $ 744 __________________________________________________________________ (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 three months ended September 30, 2015, were primarily related to U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region and an oil and gas property in the Gulf of Mexico, all of which were impaired due to lower forecasted commodity prices. Impairments during the three months ended September 30, 2014, were primarily related to a U.S. onshore oil and gas property in the Southern and Appalachia Region that was impaired due to lower forecasted natural-gas prices. Impairments during the nine months ended September 30, 2015, were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, certain other U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region, and oil and gas properties in the Gulf of Mexico, all of which were impaired due to lower forecasted commodity prices. Impairments during the nine months ended September 30, 2014, were primarily related to the U.S. onshore oil and gas property in the Southern and Appalachia Region discussed above and an oil and gas property in the Gulf of Mexico that was impaired due to a reduction in estimated future cash flows. Additional impairments may be recognized in the fourth quarter of 2015 if commodity prices decline further. Impairments of proved properties are included in impairment expense in the Company’s Consolidated Statements of Income. In addition to the proved property impairments above, during the third quarter of 2015, the Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter. The Company also recognized a $935 million impairment of unproved Greater Natural Buttes properties during the nine months ended September 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.

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	9 Months Ended
	Sep. 30, 2015
Capitalized Exploratory Well Costs [Abstract]
Suspended Exploratory Well Costs	5. Suspended Exploratory Well Costs The Company’s suspended exploratory well costs were $1.1 billion at September 30, 2015 , and $1.5 billion at December 31, 2014 . During the nine months ended September 30, 2015, $602 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, 2014 , primarily related to Brazil, were charged to exploration expense. Given the current oil-price environment and other considerations, the Company does not expect to have substantive exploration and development activities in Brazil for the foreseeable future. The decrease in suspended exploratory well costs was partially offset by the capitalization of costs associated with exploration drilling in the Gulf of Mexico, Colombia, and Mozambique. 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	9 Months Ended
	Sep. 30, 2015
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 Henry Hub, Louisiana, for natural gas and Cushing, Oklahoma, or Sullom Voe, Scotland, for oil. 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 increases (decreases) when interest rates increase (decrease). 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 10—Accumulated Other Comprehensive Income (Loss) . 6. Derivative Instruments (Continued) Oil and Natural-Gas Production/Processing Derivative Activities The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The oil prices listed below are a combination of NYMEX West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The NGLs prices listed below are Oil Price Information Services prices (OPIS). The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, 2015 : 2015 Settlement 2016 Settlement Natural Gas Three-Way Collars (thousand MMBtu/d) 635 — Average price per MMBtu Ceiling sold price (call) $ 4.76 $ — Floor purchased price (put) $ 3.75 $ — Floor sold price (put) $ 2.75 $ — Fixed-Price Contracts (thousand MMBtu/d) — 34 Average price per MMBtu $ — $ 3.18 Extendable Fixed-Price Contracts (thousand MMBtu/d) (1) 170 — Average price per MMBtu $ 4.17 $ — Oil Three-Way Collars (MBbls/d) — 28 Average price per barrel Ceiling sold price (call) $ — $ 69.29 Floor purchased price (put) $ — $ 61.43 Floor sold price (put) $ — $ 46.43 NGLs Fixed-Price Contracts (MBbls/d) 7 3 Average price per barrel $ 14.09 $ 14.87 __________________________________________________________________ (1) The extendable fixed-price contracts have a contract term of January 2015 to December 2015 with an option for the counterparty to extend the contract term to December 2016 at the same price. MMBtu—million British thermal units MMBtu/d—million British thermal units per day MBbls/d—thousand barrels per day 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 8 billion cubic feet (Bcf) at September 30, 2015 , and 6 Bcf at December 31, 2014 , which 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). During the third quarter of 2015, the Company extended the reference-period start dates on interest-rate swaps with an aggregate notional principal amount of $1.0 billion to align the portfolio with anticipated debt refinancing. The Company also amended the mandatory termination dates on interest-rate swaps with an aggregate notional principal amount of $1.8 billion so that, at the start of the reference period, Anadarko will receive quarterly payments based on the floating rate and make semi-annual payments based on the fixed interest rate. The interest-rate swaps are required to be settled in full at the mandatory termination date. As part of these interest-rate swap modifications, the fixed interest rates on the swaps were also adjusted, and the Company recognized a loss of $137 million , which is included in gains (losses) on derivatives, net in the Company’s Consolidated Statements of Income, and increased the related derivative liability. 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 September 30, 2015 : 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% $ 250 September 2016 – 2046 September 2018 6.310% $ 300 September 2016 – 2046 September 2020 6.509% $ 250 September 2016 – 2046 September 2021 6.724% $ 200 September 2017 – 2047 September 2018 6.049% $ 300 September 2017 – 2047 September 2020 6.569% $ 500 September 2017 – 2047 September 2021 6.654% Effect of Derivative Instruments — Balance Sheet The following summarizes the fair value of the Company’s derivative instruments: Gross Derivative Assets Gross Derivative Liabilities millions September 30, December 31, September 30, December 31, Balance Sheet Classification 2015 2014 2015 2014 Commodity derivatives Other current assets $ 246 $ 421 $ (74 ) $ (118 ) Other assets 42 1 (16 ) — Accrued expenses 27 71 (43 ) (114 ) Other liabilities — — — (6 ) 315 493 (133 ) (238 ) Interest-rate derivatives Accrued expenses — — (56 ) — Other liabilities — — (1,462 ) (1,217 ) — — (1,518 ) (1,217 ) Total derivatives $ 315 $ 493 $ (1,651 ) $ (1,455 ) 6. Derivative Instruments (Continued) Effect of Derivative Instruments — Statement of Income The following summarizes gains and losses related to derivative instruments: millions Three Months Ended Nine Months Ended Classification of (Gain) Loss Recognized 2015 2014 2015 2014 Commodity derivatives Gathering, processing, and marketing sales (1) $ (1 ) $ (1 ) $ — $ 9 (Gains) losses on derivatives, net (125 ) (419 ) (177 ) (40 ) Interest-rate derivatives (Gains) losses on derivatives, net 407 96 300 493 Total (gains) losses on derivatives, net $ 281 $ (324 ) $ 123 $ 462 __________________________________________________________________ (1) Represents the effect of Marketing and Trading Derivative Activities. 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 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 September 30, 2015 , $243 million of the Company’s $1.651 billion gross derivative liability balance, and at December 31, 2014 , $289 million of the Company’s $1.455 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 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 below investment grade. 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 September 30, 2015 , and $97 million (net of collateral) at December 31, 2014 . The increase is primarily a result of derivative counterparties no longer maintaining secured positions under the Company’s credit facilities, and therefore, the derivative instruments are now subject to credit-risk-related provisions. For information on the Company’s revolving credit facilities, see Note 8—Debt and Interest Expense —Anadarko Revolving Credit Facilities and Commercial Paper Program. 6. Derivative Instruments (Continued) Fair Value Fair value of futures contracts is based on 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 September 30, 2015 Level 1 Level 2 Level 3 Netting (1) Collateral Total Assets Commodity derivatives Financial institutions $ 4 $ 288 $ — $ (115 ) $ (6 ) $ 171 Other counterparties — 23 — (3 ) — 20 Total derivative assets $ 4 $ 311 $ — $ (118 ) $ (6 ) $ 191 Liabilities Commodity derivatives Financial institutions $ — $ (126 ) $ — $ 115 $ — $ (11 ) Other counterparties — (7 ) — 3 — (4 ) Interest-rate derivatives — (1,518 ) — — 67 (1,451 ) Total derivative liabilities $ — $ (1,651 ) $ — $ 118 $ 67 $ (1,466 ) December 31, 2014 Assets Commodity derivatives Financial institutions $ — $ 471 $ — $ (187 ) $ (13 ) $ 271 Other counterparties — 22 — (2 ) — 20 Total derivative assets $ — $ 493 $ — $ (189 ) $ (13 ) $ 291 Liabilities Commodity derivatives Financial institutions $ — $ (234 ) $ — $ 187 $ — $ (47 ) Other counterparties — (4 ) — 2 — (2 ) Interest-rate derivatives — (1,217 ) — — 23 (1,194 ) Total derivative liabilities $ — $ (1,455 ) $ — $ 189 $ 23 $ (1,243 ) __________________________________________________________________ (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	9 Months Ended
	Sep. 30, 2015
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 and raised net proceeds of $445 million . Each TEU is comprised of a prepaid equity purchase contract for common units of Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary, 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. Anadarko allocated the proceeds from the issuance of the TEUs to equity and debt based on the relative fair values of their respective components as follows: millions, except price per TEU Equity Component Debt Component Total Price per TEU $ 39.05 $ 10.95 $ 50.00 Gross proceeds 359 101 460 Less issuance costs 11 4 15 Net proceeds $ 348 $ 97 $ 445 The prepaid equity purchase contracts were recorded in noncontrolling interests, net of issuance costs, and the senior amortizing notes were recorded in short-term debt and long-term debt on the Company’s Consolidated Balance Sheet. 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 WGP common units (or APC shares) on the settlement date at the settlement rate based upon the applicable market value of WGP common units (or APC shares) as follows: Settlement Rate per Purchase Contract Applicable Market Value of WGP Common Units (1) WGP Common Units APC Shares (if elected) (1) Exceeds $69.8422 (Threshold Appreciation Price) 0.7159 units (Minimum Settlement Rate) a number of shares equal to (a) the Minimum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares Less than or equal to the Threshold Appreciation Price, but greater than or equal to $58.20 (Reference Price) a number of units equal to $50.00, divided by the applicable market value of WGP common units a number of shares equal to $50.00, divided by 98% of the applicable market value of APC shares Less than the Reference Price 0.8591 units (Maximum Settlement Rate) a number of shares equal to (a) the Maximum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares __________________________________________________________________ (1) The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC shares) for the 20 consecutive trading days beginning on, and including, the 23 rd scheduled trading day immediately preceding June 7, 2018. 7. Tangible Equity Units (Continued) The WGP common units underlying the purchase contract are currently issued and outstanding, and are owned by a wholly owned subsidiary of Anadarko. In the event Anadarko elects to settle in APC shares, the number of such shares issued and delivered upon settlement of each purchase contract is subject to adjustment and cannot exceed four shares under any circumstance (APC share cap). The above fixed settlement rates for WGP common units and the APC share cap are subject to adjustment upon the occurrence of certain specified dilutive events, such as certain increases in the WGP distribution rate. Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. Beginning September 7, 2015 , Anadarko will pay 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	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Debt and Interest Expense	8. Debt and Interest Expense Debt The Company’s outstanding debt, excluding the capital lease obligation, is senior unsecured. The following summarizes the Company’s outstanding debt: millions September 30, December 31, Total debt at face value $ 17,497 $ 16,687 Net unamortized discounts and premiums (1) (1,593 ) (1,616 ) Total borrowings 15,904 15,071 Capital lease obligation 21 21 Less short-term debt 33 — Total long-term debt (2) $ 15,892 $ 15,092 __________________________________________________________________ (1) Unamortized discounts and premiums are amortized over the term of the related debt. (2) Includes WES debt of $2.6 billion at September 30, 2015, and $2.4 billion at December 31, 2014 . Anadarko’s $1.750 billion 5.950% Senior Notes due September 2016 are classified as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with the Company’s $3.0 billion five -year senior unsecured revolving credit facility (Five-Year Facility). Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons (accreted value of $796 million ) were put to the Company in October 2015 . 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 variable interest rates are reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.2 billion at September 30, 2015 , and $17.4 billion at December 31, 2014 . 8. Debt and Interest Expense (Continued) Debt Activity The following summarizes the Company’s debt activity during the nine months ended September 30, 2015 : Carrying millions Value Description Balance at December 31, 2014 $ 15,071 Issuances 494 WES 3.950% Senior Notes due 2025 101 Tangible equity units - senior amortizing notes Borrowings 1,500 $5.0 billion revolving credit facility 1,800 364-Day Facility 280 WES revolving credit facility 547 Commercial paper notes, net (1) Repayments (1,500 ) $5.0 billion revolving credit facility (1,800 ) 364-Day Facility (610 ) WES revolving credit facility (8 ) Tangible equity units - senior amortizing notes Other, net 29 Amortization of debt discounts and premiums Balance at September 30, 2015 $ 15,904 __________________________________________________________________ (1) Includes repayments of $106 million related to commercial paper notes with maturities greater than 90 days. Anadarko Revolving Credit Facilities and Commercial Paper Program In January 2015, upon satisfaction of certain conditions, including the settlement payment related to the Tronox Adversary Proceeding, the Company’s $5.0 billion senior secured revolving credit facility was replaced by the Five-Year Facility, which is expandable from $3.0 billion to $4.0 billion , and a $2.0 billion 364 -day senior unsecured revolving credit facility (364-Day Facility). For additional information, see Note 12—Contingencies —Tronox Litigation . Borrowings under the Five-Year and 364-Day Facilities generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the Five-Year Facility denominated in Euro) or an alternate base rate, in each case plus an applicable margin ranging from 0.00% to 1.65% for the Five-Year Facility and 0.00% to 1.675% for the 364-Day Facility. The applicable margin will vary depending on Anadarko’s credit ratings. The Five-Year and 364-Day Facilities contain certain customary affirmative and negative covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65% and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes. At September 30, 2015 , the Company had no outstanding borrowings under the Five-Year and 364-Day Facilities and was in compliance with all covenants contained therein. During the first quarter of 2015, the Company initiated a commercial paper program, which allows 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 vary, but may not exceed 397 days . The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes. At September 30, 2015 , the Company had $547 million of commercial paper notes outstanding at a weighted-average interest rate of 0.51% . Anadarko classified the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with additional commercial paper notes supported by the Five-Year Facility. 8. Debt and Interest Expense (Continued) WES Borrowings During the second quarter of 2015 , WES completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025 . At September 30, 2015 , WES was in compliance with all covenants contained in its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to $1.5 billion . At September 30, 2015 , WES had outstanding borrowings under its RCF of $180 million at an interest rate of 1.50% , had outstanding letters of credit of $13 million , and had available borrowing capacity of $1.0 billion . Interest Expense The following summarizes interest expense: Three Months Ended Nine Months Ended millions 2015 2014 2015 2014 Debt and other $ 245 $ 250 $ 743 $ 723 Capitalized interest (46 ) (46 ) (127 ) (150 ) Total interest expense $ 199 $ 204 $ 616 $ 573

Stockholders' Equity

Stockholders' Equity	9 Months Ended
	Sep. 30, 2015
Stockholders' Equity Note [Abstract]
Stockholders' Equity	9. 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, and TEUs, 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 Nine Months Ended millions except per-share amounts 2015 2014 2015 2014 Net income (loss) Net income (loss) attributable to common stockholders $ (2,235 ) $ 1,087 $ (5,442 ) $ (1,355 ) Less noncontrolling interest effect of TEUs 3 — 3 — Less distributions on participating securities 1 2 4 3 Less undistributed income allocated to participating securities — 6 — — Basic $ (2,239 ) $ 1,079 $ (5,449 ) $ (1,358 ) Diluted $ (2,239 ) $ 1,079 $ (5,449 ) $ (1,358 ) Shares Average number of common shares outstanding—basic 508 506 508 505 Dilutive effect of stock options — 2 — — Average number of common shares outstanding—diluted 508 508 508 505 Excluded due to anti-dilutive effect 10 3 11 11 Net income (loss) per common share Basic $ (4.41 ) $ 2.13 $ (10.73 ) $ (2.69 ) Diluted $ (4.41 ) $ 2.12 $ (10.73 ) $ (2.69 )

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	9 Months Ended
	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	10. 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, 2014 $ (48 ) $ (469 ) $ (517 ) Reclassifications to Consolidated Statement of Income 4 26 30 Balance at September 30, 2015 $ (44 ) $ (443 ) $ (487 )

Noncontrolling Interests

Noncontrolling Interests	9 Months Ended
	Sep. 30, 2015
Noncontrolling Interest Items [Abstract]
Noncontrolling Interests	11. Noncontrolling Interests WGP, a publicly traded consolidated subsidiary, is a limited partnership that owns interests in WES. During the nine months ended September 30, 2015, Anadarko sold 2.3 million WGP common units to the public and raised net proceeds of $130 million . In June 2015, Anadarko issued 9.2 million TEUs, which include an equity component that may be settled in WGP common units. For additional disclosure of the TEU effect on noncontrolling interests, see Note 7—Tangible Equity Units . At September 30, 2015 , Anadarko’s ownership interest in WGP consisted of an 87.3% limited partner interest and the entire non-economic general partner interest. The remaining 12.7% limited partner interest in WGP was owned by the public. WES, a publicly traded consolidated subsidiary, is a limited partnership that acquires, owns, develops, and operates midstream assets. During the nine months ended September 30, 2015 , WES issued 874 thousand common units to the public under its continuous offering program and raised net proceeds of $57 million . In 2014, WES issued 11 million Class C units to Anadarko to partially fund the acquisition of DBM. These Class C units receive distributions in the form of additional Class C units until conversion into common units at the end of 2017, unless WES elects to convert the units earlier or Anadarko extends the conversion date. During the nine months ended September 30, 2015 , WES distributed 317 thousand Class C units to Anadarko. At September 30, 2015 , WGP’s ownership interest in WES consisted of a 34.6% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At September 30, 2015 , Anadarko also owned an 8.4% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 55.2% limited partner interest in WES was owned by the public.

Contingencies

Contingencies	9 Months Ended
	Sep. 30, 2015
Contingencies Disclosure [Abstract]
Contingencies	12. 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, 2014 . Tronox Litigation On April 3, 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries entered into a settlement agreement to resolve all claims asserted by Tronox Incorporated (Tronox) and certain of its affiliates, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding), for $5.15 billion . In addition, the Company agreed to pay interest on that amount from April 3, 2014, through the payment of the settlement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective. For additional disclosure of the Tronox Adversary Proceeding, see Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 . Anadarko recognized Tronox-related contingent losses of $850 million in the fourth quarter of 2013 and $4.3 billion in the first quarter of 2014. In addition, Anadarko recognized settlement-related interest expense, included in Tronox-related contingent loss in the Company’s Consolidated Statements of Income, of $60 million during the year ended December 31, 2014, and $5 million during the first quarter of 2015. For information on the tax effects of the settlement agreement, see Note 13—Income Taxes . 12. Contingencies (Continued) 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. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against penalties and fines, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company’s Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 17—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, 2014 . Penalties and Fines In December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (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. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA. The declaratory judgment was affirmed in June 2014 by the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit). In March 2015, Anadarko filed a petition for a writ of certiorari with the U.S. Supreme Court appealing the Fifth Circuit’s decision, which was denied in June 2015. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko will be determined by the Louisiana District Court upon its ruling in the penalty phase of trial discussed below under Civil Litigation Damage Claims . Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012 satisfies the requirement that a liability arising from the future assessment of a civil penalty against Anadarko is probable. In an effort to resolve this matter, the Company made a settlement offer to the DOJ in July 2014 of $90 million and recorded a contingent liability for this amount at June 30, 2014. The Company subsequently engaged in further discussions regarding settlement, but the parties have not been able to reach agreement on either the amount of, or the terms and conditions governing, a settlement. The Company’s settlement offer of $90 million remains outstanding and the Company remains open to resolving the matter through settlement discussions. The Company believes that $90 million under a settlement scenario is a better estimate of loss at this time than any other amount. Based on the above accounting guidance, the Company’s contingent liability for CWA penalties and fines remains $90 million at September 30, 2015 . However, the Company may ultimately incur a liability related to CWA penalties in excess of the current accrued liability. 12. Contingencies (Continued) The actual amount of a CWA penalty is subject to uncertainty, including whether the Company will be able to reach a settlement with the DOJ or will await the Louisiana District Court’s opinion in the penalty phase trial. The CWA sets forth subjective criteria to be considered by the court in assessing the magnitude of any CWA penalty: economic benefit to the violator; degree of culpability; seriousness of the violation; the nature, extent, and degree of success of any efforts to minimize or mitigate the effects of the discharge; prior history of violations; other penalties for the same incident; economic impact of the penalty on the violator; and other matters as justice may require. For the Phase I and II trials (defined in Civil Litigation Damage Claims below) and again for the penalty phase trial in January 2015, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented. In addition, in its Phase I Findings of Fact and Conclusions of Law (Phase I Findings and Conclusions), the Louisiana District Court did not allocate any fault to Anadarko. Given the subjective nature of the CWA criteria used to determine penalty assessments and the Louisiana District Court’s prior rulings related to culpability and allocation of fault, the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss if the matter is resolved by the Louisiana District Court following trial. Furthermore, BP’s July 2015 announcement of a settlement agreement in principle with the DOJ and certain states regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event, including $5.5 billion to resolve CWA penalties, and the lodging of a proposed consent decree with the Louisiana District Court in October 2015, does not affect the Company’s current conclusion concerning its ability to estimate potential penalties and fines. The Company had no involvement with the settlement and has no information concerning the rationale for allocating certain settlement proceeds as CWA penalties. The lodged consent decree also provides no explanation as to why the United States and the various states and local government entities consider the penalty amount to be fair and reasonable. Although the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss, the Company believes the following factors should limit the magnitude of any CWA penalties assessed: • the Company’s lack of direct operational involvement in the event as a non-operator, • the Louisiana District Court’s rulings excluding any evidence of Anadarko’s alleged culpability or fault, and • the Phase I Findings and Conclusions that did not allocate any fault to Anadarko. In addition, the Company is not aware that any court has ever assessed a substantial CWA penalty against a party who has been found by a court to bear no fault for a spill. Events or factors that could assist the Company in estimating the amount of settlement or potential civil penalty or a range of potential loss related to such penalty include a ruling by the Louisiana District Court or substantive settlement negotiations between the Company and the DOJ. As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments appealed, or provided indication of a likely appeal of, the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. These appeals will be dismissed as part of BP’s settlement with the United States and various states and local government entities, provided that the consent decree is ultimately approved by the Louisiana District Court. 12. Contingencies (Continued) Civil Litigation Damage Claims Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. The first phase of the trial in the MDL (Phase I) commenced in February 2013. The issues tried in Phase I included the cause of the blowout and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. In September 2014, the Louisiana District Court issued its Phase I Findings and Conclusions. The Louisiana District Court found that BP and BP America Production Company (BPAP), Transocean Ltd. (Transocean), and Halliburton Energy Services, Inc. (Halliburton), but not Anadarko, are each liable under general maritime law for the blowout, explosion, and oil spill. The court determined that BP’s and BPAP’s conduct was reckless and that both Transocean’s and Halliburton’s conduct was negligent. The Louisiana District Court apportioned 67% of the fault to BP and BPAP, 30% to Transocean, and 3% to Halliburton. No fault was allocated to Anadarko. The plaintiffs and BP have appealed the Phase I Findings and Conclusions. The second phase of trial (Phase II) began in September 2013. The issues tried in Phase II included spill-source control and quantification of the spill for the period from April 20, 2010, until the well was capped. In January 2015, the Louisiana District Court issued its Phase II Findings of Fact and Conclusions of Law (Phase II Findings and Conclusions). The Louisiana District Court found that, for purposes of calculating the maximum possible civil penalty under the CWA, 3.19 million barrels of oil were discharged into the Gulf of Mexico. The United States has appealed the Phase II Findings and Conclusions. The penalty phase of the trial began in January 2015. In March 2014, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented during the penalty phase trial. The parties rested their case in February 2015, post-trial briefing concluded in April 2015, and the matter is pending before the Louisiana District Court. The trial included Anadarko, BP, and the United States. As discussed above, in October 2015, a proposed consent decree was lodged with the Louisiana District Court that sets out a global settlement between (i) BP and (ii) the United States, certain states and local government entities resolving various claims for penalties and fines, including civil claims under the CWA and natural resources damage claims under OPA. Remaining Liability Outlook In addition to the assessment of civil penalties under the CWA discussed above, it is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential penalties and fines and certain other claims not covered by the indemnification provisions of the Settlement Agreement. Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c. The Company will continue to monitor the MDL and other legal proceedings discussed above related to the Deepwater Horizon events. The Company cannot predict the nature of additional evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings. Other Litigation In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. In August 2013, following a determination by an administrative court in a related matter that the amount of tax in dispute was not calculated properly, the Company filed a petition requesting the withdrawal of a portion of the judicial deposit to the extent it exceeds the amount of tax currently in dispute, and any interest on such amount. In April 2015, the Company’s petition was denied. For additional disclosure on this matter, see Note 17—Contingencies—Other Litigation in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 . The Company believes that it will more likely than not prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at September 30, 2015 .

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	13. Income Taxes The following summarizes income tax expense (benefit) and effective tax rates: Three Months Ended Nine Months Ended millions except percentages 2015 2014 2015 2014 Income tax expense (benefit) $ (917 ) $ 627 $ (2,232 ) $ 1,719 Income (loss) before income taxes (3,077 ) 1,774 (7,520 ) 506 Effective tax rate 30 % 35 % 30 % 340 % The Company reported a loss before income taxes for the three and nine months ended September 30, 2015 . As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2015 , was primarily attributable to Algerian exceptional profits taxes and the tax impact from foreign operations. For the three months ended September 30, 2014, the Company’s effective tax rate was the same as the 35% U.S. federal statutory rate. The effective tax rate increase related to the Algerian exceptional profits taxes was offset by the tax impact from foreign operations. The increase from the 35% U.S. federal statutory rate for the nine months ended September 30, 2014 , was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual. At September 30, 2015 , the Company had recorded a $577 million tax benefit related to the Tronox settlement. This benefit was net of a $1.3 billion uncertain tax position due to the uncertainty related to the deductibility of the settlement payment. The Company is a participant in the U.S. Internal Revenue Service’s (IRS) Compliance Assurance Process and has regular discussions with the IRS concerning the Company’s tax positions. Depending on the outcome of such discussions, it is reasonably possible that the amount of the uncertain tax position related to the settlement could change, perhaps materially. See Note 12—Contingencies —Tronox Litigation . At September 30, 2015 , the Company’s Consolidated Balance Sheet included $959 million of income taxes receivable presented in accounts receivable—others.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	9 Months Ended
	Sep. 30, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	14. Supplemental Cash Flow Information For the nine months ended September 30, 2015, the Company’s Consolidated Statement of Cash Flows includes $887 million of taxes related to the Tronox settlement included in (increase) decrease in accounts receivable, offset by an $887 million uncertain tax position included in other items—net. The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities: Nine Months Ended millions 2015 2014 Cash paid (received) Interest, net of amounts capitalized (1) $ 1,916 $ 600 Income taxes, net of refunds (163 ) 661 Non-cash investing activities Fair value of properties and equipment from non-cash transactions $ 156 $ 7 Asset retirement cost additions 139 149 Accruals of property, plant, and equipment 858 1,154 Net liabilities assumed (divested) in acquisitions and divestitures (84 ) (126 ) Non-cash investing and financing activities Floating production, storage, and offloading vessel construction period obligation $ 51 $ 88 __________________________________________________________________ (1) Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2015
Segment Reporting [Abstract]
Segment Information	15. 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 natural gas, oil, condensate, 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, 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, natural-gas, and NGLs production as well as third-party purchased volumes. 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; 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 attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX excludes exploration expense as it is not an indicator 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 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 Nine Months Ended millions 2015 2014 2015 2014 Income (loss) before income taxes $ (3,077 ) $ 1,774 $ (7,520 ) $ 506 Exploration expense 1,074 199 2,260 1,000 DD&A 1,111 1,163 3,581 3,335 Impairments 758 394 3,571 514 Interest expense 199 204 616 573 Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives 360 (276 ) 374 324 Deepwater Horizon settlement and related costs — 3 4 96 Tronox-related contingent loss — 19 5 4,338 Certain other nonoperating items — 22 22 22 Less net income attributable to noncontrolling interests 75 60 154 142 Consolidated Adjusted EBITDAX $ 350 $ 3,442 $ 2,759 $ 10,566 15. 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 September 30, 2015 Sales revenues $ 1,067 $ 195 $ 968 $ — $ 2,230 Intersegment revenues 750 315 (832 ) (233 ) — Gains (losses) on divestitures and other, net (557 ) (22 ) — 37 (542 ) Total revenues and other 1,260 488 136 (196 ) 1,688 Operating costs and expenses (1) 840 287 181 (14 ) 1,294 Net cash from settlement of commodity derivatives — — — (79 ) (79 ) Other (income) expense, net (2) — — — 47 47 Net income attributable to noncontrolling interests — 75 — — 75 Total expenses and other 840 362 181 (46 ) 1,337 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — (1 ) — (1 ) Adjusted EBITDAX $ 420 $ 126 $ (46 ) $ (150 ) $ 350 Three Months Ended September 30, 2014 Sales revenues $ 2,192 $ 119 $ 1,919 $ — $ 4,230 Intersegment revenues 1,604 364 (1,774 ) (194 ) — Gains (losses) on divestitures and other, net 724 1 — 55 780 Total revenues and other 4,520 484 145 (139 ) 5,010 Operating costs and expenses (1) 1,090 249 188 26 1,553 Net cash from settlement of commodity derivatives — — — (48 ) (48 ) Other (income) expense, net (2) — — — 2 2 Net income attributable to noncontrolling interests — 60 — — 60 Total expenses and other 1,090 309 188 (20 ) 1,567 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — (1 ) — (1 ) Adjusted EBITDAX $ 3,430 $ 175 $ (44 ) $ (119 ) $ 3,442 __________________________________________________________________ (1) Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. (2) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX. 15. Segment Information (Continued) millions Oil and Gas Exploration & Production Midstream Marketing Other and Intersegment Eliminations Total Nine Months Ended September 30, 2015 Sales revenues $ 3,493 $ 560 $ 3,399 $ — $ 7,452 Intersegment revenues 2,752 920 (2,977 ) (695 ) — Gains (losses) on divestitures and other, net (990 ) (19 ) — 202 (807 ) Total revenues and other 5,255 1,461 422 (493 ) 6,645 Operating costs and expenses (1) 2,674 761 571 (110 ) 3,896 Net cash from settlement of commodity derivatives — — — (251 ) (251 ) Other (income) expense, net (2) — — — 87 87 Net income attributable to noncontrolling interests — 154 — — 154 Total expenses and other 2,674 915 571 (274 ) 3,886 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — — — — Adjusted EBITDAX $ 2,581 $ 546 $ (149 ) $ (219 ) $ 2,759 Nine Months Ended September 30, 2014 Sales revenues $ 6,804 $ 358 $ 5,791 $ — $ 12,953 Intersegment revenues 4,947 1,010 (5,369 ) (588 ) — Gains (losses) on divestitures and other, net 2,194 (2 ) — 148 2,340 Total revenues and other 13,945 1,366 422 (440 ) 15,293 Operating costs and expenses (1) 3,128 732 555 51 4,466 Net cash from settlement of commodity derivatives — — — 132 132 Other (income) expense, net (2) — — — (10 ) (10 ) Net income attributable to noncontrolling interests — 142 — — 142 Total expenses and other 3,128 874 555 173 4,730 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 3 — 3 Adjusted EBITDAX $ 10,817 $ 492 $ (130 ) $ (613 ) $ 10,566 __________________________________________________________________ (1) Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. (2) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

Pension Plans and Other Postret

Pension Plans and Other Postretirement Benefits	9 Months Ended
	Sep. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Pension Plans and Other Postretirement Benefits	16. 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 2015 2014 2015 2014 Three Months Ended September 30 Service cost $ 30 $ 25 $ 3 $ 1 Interest cost 25 25 3 4 Expected return on plan assets (27 ) (27 ) — — Amortization of net actuarial loss (gain) 13 9 — (2 ) Amortization of net prior service cost (credit) — — 1 — Net periodic benefit cost $ 41 $ 32 $ 7 $ 3 Nine Months Ended September 30 Service cost $ 89 $ 74 $ 8 $ 5 Interest cost 76 75 11 11 Expected return on plan assets (82 ) (80 ) — — Amortization of net actuarial loss (gain) 39 26 — (5 ) Amortization of net prior service cost (credit) — — 2 — Net periodic benefit cost $ 122 $ 95 $ 21 $ 11

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; asset retirement obligations; litigation liabilities; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
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 will simplify the presentation of debt issuance costs by requiring such 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. These ASUs are effective for annual and interim periods beginning in 2016 and are required to be adopted using a retrospective approach, with early adoption permitted. The Company does not expect the adoption to have a material impact on its consolidated financial statements. The FASB issued ASU 2015-02, Consolidation—Amendments to the Consolidation Analysis . This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. 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 . This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition , and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition , and 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 effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers—Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using one of two retrospective application methods, with early adoption permitted in 2017. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

Inventories (Tables)

Inventories (Tables)	9 Months Ended
	Sep. 30, 2015
Energy Related Inventory [Abstract]
Inventory Disclosure Table	The following summarizes the major classes of inventories included in other current assets: millions September 30, December 31, Oil $ 108 $ 133 Natural gas 37 27 NGLs 57 83 Total inventories $ 202 $ 243

Impairments (Tables)

Impairments (Tables)	9 Months Ended
	Sep. 30, 2015
Asset Impairment Charges [Abstract]
Schedule of Impairment Expense	The following summarizes impairments of proved properties and the related post-impairment fair values by segment: Three Months Ended Nine Months Ended millions Impairment Fair Value (1) Impairment Fair Value (1) September 30, 2015 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ 641 $ 634 $ 2,944 $ 1,904 Gulf of Mexico properties 101 94 126 94 Cost-method investment (2) 1 32 2 32 Midstream Long-lived assets held for use 15 7 499 209 Total $ 758 $ 767 $ 3,571 $ 2,239 September 30, 2014 Oil and gas exploration and production Long-lived assets held for use U.S. onshore properties $ 387 $ 385 $ 387 $ 385 Gulf of Mexico properties — — 115 327 Cost-method investment (2) — — 2 32 Midstream Long-lived assets held for use 7 — 10 — Total $ 394 $ 385 $ 514 $ 744 __________________________________________________________________ (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)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, 2015 : 2015 Settlement 2016 Settlement Natural Gas Three-Way Collars (thousand MMBtu/d) 635 — Average price per MMBtu Ceiling sold price (call) $ 4.76 $ — Floor purchased price (put) $ 3.75 $ — Floor sold price (put) $ 2.75 $ — Fixed-Price Contracts (thousand MMBtu/d) — 34 Average price per MMBtu $ — $ 3.18 Extendable Fixed-Price Contracts (thousand MMBtu/d) (1) 170 — Average price per MMBtu $ 4.17 $ — Oil Three-Way Collars (MBbls/d) — 28 Average price per barrel Ceiling sold price (call) $ — $ 69.29 Floor purchased price (put) $ — $ 61.43 Floor sold price (put) $ — $ 46.43 NGLs Fixed-Price Contracts (MBbls/d) 7 3 Average price per barrel $ 14.09 $ 14.87 __________________________________________________________________ (1) The extendable fixed-price contracts have a contract term of January 2015 to December 2015 with an option for the counterparty to extend the contract term to December 2016 at the same price. MMBtu—million British thermal units MMBtu/d—million British thermal units per day MBbls/d—thousand barrels per day The Company had the following outstanding interest-rate swaps at September 30, 2015 : 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% $ 250 September 2016 – 2046 September 2018 6.310% $ 300 September 2016 – 2046 September 2020 6.509% $ 250 September 2016 – 2046 September 2021 6.724% $ 200 September 2017 – 2047 September 2018 6.049% $ 300 September 2017 – 2047 September 2020 6.569% $ 500 September 2017 – 2047 September 2021 6.654%
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	The following summarizes the fair value of the Company’s derivative instruments: Gross Derivative Assets Gross Derivative Liabilities millions September 30, December 31, September 30, December 31, Balance Sheet Classification 2015 2014 2015 2014 Commodity derivatives Other current assets $ 246 $ 421 $ (74 ) $ (118 ) Other assets 42 1 (16 ) — Accrued expenses 27 71 (43 ) (114 ) Other liabilities — — — (6 ) 315 493 (133 ) (238 ) Interest-rate derivatives Other liabilities — — (1,462 ) (1,217 ) Total derivatives $ 315 $ 493 $ (1,651 ) $ (1,455 ) The following summarizes gains and losses related to derivative instruments: millions Three Months Ended Nine Months Ended Classification of (Gain) Loss Recognized 2015 2014 2015 2014 Commodity derivatives Gathering, processing, and marketing sales (1) $ (1 ) $ (1 ) $ — $ 9 (Gains) losses on derivatives, net (125 ) (419 ) (177 ) (40 ) Interest-rate derivatives (Gains) losses on derivatives, net 407 96 300 493 Total (gains) losses on derivatives, net $ 281 $ (324 ) $ 123 $ 462 __________________________________________________________________ (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 September 30, 2015 Level 1 Level 2 Level 3 Netting (1) Collateral Total Assets Commodity derivatives Financial institutions $ 4 $ 288 $ — $ (115 ) $ (6 ) $ 171 Other counterparties — 23 — (3 ) — 20 Total derivative assets $ 4 $ 311 $ — $ (118 ) $ (6 ) $ 191 Liabilities Commodity derivatives Financial institutions $ — $ (126 ) $ — $ 115 $ — $ (11 ) Other counterparties — (7 ) — 3 — (4 ) Interest-rate derivatives — (1,518 ) — — 67 (1,451 ) Total derivative liabilities $ — $ (1,651 ) $ — $ 118 $ 67 $ (1,466 ) December 31, 2014 Assets Commodity derivatives Financial institutions $ — $ 471 $ — $ (187 ) $ (13 ) $ 271 Other counterparties — 22 — (2 ) — 20 Total derivative assets $ — $ 493 $ — $ (189 ) $ (13 ) $ 291 Liabilities Commodity derivatives Financial institutions $ — $ (234 ) $ — $ 187 $ — $ (47 ) Other counterparties — (4 ) — 2 — (2 ) Interest-rate derivatives — (1,217 ) — — 23 (1,194 ) Total derivative liabilities $ — $ (1,455 ) $ — $ 189 $ 23 $ (1,243 ) __________________________________________________________________ (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 (Tables)

Tangible Equity Units (Tables)	9 Months Ended
	Sep. 30, 2015
Tangible Equity Units [Abstract]
Schedule Of Proceeds From Tangible Equity Units	Anadarko allocated the proceeds from the issuance of the TEUs to equity and debt based on the relative fair values of their respective components as follows: millions, except price per TEU Equity Component Debt Component Total Price per TEU $ 39.05 $ 10.95 $ 50.00 Gross proceeds 359 101 460 Less issuance costs 11 4 15 Net proceeds $ 348 $ 97 $ 445
Tangible Equity Units Equity Component Settlement Rate Scenarios	The Company will deliver WGP common units (or APC shares) on the settlement date at the settlement rate based upon the applicable market value of WGP common units (or APC shares) as follows: Settlement Rate per Purchase Contract Applicable Market Value of WGP Common Units (1) WGP Common Units APC Shares (if elected) (1) Exceeds $69.8422 (Threshold Appreciation Price) 0.7159 units (Minimum Settlement Rate) a number of shares equal to (a) the Minimum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares Less than or equal to the Threshold Appreciation Price, but greater than or equal to $58.20 (Reference Price) a number of units equal to $50.00, divided by the applicable market value of WGP common units a number of shares equal to $50.00, divided by 98% of the applicable market value of APC shares Less than the Reference Price 0.8591 units (Maximum Settlement Rate) a number of shares equal to (a) the Maximum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares __________________________________________________________________ (1) The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC shares) for the 20 consecutive trading days beginning on, and including, the 23 rd scheduled trading day immediately preceding June 7, 2018.

Debt and Interest Expense (Tabl

Debt and Interest Expense (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Debt Outstanding and Debt Activity Tables	The following summarizes the Company’s outstanding debt: millions September 30, December 31, Total debt at face value $ 17,497 $ 16,687 Net unamortized discounts and premiums (1) (1,593 ) (1,616 ) Total borrowings $ 15,904 $ 15,071 Capital lease obligation 21 21 Less short-term debt 33 — Total long-term debt (2) $ 15,892 $ 15,092 __________________________________________________________________ (1) Unamortized discounts and premiums are amortized over the term of the related debt. (2) Includes WES debt of $2.7 billion at June 30, 2015, and $2.4 billion at December 31, 2014. The following summarizes the Company’s debt activity during the nine months ended September 30, 2015 : Carrying millions Value Description Balance at December 31, 2014 $ 15,071 Issuances 494 WES 3.950% Senior Notes due 2025 101 Tangible equity units - senior amortizing notes Borrowings 1,500 $5.0 billion revolving credit facility 1,800 364-Day Facility 280 WES revolving credit facility 547 Commercial paper notes, net (1) Repayments (1,500 ) $5.0 billion revolving credit facility (1,800 ) 364-Day Facility (610 ) WES revolving credit facility (8 ) Tangible equity units - senior amortizing notes Other, net 29 Amortization of debt discounts and premiums Balance at September 30, 2015 $ 15,904 __________________________________________________________________ (1) Includes repayments of $106 million related to commercial paper notes with maturities greater than 90 days.
Interest Expense Table	The following summarizes interest expense: Three Months Ended Nine Months Ended millions 2015 2014 2015 2014 Debt and other $ 245 $ 250 $ 743 $ 723 Capitalized interest (46 ) (46 ) (127 ) (150 ) Total interest expense $ 199 $ 204 $ 616 $ 573

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	9 Months Ended
	Sep. 30, 2015
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 Nine Months Ended millions except per-share amounts 2015 2014 2015 2014 Net income (loss) Net income (loss) attributable to common stockholders $ (2,235 ) $ 1,087 $ (5,442 ) $ (1,355 ) Less noncontrolling interest effect of TEUs 3 — 3 — Less distributions on participating securities 1 2 4 3 Less undistributed income allocated to participating securities — 6 — — Basic $ (2,239 ) $ 1,079 $ (5,449 ) $ (1,358 ) Diluted $ (2,239 ) $ 1,079 $ (5,449 ) $ (1,358 ) Shares Average number of common shares outstanding—basic 508 506 508 505 Dilutive effect of stock options — 2 — — Average number of common shares outstanding—diluted 508 508 508 505 Excluded due to anti-dilutive effect 10 3 11 11 Net income (loss) per common share Basic $ (4.41 ) $ 2.13 $ (10.73 ) $ (2.69 ) Diluted $ (4.41 ) $ 2.12 $ (10.73 ) $ (2.69 )

Accumulated Other Comprehensi31

Accumulated Other Comprehensive Income (Loss) (Tables)	9 Months Ended
	Sep. 30, 2015
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, 2014 $ (48 ) $ (469 ) $ (517 ) Reclassifications to Consolidated Statement of Income 4 26 30 Balance at September 30, 2015 $ (44 ) $ (443 ) $ (487 )

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Schedule of Income Taxes and Effective Tax Rate	The following summarizes income tax expense (benefit) and effective tax rates: Three Months Ended Nine Months Ended millions except percentages 2015 2014 2015 2014 Income tax expense (benefit) $ (917 ) $ 627 $ (2,232 ) $ 1,719 Income (loss) before income taxes (3,077 ) 1,774 (7,520 ) 506 Effective tax rate 30 % 35 % 30 % 340 %

Supplemental Cash Flow Inform33

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Table	The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities: Nine Months Ended millions 2015 2014 Cash paid (received) Interest, net of amounts capitalized (1) $ 1,916 $ 600 Income taxes, net of refunds (163 ) 661 Non-cash investing activities Fair value of properties and equipment from non-cash transactions $ 156 $ 7 Asset retirement cost additions 139 149 Accruals of property, plant, and equipment 858 1,154 Net liabilities assumed (divested) in acquisitions and divestitures (84 ) (126 ) Non-cash investing and financing activities Floating production, storage, and offloading vessel construction period obligation $ 51 $ 88 __________________________________________________________________ (1) Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2015
Segment Reporting [Abstract]
Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) Before Income Taxes	Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes: Three Months Ended Nine Months Ended millions 2015 2014 2015 2014 Income (loss) before income taxes $ (3,077 ) $ 1,774 $ (7,520 ) $ 506 Exploration expense 1,074 199 2,260 1,000 DD&A 1,111 1,163 3,581 3,335 Impairments 758 394 3,571 514 Interest expense 199 204 616 573 Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives 360 (276 ) 374 324 Deepwater Horizon settlement and related costs — 3 4 96 Tronox-related contingent loss — 19 5 4,338 Certain other nonoperating items — 22 22 22 Less net income attributable to noncontrolling interests 75 60 154 142 Consolidated Adjusted EBITDAX $ 350 $ 3,442 $ 2,759 $ 10,566
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 September 30, 2015 Sales revenues $ 1,067 $ 195 $ 968 $ — $ 2,230 Intersegment revenues 750 315 (832 ) (233 ) — Gains (losses) on divestitures and other, net (557 ) (22 ) — 37 (542 ) Total revenues and other 1,260 488 136 (196 ) 1,688 Operating costs and expenses (1) 840 287 181 (14 ) 1,294 Net cash from settlement of commodity derivatives — — — (79 ) (79 ) Other (income) expense, net (2) — — — 47 47 Net income attributable to noncontrolling interests — 75 — — 75 Total expenses and other 840 362 181 (46 ) 1,337 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — (1 ) — (1 ) Adjusted EBITDAX $ 420 $ 126 $ (46 ) $ (150 ) $ 350 Three Months Ended September 30, 2014 Sales revenues $ 2,192 $ 119 $ 1,919 $ — $ 4,230 Intersegment revenues 1,604 364 (1,774 ) (194 ) — Gains (losses) on divestitures and other, net 724 1 — 55 780 Total revenues and other 4,520 484 145 (139 ) 5,010 Operating costs and expenses (1) 1,090 249 188 26 1,553 Net cash from settlement of commodity derivatives — — — (48 ) (48 ) Other (income) expense, net (2) — — — 2 2 Net income attributable to noncontrolling interests — 60 — — 60 Total expenses and other 1,090 309 188 (20 ) 1,567 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — (1 ) — (1 ) Adjusted EBITDAX $ 3,430 $ 175 $ (44 ) $ (119 ) $ 3,442 __________________________________________________________________ (1) Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. (2) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX. 15. Segment Information (Continued) millions Oil and Gas Exploration & Production Midstream Marketing Other and Intersegment Eliminations Total Nine Months Ended September 30, 2015 Sales revenues $ 3,493 $ 560 $ 3,399 $ — $ 7,452 Intersegment revenues 2,752 920 (2,977 ) (695 ) — Gains (losses) on divestitures and other, net (990 ) (19 ) — 202 (807 ) Total revenues and other 5,255 1,461 422 (493 ) 6,645 Operating costs and expenses (1) 2,674 761 571 (110 ) 3,896 Net cash from settlement of commodity derivatives — — — (251 ) (251 ) Other (income) expense, net (2) — — — 87 87 Net income attributable to noncontrolling interests — 154 — — 154 Total expenses and other 2,674 915 571 (274 ) 3,886 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — — — — Adjusted EBITDAX $ 2,581 $ 546 $ (149 ) $ (219 ) $ 2,759 Nine Months Ended September 30, 2014 Sales revenues $ 6,804 $ 358 $ 5,791 $ — $ 12,953 Intersegment revenues 4,947 1,010 (5,369 ) (588 ) — Gains (losses) on divestitures and other, net 2,194 (2 ) — 148 2,340 Total revenues and other 13,945 1,366 422 (440 ) 15,293 Operating costs and expenses (1) 3,128 732 555 51 4,466 Net cash from settlement of commodity derivatives — — — 132 132 Other (income) expense, net (2) — — — (10 ) (10 ) Net income attributable to noncontrolling interests — 142 — — 142 Total expenses and other 3,128 874 555 173 4,730 Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement — — 3 — 3 Adjusted EBITDAX $ 10,817 $ 492 $ (130 ) $ (613 ) $ 10,566 __________________________________________________________________ (1) Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX. (2) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

Pension Plans and Other Postr35

Pension Plans and Other Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2015
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 2015 2014 2015 2014 Three Months Ended September 30 Service cost $ 30 $ 25 $ 3 $ 1 Interest cost 25 25 3 4 Expected return on plan assets (27 ) (27 ) — — Amortization of net actuarial loss (gain) 13 9 — (2 ) Amortization of net prior service cost (credit) — — 1 — Net periodic benefit cost $ 41 $ 32 $ 7 $ 3 Nine Months Ended September 30 Service cost $ 89 $ 74 $ 8 $ 5 Interest cost 76 75 11 11 Expected return on plan assets (82 ) (80 ) — — Amortization of net actuarial loss (gain) 39 26 — (5 ) Amortization of net prior service cost (credit) — — 2 — Net periodic benefit cost $ 122 $ 95 $ 21 $ 11

Acquisitions, Divestitures, a36

Acquisitions, Divestitures, and Assets Held for Sale (Detail) - USD ($) $ in Millions	Nov. 25, 2014	Jul. 31, 2015	Apr. 30, 2015	Dec. 31, 2015	Sep. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures						$ 1,248	$ 4,770
(Gains) losses on divestitures, net						$ 1,003	$ (2,194)
Held-for-sale [Member]
Property, Plant, and Equipment [Line Items]
Assets associated with assets held for sale
Liabilities associated with assets held for sale
Oil and Gas Exploration and Production Reporting Segment [Member] | Assets Disposed of by Sale [Member] | Certain Coalbed Methane Assets in the Rockies [Member]
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures					$ 107
(Gains) losses on divestitures, net					440
Oil and Gas Exploration and Production Reporting Segment [Member] | Assets Disposed of by Sale [Member] | Certain Enhanced Oil Recovery Assets in the Rockies [Member]
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures			$ 686
(Gains) losses on divestitures, net						$ 344
Original sales price			$ 703
Oil and Gas Exploration and Production Reporting Segment and Midstream Reporting Segment [Member] | Assets Disposed of by Sale [Member] | Certain U.S. Onshore East Texas Assets [Member]
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures		$ 426
(Gains) losses on divestitures, net						$ 110
Original sales price		$ 440
Midstream Reporting Segment [Member] | Held-for-sale [Member] | Certain Coalbed Methane Assets in the Rockies [Member] | Subsequent Event [Member]
Property, Plant, and Equipment [Line Items]
Original sales price				$ 80
Midstream Reporting Segment [Member] | Held-for-sale [Member] | Certain Coalbed Methane Assets in the Rockies [Member] | Nonrecurring [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 2 [Member]
Property, Plant, and Equipment [Line Items]
Loss on assets held for sale					$ 100
Gathering and Processing Assets in the Delaware Basin [Member]
Property, Plant, and Equipment [Line Items]
Purchase price	$ 1,554
Changes to the fair value of assets acquired and liabilities assumed

Inventories (Detail)

Inventories (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Energy Related Inventory [Abstract]
Oil	$ 108	$ 133
Natural gas	37	27
NGLs	57	83
Total inventories	$ 202	$ 243

Impairments - Impairments and F

Impairments - Impairments and Fair Values by Segment Table (Detail) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Impaired Long Lived Assets Held and Used [Line Items]
Total impairments		$ 758	$ 394	$ 3,571	$ 514
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]	2,239	744	2,239	744
Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 3rd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Total fair value	[1]	767	385	767	385
Oil and Gas Exploration and Production Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of cost-method investment		1	0	2	2
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 3rd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of cost-method investment	[1],[2]	32	0	32	0
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		641	387	2,944	387
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]	1,904	385	1,904	385
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 3rd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	634	385	634	385
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		101	0	126	115
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]	94	327	94	327
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 3rd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	94	0	94	0
Midstream Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Impairment of long-lived assets held for use		15	7	499	10
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]	209	0	209	0
Midstream Reporting Segment [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Assets Impaired During 3rd Quarter [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Fair value of long-lived assets held for use	[1]	$ 7	$ 0	$ 7	$ 0
[1]	Measured as of the impairment date using the income approach and Level 3 inputs.
[2]	Represents the after-tax net investment.

Impairments - Impairments of Un

Impairments - Impairments of Unproved Properties (Detail) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties		$ 1,993	$ 743
U.S. Onshore Properties [Member] | Unproved Utica Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties	$ 109
U.S. Onshore Properties [Member] | Unproved Greater Natural Buttes Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties		$ 935

Suspended Exploratory Well Co40

Suspended Exploratory Well Costs (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Capitalized Exploratory Well Costs [Abstract]
Suspended exploratory well costs	$ 1,100	$ 1,500
Suspended exploratory well costs previously capitalized for greater than one year at December 31, 2014, charged to dry hole expense	$ 602

Derivative Instruments - Oil an

Derivative Instruments - Oil and Natural-Gas Production/Processing Derivative Activities Table (Detail) - Not Designated as Hedging Instrument [Member] - Price Risk Derivative [Member]	9 Months Ended
	Sep. 30, 2015MMBTU / dMBbls / d$ / bbl$ / MMBTU
Three-Way Collars Natural Gas 2015 [Member]
Derivative [Line Items]
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	635,000
Three-Way Collars Natural Gas 2015 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price | $ / MMBTU	4.76
Three-Way Collars Natural Gas 2015 [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average floor price | $ / MMBTU	2.75
Three-Way Collars Natural Gas 2015 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price | $ / MMBTU	3.75
Forward Contracts Natural Gas 2016 [Member]
Derivative [Line Items]
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	34,000
Average price per MMBtu or barrel
Average price per MMBtu or barrel | $ / MMBTU	3.18
Extendable Fixed Price Contracts Natural Gas 2015 [Member]
Derivative [Line Items]
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d	170,000	[1]
Average price per MMBtu or barrel
Average price per MMBtu or barrel | $ / MMBTU	4.17
Three Way Collars Oil 2016 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	28
Three Way Collars Oil 2016 [Member] | Call Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average ceiling price	69.29
Three Way Collars Oil 2016 [Member] | Put Option [Member] | Short [Member]
Average price per MMBtu or barrel
Average floor price	46.43
Three Way Collars Oil 2016 [Member] | Put Option [Member] | Long [Member]
Average price per MMBtu or barrel
Average floor price	61.43
Forward Contracts NGLs 2015 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	7
Average price per MMBtu or barrel
Average price per MMBtu or barrel	14.09
Forward Contracts NGLs 2016 [Member]
Derivative [Line Items]
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d	3
Average price per MMBtu or barrel
Average price per MMBtu or barrel	14.87
[1]	The extendable fixed-price contracts have a contract term of January 2015 to December 2015 with an option for the counterparty to extend the contract term to December 2016 at the same price.

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) Mcf in Millions, $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)Mcf	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)Mcf
Derivative [Line Items]
(Gains) losses on derivatives, net	$ 281	$ (324)	$ 123	$ 462
Interest-Rate Derivatives [Member] | (Gains) Losses on Derivatives, Net [Member]
Derivative [Line Items]
(Gains) losses on derivatives, net	407	$ 96	300	$ 493
Interest-Rate Derivatives [Member] | Interest Rate Swaps 3 Through 8 [Member] | Modified Interest-Rate Swaps for Mandatory Termination Dates [Member] | (Gains) Losses on Derivatives, Net [Member]
Derivative [Line Items]
(Gains) losses on derivatives, net	137
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross derivative liabilities	1,651		1,651		$ 1,455
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		97
Not Designated as Hedging Instrument [Member] | Permitted to Offset Gross Derivative Asset with Financial Institutions [Member]
Derivative [Line Items]
Gross derivative liabilities	243		243		289
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member]
Derivative [Line Items]
Gross derivative liabilities	1,518		1,518		1,217
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Other Liabilities [Member]
Derivative [Line Items]
Gross derivative liabilities	1,462		1,462		$ 1,217
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Interest Rate Swaps 6 Through 8 [Member] | Modified Interest-Rate Swaps for Reference-Period Start Date Extensions [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	1,000		1,000
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Interest Rate Swaps 3 Through 8 [Member] | Modified Interest-Rate Swaps for Mandatory Termination Dates [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	1,800		1,800
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Interest Rate Swaps 3 Through 8 [Member] | Modified Interest-Rate Swaps for Mandatory Termination Dates [Member] | Other Liabilities [Member]
Derivative [Line Items]
Gross derivative liabilities	$ 137		$ 137
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | Commodity [Member]
Derivative [Line Items]
Financial derivative transactions | Mcf			8		6

Derivative Instruments - Intere

Derivative Instruments - Interest-Rate Derivatives Table (Detail) - Not Designated as Hedging Instrument [Member] - Interest-Rate Derivatives [Member] $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
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	$ 250
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 15, 2018
Weighted-average interest rate for interest-rate swap	6.31%
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	$ 250
Reference period start date for interest-rate swap	Sep. 15, 2016
Reference period end date for interest-rate swap	Sep. 15, 2046
Mandatory termination date for interest-rate swap	Sep. 15, 2021
Weighted-average interest rate for interest-rate swap	6.724%
Interest-Rate Swap 6 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 200
Reference period start date for interest-rate swap	Sep. 15, 2017
Reference period end date for interest-rate swap	Sep. 15, 2047
Mandatory termination date for interest-rate swap	Sep. 15, 2018
Weighted-average interest rate for interest-rate swap	6.049%
Interest-Rate Swap 7 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 300
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	6.569%
Interest-Rate Swap 8 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	$ 500
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	6.654%

Derivative Instruments - Effect

Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross derivative assets	$ 315	$ 493
Gross derivative liabilities	(1,651)	(1,455)
Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	315	493
Gross derivative liabilities	(133)	(238)
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	246	421
Gross derivative liabilities	(74)	(118)
Commodity Derivatives [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	42	1
Gross derivative liabilities	(16)	0
Commodity Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	27	71
Gross derivative liabilities	(43)	(114)
Commodity Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	0	(6)
Interest-Rate Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	(1,518)	(1,217)
Interest-Rate Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	(56)	0
Interest-Rate Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	$ (1,462)	$ (1,217)

Derivative Instruments - Effe45

Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ 281	$ (324)	$ 123	$ 462
Commodity Derivatives [Member] | Gathering, Processing, and Marketing Sales [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	[1]	(1)	(1)	0	9
Commodity Derivatives [Member] | (Gains) Losses on Derivatives, Net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		(125)	(419)	(177)	(40)
Interest-Rate Derivatives [Member] | (Gains) Losses on Derivatives, Net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net		$ 407	$ 96	$ 300	$ 493
[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		Sep. 30, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		$ 315	$ 493
Gross derivative liabilities		(1,651)	(1,455)
Derivative assets netting	[1]	(118)	(189)
Derivative liabilities netting	[1]	118	189
Cash collateral from counterparties		(6)	(13)
Cash collateral held by counterparties		67	23
Derivative assets		191	291
Derivative liabilities		(1,466)	(1,243)
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		315	493
Gross derivative liabilities		(133)	(238)
Commodity Derivatives [Member] | Financial Institutions [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	[1]	(115)	(187)
Derivative liabilities netting	[1]	115	187
Cash collateral from counterparties		(6)	(13)
Cash collateral held by counterparties		0	0
Derivative assets		171	271
Derivative liabilities		(11)	(47)
Commodity Derivatives [Member] | Other Counterparties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	[1]	(3)	(2)
Derivative liabilities netting	[1]	3	2
Cash collateral from counterparties		0	0
Cash collateral held by counterparties		0	0
Derivative assets		20	20
Derivative liabilities		(4)	(2)
Interest-Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		0	0
Gross derivative liabilities		(1,518)	(1,217)
Derivative liabilities netting	[1]	0	0
Cash collateral held by counterparties		67	23
Derivative liabilities		(1,451)	(1,194)
Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		4	0
Gross derivative liabilities		0	0
Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		311	493
Gross derivative liabilities		(1,651)	(1,455)
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] | Financial Institutions [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		4	0
Gross derivative liabilities		0	0
Recurring [Member] | Commodity Derivatives [Member] | Financial Institutions [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		288	471
Gross derivative liabilities		(126)	(234)
Recurring [Member] | Commodity Derivatives [Member] | Financial Institutions [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] | Other Counterparties [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] | Commodity Derivatives [Member] | Other Counterparties [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets		23	22
Gross derivative liabilities		(7)	(4)
Recurring [Member] | Commodity Derivatives [Member] | Other Counterparties [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 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 liabilities		(1,518)	(1,217)
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 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 - Additio

Tangible Equity Units - Additional Information (Detail) - 7.50% Tangible Equity Units [Member] shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)shares / unit$ / unitshares
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
Purchase contract, mandatory settlement date	Jun. 7, 2018
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
Debt instrument, maturity date	Jun. 7, 2018
Settled In APC Shares [Member]
Tangible Equity Units [Line Items]
APC share cap | shares / unit	4

Tangible Equity Units - Proceed

Tangible Equity Units - Proceeds from Tangible Equity Units (Detail) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)$ / shares$ / unit	Sep. 30, 2014USD ($)
Tangible Equity Units [Line Items]
Net proceeds, debt component	$ 4,810	$ 2,370
7.50% Tangible Equity Units [Member]
Tangible Equity Units [Line Items]
Price per TEU, equity component | $ / shares	$ 39.05
Gross proceeds, equity component	$ 359
Issuance costs, equity component	11
Net proceeds, equity component	$ 348	$ 0
Price per TEU, debt component | $ / unit	10.95
Gross proceeds, debt component	$ 101
Issuance costs, debt component	4
Net proceeds, debt component	$ 97
Total price per TEU | $ / unit	50
Total gross proceeds	$ 460
Total issuance costs	15
Total net proceeds	$ 445

Tangible Equity Units - Settlem

Tangible Equity Units - Settlement Rate Scenarios for Equity Component (Detail) - 7.50% Tangible Equity Units [Member]	Sep. 30, 2015$ / shares
Threshold Appreciation Price [Member]
Tangible Equity Units [Line Items]
Equity component applicable market value	$ 69.8422
Reference Price [Member]
Tangible Equity Units [Line Items]
Equity component applicable market value	$ 58.20
Exceeds Threshold Appreciation Price [Member] | Settled In WGP Shares [Member]
Tangible Equity Units [Line Items]
Minimum settlement rate	0.7159
Less Than Reference Price [Member] | Settled In WGP Shares [Member]
Tangible Equity Units [Line Items]
Maximum settlement rate	0.8591

Debt and Interest Expense - Out

Debt and Interest Expense - Outstanding Debt Table (Detail) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Total debt at face value		$ 17,497	$ 16,687
Net unamortized discounts and premiums (1)	[1]	(1,593)	(1,616)
Total borrowings		15,904	15,071
Capital lease obligation		21	21
Less short-term debt		33	0
Debt Instrument [Line Items]
Total long-term debt (2)	[2]	15,892	15,092
Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Total long-term debt (2)		$ 2,600	$ 2,400
[1]	Unamortized discounts and premiums are amortized over the term of the related debt.
[2]	Includes WES debt of $2.6 billion at September 30, 2015, and $2.4 billion at December 31, 2014.

Debt and Interest Expense - Add

Debt and Interest Expense - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2015	Jan. 23, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Debt instrument, principal amount	$ 17,497,000,000		$ 16,687,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	3,000,000,000
Commercial paper, outstanding borrowings	$ 547,000,000
Commercial paper, weighted-average interest rate	0.51%
Amount of current debt outstanding classified as long-term debt on the Company's Consolidated Balance Sheet	$ 547,000,000
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		$ 17,400,000,000
5.950% Senior Notes Due 2016 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	$ 1,750,000,000
Debt instrument, stated interest rate	5.95%
Debt instrument, maturity date	Sep. 15, 2016
Amount of current debt outstanding classified as long-term debt on the Company's Consolidated Balance Sheet	$ 1,750,000,000
Five-Year Credit Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	$ 3,000,000,000
Debt instrument, term	5 years
Line of credit, expandable maximum capacity	$ 4,000,000,000
Line of credit, outstanding borrowings	$ 0
Five-Year Credit Facility [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin added	0.00%
Five-Year Credit Facility [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin added	1.65%
Ratio of indebtedness to total capital	0.65
Zero-Coupon Senior Notes [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Oct. 10, 2036
Debt Instrument, earliest call date	Oct. 10, 2015
Zero-Coupon Senior Notes [Member] | Senior Notes [Member] | Accreted Value at Next Potential Put Date [Member]
Debt Instrument [Line Items]
Debt instrument, accreted value	$ 796,000,000
$5.0 billion Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity		$ 5,000,000,000
364-Day Credit Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	$ 2,000,000,000
Debt instrument, term	364 days
Line of credit, outstanding borrowings	$ 0
364-Day Credit Facility [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin added	0.00%
364-Day Credit Facility [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin added	1.675%
Ratio of indebtedness to total capital	0.65
WES 3.950% Senior Notes Due 2025 [Member] | Senior Notes [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount	$ 500,000,000
Debt instrument, stated interest rate	3.95%
Debt instrument, maturity date	May 15, 2025
WES RCF [Member] | Revolving Credit Facility [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	$ 1,200,000,000
Line of credit, expandable maximum capacity	1,500,000,000
Line of credit, outstanding borrowings	$ 180,000,000
Line of credit, expiration date	Feb. 26, 2019
Line of credit, interest rate	1.50%
Letters of credit, outstanding	$ 13,000,000
Line of credit, available borrowing capacity	$ 1,000,000,000

Debt and Interest Expense - Deb

Debt and Interest Expense - Debt Activity Table (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Debt Disclosure [Abstract]
Balance at December 31, 2014	$ 15,071
Debt Instrument [Line Items]
Other, net	29
Balance at September 30, 2015	15,904
Commercial Paper [Member]
Debt Instrument [Line Items]
Borrowings, commercial paper	547
Commercial Paper [Member] | Maturities Greater Than 90 Days [Member]
Debt Instrument [Line Items]
Repayments, commercial paper	$ (106)
7.50% Tangible Equity Units [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	1.50%
Debt instrument, maturity date	Jun. 7, 2018
$5.0 billion Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	$ 1,500
Repayments, credit facility	(1,500)
364-Day Credit Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	1,800
Repayments, credit facility	(1,800)
WES RCF [Member] | Western Gas Partners, LP [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings, credit facility	280
Repayments, credit facility	(610)
Senior Notes [Member] | 7.50% Tangible Equity Units [Member]
Debt Instrument [Line Items]
Issuances	101
Repayments, senior notes	$ (8)
Senior Notes [Member] | WES 3.950% Senior Notes Due 2025 [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	3.95%
Issuances	$ 494
Debt instrument, maturity date	May 15, 2025

Debt and Interest Expense - Int

Debt and Interest Expense - Interest Expense Table (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Debt Disclosure [Abstract]
Debt and other	$ 245	$ 250	$ 743	$ 723
Capitalized interest	(46)	(46)	(127)	(150)
Total interest expense	$ 199	$ 204	$ 616	$ 573

Stockholders' Equity (Detail)

Stockholders' Equity (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Net income (loss)
Net income (loss) attributable to common stockholders	$ (2,235)	$ 1,087	$ (5,442)	$ (1,355)
Less noncontrolling interest effect of TEUs	75	60	154	142
Less distributions on participating securities	1	2	4	3
Less undistributed income allocated to participating securities	0	6	0	0
Basic	(2,239)	1,079	(5,449)	(1,358)
Diluted	$ (2,239)	$ 1,079	$ (5,449)	$ (1,358)
Shares
Average number of common shares outstanding—basic	508	506	508	505
Dilutive effect of stock options	0	2	0	0
Average number of common shares outstanding—diluted	508	508	508	505
Excluded due to anti-dilutive effect	10	3	11	11
Net income (loss) per common share
Basic	$ (4.41)	$ 2.13	$ (10.73)	$ (2.69)
Diluted	$ (4.41)	$ 2.12	$ (10.73)	$ (2.69)
7.50% Tangible Equity Units [Member] | Minimum Settlement Rate Effect On Noncontrolling Interest [Member]
Net income (loss)
Less noncontrolling interest effect of TEUs	$ 3	$ 0	$ 3	$ 0

Accumulated Other Comprehensi55

Accumulated Other Comprehensive Income (Loss) (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	$ 22,318
Reclassifications to Consolidated Statement of Income	30
Balance	17,052
Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	(48)
Reclassifications to Consolidated Statement of Income	4
Balance	(44)
Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	(469)
Reclassifications to Consolidated Statement of Income	26
Balance	(443)
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance	(517)
Balance	$ (487)

Noncontrolling Interests (Detai

Noncontrolling Interests (Detail) - USD ($) shares in Thousands, $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
7.50% Tangible Equity Units [Member]
Noncontrolling Interest [Line Items]
Net proceeds	$ 348	$ 0
Number of tangible equity units issued	9,200
Western Gas Equity Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued to the public	2,300
Net proceeds	$ 130
Western Gas Equity Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	87.30%
Public ownership interest in subsidiary	12.70%
Western Gas Partners, LP [Member] | Class C Units [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement	317		11,000
Western Gas Partners, LP [Member] | Continuous Offering Program [Member]
Noncontrolling Interest [Line Items]
Units issued to the public	874
Net proceeds	$ 57
Western Gas Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Public ownership interest in subsidiary	55.20%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Western Gas Equity Partners, LP, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	34.60%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Other Anadarko Subsidiaries, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	8.40%
Western Gas Partners, LP [Member] | General Partner [Member] | Western Gas Equity Partners, LP, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	1.80%

Contingencies - Tronox Litigati

Contingencies - Tronox Litigation (Detail) - Tronox Litigation [Member] - Judicial Ruling [Member] - USD ($) $ in Millions	3 Months Ended					9 Months Ended		12 Months Ended
	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Loss Contingencies [Line Items]
Litigation-related contingent liability	$ 0			$ 5,150		$ 0		$ 5,210
Payment for Tronox settlement		$ 5,200
Litigation-related contingent loss	$ 0		$ 19	$ 4,300	$ 850	$ 5	$ 4,338
Post Settlement Interest Expense [Member]
Loss Contingencies [Line Items]
Litigation-related contingent loss		$ 5						$ 60

Contingencies - Deepwater Horiz

Contingencies - Deepwater Horizon Events (Detail) bbl in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)bbl	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Jun. 30, 2014USD ($)	Sep. 30, 2011
Macondo Exploration Well [Member]
Loss Contingencies [Line Items]
Anadarko's nonoperated interest							25.00%
Deepwater Horizon [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Litigation-related contingent loss	$ 0	$ 3,000,000	$ 4,000,000	$ 96,000,000
Litigation-related contingent liability	$ 90,000,000		$ 90,000,000		$ 90,000,000
Allocation of fault assigned in Phase I Findings and Conclusions	0.00%		0.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | BP and BPAP [Member]
Loss Contingencies [Line Items]
Allocation of fault assigned in Phase I Findings and Conclusions	67.00%		67.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | Transocean [Member]
Loss Contingencies [Line Items]
Allocation of fault assigned in Phase I Findings and Conclusions	30.00%		30.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | Halliburton Energy Services [Member]
Loss Contingencies [Line Items]
Allocation of fault assigned in Phase I Findings and Conclusions	3.00%		3.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | Clean Water Act [Member]
Loss Contingencies [Line Items]
Litigation-related contingent loss					$ 90,000,000
Litigation-related contingent liability	$ 90,000,000		$ 90,000,000			$ 90,000,000
Barrels of oil discharged | bbl			3,190
Deepwater Horizon [Member] | Pending Litigation [Member] | Clean Water Act [Member] | BP Exploration and Production Inc. [Member]
Loss Contingencies [Line Items]
Announced BP settlement in principle, portion to resolve CWA penalties	5,500,000,000		$ 5,500,000,000
Deepwater Horizon [Member] | BP indemnification liability [Member]
Loss Contingencies [Line Items]
Loss contingency accrual	$ 0		$ 0

Contingencies - Other Litigatio

Contingencies - Other Litigation (Detail)	Sep. 30, 2015USD ($)
Peregrino Litigation [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss contingency accrual	$ 0

Income Taxes - Income Tax Expen

Income Taxes - Income Tax Expense (Benefit) Table (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ (917)	$ 627	$ (2,232)	$ 1,719
Income (loss) before income taxes	$ (3,077)	$ 1,774	$ (7,520)	$ 506
Effective tax rate	30.00%	35.00%	30.00%	340.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
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	$ 959		$ 959
Tronox Litigation [Member] | Judicial Ruling [Member]
Income Tax Disclosure [Line Items]
Tax benefit related to the Tronox settlement	577		577
Uncertain tax position			1,300
Tronox Litigation [Member] | Judicial Ruling [Member] | Accounts Receivable Other [Member]
Income Tax Disclosure [Line Items]
Tax benefit related to the Tronox settlement	$ 887		$ 887

Supplemental Cash Flow Inform62

Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014
Cash (paid) received
Interest, net of amounts capitalized (1)	$ 1,916	[1]	$ 600
Income taxes, net of refunds	(163)		661
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	156		7
Asset retirement cost additions	139		149
Accruals of property, plant, and equipment	858		1,154
Net liabilities assumed (divested) in acquisitions and divestitures	(84)		(126)
Non-cash investing and financing activities
Floating production, storage, and offloading vessel construction period obligation	51		$ 88
Tronox Litigation [Member] | Judicial Ruling [Member]
Cash (paid) received
Taxes related to the Tronox settlement	577
Interest, net of amounts capitalized (1)	1,200
Tronox Litigation [Member] | Judicial Ruling [Member] | Accounts Receivable Other [Member]
Cash (paid) received
Taxes related to the Tronox settlement	887
Tronox Litigation [Member] | Judicial Ruling [Member] | Other Liabilities [Member]
Cash (paid) received
Unrecognized tax benefits	$ 887
[1]	Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.

Segment Information - Additiona

Segment Information - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015Segment
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 Table (Detail) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income (loss) before income taxes	$ (3,077)	$ 1,774			$ (7,520)	$ 506
Exploration expense	1,074	199			2,260	1,000
DD&A	1,111	1,163			3,581	3,335
Impairments	758	394			3,571	514
Interest expense	199	204			616	573
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	360	(276)			374	324
Net income attributable to noncontrolling interests	75	60			154	142
Consolidated Adjusted EBITDAX	350	3,442			2,759	10,566
Certain Other Nonoperating Items [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Certain other nonoperating items	0	22			22	22
Deepwater Horizon [Member] | Pending Litigation [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Litigation-related contingent loss	0	3			4	96
Certain other nonoperating items					0	93
Tronox Litigation [Member] | Judicial Ruling [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Litigation-related contingent loss	$ 0	$ 19	$ 4,300	$ 850	5	4,338
Certain other nonoperating items					$ (5,210)	$ 4,338

Segment Information - Selected

Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Revenues		$ 2,230	$ 4,230	$ 7,452	$ 12,953
Gains (losses) on divestitures and other, net		(542)	780	(807)	2,340
Total revenues and other		1,688	5,010	6,645	15,293
Operating costs and expenses (1)	[1]	1,294	1,553	3,896	4,466
Net cash from settlement of commodity derivatives				(251)	138
Other (income) expense, net		47	24	109	12
Net income attributable to noncontrolling interests		75	60	154	142
Total expenses and other		1,337	1,567	3,886	4,730
Consolidated Adjusted EBITDAX		350	3,442	2,759	10,566
(Gains) Losses on Derivatives, Net [Member] | Commodity Contract [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives		(79)	(48)	(251)	132
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		(1)	(1)	0	3
Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	[2]	47	2	87	(10)
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues		0	0	0	0
Gains (losses) on divestitures and other, net		37	55	202	148
Total revenues and other		(196)	(139)	(493)	(440)
Operating costs and expenses (1)	[1]	(14)	26	(110)	51
Total expenses and other		(46)	(20)	(274)	173
Consolidated Adjusted EBITDAX		(150)	(119)	(219)	(613)
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		(79)	(48)	(251)	132
Other and Intersegment Eliminations [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	[2]	47	2	87	(10)
Other and Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		(233)	(194)	(695)	(588)
Oil and Gas Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues		1,067	2,192	3,493	6,804
Gains (losses) on divestitures and other, net		(557)	724	(990)	2,194
Oil and Gas Exploration and Production Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		750	1,604	2,752	4,947
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues and other		1,260	4,520	5,255	13,945
Operating costs and expenses (1)	[1]	840	1,090	2,674	3,128
Total expenses and other		840	1,090	2,674	3,128
Consolidated Adjusted EBITDAX		420	3,430	2,581	10,817
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues		195	119	560	358
Gains (losses) on divestitures and other, net		(22)	1	(19)	(2)
Midstream Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		315	364	920	1,010
Midstream Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues and other		488	484	1,461	1,366
Operating costs and expenses (1)	[1]	287	249	761	732
Net income attributable to noncontrolling interests		75	60	154	142
Total expenses and other		362	309	915	874
Consolidated Adjusted EBITDAX		126	175	546	492
Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues		968	1,919	3,399	5,791
Gains (losses) on divestitures and other, net		0	0	0	0
Marketing Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues		(832)	(1,774)	(2,977)	(5,369)
Marketing Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues and other		136	145	422	422
Operating costs and expenses (1)	[1]	181	188	571	555
Total expenses and other		181	188	571	555
Consolidated Adjusted EBITDAX		(46)	(44)	(149)	(130)
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		$ (1)	$ (1)	$ 0	$ 3
[1]	Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX.
[2]	Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

Pension Plans and Other Postr66

Pension Plans and Other Postretirement Benefits (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	$ 30	$ 25	$ 89	$ 74
Interest cost	25	25	76	75
Expected return on plan assets	(27)	(27)	(82)	(80)
Amortization of net actuarial loss (gain)	13	9	39	26
Amortization of net prior service cost (credit)	0	0	0	0
Net periodic benefit cost	41	32	122	95
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	3	1	8	5
Interest cost	3	4	11	11
Expected return on plan assets	0	0	0	0
Amortization of net actuarial loss (gain)	0	(2)	0	(5)
Amortization of net prior service cost (credit)	1	0	2	0
Net periodic benefit cost	$ 7	$ 3	$ 21	$ 11