Anadarko Petroleum 10-K 20 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Jan. 30, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Trading Symbol	APC
Entity Registrant Name	ANADARKO PETROLEUM CORP
Entity Central Index Key	773910
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		506,650,285
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$55.30

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues and Other
Natural-gas sales	$3,849,000,000	$3,388,000,000	$2,444,000,000
Oil and condensate sales	9,748,000,000	9,178,000,000	8,728,000,000
Natural-gas liquids sales	1,572,000,000	1,262,000,000	1,224,000,000
Gathering, processing, and marketing sales	1,206,000,000	1,039,000,000	911,000,000
Gains (losses) on divestitures and other, net	2,095,000,000	-286,000,000	104,000,000
Total	18,470,000,000	14,581,000,000	13,411,000,000
Costs and Expenses
Oil and gas operating	1,171,000,000	1,092,000,000	976,000,000
Oil and gas transportation and other	1,184,000,000	1,022,000,000	955,000,000
Exploration	1,639,000,000	1,329,000,000	1,946,000,000
Gathering, processing, and marketing	1,030,000,000	869,000,000	763,000,000
General and administrative	1,316,000,000	1,090,000,000	1,246,000,000
Depreciation, depletion, and amortization	4,550,000,000	3,927,000,000	3,964,000,000
Other taxes	1,244,000,000	1,077,000,000	1,224,000,000
Impairments	836,000,000	794,000,000	389,000,000
Algeria exceptional profits tax settlement	0	33,000,000	-1,797,000,000
Deepwater Horizon settlement and related costs	97,000,000	15,000,000	18,000,000
Total	13,067,000,000	11,248,000,000	9,684,000,000
Operating Income (Loss)	5,403,000,000	3,333,000,000	3,727,000,000
Other (Income) Expense
Interest expense	772,000,000	686,000,000	742,000,000
(Gains) losses on derivatives, net	207,000,000	-392,000,000	-308,000,000
Other (income) expense, net	20,000,000	89,000,000	-4,000,000
Tronox-related contingent loss	4,360,000,000	850,000,000	-250,000,000
Total	5,349,000,000	1,227,000,000	162,000,000
Income (Loss) Before Income Taxes	54,000,000	2,106,000,000	3,565,000,000
Income tax expense (benefit)	1,617,000,000	1,165,000,000	1,120,000,000
Net Income (Loss)	-1,563,000,000	941,000,000	2,445,000,000
Net income attributable to noncontrolling interests	187,000,000	140,000,000	54,000,000
Net Income (Loss) Attributable to Common Stockholders	-1,750,000,000	801,000,000	2,391,000,000
Per Common Share
Net income (loss) attributable to common stockholders—basic	($3.47)	$1.58	$4.76
Net income (loss) attributable to common stockholders—diluted	($3.47)	$1.58	$4.74
Average Number of Common Shares Outstanding—Basic	506	502	500
Average Number of Common Shares Outstanding—Diluted	506	505	502
Dividends (per Common Share)	$0.99	$0.54	$0.36
Commodity Contract and Interest-Rate Swap [Member]
Other (Income) Expense
(Gains) losses on derivatives, net	$197,000,000	($398,000,000)	($326,000,000)

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	($1,563)	$941	$2,445
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	9	11	12
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	-3	-4	-4
Total adjustments for derivative instruments, net of taxes	6	7	8
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	-405	416	-155
Income taxes on net gain (loss) incurred during period	149	-152	56
Amortization of net actuarial (gain) loss to general and administrative expense	27	132	93
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	-9	-49	-32
Amortization of net prior service (credit) cost to general and administrative expense	0	1	2
Total adjustments for pension and other postretirement plans, net of taxes	-238	348	-36
Total	-232	355	-28
Comprehensive Income (Loss)	-1,795	1,296	2,417
Comprehensive income attributable to noncontrolling interests	187	140	54
Comprehensive Income (Loss) Attributable to Common Stockholders	($1,982)	$1,156	$2,363

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2014
In Millions, unless otherwise specified
Current Assets
Cash and cash equivalents	$7,369	$3,698
Accounts receivable (net of allowance of $7 million and $5 million)
Customers	1,118	1,481
Others	1,409	1,241
Other current assets	1,325	688
Total	11,221	7,108
Properties and Equipment
Cost	75,107	71,244
Less accumulated depreciation, depletion, and amortization	33,518	30,315
Net properties and equipment	41,589	40,929
Other Assets	2,310	2,082
Goodwill and Other Intangible Assets	6,569	5,662
Total Assets	61,689	55,781
Current Liabilities
Accounts payable	3,683	3,530
Current asset retirement obligations	257	409
Accrued expenses	994	1,264
Current portion of long-term debt	0	500
Total	10,234	5,703
Long-term Debt	15,092	13,065
Other Long-term Liabilities
Deferred income taxes	9,249	9,245
Asset retirement obligations	1,796	1,613
Other	3,000	1,655
Total	14,045	13,363
Stockholders' equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 525.9 million and 522.5 million shares issued)	52	52
Paid-in capital	9,005	8,629
Retained earnings	12,125	14,356
Treasury stock (19.3 million and 18.8 million shares)	-940	-895
Accumulated other comprehensive income (loss)	-517	-285
Total Stockholders’ Equity	19,725	21,857
Noncontrolling interests	2,593	1,793
Total Equity	22,318	23,650
Total Liabilities and Equity	61,689	55,781
Pending Litigation [Member] | Deepwater Horizon [Member]
Current Liabilities
Litigation-related contingent liability	90	0
Pending Litigation [Member] | Tronox Litigation [Member]
Current Liabilities
Litigation-related contingent liability	5,210	0	5,150
Other Long-term Liabilities
Tronox-related contingent liability	$0	$850

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$7	$5
Common stock, par value	$0.10	$0.10
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	525,900,000	522,500,000
Treasury stock, shares	19,300,000	18,800,000

CONSOLIDATED_STATEMENTS_OF_EQU

CONSOLIDATED STATEMENTS OF EQUITY (USD $)	Total	Common Stock [Member]	Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]
In Millions
Balance at Dec. 31, 2011	$18,983	$51	$7,851	$11,619	($804)	($612)	$878
Net income (loss)	2,445			2,391			54
Common stock issued	249		249
Dividends—common stock	-181			-181
Repurchase of common stock	-37				-37
Subsidiary equity transactions	547		130				417
Distributions to noncontrolling interest owners	-112						-112
Contributions from noncontrolling interest owners	16						16
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	8					8
Adjustments for pension and other postretirement plans	-36					-36
Balance at Dec. 31, 2012	21,882	51	8,230	13,829	-841	-640	1,253
Net income (loss)	941			801			140
Common stock issued	293	1	292
Dividends—common stock	-274			-274
Repurchase of common stock	-54				-54
Subsidiary equity transactions	661		107				554
Distributions to noncontrolling interest owners	-156						-156
Contributions from noncontrolling interest owners	2						2
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	7					7
Adjustments for pension and other postretirement plans	348					348
Balance at Dec. 31, 2013	23,650	52	8,629	14,356	-895	-285	1,793
Net income (loss)	-1,563			-1,750			187
Common stock issued	286		286
Dividends—common stock	-505			-505
Repurchase of common stock	-45				-45
Subsidiary equity transactions	943		90	24			829
Distributions to noncontrolling interest owners	-216						-216
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	6					6
Adjustments for pension and other postretirement plans	-238					-238
Balance at Dec. 31, 2014	$22,318	$52	$9,005	$12,125	($940)	($517)	$2,593

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities
Net income (loss)	($1,563)	$941	$2,445
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization	4,550	3,927	3,964
Deferred income taxes	-105	90	164
Dry hole expense and impairments of unproved properties	1,245	864	1,544
Impairments	836	794	389
(Gains) losses on divestitures, net	-1,891	470	71
Total (gains) losses on derivatives, net	207	-392	-308
Operating portion of net cash received (paid) in settlement of derivative instruments	371	85	685
Other	327	246	232
Changes in assets and liabilities
Algeria exceptional profits tax settlement	0	730	-791
Statement [Line Items]
(Increase) decrease in accounts receivable	103	-11	520
Increase (decrease) in accounts payable and accrued expenses	7	150	-476
Other items—net	-71	146	126
Net cash provided by (used in) operating activities	8,466	8,888	8,339
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	-9,508	-7,721	-7,242
Acquisition of businesses	-1,527	-473	0
Divestitures of properties and equipment and other assets	4,968	567	657
Other—net	-405	-589	-284
Net cash provided by (used in) investing activities	-6,472	-8,216	-6,869
Cash Flows from Financing Activities
Borrowings, net of issuance costs	2,879	958	1,042
Repayments of debt	-1,425	-710	-3,044
Financing portion of net cash paid in settlement of derivative instruments	-222	0	0
Increase (decrease) in outstanding checks	62	-13	-69
Dividends paid	-505	-274	-181
Repurchase of common stock	-45	-54	-37
Issuance of common stock, including tax benefit on share-based compensation awards	121	146	103
Sale of subsidiary units	1,026	724	623
Distributions to noncontrolling interest owners	-216	-156	-112
Contributions from noncontrolling interest owners	0	2	16
Net cash provided by (used in) financing activities	1,675	623	-1,659
Effect of Exchange Rate Changes on Cash	2	-68	-37
Net Increase (Decrease) in Cash and Cash Equivalents	3,671	1,227	-226
Cash and Cash Equivalents at Beginning of Period	3,698	2,471	2,697
Cash and Cash Equivalents at End of Period	7,369	3,698	2,471
Deepwater Horizon [Member] | Pending Litigation [Member]
Statement [Line Items]
Litigation-related contingent loss	90	-2	24
Tronox Litigation [Member] | Pending Litigation [Member]
Statement [Line Items]
Litigation-related contingent loss	$4,360	$850	($250)

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
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 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 Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States. The Consolidated Financial Statements include the accounts of Anadarko and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Anadarko has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Certain prior-period amounts have been reclassified to conform to the current-year presentation.
	Use of Estimates  The preparation of financial statements in accordance with generally accepted accounting principles in the United States (GAAP) requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; 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.
	Fair Value  Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
	Level 1—Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
	Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
	Level 3—Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).
	In determining fair value, the Company uses observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value.
	1. Summary of Significant Accounting Policies (Continued)
	In arriving at fair-value estimates, the Company uses relevant observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. For Anadarko, recurring fair-value measurements are performed for interest-rate derivatives, commodity derivatives, and investments in trading securities.
	The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 12—Debt and Interest Expense, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.
	Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, asset retirement obligations, exit or disposal costs, and capital lease assets where the present value of lease payments is greater than the fair value of the leased asset.
	Revenues  The Company’s natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. Oil and condensate are sold primarily to marketers, gatherers, and refiners. NGLs are sold primarily to direct end-users, refiners, and marketers.
	The Company recognizes sales revenues for natural gas, oil and condensate, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.
	Anadarko provides gathering, processing, treating, and transporting services pursuant to a variety of contracts. Under these arrangements, the Company receives fees, or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time the services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.
	Marketing margins related to the Company’s production are included in natural-gas sales, oil and condensate sales, and NGLs sales. Marketing margins related to sales of commodities purchased from third parties and gains and losses on derivatives related to such marketing activities are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.
	The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These transactions are reported on a net basis and included in oil and gas transportation in the Consolidated Statements of Income.
	Cash Equivalents  The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
	1. Summary of Significant Accounting Policies (Continued)
	Accounts Receivable and Allowance for Uncollectible Accounts  The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based on these analyses, the Company may require a standby letter of credit or a financial guarantee. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued.
	Inventories  Commodity inventories are stated at the lower of average cost or market.
	Properties and Equipment  Properties and equipment are stated at cost less accumulated depreciation, depletion, and amortization expense (DD&A). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gain or loss is recognized in gains (losses) on divestitures and other, net.
	Oil and Gas Properties  The Company applies the successful efforts method of accounting for oil and gas properties. Exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are charged against earnings as incurred. If an exploratory well provides evidence to justify potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally in deepwater and international locations) depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
	Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average lease terms at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense in the Consolidated Statements of Income.
	1. Summary of Significant Accounting Policies (Continued)
	Capitalized Interest  For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principle operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 12—Debt and Interest Expense.
	Asset Retirement Obligations  Asset retirement obligations (AROs) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. See Note 7—Asset Retirement Obligations.
	Impairments  Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. See Note 5—Impairments.
	Depreciation, Depletion, and Amortization  Costs of drilling and equipping successful wells, costs to construct or acquire facilities other than offshore platforms, associated asset retirement costs, and capital lease assets used in oil and gas activities are depreciated using the unit-of-production (UOP) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the UOP method. All other properties are stated at historical acquisition cost, net of impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 40 years for buildings, and up to 47 years for gathering facilities.
	Goodwill and Other Intangible Assets  Goodwill is subject to annual impairment testing at October 1 (or more frequent testing as circumstances dictate). Anadarko has allocated goodwill to the following reporting units: oil and gas exploration and production, other gathering and processing, Western Gas Partners, LP (WES) gathering and processing, and WES transportation. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures. See Note 8—Goodwill and Other Intangible Assets.
	Other intangible assets represent contractual rights obtained in connection with business combinations that had favorable contractual terms relative to market at the acquisition date as well as customer-related intangible assets, including customer relationships established by acquired contracts. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment whenever impairment indicators are present. See Note 8—Goodwill and Other Intangible Assets.
	1. Summary of Significant Accounting Policies (Continued)
	Derivative Instruments  Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risk. Derivatives are carried on the balance sheet at fair value and are included in other current assets, other assets, accrued expenses, or other long-term liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the normal purchases and sales exception criteria. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis.
	Gains and losses on derivative instruments are recognized currently in earnings. Net losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 11—Derivative Instruments.
	Accounts Payable  Accounts payable included liabilities of $388 million at December 31, 2014, and $326 million at December 31, 2013, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in applicable bank accounts. Changes in these liabilities are reflected in cash flows from financing activities.
	Legal Contingencies  The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. If the Company determines that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 17—Contingencies.
	Environmental Contingencies  The Company is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. Except for environmental contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 17—Contingencies.
	Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans  The Company measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and the health care cost trend rate (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.
	The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. See Note 21—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans.
	1. Summary of Significant Accounting Policies (Continued)
	Noncontrolling Interests  Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 9—Noncontrolling Interests.
	Income Taxes  The Company files various U.S. federal, state, and foreign income tax returns. Deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). The Company uses the flow-through method to account for its investment tax credits. See Note 18—Income Taxes.
	Share-Based Compensation  The Company accounts for share-based compensation at fair value. The Company grants equity-classified awards including stock options and non-vested equity shares (restricted stock awards and units). The Company may also grant equity-classified and liability-classified awards based on a comparison of the Company’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies (performance units).
	The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of Anadarko common stock. For other share-based compensation awards, fair value is determined using a Monte Carlo simulation or discounted-cash-flow methodology.
	The Company records compensation cost, net of estimated forfeitures, for share-based compensation awards over the requisite service period using the straight-line method. An adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the awards. For equity-classified share-based compensation awards, expense is recognized based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid. See Note 15—Share-Based Compensation.
	Earnings Per Share  The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and performance-based stock awards, if the inclusion of these items is dilutive. See Note 13—Stockholders’ Equity.
	Recently Issued Accounting Standards  The Financial Accounting Standards Board issued Accounting Standards Update (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. This ASU is effective for annual and interim periods beginning in 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.
	1. Summary of Significant Accounting Policies (Continued)
	ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. This ASU is effective beginning in 2015, with early adoption permitted for disposals or for assets classified as held for sale not reported in previously issued financial statements. Anadarko early adopted this ASU on a prospective basis in the first quarter of 2014 with no material impact on the Company’s consolidated financial statements.
	ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented in the financial statements as a reduction to a deferred tax asset, except in certain circumstances. This ASU is effective for annual and interim periods beginning in 2014. See Note 18—Income Taxes.

Acquisitions_Divestitures_and_

Acquisitions, Divestitures, and Assets Held for Sale	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Acquisitions, Divestitures, and Assets Held for Sale	2. Acquisitions, Divestitures, and Assets Held for Sale
	Acquisitions  In November 2014, WES acquired Nuevo Midstream, LLC (Nuevo), which owns and operates gathering and processing assets in the Delaware basin in West Texas, for $1.554 billion. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). This acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. This acquisition aligns the Company’s gas gathering and processing capacity with future industry production growth plans in the Delaware basin. The following summarizes the preliminary fair value of assets acquired and liabilities assumed at the acquisition date, pending the acquired entity’s final financial statements:
	millions
	Current assets		$	46
	Properties and equipment		441
	Other intangible assets		836
	Accounts payable		(13		)
	Accrued expenses		(25		)
	Deferred income taxes		(1		)
	Asset retirement obligations		(9		)
	Goodwill		279
	Total assets acquired and liabilities assumed		$	1,554
	Fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets (liabilities) represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. All of the goodwill related to this acquisition is amortizable for tax purposes. The assets acquired and liabilities assumed are included within the midstream reporting segment.
	Results of operations attributable to this acquisition are included in the Company’s Consolidated Statements of Income from the date acquired. The amounts of revenue and earnings included in the Company’s Consolidated Statement of Income for the year ended December 31, 2014, and the amounts of revenue and earnings that would have been recognized had the acquisition occurred on January 1, 2014, are not material to the Company’s Consolidated Statements of Income.
	2. Acquisitions, Divestitures, and Assets Held for Sale (Continued)
	There were no other material acquisitions made during 2014. The following summarizes acquisitions made during 2013:
	millions, except percentages	Percentage			Cash Paid
		Acquired
	Certain oil and gas properties and related assets in the Moxa area of Wyoming	100	%		$	310		(1)
	Gas-gathering systems in the Marcellus shale in north-central Pennsylvania	33.75	%		135
	Joint venture formed to design, construct, and own two fractionators located in	25	%		78
	Mont Belvieu, Texas
	Intrastate pipeline in southwestern Wyoming	100	%		28
	__________________________________________________________________
	(1)	Includes $306 million that represents the fair value of the oil and gas properties acquired.
	Divestitures and Assets Held for Sale  The following summarizes the proceeds received and gains (losses) recognized on divestitures for the years ended December 31:
	millions	2014				2013			2012
	Proceeds received	$	4,968			$	567		$	657
	Gains (losses) on divestitures, net	1,891				(470		)	(71		)
	Divestitures The 2014 proceeds and net gains were primarily related to assets included in the oil and gas exploration and production reporting segment. The Company sold a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion, recognizing a gain of $1.5 billion. In addition, the Company sold its Chinese subsidiary for $1.075 billion, recognizing a gain of $510 million; sold its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for $500 million, recognizing a gain of $237 million; and sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million. These gains were partially offset by losses of $456 million discussed under Assets Held for Sale below.
	The 2013 sales proceeds were primarily related to the Company’s divestiture of its interests in a soda ash joint venture and certain U.S. onshore and Indonesian oil and gas properties. Net losses were primarily related to the Company’s sale of the Pinedale/Jonah assets discussed under Assets Held for Sale below, partially offset by the Company’s divestiture of its interests in the soda ash joint venture and certain U.S. oil and gas properties. The 2012 sales proceeds were primarily related to U.S. oil and gas properties and net losses were primarily related to Indonesian oil and gas properties.
	2. Acquisitions, Divestitures, and Assets Held for Sale (Continued)
	Assets Held for Sale  During the fourth quarter of 2014, Anadarko considered certain U.S. onshore assets from the oil and gas exploration and production reporting segment to be held for sale. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement, and the Company recognized a loss of $456 million. 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. Volatility in the current commodity-price environment has reduced the probability that the assets will be sold within one year and the assets are therefore no longer considered held for sale at December 31, 2014. At December 31, 2014, the balances of assets and liabilities associated with assets held for sale were not material.
	During the fourth quarter of 2013, the Company began marketing certain other domestic properties from the oil and gas exploration and production reporting segment to redirect its operating activities and capital investments to other areas. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement. In 2013, the Company recognized losses of $704 million primarily related to the sale of the Pinedale/Jonah assets in Wyoming, which closed in 2014. At December 31, 2013, the Company’s Consolidated Balance Sheets included long-term assets of $616 million and long-term liabilities of $27 million associated with assets held for sale.
	Property Exchange  In 2013, the Company exchanged certain oil and gas properties in the Wattenberg field with a third party. The properties exchanged were measured at the Company’s historical net cost with no gain or loss recognized. Anadarko paid $106 million in cash as part of the exchange, which is included as an addition to properties and equipment on the Company’s Consolidated Statement of Cash Flows.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2014
Energy Related Inventory [Abstract]
Inventories	3. Inventories
	The following summarizes the major classes of inventories included in other current assets at December 31:
	millions	2014		2013
	Oil	$	133	$	88
	Natural gas	27		43
	NGLs	83		79
	Total inventories	$	243	$	210

Properties_and_Equipment

Properties and Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Gross [Abstract]
Properties and Equipment	4. Properties and Equipment
	The following summarizes the cost of properties and equipment by segment at December 31:
	millions	2014		2013
	Oil and gas exploration and production (1)	$	63,674	$	61,302
	Midstream	8,647		7,285
	Marketing	—		9
	Other	2,786		2,648
	Total properties and equipment	$	75,107	$	71,244
	__________________________________________________________________
	(1)	Includes costs associated with unproved properties of $5.1 billion at December 31, 2014, and $6.9 billion at December 31, 2013.

Impairments

Impairments	12 Months Ended
	Dec. 31, 2014
Asset Impairment Charges [Abstract]
Impairments	5. Impairments
	The following summarizes impairments by segment for the years ended December 31:
	millions	2014			2013			2012
	Oil and gas exploration and production
	Long-lived assets held for use
	U.S. onshore properties	$	545		$	142		$	259
	Gulf of Mexico properties	276			562			104
	Cost-method investment	3			11			13
	Midstream
	Long-lived assets held for use	12			79			13
	Total impairments	$	836		$	794		$	389
	In 2014, certain U.S. onshore and Gulf of Mexico oil and gas properties were impaired primarily due to lower forecasted natural-gas and oil prices. While the Company’s other U.S. onshore oil and gas properties indicated no impairment at December 31, 2014, it is reasonably possible the estimate of undiscounted cash flows related to certain of these properties may change in the near term due to declines in commodity prices and could result in additional property impairments.
	In 2013, certain Gulf of Mexico properties were impaired due to a reduction in estimated future net cash flows and downward revisions of reserves resulting from changes to the Company’s development plans. Also in 2013, certain U.S. onshore properties and related midstream assets were impaired due to downward revisions of reserves resulting from changes to the Company’s development plans. In addition, a midstream property was impaired during 2013 due to a reduction in estimated future cash flows. In 2012, certain U.S. onshore and midstream properties were impaired primarily due to lower natural-gas prices and Gulf of Mexico properties were impaired primarily as a result of downward reserves revisions for a property that was near the end of its economic life. Impairments of the Company’s Venezuelan cost-method investment were due to declines in estimated recoverable value.
	The following summarizes the post-impairment fair value of the above-described assets, which was measured using the income approach and Level 3 inputs:
	millions		2014			2013
	Long-lived assets held for use		$	731		$	548
	Cost-method investment (1)		32			32
	__________________________________________________________________
	(1)	This represents the Company’s after-tax net investment.
	Impairments of Unproved Properties  Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. In 2012, the Company recognized a $721 million impairment of unproved Powder River coalbed methane properties primarily due to lower natural-gas prices. Also in 2012, the Company recognized a $124 million impairment of an unproved Gulf of Mexico natural-gas property that the Company did not expect to develop under the forecasted natural-gas price environment.

Suspended_Exploratory_Well_Cos

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2014
Capitalized Exploratory Well Costs [Abstract]
Suspended Exploratory Well Costs	6. Suspended Exploratory Well Costs
	The following summarizes the changes in suspended exploratory well costs at December 31 for each of the last three years. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.
	millions	2014			2013			2012
	Balance at January 1	$	2,232		$	2,062		$	1,353
	Additions pending the determination of proved reserves	421			848			960
	Divestitures (1)	(913		)	(48		)	—
	Reclassifications to proved properties	(100		)	(507		)	(129		)
	Charges to exploration expense	(118		)	(123		)	(122		)
	Balance at December 31	$	1,522		$	2,232		$	2,062
	__________________________________________________________________
	(1)	Includes $(744) million related to the Company’s sale of a 10% working interest in Offshore Area 1 in Mozambique during 2014.
	The following summarizes an aging of suspended exploratory well costs by geographic area and the year the costs were suspended at December 31, 2014:
					Year Costs Incurred(1)
	millions	Total			2014			2013			2012		2011 and
													prior
	United States—Onshore	$	164		$	131		$	17		$	5	$	11
	United States—Offshore	314			78			80			63		93
	International	1,044			179			271			184		410
		$	1,522		$	388		$	368		$	252	$	514
	__________________________________________________________________
	(1)	Excludes additions subsequently reclassified to proved properties within the same year.
	Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling were associated with 24 projects at December 31, 2014, primarily located in Brazil, Ghana, and the Gulf of Mexico. Project costs suspended for longer than one year were primarily suspended pending the completion of economic evaluations including, but not limited to, results of additional appraisal drilling, well-test analysis, additional geological and geophysical data, facilities and infrastructure development options, development plan approval, and permitting. 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.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	7. Asset Retirement Obligations
	The majority of Anadarko’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement. The following summarizes changes in the Company’s AROs during 2014 and 2013:
	millions	2014			2013
	Carrying amount of asset retirement obligations at January 1	$	2,022		$	1,885
	Liabilities incurred	119			182
	Property dispositions	(70		)	(76		)
	Liabilities settled	(443		)	(162		)
	Accretion expense	93			110
	Revisions in estimated liabilities	332			83
	Carrying amount of asset retirement obligations at December 31	$	2,053		$	2,022

Goodwill_and_Other_Intangible_

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangible Assets	8. Goodwill and Other Intangible Assets
	Goodwill  The Company’s 2014 annual impairment assessment of goodwill indicated no impairment. Procedures were also performed in the fourth quarter of 2014 to review any changes in circumstances subsequent to the annual test, including changes in commodity prices. These procedures also indicated no impairment. At December 31, 2014, the Company had $5.6 billion of goodwill allocated to the following reporting units: $5.1 billion to oil and gas exploration and production, $69 million to other gathering and processing, $379 million to WES gathering and processing, and $5 million to WES transportation.
	Significant declines in commodity prices, difficulties or potential delays in obtaining drilling permits, or other unanticipated events could result in further goodwill impairment tests in the near term, the results of which may have a material adverse impact on the Company’s results of operations.
	Other Intangible Assets  Intangible assets and associated amortization expense were as follows:
	millions	Gross Carrying		Accumulated			Net Carrying		Amortization
		Amount		Amortization			Amount		Expense
	December 31, 2014
	Offshore platform leases	$	33	$	(29	)	$	4	$	—
	Customer contracts	1,004		(15		)	989		6
		$	1,037	$	(44	)	$	993	$	6
	December 31, 2013
	Offshore platform leases	$	60	$	(50	)	$	10	$	3
	Customer contracts	169		(9		)	160		4
		$	229	$	(59	)	$	170	$	7
	Customer contract intangible assets are primarily related to WES’s DBM acquisition in 2014. These contracts are being amortized over 30 years. See Note 2—Acquisitions, Divestitures, and Assets Held for Sale. The annual aggregate amortization expense for intangible assets is expected to be $31 million each of the next five years.

Noncontrolling_Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2014
Noncontrolling Interest Items [Abstract]
Noncontrolling Interests	9. Noncontrolling Interests
	In December 2012, Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary formed to own substantially all of the partnership interests in WES previously owned by Anadarko, completed its initial public offering (IPO) of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit, for net proceeds of $411 million. During 2014, Anadarko sold approximately six million WGP common units to the public, raising net proceeds of $335 million. At December 31, 2014, Anadarko’s ownership interest in WGP consisted of an 88.3% limited partner interest and the entire non-economic general partner interest. The remaining 11.7% limited partner interest in WGP was owned by the public.
	WES, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES issued approximately 10 million common units to the public raising net proceeds of $691 million in 2014, approximately 12 million common units to the public raising net proceeds of $725 million in 2013, and approximately 5 million common units to the public raising net proceeds of $212 million in 2012. In addition, WES issued 11 million Class C units to Anadarko in 2014 to partially fund the DBM acquisition. These units will receive distributions in the form of additional Class C units until the end of 2017. At December 31, 2014, WGP’s ownership interest in WES consisted of a 34.9% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At December 31, 2014, Anadarko also owned an 8.3% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 55% limited partner interest in WES was owned by the public.

EquityMethod_Investments

Equity-Method Investments	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity-Method Investments	10. Equity-Method Investments
	In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of $2.9 billion at the time of the contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable London Interbank Offered Rate (LIBOR) based preferred interests in those entities. The common equity of the investee entities is 95% owned by third parties that also maintain control over the assets. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion. The Company accounts for its investment in these entities using the equity method of accounting. The carrying amount of these investments was $2.8 billion and the carrying amount of notes payable to affiliates was $2.9 billion at December 31, 2014. Anadarko has legal right of setoff and intends to net settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets in other long-term liabilities—other for all periods presented.
	Interest on the notes issued by Anadarko is variable, based on LIBOR, plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.24% at December 31, 2014 and December 31, 2013. The note payable agreement contains a covenant that provides for a maximum Anadarko debt-to-capital ratio of 67%. Anadarko was in compliance with this covenant at December 31, 2014. Other (income) expense, net includes interest expense on the notes payable of $36 million in 2014, $37 million in 2013, and $42 million in 2012, and equity earnings from Anadarko’s investments in the investee entities of $(45) million in 2014, $(42) million in 2013, and $(43) million in 2012.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	11. Derivative Instruments
	Objective and Strategy  The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as 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 14—Accumulated Other Comprehensive Income (Loss).
	Oil and Natural-Gas Production/Processing Derivative Activities  The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The following is a summary of the Company’s derivative instruments related to natural-gas production/processing derivative activities at December 31, 2014:
			2015 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
	Extendable Fixed-Price Contracts (thousand MMBtu/d) (1)		170
	Average price per MMBtu		$	4.17
	__________________________________________________________________
	(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
	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.
	In 2014, the Company terminated or offset then-existing 2015 oil three-way collars with a notional volume of 25 thousand barrels per day due to lower oil prices, resulting in a cash receipt of $126 million.
	11. Derivative Instruments (Continued)
	Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 6 billion cubic feet (Bcf) at December 31, 2014, and 16 Bcf at December 31, 2013, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.
	Interest-Rate Derivatives  Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. These swap instruments include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period.
	To align the interest-rate swap portfolio with anticipated future debt financing, in 2014 the Company extended the reference-period start dates from June 2014 to September 2016 and adjusted the related fixed interest rates for interest-rate swaps with an aggregate notional principal amount of $1.1 billion, and in 2012 the Company extended the reference-period start dates from October 2012 to September 2016 and adjusted the related fixed interest rates for interest-rate swap agreements with an aggregate notional principal amount of $800 million. In addition, in anticipation of the July 2014 issuance of an aggregate $1.25 billion of Senior Notes, interest-rate swap agreements with an aggregate notional principal amount of $750 million were settled in 2014, resulting in a cash payment of $222 million. Interest-rate swap agreements with an aggregate notional principal amount of $200 million were also settled in October 2012, resulting in a cash payment of $64 million.
	Derivative settlements are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements 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 settlements 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 December 31, 2014:
	millions except percentages					Reference Period				Weighted-Average
	Notional Principal Amount					Start		End		Interest Rate
	$	50				Sep-16		Sep-26		5.91%
	$	1,850				Sep-16		Sep-46		6.05%
	11. Derivative Instruments (Continued)
	Effect of Derivative Instruments—Balance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31:
	millions		Gross								Gross
			Derivative Assets								Derivative Liabilities
	Balance Sheet Classification		2014				2013				2014				2013
	Commodity derivatives
	Other current assets		$	421			$	181			$	(118	)		$	(102	)
	Other assets		1				89				—				(66		)
	Accrued expenses		71				106				(114		)		(149		)
	Other liabilities		—				4				(6		)		(15		)
			493				380				(238		)		(332		)
	Interest-rate and other derivatives
	Accrued expenses		—				—				—				(480		)
	Other liabilities		—				—				(1,217		)		(174		)
			—				—				(1,217		)		(654		)
	Total derivatives		$	493			$	380			$	(1,455	)		$	(986	)
	Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:
	millions
	Classification of (Gain) Loss Recognized		2014				2013				2012
	Commodity derivatives
	Gathering, processing, and marketing sales (1)		$	10			$	6			$	18
	(Gains) losses on derivatives, net		(589		)		141				(387		)
	Interest-rate and other derivatives
	(Gains) losses on derivatives, net		786				(539		)		61
	Total (gains) losses on derivatives, net		$	207			$	(392	)		$	(308	)
	__________________________________________________________________
	(1)	Represents the effect of Marketing and Trading Derivative Activities.
	11. Derivative Instruments (Continued)
	Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or IntercontinentalExchange, Inc. 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 December 31, 2014, $289 million of the Company’s $1.455 billion gross derivative liability balance, and at December 31, 2013, $76 million of the Company’s $986 million 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 declined to below investment grade. However, most of the Company’s derivative counterparties maintained secured positions at December 31, 2014, with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility ($5.0 billion Facility). In January 2015, the Company’s $5.0 billion Facility was replaced by new unsecured facilities under which the Company’s derivative counterparties no longer maintain security interests in any of the Company’s assets. As a result, the Company may be required from time to time to post collateral of cash or letters of credit based on the negotiated terms of the individual derivative agreements. For information on the Company’s revolving credit facilities, see Note 12—Debt and Interest Expense—Anadarko Revolving Credit Facilities and Commercial Paper Program.
	The aggregate fair value of unsecured derivative instruments with credit-risk-related contingent features for which a net liability position existed was $97 million (net of collateral) at December 31, 2014, and $42 million at December 31, 2013. The current portion of these amounts was included in accrued expenses and the long-term portion of these amounts was included in other long-term liabilities—other on the Company’s Consolidated Balance Sheets.
	11. Derivative Instruments (Continued)
	Fair Value  Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.
The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:
millions	Level 1				Level 2				Level 3				Netting (1)				Collateral			Total
December 31, 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			$	23		$	(24	)
Other counterparties	—				(4		)		—				2				—			(2		)
Interest-rate and other derivatives	—				(1,217		)		—				—				—			(1,217		)
Total derivative liabilities	$	—			$	(1,455	)		$	—			$	189			$	23		$	(1,243	)
December 31, 2013
Assets
Commodity derivatives
Financial institutions	$	—			$	211			$	—			$	(153	)		$	—		$	58
Other counterparties	—				169				—				(126		)		—			43
Total derivative assets	$	—			$	380			$	—			$	(279	)		$	—		$	101
Liabilities
Commodity derivatives
Financial institutions	$	—			$	(200	)		$	—			$	153			$	7		$	(40	)
Other counterparties	—				(132		)		—				126				—			(6		)
Interest-rate and other derivatives	—				(654		)		—				—				—			(654		)
Total derivative liabilities	$	—			$	(986	)		$	—			$	279			$	7		$	(700	)
__________________________________________________________________
(1)	Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

Debt_and_Interest_Expense

Debt and Interest Expense	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt and Interest Expense	12. Debt and Interest Expense
	Debt  The Company’s outstanding debt is senior unsecured, except for borrowings, if any, under the $5.0 billion Facility. See Note 10—Equity-Method Investments for disclosure regarding Anadarko’s notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. The following summarizes the Company’s outstanding debt:
		December 31,
	millions	2014			2013
	5.750% Senior Notes due 2014	$	—		$	275
	7.625% Senior Notes due 2014	—			500
	5.950% Senior Notes due 2016	1,750			1,750
	6.375% Senior Notes due 2017	2,000			2,000
	7.050% Debentures due 2018	114			114
	WES 2.600% Senior Notes due 2018	350			250
	6.950% Senior Notes due 2019	300			300
	8.700% Senior Notes due 2019	600			600
	WES 5.375% Senior Notes due 2021	500			500
	WES 4.000% Senior Notes due 2022	670			670
	3.450% Senior Notes due 2024	625			—
	6.950% Senior Notes due 2024	650			650
	7.500% Debentures due 2026	112			112
	7.000% Debentures due 2027	54			54
	7.125% Debentures due 2027	150			150
	6.625% Debentures due 2028	17			17
	7.150% Debentures due 2028	235			235
	7.200% Debentures due 2029	135			135
	7.950% Debentures due 2029	117			117
	7.500% Senior Notes due 2031	900			900
	7.875% Senior Notes due 2031	500			500
	Zero-Coupon Senior Notes due 2036	2,360			2,360
	6.450% Senior Notes due 2036	1,750			1,750
	7.950% Senior Notes due 2039	325			325
	6.200% Senior Notes due 2040	750			750
	4.500% Senior Notes due 2044	625			—
	WES 5.450% Senior Notes due 2044	400			—
	7.730% Debentures due 2096	61			61
	7.500% Debentures due 2096	78			78
	7.250% Debentures due 2096	49			49
	WES revolving credit facility	510			—
	Total debt at face value	$	16,687		$	15,202
	Net unamortized discounts and premiums (1)	(1,616		)	(1,645		)
	Total borrowings	$	15,071		$	13,557
	Capital lease obligation	21			8
	Less current portion of long-term debt	—			500
	Total long-term debt	$	15,092		$	13,065
	__________________________________________________________________
	(1)	Unamortized discounts and premiums are amortized over the term of the related debt.
	12. Debt and Interest Expense (Continued)
	In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the Zero-Coupon Senior Notes due 2036 (Zero Coupons). The Zero Coupons mature in 2036 and have an aggregate principal amount due at maturity of approximately $2.4 billion, reflecting a yield to maturity of 5.24%. The 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. The accreted value of the outstanding Zero Coupons was $765 million at December 31, 2014. Anadarko’s Zero Coupons are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt.
	Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.4 billion at December 31, 2014, and $15.3 billion at December 31, 2013.
	Debt Activity  The following summarizes the Company’s debt activity during 2014 and 2013:
	millions	Carrying			Description
		Value
	Balance at December 31, 2012	$	13,269
	Issuances	250			WES 2.600% Senior Notes due 2018
	Borrowings	710			WES revolving credit facility
	Repayments	(710		)	WES revolving credit facility
	Other, net	38			Amortization of debt discounts and premiums
	Balance at December 31, 2013	$	13,557
	Issuances	101			WES 2.600% Senior Notes due 2018
		394			WES 5.450% Senior Notes due 2044
		624			3.450% Senior Notes due 2024
		621			4.500% Senior Notes due 2044
	Borrowings	1,160			WES revolving credit facility
	Repayments	(500		)	7.625% Senior Notes due 2014
		(275		)	5.750% Senior Notes due 2014
		(650		)	WES revolving credit facility
	Other, net	39			Amortization of debt discounts and premiums
Balance at December 31, 2014	$	15,071
12. Debt and Interest Expense (Continued)
Anadarko Revolving Credit Facilities and Commercial Paper Program  During 2014, the Company maintained the $5.0 billion Facility maturing in September 2015. Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko had to lenders or their affiliates pursuant to certain derivative instruments that were supported by the $5.0 billion Facility as discussed in Note 11—Derivative Instruments, were guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and were secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries. During 2014, the Company had no outstanding borrowings under the $5.0 billion Facility.
In June 2014, Anadarko entered into a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). The new facilities (collectively, the New Credit Facilities) replaced the $5.0 billion Facility upon satisfaction of certain conditions, including the January 2015 settlement payment related to the Tronox Adversary Proceeding. For additional information, see Note 17—Contingencies—Tronox Litigation.
In January 2015, the Company borrowed $1.5 billion under the 364-Day Facility. Borrowings under the New Credit Facilities generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the 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 New Credit Facilities contain certain customary affirmative and negative covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65%, and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes.
In January 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes. 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.
WES Borrowings  In February 2014, WES amended and restated its then-existing $800 million senior unsecured revolving credit facility by entering into a five-year, $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to a maximum of $1.5 billion. Borrowings under the RCF bear interest at LIBOR plus an applicable margin ranging from 0.975% to 1.45% depending on WES’s credit rating, or the greatest of (i) rates at a margin above the one-month LIBOR, (ii) the federal funds rate, or (iii) prime rates offered by certain designated banks. At December 31, 2014, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $510 million at an interest rate of 1.47%, and had available borrowing capacity of approximately $677 million ($1.2 billion capacity, less $510 million of outstanding borrowings and $13 million of outstanding letters of credit).
12. Debt and Interest Expense (Continued)
Scheduled Maturities  Total principal amount of debt maturities for the five years ending December 31, 2019, excluding the potential repayment of the outstanding Zero Coupons that may be put by the holder to the Company annually, were as follows:
millions	Principal
	Amount of
	Debt Maturities
2015	$	—
2016	1,750
2017	2,000
2018	464
2019	1,410
Interest Expense  The following summarizes interest expense for the years ended December 31:
millions	2014			2013			2012
Debt and other	$	973		$	949		$	963
Capitalized interest	(201		)	(263		)	(221		)
Total interest expense	$	772		$	686		$	742

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Stockholders' Equity	13. Stockholders’ Equity
	Common Stock  The following summarizes the changes in the Company’s outstanding shares of common stock:
	millions	2014			2013			2012
	Shares of common stock issued
	Shares at January 1	523			519			516
	Exercise of stock options	2			2			1
	Issuance of restricted stock	1			2			2
	Shares at December 31	526			523			519
	Shares of common stock held in treasury
	Shares at January 1	19			18			18
	Shares received for restricted stock vested and options exercised	—			1			—
	Shares at December 31	19			19			18
	Shares of common stock outstanding at December 31	507			504			501
	The following provides a reconciliation between basic and diluted EPS attributable to common stockholders for the years ended December 31:
	millions except per-share amounts	2014				2013			2012
	Net income (loss)
	Net income (loss) attributable to common stockholders	$	(1,750	)		$	801		$	2,391
	Less distributions on participating securities	4				2			1
	Less undistributed income allocated to participating securities	—				4			14
	Basic	$	(1,754	)		$	795		$	2,376
	Diluted	$	(1,754	)		$	795		$	2,376
	Shares
	Average number of common shares outstanding—basic	506				502			500
	Dilutive effect of stock options	—				3			2
	Average number of common shares outstanding—diluted	506				505			502
	Excluded (1)	11				4			6
	Net income (loss) per common share
	Basic	$	(3.47	)		$	1.58		$	4.76
	Diluted	$	(3.47	)		$	1.58		$	4.74
	Dividends per common share	$	0.99			$	0.54		$	0.36
	__________________________________________________________________
	(1)	Inclusion of certain shares would have had an anti-dilutive effect.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	14. Accumulated Other Comprehensive Income (Loss)
	The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss):
	millions	Interest-rate			Pension and Other Postretirement			Total
		Derivatives			Plans
		Previously
		Subject to Hedge
		Accounting
	Balance at December 31, 2013	$	(54	)	$	(231	)	$	(285	)
	Other comprehensive income (loss), before	—			(256		)	(256		)
	reclassifications
	Reclassifications to Consolidated Statement of Income	6			18			24
	Net other comprehensive income (loss)	6			(238		)	(232		)
	Balance at December 31, 2014	$	(48	)	$	(469	)	$	(517	)

ShareBased_Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	15. Share-Based Compensation
	At December 31, 2014, 21 million shares of the 31 million shares of Anadarko common stock originally authorized for awards under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. The following summarizes share-based compensation expense for the years ended December 31:
	millions	2014			2013				2012
	Restricted stock	$	144		$	122			$	103
	Stock options	21			27				43
	Other equity-classified awards	1			1				1
	Value creation plan	136			—				(2		)
	Performance-based unit awards	23			4				8
	Other performance-based awards	—			—				165
	Other liability-classified awards	—			1				2
	Pretax compensation expense	$	325		$	155			$	320
	Income tax benefit	$	120		$	57			$	117
	Cash flows from financing activities included excess tax benefits related to share-based compensation of $22 million in 2014, $11 million in 2013, and $51 million in 2012. Cash received from stock option exercises was $99 million in 2014, $135 million in 2013, and $52 million in 2012.
	15. Share-Based Compensation (Continued)
	Equity-Classified Awards
	Restricted Stock  Certain employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. A restricted stock unit is equivalent to a restricted stock award except that unit holders do not have the right to vote. Restricted stock vests over service periods ranging from the date of grant up to three years and is not considered issued and outstanding until vested.
	Non-employee directors are granted deferred shares, which are also considered restricted stock, that are held in a grantor trust by the Company until payable. Non-employee directors may receive these shares in a lump-sum payment or in annual installments.
	The following summarizes the Company’s restricted stock activity:
		Shares		Weighted-
		(millions)		Average
				Grant-Date
				Fair Value
				(per share)
	Non-vested at January 1, 2014	3.22		$	82.53
	Granted	2.05		$	87.42
	Vested	(1.52	)	$	82.35
	Forfeited	(0.15	)	$	84.49
	Non-vested at December 31, 2014	3.6		$	85.31
	The weighted-average grant-date fair value per share of restricted stock granted was $84.17 during 2013 and $79.97 during 2012. The total fair value of restricted shares vested was $132 million during 2014, $110 million during 2013, and $105 million during 2012, based on the market price at the vesting date. At December 31, 2014, total unrecognized compensation cost related to restricted stock of $199 million is expected to be recognized over a weighted-average remaining service period of 1.9 years.
	15. Share-Based Compensation (Continued)
	Stock Options  Certain employees may be granted nonqualified options to purchase shares of Anadarko common stock with an exercise price equal to, or greater than, the fair market value of Anadarko common stock on the date of grant. These stock options generally vest over three years from the date of grant and terminate at the earlier of the date of exercise or seven years from the date of grant.
	The fair value of stock option awards is determined using the Black-Scholes option-pricing model with the following assumptions:
	•	Expected life—Based on historical exercise behavior.
	•	Volatility—Based on an average of historical volatility over the expected life of an option and the 12-month average implied volatility.
	•	Risk-free interest rates—Based on the U.S. Treasury rate over the expected life of an option.
	•	Dividend yield—Based on a 12-month average dividend yield, taking into account the Company’s expected dividend policy over the expected life of an option.
	•	Expected forfeiture—Based on historical forfeiture experience.
	The Company used the following weighted-average assumptions to estimate the fair value of stock options granted:
		2014				2013					2012
	Weighted-average grant-date fair value	$	23.55			$	26.27				$	25.84
	Assumptions
	Expected option life—years	4.9				4.8					4.9
	Volatility	29.9		%		33.9			%		44.2		%
	Risk-free interest rate	1.6		%		1.3			%		0.7		%
	Dividend yield	1.1		%		0.8			%		0.5		%
	The following summarizes the Company’s stock option activity:
		Shares		Weighted-				Weighted-		Aggregate
		(millions)		Average				Average		Intrinsic
				Exercise				Remaining		Value
				Price				Contractual		(millions)
				(per share)				Term
								(years)
	Outstanding at January 1, 2014	7.72		$	63.3
	Granted	0.95		$	93.34
	Exercised (1)	(1.85	)	$	54.03
	Forfeited or expired	(0.03	)	$	76
	Outstanding at December 31, 2014	6.79		$	69.96			3.56		$	104.3
	Vested or expected to vest at December 31, 2014	6.73		$	69.79			3.54		$	104.2
	Exercisable at December 31, 2014	4.99		$	62.91			2.6		$	101.1
	__________________________________________________________________
	(1)	The total intrinsic value of stock options exercised was $88 million during 2014, $80 million during 2013, and $49 million during 2012, based on the difference between the market price at the exercise date and the exercise price.
	At December 31, 2014, total unrecognized compensation cost related to stock options of $40 million is expected to be recognized over a weighted-average remaining service period of 2.2 years.
	15. Share-Based Compensation (Continued)
	Liability-Classified Awards
Value Creation Plan  As a part of its employee compensation program, the Company offers an incentive compensation program that provides non-officer employees the opportunity to earn cash bonus awards based on the Company’s TSR for the year, compared to the TSR of a predetermined group of peer companies. The Company paid zero during 2014 and 2013 related to the plan and $24 million during 2012. At December 31, 2014, the Company had $137 million outstanding liability attributable to the 2014 performance period.
Performance-Based Unit Awards  Certain officers of the Company were provided Performance Unit Award Agreements with two- and three-year performance periods. The vesting of these units is based on comparing the Company’s TSR to the TSR of a predetermined group of peer companies over the specified performance period. Each performance unit represents the value of one share of the Company’s common stock. At the end of each performance period, the value of the vested performance units, if any, is paid in cash. The Company paid $12 million related to vested performance units in 2014, $15 million in 2013, and $37 million in 2012. At December 31, 2014, the Company’s liability under Performance Unit Award Agreements was $26 million, with total unrecognized compensation cost related to these awards of $43 million expected to be recognized over a weighted-average remaining performance period of 2.2 years.
Other Performance-Based Awards  Prior to 2011, certain officers of the general partner of WES were awarded general partner Unit Appreciation Rights (UARs) pursuant to the Western Gas Holdings, LLC Equity Incentive Plan. The fair value of the UARs was determined based on the fair value of WES’s general partner, as determined by the WGP IPO price. The Company paid $203 million related to the UARs upon the WGP IPO in 2012 in settlement of obligations related to all awards then outstanding.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2014
Commitments [Abstract]
Commitments	16. Commitments
	Operating Leases  At December 31, 2014, the Company had $2.7 billion in long-term drilling rig commitments that satisfy operating lease criteria. The Company also had $324 million of various commitments under non-cancelable operating lease agreements for production platforms and equipment, buildings, facilities, compressors, and aircraft. These operating leases expire at various dates through 2026. Certain of these operating leases contain residual value guarantees at the end of the lease term, totaling $53 million at December 31, 2014. No liability has been accrued for residual value guarantees. In addition, these operating leases include options to purchase the leased property during or at the end of the lease term for the fair market value or other specified amount at that time. The following summarizes future minimum lease payments under operating leases at December 31, 2014:
	millions
	2015	$	1,022
	2016	833
	2017	592
	2018	324
	2019	203
	Later years	87
	Total future minimum lease payments	$	3,061
	Anadarko has entered into various agreements to secure drilling rigs necessary to support the execution of its drilling plans over the next several years. The table of future minimum lease payments above includes $2.5 billion related to seven offshore drilling vessels and $208 million related to certain contracts for U.S. onshore drilling rigs. Lease payments associated with the drilling of exploratory wells and development wells, net of amounts billed to partners, will initially be capitalized as a component of oil and gas properties, and either depreciated or impaired in future periods or written off as exploration expense.
	Total rent expense, net of sublease income and amounts capitalized, amounted to $85 million in 2014, $119 million in 2013, and $136 million in 2012. Total rent expense includes contingent rent expense related to transportation and processing fees of $22 million in 2014, $24 million in 2013, and $28 million in 2012.
	Other Commitments  In the normal course of business, the Company enters into other contractual agreements for processing, treating, transportation, and storage of natural gas, oil, and NGLs, as well as for other oil and gas activities. These agreements expire at various dates through 2036. At December 31, 2014, aggregate future payments under these contracts totaled $10.4 billion, of which $2.2 billion is expected to be paid in 2015, $1.6 billion in 2016, $1.3 billion in 2017, $1.2 billion in 2018, $1.0 billion in 2019, and $3.1 billion thereafter.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2014
Contingencies [Abstract]
Contingencies	17. Contingencies
	Litigation  The Company is a defendant in a number of lawsuits, is involved in governmental proceedings, and is subject to regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. The Company’s Consolidated Balance Sheets include liabilities of $5.3 billion at December 31, 2014, and $854 million at December 31, 2013, for litigation-related contingencies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial condition, results of operations, or cash flows.
	Tronox Litigation  On November 28, 2005, Tronox Incorporated (Tronox), at the time a subsidiary of Kerr-McGee Corporation, completed an IPO and was subsequently spun-off from Kerr-McGee Corporation. In August 2006, Anadarko acquired all of the stock of Kerr-McGee Corporation. In January 2009, Tronox and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court), which is the court that presided over the Adversary Proceeding (defined below). In May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) asserting several claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleged, among other things, that it was insolvent or undercapitalized at the date of its IPO and sought, among other things, to recover damages in excess of $18.85 billion from Kerr-McGee and Anadarko, as well as interest and attorneys’ fees and costs. In accordance with Tronox’s Bankruptcy Court-approved Plan of Reorganization (Plan), the Adversary Proceeding was pursued by a litigation trust (Litigation Trust). Pursuant to the Plan, the Litigation Trust was “deemed substituted” for the Tronox plaintiffs in the Adversary Proceeding. For purposes of this Form 10-K, references to “Tronox” after February 2011 refer to the Litigation Trust.
	The U.S. government intervened in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). The Litigation Trust and the U.S. government agreed that the recovery of damages under the Adversary Proceeding, if any, would cover both the Adversary Proceeding and the FDCPA Complaint.
	Liability Accrual  On April 3, 2014, Anadarko and Kerr-McGee entered into a settlement agreement with the Litigation Trust and the U.S. government (in its capacity as plaintiff-intervenor and acting for and on behalf of certain U.S. government agencies) to resolve all claims asserted in the Adversary Proceeding and FDCPA Complaint for $5.15 billion, which represents principal of approximately $3.98 billion plus 6% interest from the filing of the Adversary Proceeding on May 12, 2009, through April 3, 2014. In addition, the Company agreed to pay interest on the above amount from April 3, 2014, through the payment of the settlement, with an annual interest rate of 1.5% for the first 180 days and 1.5% plus the one-month LIBOR thereafter. Under the terms of the settlement agreement, the Litigation Trust, Anadarko, and Kerr-McGee agreed to mutually release all claims that were or could have been asserted in the Adversary Proceeding. The U.S. government (representing federal agencies that filed claims in the Tronox bankruptcy), Anadarko, and Kerr-McGee also provided covenants not to sue each other with respect to certain claims and causes of action. The U.S. government also provided contribution protection from third-party claims seeking reimbursement from Anadarko and certain of its affiliates for the sites identified in the settlement agreement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective.
	17. Contingencies (Continued)
	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 of $60 million, included in Tronox-related contingent loss in the Company’s Consolidated Statement of Income, during the year ended December 31, 2014, for an aggregate $5.2 billion Tronox-related contingent liability on the Company’s Consolidated Balance Sheet at December 31, 2014. For information on the tax effects of the Tronox settlement agreement, see Note 18—Income Taxes.
	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, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement), under which the Company paid $4.0 billion in cash and transferred its interest in the Macondo well and the Mississippi Canyon Block 252 (Lease) to BP. Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims 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 (OA). 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.
	Liability Accrual  Below is a discussion of the Company’s current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the OA (OA Liabilities), (ii) OPA-related environmental costs, and (iii) other contingent liabilities. Applicable accounting guidance requires the Company to accrue a liability if both (a) it is probable that a liability has been incurred and (b) the amount of that liability can be reasonably estimated.
	The Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and 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 has not recorded a liability for any costs that are subject to indemnification by BP.
	OA Liabilities  Pursuant to the Settlement Agreement, all amounts deemed by BP to have been due under the OA, as well as all future amounts that otherwise would be invoiced to Anadarko under the OA, have been satisfied.
	OPA-Related Environmental Costs  BP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the U.S. Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under OPA. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup. The USCG’s identification of Anadarko as an RP arises as a result of Anadarko’s status as a co-lessee in the Lease.
	Under accounting guidance applicable to environmental liabilities, a liability is presumed probable if the entity is both identified as an RP and associated with the environmental event. The Company’s co-lessee status in the Lease at the time of the event and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company’s potential environmental liabilities related to the Deepwater Horizon events are probable.
	17. Contingencies (Continued)
	As BP funds OPA-related environmental costs, any potential joint and several liability for these costs is satisfied for all RPs, including Anadarko. This bears significance in that once these costs are funded by BP, such costs are no longer analyzed as OPA-related environmental costs, but instead are analyzed as OA Liabilities. As discussed above, Anadarko has settled its OA Liabilities with BP. Thus, potential liability to the Company for OPA-related environmental costs can arise only where BP does not, or otherwise is unable to, fund all of the OPA-related environmental costs. Under this scenario, the joint and several nature of the liability for these costs could cause the Company to recognize a liability for OPA-related environmental costs. However, the Company is fully indemnified by BP against these costs (including guarantees by BPCNA or BP p.l.c.).
	Gross OPA-Related Environmental Cost Estimate  In prior periods through the fourth quarter of 2011, the Company provided an estimated range of gross OPA-related environmental costs for all identified RPs. This estimate was comprised of spill-response costs and OPA damage claims and was derived from cost information received by the Company from BP. The Company no longer receives Deepwater Horizon-related cost and claims data from BP. Accordingly, the OPA-related environmental cost estimate included in BP’s public releases is the best data available to the Company.
	Based on information included in BP p.l.c.’s public release on February 3, 2015, gross OPA-related environmental costs are estimated to be $11.0 billion, excluding (i) amounts BP has already funded, which constitute settled OA Liabilities; (ii) amounts that in BP’s view cannot reasonably be estimated, which include NRD claims and other litigation damages; (iii) non-OPA-related fines and penalties that may be assessed against Anadarko, including assessments under the Clean Water Act (CWA); and (iv) estimated state and local governmental claims, which BP no longer publicly discloses and, as a result, Anadarko cannot estimate. Actual gross OPA-related environmental costs may vary from those estimated by BP p.l.c. in its public releases, perhaps materially from the above estimate.
	Allocable Share of Gross OPA-Related Environmental Costs  Under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs. To date, BP has paid all Deepwater Horizon event-related costs, which satisfies the Company’s potential liability for these costs. Additionally, BP has repeatedly stated publicly and in congressional testimony that it will continue to pay these costs. BP’s funding and public commentary has continued subsequent to the release of BP’s own investigation report, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling’s final report, and the Deepwater Horizon Joint Investigation Team final report, which the Company considers to be significant positive indications in assessing the likelihood of BP continuing to fund all of these costs. Based on BP’s stated intent to continue funding these costs, the Company’s assessment of BP’s financial ability to continue funding these costs, and the impact of BP’s settlements with both of its OA partners, the Company believes the likelihood of BP not continuing to satisfy these claims to be remote. Accordingly, the Company considers zero to be its allocable share of gross OPA-related environmental costs and, consistent with applicable accounting guidance, has not recorded a liability for these amounts.
	17. Contingencies (Continued)
	Penalties and Fines  These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the CWA, the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company. To date, no penalties or fines have been assessed against the Company. However, 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 in New Orleans, Louisiana (Louisiana District Court) against several parties, including the Company, seeking an assessment of civil penalties under the 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, which was affirmed in June 2014 by the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit), addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko will follow a bench trial, which began in January 2015.
	In July 2014, Anadarko filed a motion for rehearing with the Fifth Circuit requesting that the full court sit to reconsider Anadarko’s appeal concerning that portion of the February 2012 declaratory judgment which found Anadarko liable for civil penalties under the CWA. In September 2014, Anadarko filed a letter notifying the Fifth Circuit that the Louisiana District Court issued Findings of Fact and Conclusions of Law in the first phase of the Deepwater Horizon trial (Phase I Findings and Conclusions), which included facts that contradict certain key facts assumed by the Fifth Circuit panel in its June 2014 decision. In January 2015, the Fifth Circuit denied the petition for full court reconsideration with six of the thirteen participating justices filing a dissent.
	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 December 31, 2014. However, the Company may ultimately incur a liability related to CWA penalties in excess of the current accrued liability.
	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 following the bench trial. The CWA sets forth subjective criteria to be considered by the court in assessing the magnitude of any CWA penalty, including the degree of fault of the owner. In the Phase I and II trials (defined 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 may be presented. In addition, in its 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. However, given the Company’s lack of direct operational involvement in the event, the Louisiana District Court’s rulings excluding any evidence of Anadarko’s alleged culpability or fault, the Phase I Findings and Conclusions that did not allocate any fault to Anadarko, and the subjective criteria of the CWA, the Company believes that any CWA penalties assessed to it will not materially impact the Company’s financial condition, results of operations, or cash flows.
	17. Contingencies (Continued)
	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 (i) an assessment by the DOJ, (ii) a ruling by a court of competent jurisdiction, or (iii) 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. For example, eleven Louisiana Parish District Attorneys appealed that decision to the Fifth Circuit. In February 2014, the Fifth Circuit denied the appeal and upheld the Louisiana District Court’s decision. In October 2014, the United States Supreme Court denied the Parish District Attorneys’ petition to review the case. While that denial ends further appeal of that decision by the eleven Parish District Attorneys, any other party subject to the decision who has not yet appealed, including private parties who opted out of the BP settlement, the states, and other local governments, may do so after obtaining a final judgment on their damages claims. If any further appeal is taken and is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.
	Natural Resource Damages  This category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.
	The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior (DOI), and the Department of Defense. These governmental departments, along with the five affected states – Alabama, Florida, Louisiana, Mississippi, and Texas – are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning.
	The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related state law claims against the Company in the Louisiana District Court. In November 2011, after ruling that only federal law applies, the Louisiana District Court dismissed all the NRD-related state law claims asserted against the Company by the states of Alabama and Louisiana. In April 2013, the states of Texas and Mississippi filed NRD-related state law claims against the Company, which were consolidated in the federal Multidistrict Litigation (MDL) action before the Louisiana District Court discussed below and are stayed until further order of the Louisiana District Court.
	NRD claims are generally sought after the damage assessment and restoration planning is completed, which may take several years. Thus, the Company remains unable to reasonably estimate the magnitude of any NRD claim. The Company anticipates that BP will satisfy any NRD claim, which eliminates any potential liability to Anadarko for such costs. In the event any NRD damage claim is made directly against Anadarko, the Company is fully indemnified by BP against such claims (including guarantees by BPCNA or BP p.l.c.).
	Civil Litigation Damage Claims  Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the States of Alabama, Louisiana, Texas, and Mississippi, and several of their political subdivisions; the DOJ; environmental non-governmental organizations; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief.
	17. Contingencies (Continued)
	This litigation has been consolidated into a federal MDL action pending before Judge Carl Barbier in the Louisiana District Court. In March 2012, BP and the Plaintiffs’ Steering Committee (PSC) entered into a settlement agreement to resolve a substantial majority of the economic loss and medical claims stemming from the Deepwater Horizon events, which the Louisiana District Court approved in orders issued in December 2012 and January 2013. Only OPA claims seeking economic loss damages against the Company remain. In addition, other than those who previously appealed unsuccessfully, certain state and local governments have 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. Certain Mexican states also have appealed the dismissal of their claims against BP, the Company, and others. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.
	The first phase of the trial in the MDL (Phase I) commenced in February 2013. The PSC, BP, BP America Production Company (BPAP), BP p.l.c., the United States, state and local governments, Halliburton Energy Services, Inc. (Halliburton), and certain subsidiaries of Transocean Ltd. (Transocean) participated in Phase I. Anadarko was excused from participation in Phase I. 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 BPAP, Transocean, and 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. BP is challenging certain of the Louisiana District Court’s findings.
	The second phase of trial (Phase II) began in September 2013 and in November 2013 the parties rested their Phase II cases. 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. The Company, the PSC, BP, BPAP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean participated in Phase II of the trial. In January 2015, the Louisiana District Court issued its Phase II Findings of Fact and Conclusions of Law. 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 penalty phase of the trial began in January 2015. Post-trial briefs are due in March and April 2015. The trial included Anadarko, BP, and the United States, and will assess findings and penalties under the CWA. 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 State of Alabama previously brought actions against the Company and other parties for claims arising from the Deepwater Horizon event, including claims for penalties and fines under state environmental laws, which were subsequently dismissed by the Louisiana District Court. The Louisiana District Court has selected this case as its test case for valuing the damages sought by states for claims under federal laws arising from the Deepwater Horizon event. Trial is set for November 2015 and the parties are conducting discovery. The Louisiana District Court’s previous rulings apply to Alabama’s claims, including the court’s decision that only federal law, and not state law, applies; its decision allocating fault and liability among BP and BPAP, Transocean, and Halliburton; and its orders precluding evidence of alleged culpability by Anadarko, leaving only damages to be decided. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages.
	17. Contingencies (Continued)
	Two separate class-action complaints were filed in June and August 2010, in the New York District Court on behalf of purported purchasers of the Company’s stock between June 12, 2009, and June 9, 2010, against Anadarko and certain of its officers. The consolidated action was subsequently transferred to the U.S. District Court for the Southern District of Texas - Houston Division (Texas District Court). The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In March 2014, the parties reached a settlement in this matter, which was approved by the Texas District Court in September 2014. The settlement was directly funded by the Company’s insurers.
	Remaining Liability Outlook  It is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties and certain other claims not covered by the indemnification provisions of the Settlement Agreement; however, the Company does not believe that any potential liability attributable to the foregoing items, individually or in the aggregate, will have a material impact on the Company’s financial condition, results of operations, or cash flows. This assessment takes into account certain qualitative factors, including the subjective and fault-based nature of CWA penalties, the Company’s indemnification by BP against certain damage claims as discussed above and BP’s creditworthiness.
	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 as well as federal investigations 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.
	Deepwater Horizon and Tronox Derivative Claims  In May 2013, an Anadarko shareholder filed a derivative action in the 215th District Court of Harris County, Texas (215th District Court) against Anadarko and certain current and former directors and officers (DWH Derivative Action). The shareholder purported to bring claims on behalf of Anadarko and alleged, among other things, that certain current and former directors and officers breached their fiduciary duty in connection with the Company’s investment in the Macondo lease.
	In addition, in April 2014, the Company’s Board of Directors received a letter from a current shareholder demanding that the Board undertake an independent investigation of certain current and former officers and directors for alleged breach of fiduciary duty related to the Company’s April 2014 settlement of the Tronox Adversary Proceeding (Tronox Derivative Demand).
	In May 2014, the parties reached an agreement to jointly resolve the DWH Derivative Action and the Tronox Derivative Demand in one settlement. In order to achieve the joint settlement, the petition in the DWH Derivative Action was amended to include the allegations asserted in the Tronox Derivative Demand. In August 2014, the 215th District Court approved the settlement. The settlement did not have a material impact on the Company’s financial condition, results of operations, or cash flows.
	17. Contingencies (Continued)
	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. Currently, $128 million, the amount of tax originally in dispute, resides in a judicially controlled Brazilian bank account pending final resolution of the matter and is included in other assets on the Company’s Consolidated Balance Sheet at December 31, 2014.
	In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court’s ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior Court and the Brazilian Supreme Court. The Brazilian Superior Court and the Brazilian Supreme Court have agreed to hear the case and the Company currently is awaiting the setting of initial hearing dates. 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 $42 million, the amount of tax currently in dispute, and any interest on such amount.
	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 December 31, 2014. The Company continues to vigorously defend its position in Brazilian courts.
	Guarantees and Indemnifications  The Company provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation, or tax matters existing at the date of disposition. In 2013, as a result of a Chapter 11 bankruptcy declaration by a third party, the DOI ordered Anadarko to perform the decommissioning of a production facility and related wells, which were previously sold to the third party. During 2013, the Company accrued costs of $117 million to decommission the production facility and related wells, reported in other (income) expense, net in the Consolidated Statement of Income. During 2014, the Company recognized a $22 million increase in the estimated decommissioning costs. Anadarko completed decommissioning of the production facility in 2014 and expects to complete decommissioning of the wells in 2015. Decommissioning obligations of $114 million were included in accrued expenses on the Consolidated Balance Sheet at December 31, 2014. Actual costs may vary from this estimate; however, the Company does not believe that any such change will materially impact its financial condition, results of operations, or cash flows.
	Environmental Matters  Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. The Company’s Consolidated Balance Sheets include liabilities for remediation and reclamation obligations of $126 million at December 31, 2014 and December 31, 2013. The current portion of these amounts was included in accounts payable and the long-term portion of these amounts was included in other long-term liabilities—other on the Company’s Consolidated Balance Sheets. The Company continually monitors remediation and reclamation processes and adjusts its liability for these obligations as necessary.
	The Company is one of numerous parties previously notified by the California Department of Toxic Substances Control (DTSC) that, as a result of a prior acquisition, it is a potentially responsible party with respect to a landfill located in West Covina, California. While no agreement is in place with the DTSC, the Company recorded a $50 million restoration liability in 2013 with respect to the site, representing the current estimated obligation, which is included in the Company’s liability balance at December 31, 2014. The Company could incur additional obligations if any of the potentially responsible parties are ultimately not able to fund their allocated share of the costs or if the DTSC requires a more costly remedial approach. It is possible that the Company’s current estimate of probable loss related to this matter could change, perhaps materially, in the future.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	18. Income Taxes
	The following summarizes components of income tax expense (benefit) for the years ended December 31:
	millions	2014				2013				2012
	Current
	Federal	$	188			$	113			$	45
	State	2				42				25
	Foreign	1,574				873				891
		1,764				1,028				961
	Deferred
	Federal	(389		)		94				(30		)
	State	27				(9		)		115
	Foreign	215				52				74
		(147		)		137				159
	Total income tax expense (benefit)	$	1,617			$	1,165			$	1,120
	Total income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate to income (loss) before income taxes. The following summarizes the sources of these differences for the years ended December 31:
	millions except percentages	2014				2013				2012
	Income (loss) before income taxes
	Domestic	$	(3,564	)		$	428			$	132
	Foreign	3,618				1,678				3,433
	Total	$	54			$	2,106			$	3,565
	U.S. federal statutory tax rate	35		%		35		%		35		%
	Tax computed at the U.S. federal statutory rate	$	19			$	737			$	1,248
	Adjustments resulting from
	State income taxes (net of federal income tax benefit)	(11		)		23				93
	Tax impact from foreign operations	62				204				215
	Non-deductible Algerian exceptional profits tax	193				144				188
	Non-taxable Algeria exceptional profits tax settlement	—				13				(679		)
	Net changes in uncertain tax positions	1,427				(29		)		28
	Deferred tax adjustments	15				76				22
	Non-deductible Tronox-related contingent loss	(36		)		36				—
	Income attributable to noncontrolling interests	(66		)		(48		)		(24		)
	Non-deductible Deepwater Horizon settlement	32				—				—
	Federal manufacturing deduction	(27		)		—				—
	Non-deductible goodwill	21				—				15
	Other—net	(12		)		9				14
	Total income tax expense (benefit)	$	1,617			$	1,165			$	1,120
	Effective tax rate	2,994		%		55		%		31		%
	18. Income Taxes (Continued)
	The following summarizes components of total deferred taxes at December 31:
	millions	2014				2013
	Federal	$	(7,649	)		$	(8,246	)
	State, net of federal	(341		)		(332		)
	Foreign	(537		)		(307		)
	Total deferred taxes	$	(8,527	)		$	(8,885	)
	The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31:
	millions	2014				2013
	Current deferred tax assets	$	210			$	412
	Settlement agreement related to the Tronox Adversary Proceeding	590				—
	Valuation allowances on deferred tax assets not expected to be realized	(78		)		(52		)
	Net current deferred tax assets	722				360
	Oil and gas exploration and development operations	(8,418		)		(8,213		)
	Mineral operations	(412		)		(410		)
	Midstream and other depreciable properties	(1,611		)		(1,586		)
	Other	(351		)		(499		)
	Gross long-term deferred tax liabilities	(10,792		)		(10,708		)
	Oil and gas exploration and development costs	177				94
	Net operating loss carryforward	558				599
	Foreign tax credit carryforward and alternative minimum tax credit carryforward	166				325
	Other	1,428				1,211
	Gross long-term deferred tax assets	2,329				2,229
	Valuation allowances on deferred tax assets not expected to be realized	(786		)		(766		)
	Net long-term deferred tax assets	1,543				1,463
	Net long-term deferred tax liabilities	(9,249		)		(9,245		)
	Total deferred taxes	$	(8,527	)		$	(8,885	)
Changes to valuation allowances, due to changes in judgment regarding the future realizability of deferred tax assets, were an increase of $2 million in 2013 and $23 million in 2012. There were no changes to valuation allowances due to changes in judgment regarding the future realizability of deferred tax assets in 2014.
The following summarizes changes in the balance of valuation allowances on deferred tax assets:
millions	2014				2013				2012
Balance at January 1	$	(818	)		$	(922	)		$	(555	)
Additions	(59		)		(38		)		(426		)
Reductions	13				142				59
Balance at December 31	$	(864	)		$	(818	)		$	(922	)
18. Income Taxes (Continued)
The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31:
Balance Sheet Classification		2014				2013
Income taxes receivable
Accounts receivable—other		$	93			$	66
Other assets		35				35
		128				101
Income taxes (payable)
Accrued expense		(152		)		(82		)
Total net income taxes receivable (payable)		$	(24	)		$	19
Tax carryforwards available for use on future income tax returns at December 31, 2014, were as follows:
millions	Domestic				Foreign				Expiration
Net operating loss—foreign	$	—			$	1,165			2015 - Indefinite
Net operating loss—state	$	4,477			$	—			2015-2034
Foreign tax credits	$	167			$	—			2022-2023
Texas margins tax credit	$	34			$	—			2026
Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:
	Assets (Liabilities)
millions	2014				2013				2012
Balance at January 1	$	(147	)		$	(46	)		$	(31	)
Increases related to prior-year tax positions	(11		)		(54		)		(17		)
Decreases related to prior-year tax positions	39				3				3
Increases related to current-year tax positions	(1,568		)		(72		)		(1		)
Settlements	—				5				—
Lapse of statute of limitations	—				17				—
Balance at December 31	$	(1,687	)		$	(147	)		$	(46	)
Included in the 2014 ending balance of unrecognized tax benefits presented above are potential benefits of $1.679 billion, of which, if recognized, $1.456 billion would affect the effective tax rate on income, and $188 million would be in the form of tax credits and net operating loss carryforwards that would attract a full valuation allowance. Also included in the 2014 ending balance are benefits of $8 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain.
18. Income Taxes (Continued)
In 2013, the Company recognized a deferred tax benefit of $274 million related to the $850 million loss for the Tronox-related contingent liability. In 2014, the Company recognized a deferred tax benefit of $316 million related to the additional $4.360 billion loss for the Tronox-related contingent liability. The total deferred tax benefit of $590 million is net of a $1.326 billion uncertain tax position due to the uncertainty related to the deductibility of the settlement payment. This uncertain tax position is presented in deferred income taxes and as a reduction to the associated deferred tax asset. 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 17—Contingencies—Tronox Litigation.
Income tax audits and the Company’s acquisition and divestiture activity have given rise to tax disputes in U.S. and foreign jurisdictions. See Note 17—Contingencies—Other Litigation. The Company estimates that $120 million to $130 million of unrecognized tax benefits related to adjustments to taxable income and credits previously recorded pursuant to the accounting standard for accounting for tax uncertainties will reverse within the next 12 months due to expiration of statutes of limitation and audit settlements. Management does not believe that the final resolution of outstanding tax audits and litigation will have a material adverse effect on the Company’s consolidated financial condition, results of operations, or cash flows.
The Company had accrued approximately $9 million of interest related to uncertain tax positions at December 31, 2014, and $8 million at December 31, 2013. The Company recognized interest and penalties in income tax expense (benefit) of $1 million during 2014 and $(20) million during 2013.
Anadarko is subject to audit by tax authorities in the U.S. federal, state, and local tax jurisdictions as well as in various foreign jurisdictions. The Company is currently under routine examination by the IRS for the tax years 2008 through 2014.
The following lists the tax years subject to examination by major tax jurisdiction:
	Tax Years
United States	2008-2014
Algeria	2011-2014
Ghana	2006-2014

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	19. Supplemental Cash Flow Information
	The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities for the years ended December 31:
	millions	2014			2013			2012
	Cash paid (received)
	Interest, net of amounts capitalized	$	689		$	627		$	684
	Income taxes, net of refunds	956			169			(300		)
	Non-cash investing activities
	Fair value of properties and equipment from non-cash transactions	$	18		$	62		$	65
	Asset retirement cost additions	348			297			142
	Accruals of property, plant, and equipment	1,156			1,446			1,205
	Net liabilities assumed or divested in acquisitions and divestitures	(92		)	(80		)	(34		)
	Non-cash investing and financing activities
	Capital lease obligation	$	13		$	8		$	—
	Floating production, storage, and offloading vessel construction	149			17			—
	period obligation

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment Information	20. 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.
	20. Segment Information (Continued)
	To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; exploration expense; 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, Algeria exceptional profits tax settlement, 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 for the years ended December 31:
	millions	2014			2013			2012
	Income (loss) before income taxes	$	54		$	2,106		$	3,565
	Exploration expense	1,639			1,329			1,946
	DD&A	4,550			3,927			3,964
	Impairments	836			794			389
	Interest expense	772			686			742
	Total (gains) losses on derivatives, net, less net cash from	578			(307		)	443
	settlement of commodity derivatives
	Deepwater Horizon settlement and related costs	97			15			18
	Algeria exceptional profits tax settlement	—			33			(1,797		)
	Tronox-related contingent loss	4,360			850			(250		)
	Certain other nonoperating items	22			110			—
	Less net income attributable to noncontrolling interests	187			140			54
	Consolidated Adjusted EBITDAX	$	12,721		$	9,403		$	8,966
	20. Segment Information (Continued)
	The Company’s accounting policies for individual segments are the same as those described in the summary of significant accounting policies, with the following exception: certain intersegment commodity contracts may meet the GAAP definition of a derivative instrument, which would be accounted for at fair value under GAAP. However, Anadarko does not recognize any mark-to-market adjustments on such intersegment arrangements. Additionally, intersegment asset transfers are accounted for at historical cost basis, and do not give rise to gain or loss recognition.
	Information presented below as “Other and Intersegment Eliminations” includes corporate costs, 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			Midstream			Marketing			Other and			Total
		Exploration									Intersegment
		& Production									Eliminations
	2014
	Sales revenues	$	8,603		$	484		$	7,288		$	—		$	16,375
	Intersegment revenues	6,225			1,338			(6,771		)	(792		)	—
	Gains (losses) on divestitures and other, net	1,893			(3		)	—			205			2,095
	Total revenues and other	16,721			1,819			517			(587		)	18,470
	Operating costs and expenses (1)	4,216			972			740			17			5,945
	Net cash from settlement of	—			—			—			(377		)	(377		)
	commodity derivatives
	Other (income) expense, net (2)	—			—			—			(2		)	(2		)
	Net income attributable to noncontrolling	—			187			—			—			187
	interests
	Total expenses and other	4,216			1,159			740			(362		)	5,753
	Total (gains) losses on derivatives, net	—			—			4			—			4
	included in marketing revenue, less net
	cash from settlement
	Adjusted EBITDAX	$	12,505		$	660		$	(219	)	$	(225	)	$	12,721
	Net properties and equipment	$	32,717		$	6,697		$	—		$	2,175		$	41,589
	Capital expenditures	$	7,934		$	1,149		$	—		$	173		$	9,256
	Goodwill	$	5,123		$	453		$	—		$	—		$	5,576
	__________________________________________________________________
	(1)	Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement 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.
	20. Segment Information (Continued)
	millions	Oil and Gas			Midstream			Marketing			Other and			Total
		Exploration									Intersegment
		& Production									Eliminations
	2013
	Sales revenues	$	7,090		$	387		$	7,390		$	—		$	14,867
	Intersegment revenues	6,405			1,105			(6,859		)	(651		)	—
	Gains (losses) on divestitures and other, net	(622		)	(1		)	—			337			(286		)
	Total revenues and other	12,873			1,491			531			(314		)	14,581
	Operating costs and expenses (1)	3,635			843			652			20			5,150
	Net cash from settlement of	—			—			—			(95		)	(95		)
	commodity derivatives
	Other (income) expense, net (2)	—			—			—			(21		)	(21		)
	Net income attributable to noncontrolling	—			140			—			—			140
	interests
	Total expenses and other	3,635			983			652			(96		)	5,174
	Total (gains) losses on derivatives, net	—			—			(4		)	—			(4		)
included in marketing revenue, less net
cash from settlement
Adjusted EBITDAX	$	9,238		$	508		$	(125	)	$	(218	)	$	9,403
Net properties and equipment	$	33,409		$	5,408		$	9		$	2,103		$	40,929
Capital expenditures	$	7,008		$	1,248		$	—		$	267		$	8,523
Goodwill	$	5,317		$	175		$	—		$	—		$	5,492
2012
Sales revenues	$	6,752		$	325		$	6,230		$	—		$	13,307
Intersegment revenues	5,318			959			(5,734		)	(543		)	—
Gains (losses) on divestitures and other, net	(65		)	(8		)	—			177			104
Total revenues and other	12,005			1,276			496			(366		)	13,411
Operating costs and expenses (1)	3,505			748			616			295			5,164
Net cash from settlement of	—			—			—			(753		)	(753		)
commodity derivatives
Other (income) expense, net	—			—			—			(4		)	(4		)
Net income attributable to noncontrolling	—			54			—			—			54
interests
Total expenses and other	3,505			802			616			(462		)	4,461
Total (gains) losses on derivatives, net	—			—			16			—			16
included in marketing revenue, less net
cash from settlement
Adjusted EBITDAX	$	8,500		$	474		$	(104	)	$	96		$	8,966
Net properties and equipment	$	32,024		$	4,459		$	9		$	1,906		$	38,398
Capital expenditures	$	5,906		$	1,250		$	—		$	155		$	7,311
Goodwill	$	5,317		$	175		$	—		$	—		$	5,492
__________________________________________________________________
(1)	Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement 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.
20. Segment Information (Continued)
The following represents Anadarko’s sales revenues (based on the origin of the sales) and net properties and equipment by geographic area:
	Years Ended December 31,
millions	2014			2013			2012
Sales Revenues
United States	$	13,083		$	11,290		$	9,911
Algeria	2,435			2,184			2,182
Other International	857			1,393			1,214
Total sales revenues	$	16,375		$	14,867		$	13,307
	December 31,
millions	2014			2013
Net Properties and Equipment
United States	$	37,186		$	35,486
Algeria	1,431			1,582
Other International	2,972			3,861
Total net properties and equipment	$	41,589		$	40,929
Major Customers  In 2014, there were no sales to individual customers that exceeded 10% of the Company’s total sales revenues. Sales to Total S.A. were $2.0 billion in 2013 and $1.9 billion in 2012. These amounts are included in the oil and gas exploration and production reporting segment.

Pension_Plans_Other_Postretire

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans	21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans
	The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is non-contributory.
	While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2014, the Company monitors the status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. During 2014, the Company made contributions of $106 million to its funded pension plans, $15 million to its unfunded pension plans, and $15 million to its unfunded other postretirement benefit plans. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. The Company expects to contribute $5 million to its funded pension plans, $24 million to its unfunded pension plans, and $16 million to its unfunded other postretirement benefit plans in 2015.
	21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
	The following sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2014 and 2013, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2014 and 2013:
		Pension Benefits								Other Benefits
	millions	2014				2013				2014			2013
	Change in benefit obligation
	Benefit obligation at beginning of year	$	2,158			$	2,297			$	294		$	359
	Service cost	99				85				7			9
	Interest cost	99				78				15			14
	Actuarial (gain) loss	337				(156		)		72			(74		)
	Participant contributions	1				—				4			4
	Benefit payments	(159		)		(149		)		(19		)	(18		)
	Foreign-currency exchange-rate changes	(7		)		3				—			—
	Benefit obligation at end of year (1)	$	2,528			$	2,158			$	373		$	294
	Change in plan assets
	Fair value of plan assets at beginning of year	$	1,754			$	1,462			$	—		$	—
	Actual return on plan assets	111				278				—			—
	Employer contributions	121				160				15			14
	Participant contributions	1				—				4			4
	Benefit payments	(159		)		(149		)		(19		)	(18		)
	Foreign-currency exchange-rate changes	(10		)		3				—			—
	Fair value of plan assets at end of year	$	1,818			$	1,754			$	—		$	—
	Funded status of the plans at end of year	$	(710	)		$	(404	)		$	(373	)	$	(294	)
	Total recognized amounts in the balance sheet consist of
	Other assets	$	41			$	37			$	—		$	—
	Accrued expenses	(24		)		(19		)		(15		)	(15		)
	Other long-term liabilities—other	(727		)		(422		)		(358		)	(279		)
	Total	$	(710	)		$	(404	)		$	(373	)	$	(294	)
	Total recognized amounts in accumulated other
	comprehensive income consist of
	Prior service cost (credit)	$	(1	)		$	(1	)		$	2		$	2
	Net actuarial (gain) loss	740				441				1			(78		)
	Total	$	739			$	440			$	3		$	(76	)
	__________________________________________________________________
	(1)	The accumulated benefit obligation for all defined-benefit pension plans was $2.1 billion at December 31, 2014, and $1.8 billion at December 31, 2013.
	21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
	The following summarizes the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets for the years ended December 31:
	millions	2014				2013
	Projected benefit obligation	$	2,403			$	2,047
	Accumulated benefit obligation	2,024				1,742
	Fair value of plan assets	1,652				1,606
	The following summarizes the Company’s pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31:
		Pension Benefits											Other Benefits
	millions	2014				2013				2012			2014				2013		2012
	Components of net periodic benefit cost
	Service cost	$	99			$	85			$	76		$	7			$	9	$	9
	Interest cost	99				78				85			15				14		16
	Expected return on plan assets	(106		)		(91		)		(91		)	—				—		—
	Amortization of net actuarial loss (gain)	34				118				93			(7		)		—		—
	Amortization of net prior service cost (credit)	—				—				—			—				1		2
	Settlement loss	—				14				—			—				—		—
	Net periodic benefit cost	$	126			$	204			$	163		$	15			$	24	$	27
	Amounts recognized in other comprehensive
	income (expense)
	Net actuarial gain (loss)	$	(333	)		$	342			$	(156	)	$	(72	)		$	74	$	1
	Amortization of net actuarial (gain) loss	34				118				93			(7		)		—		—
	Amortization of net prior service cost (credit)	—				—				—			—				1		2
	Settlement loss	—				14				—			—				—		—
	Total amounts recognized in other	$	(299	)		$	474			$	(63	)	$	(79	)		$	75	$	3
	comprehensive income (expense)
	In 2015, an estimated $49 million of net actuarial loss for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost.
	The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations at December 31:
	Pension Benefits						Other Benefits
	2014			2013			2014			2013
Discount rate	4	%		4.75	%		4.25	%		5.25	%
Rates of increase in compensation levels	5.25	%		5	%		5.25	%		5.25	%
21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. Assumed rates of compensation increases for active participants vary by age group, with the resulting weighted-average assumed rate (weighted by the plan-level benefit obligation) provided in the preceding table.
The following summarizes the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost:
	Pension Benefits									Other Benefits
	2014			2013			2012			2014		2013			2012
Discount rate	4.75	%		3.5	%		4.5	%		5.25	%	4	%		4.75	%
Long-term rate of return on plan assets	6.75	%		7	%		7	%		N/A		N/A			N/A
Rates of increase in compensation levels	5	%		4.5	%		4.5	%		5.25	%	4.5	%		4.5	%
At December 31, 2014 and December 31, 2013, an 8.00% annual rate of increase in the per-capita cost of covered health care benefits for the next year was assumed for purposes of measuring other postretirement benefit obligations. This rate is expected to gradually decrease to 5.00% in 2020 and beyond. The assumed health care cost trend rate can have a significant effect on the cost and obligation amounts reported for the health care plan. A 1% change in the assumed health care cost trend rate over the projected period would have the following effects:
millions	1% Increase				1% Decrease
Effect on total of service and interest cost components	$	3			$	(2	)
Effect on other postretirement benefit obligation	$	40			$	(33	)
21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Plan Assets
Investment Policies and Strategies  The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (domestic equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 45%-55% equity securities, 20%-30% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines.
Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ collective fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2014 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach, while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, and inflation. Returns on fixed-income securities are generally developed based on expected inflation, real bond yield, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are derived from their relationship to the equity and fixed-income markets.
21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The fair value of the Company’s pension plan assets by asset class and input level within the fair-value hierarchy were as follows:
millions
December 31, 2014	Level 1				Level 2				Level 3			Total
Investments
Cash and cash equivalents	$	3			$	53			$	—		$	56
Fixed income
Mortgage-backed securities	—				51				—			51
U.S. government securities	—				56				—			56
Other fixed-income securities (1)	48				212				—			260
Equity securities
Domestic	446				130				—			576
International	124				299				—			423
Other
Real estate	—				56				94			150
Private equity	—				—				84			84
Hedge funds and other alternative strategies	9				—				126			135
Other	$	—			$	30			$	—		$	30
Total investments (2)	$	630			$	887			$	304		$	1,821
Liabilities
Hedge funds and other alternative strategies	$	(3	)		$	—			$	—		$	(3	)
Total liabilities	$	(3	)		$	—			$	—		$	(3	)
December 31, 2013
Investments
Cash and cash equivalents	$	17			$	80			$	—		$	97
Fixed income
Mortgage-backed securities	—				54				—			54
U.S. government securities	—				52				—			52
Other fixed-income securities (1)	42				197				—			239
Equity securities
Domestic	445				116				—			561
International	148				303				—			451
Other
Real estate	—				47				86			133
Private equity	—				—				72			72
Hedge funds and other alternative strategies	31				—				79			110
Total investments (2)	$	683			$	849			$	237		$	1,769
Liabilities
Hedge funds and other alternative strategies	$	(17	)		$	—			$	—		$	(17	)
Total liabilities	$	(17	)		$	—			$	—		$	(17	)
__________________________________________________________________
(1)	Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities.
(2)	Amount excludes receivables and payables, primarily related to Level 1 investments.
21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Investments in securities traded in active markets are measured based on quoted prices, which represent Level 1 inputs. Investments based on Level 2 inputs include direct investments in corporate debt and other fixed-income securities, as well as shares of open-end mutual funds or similar investment vehicles that do not have a readily determinable fair value, but are valued at the net asset value per share (NAV). For such funds, the NAV is the value at which investors transact with the fund, and is determined by the fund based on the estimated fair values of the underlying fund assets. Fair value of investments included as Level 3 inputs generally also reflect investments valued at fund NAVs, but, unlike investments characteristic of Level 2 fair-value measurements, such plan assets have significant liquidity restrictions or other features that are not reflected in NAV.
The following summarizes changes in the fair value of investments based on Level 3 inputs:
millions	Hedge Funds				Private				Real Estate			Total
	and Other				Equity
	Alternative
	Strategies
Balance at January 1, 2013	$	77			$	64			$	78		$	219
Acquisitions (dispositions), net	(6		)		—				2			(4		)
Actual return on plan assets
Relating to assets sold during the reporting period	1				4				—			5
Relating to assets still held at the reporting date	7				4				6			17
Balance at December 31, 2013	$	79			$	72			$	86		$	237
Acquisitions (dispositions), net	42				—				2			44
Actual return on plan assets
Relating to assets sold during the reporting period	2				5				—			7
Relating to assets still held at the reporting date	3				7				6			16
Balance at December 31, 2014	$	126			$	84			$	94		$	304
Risks and Uncertainties  The plan assets include various investment securities that are exposed to various risks, such as interest-rate, credit, and market risks. Due to the level of risk associated with certain investment securities, it is possible that changes in the values of investment securities could significantly impact the plan assets.
The plan assets may include securities with contractual cash flows, such as asset-backed securities, collateralized mortgage obligations, and commercial mortgage-backed securities, including securities backed by subprime mortgage loans. The value, liquidity, and related income of those securities are sensitive to changes in economic conditions, including real estate values, delinquencies or defaults, or both, and may be adversely affected by shifts in the market’s perception of the issuers and changes in interest rates.
21. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Expected Benefit Payments
The following summarizes estimated benefit payments for the next ten years, including benefit increases due to continuing employee service:
millions	Pension				Other
	Benefit				Benefit
	Payments				Payments
2015	$	162			$	16
2016	175				17
2017	199				18
2018	194				18
2019	216				19
2020-2024	1,192				109
Defined-Contribution Plans  The Company maintains several defined-contribution benefit plans, the most significant of which is the Anadarko Employee Savings Plan (ESP). All regular employees of the Company on its U.S. payroll are eligible to participate in the ESP by making elective contributions that are matched by the Company, subject to certain limitations. The Company recognized expense of $76 million for 2014, $78 million for 2013, and $55 million for 2012, related to these plans.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Consolidation	Basis of Presentation  The Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States. The Consolidated Financial Statements include the accounts of Anadarko and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Anadarko has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Certain prior-period amounts have been reclassified to conform to the current-year presentation.
	Noncontrolling Interests  Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 9—Noncontrolling Interests.
Use of Estimates	Use of Estimates  The preparation of financial statements in accordance with generally accepted accounting principles in the United States (GAAP) requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; 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.
Fair Value	Fair Value  Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
	Level 1—Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
	Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
	Level 3—Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).
	In determining fair value, the Company uses observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value.
	1. Summary of Significant Accounting Policies (Continued)
	In arriving at fair-value estimates, the Company uses relevant observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. For Anadarko, recurring fair-value measurements are performed for interest-rate derivatives, commodity derivatives, and investments in trading securities.
	The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 12—Debt and Interest Expense, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.
	Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, asset retirement obligations, exit or disposal costs, and capital lease assets where the present value of lease payments is greater than the fair value of the leased asset.
Revenues	Revenues  The Company’s natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. Oil and condensate are sold primarily to marketers, gatherers, and refiners. NGLs are sold primarily to direct end-users, refiners, and marketers.
	The Company recognizes sales revenues for natural gas, oil and condensate, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.
	Anadarko provides gathering, processing, treating, and transporting services pursuant to a variety of contracts. Under these arrangements, the Company receives fees, or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time the services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.
	Marketing margins related to the Company’s production are included in natural-gas sales, oil and condensate sales, and NGLs sales. Marketing margins related to sales of commodities purchased from third parties and gains and losses on derivatives related to such marketing activities are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.
	The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These transactions are reported on a net basis and included in oil and gas transportation in the Consolidated Statements of Income.
Cash Equivalents	Cash Equivalents  The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Accounts Receivable and Allowance for Uncollectible Accounts	Accounts Receivable and Allowance for Uncollectible Accounts  The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based on these analyses, the Company may require a standby letter of credit or a financial guarantee. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued.
Inventories	Inventories  Commodity inventories are stated at the lower of average cost or market.
Properties and Equipment	Properties and Equipment  Properties and equipment are stated at cost less accumulated depreciation, depletion, and amortization expense (DD&A). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gain or loss is recognized in gains (losses) on divestitures and other, net.
Oil and Gas Properties	Oil and Gas Properties  The Company applies the successful efforts method of accounting for oil and gas properties. Exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are charged against earnings as incurred. If an exploratory well provides evidence to justify potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally in deepwater and international locations) depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
	Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average lease terms at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense in the Consolidated Statements of Income.
Capitalized Interest	Capitalized Interest  For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principle operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 12—Debt and Interest Expense.
Asset Retirement Obligations	Asset Retirement Obligations  Asset retirement obligations (AROs) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. See Note 7—Asset Retirement Obligations.
Impairments	Impairments  Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. See Note 5—Impairments.
Depreciation, Depletion, and Amortization	Depreciation, Depletion, and Amortization  Costs of drilling and equipping successful wells, costs to construct or acquire facilities other than offshore platforms, associated asset retirement costs, and capital lease assets used in oil and gas activities are depreciated using the unit-of-production (UOP) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the UOP method. All other properties are stated at historical acquisition cost, net of impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 40 years for buildings, and up to 47 years for gathering facilities.
Goodwill	Goodwill is subject to annual impairment testing at October 1 (or more frequent testing as circumstances dictate). Anadarko has allocated goodwill to the following reporting units: oil and gas exploration and production, other gathering and processing, Western Gas Partners, LP (WES) gathering and processing, and WES transportation. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures. See Note 8—Goodwill and Other Intangible Assets.
Other Intangible Assets	Other intangible assets represent contractual rights obtained in connection with business combinations that had favorable contractual terms relative to market at the acquisition date as well as customer-related intangible assets, including customer relationships established by acquired contracts. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment whenever impairment indicators are present. See Note 8—Goodwill and Other Intangible Assets.
Derivative Instruments	Derivative Instruments  Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risk. Derivatives are carried on the balance sheet at fair value and are included in other current assets, other assets, accrued expenses, or other long-term liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the normal purchases and sales exception criteria. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis.
	Gains and losses on derivative instruments are recognized currently in earnings. Net losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 11—Derivative Instruments.
Legal Contingencies	Legal Contingencies  The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. If the Company determines that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 17—Contingencies.
Environmental Contingencies	Environmental Contingencies  The Company is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. Except for environmental contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 17—Contingencies.
Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans	Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans  The Company measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and the health care cost trend rate (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.
	The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. See Note 21—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans.
	Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date.
	Investment Policies and Strategies  The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (domestic equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 45%-55% equity securities, 20%-30% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines.
	Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ collective fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2014 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach, while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, and inflation. Returns on fixed-income securities are generally developed based on expected inflation, real bond yield, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are derived from their relationship to the equity and fixed-income markets.
Income Taxes	Income Taxes  The Company files various U.S. federal, state, and foreign income tax returns. Deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). The Company uses the flow-through method to account for its investment tax credits. See Note 18—Income Taxes.
Share-Based Compensation	Share-Based Compensation  The Company accounts for share-based compensation at fair value. The Company grants equity-classified awards including stock options and non-vested equity shares (restricted stock awards and units). The Company may also grant equity-classified and liability-classified awards based on a comparison of the Company’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies (performance units).
	The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of Anadarko common stock. For other share-based compensation awards, fair value is determined using a Monte Carlo simulation or discounted-cash-flow methodology.
	The Company records compensation cost, net of estimated forfeitures, for share-based compensation awards over the requisite service period using the straight-line method. An adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the awards. For equity-classified share-based compensation awards, expense is recognized based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid. See Note 15—Share-Based Compensation.
Earnings Per Share	Earnings Per Share  The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and performance-based stock awards, if the inclusion of these items is dilutive. See Note 13—Stockholders’ Equity.
Recently Issued Accounting Standards	Recently Issued Accounting Standards  The Financial Accounting Standards Board issued Accounting Standards Update (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. This ASU is effective for annual and interim periods beginning in 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.
	1. Summary of Significant Accounting Policies (Continued)
	ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. This ASU is effective beginning in 2015, with early adoption permitted for disposals or for assets classified as held for sale not reported in previously issued financial statements. Anadarko early adopted this ASU on a prospective basis in the first quarter of 2014 with no material impact on the Company’s consolidated financial statements.
	ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented in the financial statements as a reduction to a deferred tax asset, except in certain circumstances. This ASU is effective for annual and interim periods beginning in 2014. See Note 18—Income Taxes.

Pension_Plans_Other_Postretire1

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Policies)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans	Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans  The Company measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and the health care cost trend rate (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.
	The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. See Note 21—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans.
	Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date.
	Investment Policies and Strategies  The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (domestic equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 45%-55% equity securities, 20%-30% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines.
	Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ collective fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2014 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach, while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, and inflation. Returns on fixed-income securities are generally developed based on expected inflation, real bond yield, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are derived from their relationship to the equity and fixed-income markets.

Acquisitions_Divestitures_and_1

Acquisitions, Divestitures, and Assets Held for Sale (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of Assets Acquired and Liabilities Assumed	The following summarizes the preliminary fair value of assets acquired and liabilities assumed at the acquisition date, pending the acquired entity’s final financial statements:
	millions
	Current assets		$	46
	Properties and equipment		441
	Other intangible assets		836
	Accounts payable		(13		)
	Accrued expenses		(25		)
	Deferred income taxes		(1		)
	Asset retirement obligations		(9		)
	Goodwill		279
	Total assets acquired and liabilities assumed		$	1,554
Acquisitions Table	The following summarizes acquisitions made during 2013:
	millions, except percentages	Percentage			Cash Paid
		Acquired
	Certain oil and gas properties and related assets in the Moxa area of Wyoming	100	%		$	310		(1)
	Gas-gathering systems in the Marcellus shale in north-central Pennsylvania	33.75	%		135
	Joint venture formed to design, construct, and own two fractionators located in	25	%		78
	Mont Belvieu, Texas
	Intrastate pipeline in southwestern Wyoming	100	%		28
	__________________________________________________________________
	(1)	Includes $306 million that represents the fair value of the oil and gas properties acquired.
Schedule of Proceeds Received and Gains (Losses) Recognized on Divestitures	The following summarizes the proceeds received and gains (losses) recognized on divestitures for the years ended December 31:
	millions	2014				2013			2012
	Proceeds received	$	4,968			$	567		$	657
	Gains (losses) on divestitures, net	1,891				(470		)	(71		)

Inventories_Tables

Inventories (Tables)	12 Months Ended
	Dec. 31, 2014
Energy Related Inventory [Abstract]
Inventory Disclosure Table	The following summarizes the major classes of inventories included in other current assets at December 31:
	millions	2014		2013
	Oil	$	133	$	88
	Natural gas	27		43
	NGLs	83		79
	Total inventories	$	243	$	210

Properties_and_Equipment_Table

Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Gross [Abstract]
Cost of Properties and Equipment by Segment Table	The following summarizes the cost of properties and equipment by segment at December 31:
	millions	2014		2013
	Oil and gas exploration and production (1)	$	63,674	$	61,302
	Midstream	8,647		7,285
	Marketing	—		9
	Other	2,786		2,648
	Total properties and equipment	$	75,107	$	71,244
	__________________________________________________________________
	(1)	Includes costs associated with unproved properties of $5.1 billion at December 31, 2014, and $6.9 billion at December 31, 2013.

Impairments_Tables

Impairments (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Impairment Charges [Abstract]
Schedule of Impairment Expense	The following summarizes impairments by segment for the years ended December 31:
	millions	2014			2013			2012
	Oil and gas exploration and production
	Long-lived assets held for use
	U.S. onshore properties	$	545		$	142		$	259
	Gulf of Mexico properties	276			562			104
	Cost-method investment	3			11			13
	Midstream
	Long-lived assets held for use	12			79			13
	Total impairments	$	836		$	794		$	389
Nonrecurring Fair Value Measurements Table	The following summarizes the post-impairment fair value of the above-described assets, which was measured using the income approach and Level 3 inputs:
	millions		2014			2013
	Long-lived assets held for use		$	731		$	548
	Cost-method investment (1)		32			32
	__________________________________________________________________
	(1)	This represents the Company’s after-tax net investment.

Suspended_Exploratory_Well_Cos1

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2014
Capitalized Exploratory Well Costs [Abstract]
Suspended Exploratory Well Costs Rollforward	The following summarizes the changes in suspended exploratory well costs at December 31 for each of the last three years. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.
	millions	2014			2013			2012
	Balance at January 1	$	2,232		$	2,062		$	1,353
	Additions pending the determination of proved reserves	421			848			960
	Divestitures (1)	(913		)	(48		)	—
	Reclassifications to proved properties	(100		)	(507		)	(129		)
	Charges to exploration expense	(118		)	(123		)	(122		)
	Balance at December 31	$	1,522		$	2,232		$	2,062
	__________________________________________________________________
	(1)	Includes $(744) million related to the Company’s sale of a 10% working interest in Offshore Area 1 in Mozambique during 2014.
Schedule of Aging of Suspended Exploratory Well Costs by Geographic Area	The following summarizes an aging of suspended exploratory well costs by geographic area and the year the costs were suspended at December 31, 2014:
					Year Costs Incurred(1)
	millions	Total			2014			2013			2012		2011 and
													prior
	United States—Onshore	$	164		$	131		$	17		$	5	$	11
	United States—Offshore	314			78			80			63		93
	International	1,044			179			271			184		410
		$	1,522		$	388		$	368		$	252	$	514
	__________________________________________________________________
	(1)	Excludes additions subsequently reclassified to proved properties within the same year

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Rollforward	The following summarizes changes in the Company’s AROs during 2014 and 2013:
	millions	2014			2013
	Carrying amount of asset retirement obligations at January 1	$	2,022		$	1,885
	Liabilities incurred	119			182
	Property dispositions	(70		)	(76		)
	Liabilities settled	(443		)	(162		)
	Accretion expense	93			110
	Revisions in estimated liabilities	332			83
	Carrying amount of asset retirement obligations at December 31	$	2,053		$	2,022

Goodwill_and_Other_Intangible_1

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Other Intangible Assets	Intangible assets and associated amortization expense were as follows:
	millions	Gross Carrying		Accumulated			Net Carrying		Amortization
		Amount		Amortization			Amount		Expense
	December 31, 2014
	Offshore platform leases	$	33	$	(29	)	$	4	$	—
	Customer contracts	1,004		(15		)	989		6
		$	1,037	$	(44	)	$	993	$	6
	December 31, 2013
	Offshore platform leases	$	60	$	(50	)	$	10	$	3
	Customer contracts	169		(9		)	160		4
		$	229	$	(59	)	$	170	$	7

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following is a summary of the Company’s derivative instruments related to natural-gas production/processing derivative activities at December 31, 2014:
			2015 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
	Extendable Fixed-Price Contracts (thousand MMBtu/d) (1)		170
	Average price per MMBtu		$	4.17
	__________________________________________________________________
	(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.
	The Company had the following outstanding interest-rate swaps at December 31, 2014:
	millions except percentages					Reference Period				Weighted-Average
	Notional Principal Amount					Start		End		Interest Rate
	$	50				Sep-16		Sep-26		5.91%
	$	1,850				Sep-16		Sep-46		6.05%
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	The following summarizes the fair value of the Company’s derivative instruments at December 31:
	millions		Gross								Gross
			Derivative Assets								Derivative Liabilities
	Balance Sheet Classification		2014				2013				2014				2013
	Commodity derivatives
	Other current assets		$	421			$	181			$	(118	)		$	(102	)
	Other assets		1				89				—				(66		)
	Accrued expenses		71				106				(114		)		(149		)
	Other liabilities		—				4				(6		)		(15		)
			493				380				(238		)		(332		)
	Interest-rate and other derivatives
	Accrued expenses		—				—				—				(480		)
	Other liabilities		—				—				(1,217		)		(174		)
			—				—				(1,217		)		(654		)
	Total derivatives		$	493			$	380			$	(1,455	)		$	(986	)
	The following summarizes gains and losses related to derivative instruments:
	millions
	Classification of (Gain) Loss Recognized		2014				2013				2012
	Commodity derivatives
	Gathering, processing, and marketing sales (1)		$	10			$	6			$	18
	(Gains) losses on derivatives, net		(589		)		141				(387		)
	Interest-rate and other derivatives
	(Gains) losses on derivatives, net		786				(539		)		61
	Total (gains) losses on derivatives, net		$	207			$	(392	)		$	(308	)
	__________________________________________________________________
	(1)	Represents the effect of Marketing and Trading Derivative Activities.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:
	millions	Level 1				Level 2				Level 3				Netting (1)				Collateral			Total
	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			$	23		$	(24	)
	Other counterparties	—				(4		)		—				2				—			(2		)
	Interest-rate and other derivatives	—				(1,217		)		—				—				—			(1,217		)
	Total derivative liabilities	$	—			$	(1,455	)		$	—			$	189			$	23		$	(1,243	)
	December 31, 2013
	Assets
	Commodity derivatives
	Financial institutions	$	—			$	211			$	—			$	(153	)		$	—		$	58
	Other counterparties	—				169				—				(126		)		—			43
	Total derivative assets	$	—			$	380			$	—			$	(279	)		$	—		$	101
	Liabilities
	Commodity derivatives
	Financial institutions	$	—			$	(200	)		$	—			$	153			$	7		$	(40	)
	Other counterparties	—				(132		)		—				126				—			(6		)
	Interest-rate and other derivatives	—				(654		)		—				—				—			(654		)
	Total derivative liabilities	$	—			$	(986	)		$	—			$	279			$	7		$	(700	)
	__________________________________________________________________
	(1)	Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

Debt_and_Interest_Expense_Tabl

Debt and Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt Outstanding and Debt Activity Tables	The following summarizes the Company’s outstanding debt:
		December 31,
	millions	2014			2013
	5.750% Senior Notes due 2014	$	—		$	275
	7.625% Senior Notes due 2014	—			500
	5.950% Senior Notes due 2016	1,750			1,750
	6.375% Senior Notes due 2017	2,000			2,000
	7.050% Debentures due 2018	114			114
	WES 2.600% Senior Notes due 2018	350			250
	6.950% Senior Notes due 2019	300			300
	8.700% Senior Notes due 2019	600			600
	WES 5.375% Senior Notes due 2021	500			500
	WES 4.000% Senior Notes due 2022	670			670
	3.450% Senior Notes due 2024	625			—
	6.950% Senior Notes due 2024	650			650
	7.500% Debentures due 2026	112			112
	7.000% Debentures due 2027	54			54
	7.125% Debentures due 2027	150			150
	6.625% Debentures due 2028	17			17
	7.150% Debentures due 2028	235			235
	7.200% Debentures due 2029	135			135
	7.950% Debentures due 2029	117			117
	7.500% Senior Notes due 2031	900			900
	7.875% Senior Notes due 2031	500			500
	Zero-Coupon Senior Notes due 2036	2,360			2,360
	6.450% Senior Notes due 2036	1,750			1,750
	7.950% Senior Notes due 2039	325			325
	6.200% Senior Notes due 2040	750			750
	4.500% Senior Notes due 2044	625			—
	WES 5.450% Senior Notes due 2044	400			—
	7.730% Debentures due 2096	61			61
	7.500% Debentures due 2096	78			78
	7.250% Debentures due 2096	49			49
	WES revolving credit facility	510			—
	Total debt at face value	$	16,687		$	15,202
	Net unamortized discounts and premiums (1)	(1,616		)	(1,645		)
	Total borrowings	$	15,071		$	13,557
	Capital lease obligation	21			8
	Less current portion of long-term debt	—			500
	Total long-term debt	$	15,092		$	13,065
	__________________________________________________________________
	(1)	Unamortized discounts and premiums are amortized over the term of the related debt.
	The following summarizes the Company’s debt activity during 2014 and 2013:
	millions	Carrying			Description
		Value
	Balance at December 31, 2012	$	13,269
	Issuances	250			WES 2.600% Senior Notes due 2018
	Borrowings	710			WES revolving credit facility
	Repayments	(710		)	WES revolving credit facility
	Other, net	38			Amortization of debt discounts and premiums
	Balance at December 31, 2013	$	13,557
	Issuances	101			WES 2.600% Senior Notes due 2018
		394			WES 5.450% Senior Notes due 2044
		624			3.450% Senior Notes due 2024
		621			4.500% Senior Notes due 2044
	Borrowings	1,160			WES revolving credit facility
	Repayments	(500		)	7.625% Senior Notes due 2014
		(275		)	5.750% Senior Notes due 2014
		(650		)	WES revolving credit facility
	Other, net	39			Amortization of debt discounts and premiums
	Balance at December 31, 2014	$	15,071
Scheduled Maturities Table	Total principal amount of debt maturities for the five years ending December 31, 2019, excluding the potential repayment of the outstanding Zero Coupons that may be put by the holder to the Company annually, were as follows:
	millions	Principal
		Amount of
		Debt Maturities
	2015	$	—
	2016	1,750
	2017	2,000
	2018	464
	2019	1,410
Interest Expense Table	The following summarizes interest expense for the years ended December 31:
	millions	2014			2013			2012
	Debt and other	$	973		$	949		$	963
	Capitalized interest	(201		)	(263		)	(221		)
	Total interest expense	$	772		$	686		$	742

Stockholders_Equity_Tables

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Common Stock Rollforward	The following summarizes the changes in the Company’s outstanding shares of common stock:
	millions	2014			2013			2012
	Shares of common stock issued
	Shares at January 1	523			519			516
	Exercise of stock options	2			2			1
	Issuance of restricted stock	1			2			2
	Shares at December 31	526			523			519
	Shares of common stock held in treasury
	Shares at January 1	19			18			18
	Shares received for restricted stock vested and options exercised	—			1			—
	Shares at December 31	19			19			18
	Shares of common stock outstanding at December 31	507			504			501
Earnings Per Share Table	The following provides a reconciliation between basic and diluted EPS attributable to common stockholders for the years ended December 31:
	millions except per-share amounts	2014				2013			2012
	Net income (loss)
	Net income (loss) attributable to common stockholders	$	(1,750	)		$	801		$	2,391
	Less distributions on participating securities	4				2			1
	Less undistributed income allocated to participating securities	—				4			14
	Basic	$	(1,754	)		$	795		$	2,376
	Diluted	$	(1,754	)		$	795		$	2,376
	Shares
	Average number of common shares outstanding—basic	506				502			500
	Dilutive effect of stock options	—				3			2
	Average number of common shares outstanding—diluted	506				505			502
	Excluded (1)	11				4			6
	Net income (loss) per common share
	Basic	$	(3.47	)		$	1.58		$	4.76
	Diluted	$	(3.47	)		$	1.58		$	4.74
	Dividends per common share	$	0.99			$	0.54		$	0.36
	__________________________________________________________________
	(1)	Inclusion of certain shares would have had an anti-dilutive effect.

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule Of Accumulated Other Comprehensive Income (Loss) Table	The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss):
	millions	Interest-rate			Pension and Other Postretirement			Total
		Derivatives			Plans
		Previously
		Subject to Hedge
		Accounting
	Balance at December 31, 2013	$	(54	)	$	(231	)	$	(285	)
	Other comprehensive income (loss), before	—			(256		)	(256		)
	reclassifications
	Reclassifications to Consolidated Statement of Income	6			18			24
	Net other comprehensive income (loss)	6			(238		)	(232		)
	Balance at December 31, 2014	$	(48	)	$	(469	)	$	(517	)

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation Cost Table	The following summarizes share-based compensation expense for the years ended December 31:
	millions	2014			2013				2012
	Restricted stock	$	144		$	122			$	103
	Stock options	21			27				43
	Other equity-classified awards	1			1				1
	Value creation plan	136			—				(2		)
	Performance-based unit awards	23			4				8
	Other performance-based awards	—			—				165
	Other liability-classified awards	—			1				2
	Pretax compensation expense	$	325		$	155			$	320
	Income tax benefit	$	120		$	57			$	117
Restricted Stock Activity Table	The following summarizes the Company’s restricted stock activity:
		Shares		Weighted-
		(millions)		Average
				Grant-Date
				Fair Value
				(per share)
	Non-vested at January 1, 2014	3.22		$	82.53
	Granted	2.05		$	87.42
	Vested	(1.52	)	$	82.35
	Forfeited	(0.15	)	$	84.49
	Non-vested at December 31, 2014	3.6		$	85.31
Stock Option Valuation Assumptions Table	The Company used the following weighted-average assumptions to estimate the fair value of stock options granted:
		2014				2013					2012
	Weighted-average grant-date fair value	$	23.55			$	26.27				$	25.84
	Assumptions
	Expected option life—years	4.9				4.8					4.9
	Volatility	29.9		%		33.9			%		44.2		%
	Risk-free interest rate	1.6		%		1.3			%		0.7		%
	Dividend yield	1.1		%		0.8			%		0.5		%
Stock Option Activity Table	The following summarizes the Company’s stock option activity:
		Shares		Weighted-				Weighted-		Aggregate
		(millions)		Average				Average		Intrinsic
				Exercise				Remaining		Value
				Price				Contractual		(millions)
				(per share)				Term
								(years)
	Outstanding at January 1, 2014	7.72		$	63.3
	Granted	0.95		$	93.34
	Exercised (1)	(1.85	)	$	54.03
	Forfeited or expired	(0.03	)	$	76
	Outstanding at December 31, 2014	6.79		$	69.96			3.56		$	104.3
	Vested or expected to vest at December 31, 2014	6.73		$	69.79			3.54		$	104.2
	Exercisable at December 31, 2014	4.99		$	62.91			2.6		$	101.1
	__________________________________________________________________
	(1)	The total intrinsic value of stock options exercised was $88 million during 2014, $80 million during 2013, and $49 million during 2012, based on the difference between the market price at the exercise date and the exercise price.

Commitments_Tables

Commitments (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments [Abstract]
Schedule of Future Minimum Lease Payments	The following summarizes future minimum lease payments under operating leases at December 31, 2014:
	millions
	2015	$	1,022
	2016	833
	2017	592
	2018	324
	2019	203
	Later years	87
	Total future minimum lease payments	$	3,061

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The following summarizes components of income tax expense (benefit) for the years ended December 31:
	millions	2014				2013				2012
	Current
	Federal	$	188			$	113			$	45
	State	2				42				25
	Foreign	1,574				873				891
		1,764				1,028				961
	Deferred
	Federal	(389		)		94				(30		)
	State	27				(9		)		115
	Foreign	215				52				74
		(147		)		137				159
	Total income tax expense (benefit)	$	1,617			$	1,165			$	1,120
Schedule of Effective Income Tax Rate Reconciliation	The following summarizes the sources of these differences for the years ended December 31:
	millions except percentages	2014				2013				2012
	Income (loss) before income taxes
	Domestic	$	(3,564	)		$	428			$	132
	Foreign	3,618				1,678				3,433
	Total	$	54			$	2,106			$	3,565
	U.S. federal statutory tax rate	35		%		35		%		35		%
	Tax computed at the U.S. federal statutory rate	$	19			$	737			$	1,248
	Adjustments resulting from
	State income taxes (net of federal income tax benefit)	(11		)		23				93
	Tax impact from foreign operations	62				204				215
	Non-deductible Algerian exceptional profits tax	193				144				188
	Non-taxable Algeria exceptional profits tax settlement	—				13				(679		)
	Net changes in uncertain tax positions	1,427				(29		)		28
	Deferred tax adjustments	15				76				22
	Non-deductible Tronox-related contingent loss	(36		)		36				—
	Income attributable to noncontrolling interests	(66		)		(48		)		(24		)
	Non-deductible Deepwater Horizon settlement	32				—				—
	Federal manufacturing deduction	(27		)		—				—
	Non-deductible goodwill	21				—				15
	Other—net	(12		)		9				14
	Total income tax expense (benefit)	$	1,617			$	1,165			$	1,120
	Effective tax rate	2,994		%		55		%		31		%
Deferred Tax Assets (Liabilities) Table	The following summarizes components of total deferred taxes at December 31:
	millions	2014				2013
	Federal	$	(7,649	)		$	(8,246	)
	State, net of federal	(341		)		(332		)
	Foreign	(537		)		(307		)
	Total deferred taxes	$	(8,527	)		$	(8,885	)
	The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31:
	millions	2014				2013
	Current deferred tax assets	$	210			$	412
	Settlement agreement related to the Tronox Adversary Proceeding	590				—
	Valuation allowances on deferred tax assets not expected to be realized	(78		)		(52		)
	Net current deferred tax assets	722				360
	Oil and gas exploration and development operations	(8,418		)		(8,213		)
	Mineral operations	(412		)		(410		)
	Midstream and other depreciable properties	(1,611		)		(1,586		)
	Other	(351		)		(499		)
	Gross long-term deferred tax liabilities	(10,792		)		(10,708		)
	Oil and gas exploration and development costs	177				94
	Net operating loss carryforward	558				599
	Foreign tax credit carryforward and alternative minimum tax credit carryforward	166				325
	Other	1,428				1,211
	Gross long-term deferred tax assets	2,329				2,229
	Valuation allowances on deferred tax assets not expected to be realized	(786		)		(766		)
	Net long-term deferred tax assets	1,543				1,463
	Net long-term deferred tax liabilities	(9,249		)		(9,245		)
	Total deferred taxes	$	(8,527	)		$	(8,885	)
Valuation Allowances on Deferred Tax Assets Rollforwad	The following summarizes changes in the balance of valuation allowances on deferred tax assets:
	millions	2014				2013				2012
	Balance at January 1	$	(818	)		$	(922	)		$	(555	)
	Additions	(59		)		(38		)		(426		)
	Reductions	13				142				59
	Balance at December 31	$	(864	)		$	(818	)		$	(922	)
Taxes Receivable (Payable) Table	The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31:
	Balance Sheet Classification		2014				2013
	Income taxes receivable
	Accounts receivable—other		$	93			$	66
	Other assets		35				35
			128				101
	Income taxes (payable)
	Accrued expense		(152		)		(82		)
	Total net income taxes receivable (payable)		$	(24	)		$	19
Schedule of Operating Loss, Tax Credit, And Other Carryforwards	Tax carryforwards available for use on future income tax returns at December 31, 2014, were as follows:
	millions	Domestic				Foreign				Expiration
	Net operating loss—foreign	$	—			$	1,165			2015 - Indefinite
	Net operating loss—state	$	4,477			$	—			2015-2034
	Foreign tax credits	$	167			$	—			2022-2023
	Texas margins tax credit	$	34			$	—			2026
Unrecognized Tax Benefits Rollforward	Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:
		Assets (Liabilities)
	millions	2014				2013				2012
	Balance at January 1	$	(147	)		$	(46	)		$	(31	)
	Increases related to prior-year tax positions	(11		)		(54		)		(17		)
	Decreases related to prior-year tax positions	39				3				3
	Increases related to current-year tax positions	(1,568		)		(72		)		(1		)
	Settlements	—				5				—
	Lapse of statute of limitations	—				17				—
	Balance at December 31	$	(1,687	)		$	(147	)		$	(46	)
Tax Years Subject to Examination by Major Tax Jurisdiction Table	The following lists the tax years subject to examination by major tax jurisdiction:
		Tax Years
	United States	2008-2014
	Algeria	2011-2014
	Ghana	2006-2014

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Table	The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities for the years ended December 31:
	millions	2014			2013			2012
	Cash paid (received)
	Interest, net of amounts capitalized	$	689		$	627		$	684
	Income taxes, net of refunds	956			169			(300		)
	Non-cash investing activities
	Fair value of properties and equipment from non-cash transactions	$	18		$	62		$	65
	Asset retirement cost additions	348			297			142
	Accruals of property, plant, and equipment	1,156			1,446			1,205
	Net liabilities assumed or divested in acquisitions and divestitures	(92		)	(80		)	(34		)
	Non-cash investing and financing activities
	Capital lease obligation	$	13		$	8		$	—
	Floating production, storage, and offloading vessel construction	149			17			—
	period obligation

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes	Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes for the years ended December 31:
	millions	2014			2013			2012
	Income (loss) before income taxes	$	54		$	2,106		$	3,565
	Exploration expense	1,639			1,329			1,946
	DD&A	4,550			3,927			3,964
	Impairments	836			794			389
	Interest expense	772			686			742
	Total (gains) losses on derivatives, net, less net cash from	578			(307		)	443
	settlement of commodity derivatives
	Deepwater Horizon settlement and related costs	97			15			18
	Algeria exceptional profits tax settlement	—			33			(1,797		)
	Tronox-related contingent loss	4,360			850			(250		)
	Certain other nonoperating items	22			110			—
	Less net income attributable to noncontrolling interests	187			140			54
	Consolidated Adjusted EBITDAX	$	12,721		$	9,403		$	8,966
Schedule of Segment Reporting Information by Segment	The following summarizes selected financial information for Anadarko’s reporting segments:
	millions	Oil and Gas			Midstream			Marketing			Other and			Total
		Exploration									Intersegment
		& Production									Eliminations
	2014
	Sales revenues	$	8,603		$	484		$	7,288		$	—		$	16,375
	Intersegment revenues	6,225			1,338			(6,771		)	(792		)	—
	Gains (losses) on divestitures and other, net	1,893			(3		)	—			205			2,095
	Total revenues and other	16,721			1,819			517			(587		)	18,470
	Operating costs and expenses (1)	4,216			972			740			17			5,945
	Net cash from settlement of	—			—			—			(377		)	(377		)
	commodity derivatives
	Other (income) expense, net (2)	—			—			—			(2		)	(2		)
	Net income attributable to noncontrolling	—			187			—			—			187
	interests
	Total expenses and other	4,216			1,159			740			(362		)	5,753
	Total (gains) losses on derivatives, net	—			—			4			—			4
	included in marketing revenue, less net
	cash from settlement
	Adjusted EBITDAX	$	12,505		$	660		$	(219	)	$	(225	)	$	12,721
	Net properties and equipment	$	32,717		$	6,697		$	—		$	2,175		$	41,589
	Capital expenditures	$	7,934		$	1,149		$	—		$	173		$	9,256
	Goodwill	$	5,123		$	453		$	—		$	—		$	5,576
	millions	Oil and Gas			Midstream			Marketing			Other and			Total
		Exploration									Intersegment
		& Production									Eliminations
	2013
	Sales revenues	$	7,090		$	387		$	7,390		$	—		$	14,867
	Intersegment revenues	6,405			1,105			(6,859		)	(651		)	—
	Gains (losses) on divestitures and other, net	(622		)	(1		)	—			337			(286		)
	Total revenues and other	12,873			1,491			531			(314		)	14,581
	Operating costs and expenses (1)	3,635			843			652			20			5,150
	Net cash from settlement of	—			—			—			(95		)	(95		)
	commodity derivatives
	Other (income) expense, net (2)	—			—			—			(21		)	(21		)
	Net income attributable to noncontrolling	—			140			—			—			140
	interests
	Total expenses and other	3,635			983			652			(96		)	5,174
	Total (gains) losses on derivatives, net	—			—			(4		)	—			(4		)
	included in marketing revenue, less net
	cash from settlement
	Adjusted EBITDAX	$	9,238		$	508		$	(125	)	$	(218	)	$	9,403
	Net properties and equipment	$	33,409		$	5,408		$	9		$	2,103		$	40,929
	Capital expenditures	$	7,008		$	1,248		$	—		$	267		$	8,523
	Goodwill	$	5,317		$	175		$	—		$	—		$	5,492
	2012
	Sales revenues	$	6,752		$	325		$	6,230		$	—		$	13,307
	Intersegment revenues	5,318			959			(5,734		)	(543		)	—
	Gains (losses) on divestitures and other, net	(65		)	(8		)	—			177			104
	Total revenues and other	12,005			1,276			496			(366		)	13,411
	Operating costs and expenses (1)	3,505			748			616			295			5,164
	Net cash from settlement of	—			—			—			(753		)	(753		)
	commodity derivatives
	Other (income) expense, net	—			—			—			(4		)	(4		)
	Net income attributable to noncontrolling	—			54			—			—			54
	interests
	Total expenses and other	3,505			802			616			(462		)	4,461
	Total (gains) losses on derivatives, net	—			—			16			—			16
	included in marketing revenue, less net
	cash from settlement
	Adjusted EBITDAX	$	8,500		$	474		$	(104	)	$	96		$	8,966
	Net properties and equipment	$	32,024		$	4,459		$	9		$	1,906		$	38,398
	Capital expenditures	$	5,906		$	1,250		$	—		$	155		$	7,311
	Goodwill	$	5,317		$	175		$	—		$	—		$	5,492
__________________________________________________________________
(1)	Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement 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.
Schedule of Sales Revenues by Geographic Areas
		Years Ended December 31,
	millions	2014			2013			2012
	Sales Revenues
	United States	$	13,083		$	11,290		$	9,911
	Algeria	2,435			2,184			2,182
	Other International	857			1,393			1,214
	Total sales revenues	$	16,375		$	14,867		$	13,307
Schedule of Net Properties and Equipment by Geographic Areas
		December 31,
	millions	2014			2013
	Net Properties and Equipment
	United States	$	37,186		$	35,486
	Algeria	1,431			1,582
	Other International	2,972			3,861
	Total net properties and equipment	$	41,589		$	40,929

Pension_Plans_Other_Postretire2

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of Changes in Benefit Obligations, Fair Value of Plan Assets, and Funded Status of the Plans	The following sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2014 and 2013, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2014 and 2013:
		Pension Benefits								Other Benefits
	millions	2014				2013				2014			2013
	Change in benefit obligation
	Benefit obligation at beginning of year	$	2,158			$	2,297			$	294		$	359
	Service cost	99				85				7			9
	Interest cost	99				78				15			14
	Actuarial (gain) loss	337				(156		)		72			(74		)
	Participant contributions	1				—				4			4
	Benefit payments	(159		)		(149		)		(19		)	(18		)
	Foreign-currency exchange-rate changes	(7		)		3				—			—
	Benefit obligation at end of year (1)	$	2,528			$	2,158			$	373		$	294
	Change in plan assets
	Fair value of plan assets at beginning of year	$	1,754			$	1,462			$	—		$	—
	Actual return on plan assets	111				278				—			—
	Employer contributions	121				160				15			14
	Participant contributions	1				—				4			4
	Benefit payments	(159		)		(149		)		(19		)	(18		)
	Foreign-currency exchange-rate changes	(10		)		3				—			—
	Fair value of plan assets at end of year	$	1,818			$	1,754			$	—		$	—
	Funded status of the plans at end of year	$	(710	)		$	(404	)		$	(373	)	$	(294	)
	__________________________________________________________________
	(1)	The accumulated benefit obligation for all defined-benefit pension plans was $2.1 billion at December 31, 2014, and $1.8 billion at December 31, 2013.
Schedule of Amounts Recognized in Balance Sheet
	Total recognized amounts in the balance sheet consist of
	Other assets	$	41			$	37			$	—		$	—
	Accrued expenses	(24		)		(19		)		(15		)	(15		)
	Other long-term liabilities—other	(727		)		(422		)		(358		)	(279		)
	Total	$	(710	)		$	(404	)		$	(373	)	$	(294	)
Schedule of Total Recognized Amounts in Accumulated Other Comprehensive Income
	Total recognized amounts in accumulated other
	comprehensive income consist of
	Prior service cost (credit)	$	(1	)		$	(1	)		$	2		$	2
	Net actuarial (gain) loss	740				441				1			(78		)
	Total	$	739			$	440			$	3		$	(76	)
Schedule of Defined-Benefit Pension Plans With Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	The following summarizes the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets for the years ended December 31:
	millions	2014				2013
	Projected benefit obligation	$	2,403			$	2,047
	Accumulated benefit obligation	2,024				1,742
	Fair value of plan assets	1,652				1,606
Components of Net Periodic Benefit Cost Table	The following summarizes the Company’s pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31:
		Pension Benefits											Other Benefits
	millions	2014				2013				2012			2014				2013		2012
	Components of net periodic benefit cost
	Service cost	$	99			$	85			$	76		$	7			$	9	$	9
	Interest cost	99				78				85			15				14		16
	Expected return on plan assets	(106		)		(91		)		(91		)	—				—		—
	Amortization of net actuarial loss (gain)	34				118				93			(7		)		—		—
	Amortization of net prior service cost (credit)	—				—				—			—				1		2
	Settlement loss	—				14				—			—				—		—
	Net periodic benefit cost	$	126			$	204			$	163		$	15			$	24	$	27
Schedule of Amounts Recognized in Other Comprehensive Income
	Amounts recognized in other comprehensive
	income (expense)
	Net actuarial gain (loss)	$	(333	)		$	342			$	(156	)	$	(72	)		$	74	$	1
	Amortization of net actuarial (gain) loss	34				118				93			(7		)		—		—
	Amortization of net prior service cost (credit)	—				—				—			—				1		2
	Settlement loss	—				14				—			—				—		—
	Total amounts recognized in other	$	(299	)		$	474			$	(63	)	$	(79	)		$	75	$	3
	comprehensive income (expense)
Schedule of Assumptions Used	The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations at December 31:
		Pension Benefits						Other Benefits
		2014			2013			2014			2013
	Discount rate	4	%		4.75	%		4.25	%		5.25	%
	Rates of increase in compensation levels	5.25	%		5	%		5.25	%		5.25	%
	The following summarizes the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost:
		Pension Benefits									Other Benefits
		2014			2013			2012			2014		2013			2012
	Discount rate	4.75	%		3.5	%		4.5	%		5.25	%	4	%		4.75	%
	Long-term rate of return on plan assets	6.75	%		7	%		7	%		N/A		N/A			N/A
	Rates of increase in compensation levels	5	%		4.5	%		4.5	%		5.25	%	4.5	%		4.5	%
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	A 1% change in the assumed health care cost trend rate over the projected period would have the following effects:
	millions	1% Increase				1% Decrease
	Effect on total of service and interest cost components	$	3			$	(2	)
	Effect on other postretirement benefit obligation	$	40			$	(33	)
Fair Value Hierarchy of Plan Assets Table	The fair value of the Company’s pension plan assets by asset class and input level within the fair-value hierarchy were as follows:
	millions
	December 31, 2014	Level 1				Level 2				Level 3			Total
	Investments
	Cash and cash equivalents	$	3			$	53			$	—		$	56
	Fixed income
	Mortgage-backed securities	—				51				—			51
	U.S. government securities	—				56				—			56
	Other fixed-income securities (1)	48				212				—			260
	Equity securities
	Domestic	446				130				—			576
	International	124				299				—			423
	Other
	Real estate	—				56				94			150
	Private equity	—				—				84			84
	Hedge funds and other alternative strategies	9				—				126			135
	Other	$	—			$	30			$	—		$	30
	Total investments (2)	$	630			$	887			$	304		$	1,821
	Liabilities
	Hedge funds and other alternative strategies	$	(3	)		$	—			$	—		$	(3	)
	Total liabilities	$	(3	)		$	—			$	—		$	(3	)
	December 31, 2013
	Investments
	Cash and cash equivalents	$	17			$	80			$	—		$	97
	Fixed income
	Mortgage-backed securities	—				54				—			54
	U.S. government securities	—				52				—			52
	Other fixed-income securities (1)	42				197				—			239
	Equity securities
	Domestic	445				116				—			561
	International	148				303				—			451
	Other
	Real estate	—				47				86			133
	Private equity	—				—				72			72
	Hedge funds and other alternative strategies	31				—				79			110
	Total investments (2)	$	683			$	849			$	237		$	1,769
	Liabilities
	Hedge funds and other alternative strategies	$	(17	)		$	—			$	—		$	(17	)
	Total liabilities	$	(17	)		$	—			$	—		$	(17	)
	__________________________________________________________________
	(1)	Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities.
	(2)	Amount excludes receivables and payables, primarily related to Level 1 investments.
Schedule of Changes in Level 3 Fair Value of Investments	The following summarizes changes in the fair value of investments based on Level 3 inputs:
	millions	Hedge Funds				Private				Real Estate			Total
		and Other				Equity
		Alternative
		Strategies
	Balance at January 1, 2013	$	77			$	64			$	78		$	219
	Acquisitions (dispositions), net	(6		)		—				2			(4		)
	Actual return on plan assets
	Relating to assets sold during the reporting period	1				4				—			5
	Relating to assets still held at the reporting date	7				4				6			17
	Balance at December 31, 2013	$	79			$	72			$	86		$	237
	Acquisitions (dispositions), net	42				—				2			44
	Actual return on plan assets
	Relating to assets sold during the reporting period	2				5				—			7
	Relating to assets still held at the reporting date	3				7				6			16
	Balance at December 31, 2014	$	126			$	84			$	94		$	304
Schedule of Estimated Future Benefit Payments	The following summarizes estimated benefit payments for the next ten years, including benefit increases due to continuing employee service:
	millions	Pension				Other
		Benefit				Benefit
		Payments				Payments
	2015	$	162			$	16
	2016	175				17
	2017	199				18
	2018	194				18
	2019	216				19
	2020-2024	1,192				109

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant, and Equipment [Line Items]
Outstanding checks in excess of bank account balances	388	$326
Furniture And Equipment [Member] | Minimum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	3 years
Furniture And Equipment [Member] | Maximum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	15 years
Buildings [Member] | Maximum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	40 years
Gathering Facilities [Member] | Maximum [Member]
Property, Plant, and Equipment [Line Items]
Useful life of assets	47 years

Acquisitions_Divestitures_and_2

Acquisitions, Divestitures, and Assets Held for Sale - Acquisitions (Detail) (USD $)	12 Months Ended				0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012	Nov. 25, 2014
Business Acquisition [Line Items]
Purchase price	$1,527,000,000	$473,000,000		$0
Goodwill	5,576,000,000	5,492,000,000		5,492,000,000
Revenues	18,470,000,000	14,581,000,000		13,411,000,000
Gathering and Processing Assets in the Delaware basin [Member]
Business Acquisition [Line Items]
Purchase price					1,554,000,000
Current assets					46,000,000
Properties and equipment					441,000,000
Other intangible assets					836,000,000
Accounts payable					-13,000,000
Accrued expenses					-25,000,000
Deferred income taxes					-1,000,000
Asset retirement obligations					-9,000,000
Goodwill					279,000,000
Total assets acquired and liabilities assumed					1,554,000,000
Goodwill amortizable for tax purposes					279,000,000
Revenues
Revenue and earnings that would have been recognized had the acquisition occurred on January 1
Moxa Oil and Gas Properties [Member]
Business Acquisition [Line Items]
Purchase price		310,000,000	[1]
Properties and equipment		306,000,000
Ownership interest purchased		100.00%
Marcellus Interest in Gas-Gathering Systems [Member]
Business Acquisition [Line Items]
Purchase price		135,000,000
Ownership interest purchased		33.75%
Mont Belvieu Joint Venture [Member]
Business Acquisition [Line Items]
Purchase price		78,000,000
Ownership interest purchased		25.00%
Intrastate Pipeline in Wyoming [Member]
Business Acquisition [Line Items]
Purchase price		$28,000,000
Ownership interest purchased		100.00%
[1]	Includes $306 million that represents the fair value of the oil and gas properties acquired.

Acquisitions_Divestitures_and_3

Acquisitions, Divestitures, and Assets Held for Sale - Divestitures and Assets Held for Sale (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures	$4,968	$567	$657
Gains (losses) on divestitures, net	1,891	-470	-71
Assets Held For Sale [Member]
Property, Plant, and Equipment [Line Items]
Long-term assets associated with assets held-for-sale		616
Long-term liabilities associated with assets held for sale		27
Oil and Gas Exploration and Production Reporting Segment [Member] | Assets Held For Sale [Member] | Fair Value, Inputs, Level 2 [Member] | Market Approach Valuation Technique [Member] | Nonrecurring [Member]
Property, Plant, and Equipment [Line Items]
Losses on assets held for sale	456	704
Oil and Gas Exploration and Production Reporting Segment [Member] | Offshore Area 1 in Mozambique [Member]
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures	2,640
Gains (losses) on divestitures, net	1,500
Working interest sold	10.00%
Oil and Gas Exploration and Production Reporting Segment [Member] | Chinese subsidiary [Member]
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures	1,075
Gains (losses) on divestitures, net	510
Oil and Gas Exploration and Production Reporting Segment [Member] | Vito Deepwater Development and Surrounding Exploration Blocks [Member]
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures	500
Gains (losses) on divestitures, net	237
Oil and Gas Exploration and Production Reporting Segment [Member] | Pinedale/Jonah Assets [Member]
Property, Plant, and Equipment [Line Items]
Proceeds from divestitures	$581

Acquisitions_Divestitures_and_4

Acquisitions, Divestitures, and Assets Held for Sale - Property Exchange (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Nonmonetary Transaction [Line Items]
Cash paid in property exchange	$9,508,000,000	$7,721,000,000	$7,242,000,000
Wattenberg Properties [Member]
Nonmonetary Transaction [Line Items]
Gain or loss recognized in property exchange		0
Cash paid in property exchange		$106,000,000

Inventories_Detail

Inventories (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Energy Related Inventory [Abstract]
Oil	$133	$88
Natural gas	27	43
NGLs	83	79
Total inventories	$243	$210

Properties_and_Equipment_Detai

Properties and Equipment (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Property, Plant, and Equipment [Line Items]
Cost of properties and equipment	$75,107,000,000		$71,244,000,000
Oil and Gas Exploration and Production Reporting Segment [Member]
Property, Plant, and Equipment [Line Items]
Cost of properties and equipment	63,674,000,000	[1]	61,302,000,000	[1]
Costs associated with unproved properties	5,100,000,000		6,900,000,000
Midstream Reporting Segment [Member]
Property, Plant, and Equipment [Line Items]
Cost of properties and equipment	8,647,000,000		7,285,000,000
Marketing Reporting Segment [Member]
Property, Plant, and Equipment [Line Items]
Cost of properties and equipment	0		9,000,000
Other and Intersegment Eliminations [Member]
Property, Plant, and Equipment [Line Items]
Cost of properties and equipment	$2,786,000,000		$2,648,000,000
[1]	Includes costs associated with unproved properties of $5.1 billion at December 31, 2014, and $6.9 billion at December 31, 2013.

Impairments_Impairments_by_Seg

Impairments - Impairments by Segment Table (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long Lived Assets Held and Used [Line Items]
Total impairments	$836,000,000	$794,000,000	$389,000,000
Oil and Gas Exploration and Production Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Cost-method investment	3,000,000	11,000,000	13,000,000
Oil and Gas Exploration and Production Reporting Segment [Member] | U.S. Onshore Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	545,000,000	142,000,000	259,000,000
Oil and Gas Exploration and Production Reporting Segment [Member] | Gulf of Mexico Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	276,000,000	562,000,000	104,000,000
Oil and Gas Exploration and Production Reporting Segment [Member] | Other U.S. Onshore Properties [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	0
Midstream Reporting Segment [Member]
Impaired Long Lived Assets Held and Used [Line Items]
Long-lived assets held for use	$12,000,000	$79,000,000	$13,000,000

Impairments_Fair_Value_Measure

Impairments - Fair Value Measurements Table (Detail) (Fair Value, Inputs, Level 3 [Member], Income Approach Valuation Technique [Member], Nonrecurring [Member], USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member] | Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets held for use	$731		$548
Cost-method investment (1)	$32	[1]	$32	[1]
[1]	This represents the Company’s after-tax net investment.

Impairments_Impairments_of_Unp

Impairments - Impairments of Unproved Properties (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties	$1,245	$864	$1,544
U.S. Onshore Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties			721
Gulf of Mexico Properties [Member]
Property, Plant, and Equipment [Line Items]
Impairment of unproved properties			$124

Suspended_Exploratory_Well_Cos2

Suspended Exploratory Well Costs - Rollforward (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$2,232		$2,062	$1,353
Additions pending the determination of proved reserves	421		848	960
Divestitures	-913	[1]	-48	0
Reclassifications to proved properties	-100		-507	-129
Charges to exploration expense	-118		-123	-122
Balance at December 31	1,522		2,232	2,062
Offshore Area 1 in Mozambique [Member] | Oil and Gas Exploration and Production Reporting Segment [Member]
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Divestitures	($744)
Working interest sold	10.00%
[1]	Includes $(744) million related to the Company’s sale of a 10% working interest in Offshore Area 1 in Mozambique during 2014.

Suspended_Exploratory_Well_Cos3

Suspended Exploratory Well Costs - Aging by Geographic Area and the Year the Costs Were Suspended (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs	$1,522	$2,232	$2,062	$1,353
Suspended exploratory well costs capitalized for a period less than one year after completion of drilling	388
Projects with exploratory well costs capitalized for a period greater than one year after completion of drilling	24
Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	368
Aging of Capitalized Exploratory Well Costs, Period Start Date	1-Jan-13
Aging of Capitalized Exploratory Well Costs, Period End Date	31-Dec-13
Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	252
Aging of Capitalized Exploratory Well Costs, Period Start Date	1-Jan-12
Aging of Capitalized Exploratory Well Costs, Period End Date	31-Dec-12
Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	514
Aging of Capitalized Exploratory Well Costs, Period End Date	31-Dec-11
United States Onshore [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs	164
Suspended exploratory well costs capitalized for a period less than one year after completion of drilling	131
United States Onshore [Member] | Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	17
United States Onshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	5
United States Onshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	11
United States Offshore [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs	314
Suspended exploratory well costs capitalized for a period less than one year after completion of drilling	78
United States Offshore [Member] | Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	80
United States Offshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	63
United States Offshore [Member] | Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	93
International [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs	1,044
Suspended exploratory well costs capitalized for a period less than one year after completion of drilling	179
International [Member] | Aging of Capitalized Exploratory Well Costs, Period One [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	271
International [Member] | Aging of Capitalized Exploratory Well Costs, Period Two [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	184
International [Member] | Aging of Capitalized Exploratory Well Costs, Period Three [Member]
Capitalized Exploratory Well Costs [Line Items]
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling	$410

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Carrying amount of asset retirement obligations at January 1	$2,022	$1,885
Liabilities incurred	119	182
Property dispositions	-70	-76
Liabilities settled	-443	-162
Accretion expense	93	110
Revisions in estimated liabilities	332	83
Carrying amount of asset retirement obligations at December 31	$2,053	$2,022

Goodwill_and_Other_Intangible_2

Goodwill and Other Intangible Assets - Goodwill (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill impairment loss	$0
Goodwill [Line Items]
Goodwill	5,576,000,000	5,492,000,000	5,492,000,000
Oil and Gas Exploration and Production Reporting Unit [Member]
Goodwill [Line Items]
Goodwill	5,100,000,000
Other Gathering and Processing Reporting Unit [Member]
Goodwill [Line Items]
Goodwill	69,000,000
WES Gathering and Processing Reporting Unit [Member]
Goodwill [Line Items]
Goodwill	379,000,000
WES Transportation Reporting Unit [Member]
Goodwill [Line Items]
Goodwill	$5,000,000

Goodwill_and_Other_Intangible_3

Goodwill and Other Intangible Assets - Other Intangible Assets Amortization Expense Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	$1,037	$229
Accumulated amortization	-44	-59
Net carrying amount	993	170
Amortization expense	6	7
Offshore Platform Leases [Member]
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	33	60
Accumulated amortization	-29	-50
Net carrying amount	4	10
Amortization expense	0	3
Customer Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	1,004	169
Accumulated amortization	-15	-9
Net carrying amount	989	160
Amortization expense	$6	$4

Goodwill_and_Other_Intangible_4

Goodwill and Other Intangible Assets - Other Intangible Assets (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Expected aggregate amortization expense for intangible assets in 2015	31
Expected aggregate amortization expense for intangible assets in 2016	31
Expected aggregate amortization expense for intangible assets in 2017	31
Expected aggregate amortization expense for intangible assets in 2018	31
Expected aggregate amortization expense for intangible assets in 2019	31
Customer Contracts [Member] | Gathering and Processing Assets in the Delaware basin [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired intangible assets, useful life	30 years

Noncontrolling_Interests_Detai

Noncontrolling Interests (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Noncontrolling Interest [Line Items]
Net proceeds raised from offering	$1,026	$724	$623
Western Gas Equity Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued to the public	6
Net proceeds raised from initial public offering by subsidiary			411
Net proceeds raised from offering	335
Western Gas Equity Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	88.30%
Public ownership interest in subsidiary	11.70%
Western Gas Equity Partners, LP [Member] | IPO [Member]
Noncontrolling Interest [Line Items]
Units issued to the public			20
Issuance price per common unit			$22
Western Gas Partners, LP [Member]
Noncontrolling Interest [Line Items]
Units issued to the public	10	12	5
Net proceeds raised from offering	$691	$725	$212
Western Gas Partners, LP [Member] | Class C Units [Member]
Noncontrolling Interest [Line Items]
Units issued in private placement	11
Western Gas Partners, LP [Member] | Limited Partner [Member]
Noncontrolling Interest [Line Items]
Public ownership interest in subsidiary	55.00%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Western Gas Equity Partners, LP, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	34.90%
Western Gas Partners, LP [Member] | Limited Partner [Member] | Other Anadarko Subsidiaries, Ownership Interest [Member]
Noncontrolling Interest [Line Items]
Ownership interest in subsidiary	8.30%
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%

EquityMethod_Investments_Detai

Equity-Method Investments (Detail) (Equity-Method Investments [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2007
Schedule of Equity Method Investments [Line Items]
Ownership interest of investee entities	95.00%
Carrying amount of notes payable to affiliates	$2,900,000,000			$2,900,000,000
Carrying amount of investments	2,800,000,000
Applicable interest rate	1.24%	1.24%
Interest expense on the notes payable	36,000,000	37,000,000	42,000,000
Equity earnings from investments in the investee entities	-45,000,000	-42,000,000	-43,000,000
Maximum [Member]
Schedule of Equity Method Investments [Line Items]
Debt-to-capital ratio covenant	0.67
Contributed Property to Investees [Member]
Schedule of Equity Method Investments [Line Items]
Fair value of oil and gas properties and gathering and processing assets contributed by Anadarko				$2,900,000,000

Derivative_Instruments_Oil_and

Derivative Instruments - Oil and Natural-Gas Production/Processing Derivative Activities Table (Detail) (Not Designated as Hedging Instrument [Member], Price Risk Derivative [Member])	12 Months Ended
	Dec. 31, 2014
Three Way Collars Natural Gas 2015 [Member]
Derivative [Line Items]
Natural-gas derivative nonmonetary notional amount per day	635,000
Extendable Fixed Price Contracts Natural Gas 2015 [Member]
Derivative [Line Items]
Natural-gas derivative nonmonetary notional amount per day	170,000	[1]
Average price per MMBtu
Average price per MMBtu	4.17
Call Option [Member] | Short [Member] | Three Way Collars Natural Gas 2015 [Member]
Average price per MMBtu
Average ceiling price	4.76
Put Option [Member] | Short [Member] | Three Way Collars Natural Gas 2015 [Member]
Average price per MMBtu
Average floor price	2.75
Put Option [Member] | Long [Member] | Three Way Collars Natural Gas 2015 [Member]
Average price per MMBtu
Average floor price	3.75
[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_Additio

Derivative Instruments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Cash received (paid) in settlement of derivative instruments	$371,000,000	$85,000,000	$685,000,000
Cash paid in settlement of interest-rate swap agreements	222,000,000	0	0
5.0 billion Facility [Member] | Revolving Credit Facility [Member]
Derivative [Line Items]
Line of credit, maximum capacity	5,000,000,000
Senior Notes [Member] | Senior Note 16 And Senior Note 17 [Member]
Derivative [Line Items]
Debt instrument, principal amount	1,250,000,000
Securing most derivative counterparties [Member] | 5.0 billion Facility [Member] | Revolving Credit Facility [Member]
Derivative [Line Items]
Line of credit, maximum capacity	5,000,000,000
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross derivative liability	1,455,000,000	986,000,000
Aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed	97,000,000	42,000,000
Not Designated as Hedging Instrument [Member] | Commodity [Member] | Natural Gas [Member]
Derivative [Line Items]
Financial derivative transactions	6,000,000	16,000,000
Not Designated as Hedging Instrument [Member] | Permitted to Offset Gross Derivative Asset with Financial Institutions [Member]
Derivative [Line Items]
Gross derivative liability	289,000,000	76,000,000
Not Designated as Hedging Instrument [Member] | Price Risk Derivative [Member] | Three-Way Collars Oil 2015 [Member]
Derivative [Line Items]
Oil derivative nonmonetary notional amount per day	25
Cash received (paid) in settlement of derivative instruments	126,000,000
Not Designated as Hedging Instrument [Member] | Modified Interest Rate Swap [Member]
Derivative [Line Items]
Interest-rate swap reference-period start date	1-Jun-14		1-Oct-12
Aggregate notional principal amount of interest-rate swap	1,100,000,000		800,000,000
Not Designated as Hedging Instrument [Member] | Settled Interest Rate Swap [Member]
Derivative [Line Items]
Cash received (paid) in settlement of derivative instruments			-64,000,000
Aggregate notional principal amount of interest-rate swap	750,000,000		200,000,000
Cash paid in settlement of interest-rate swap agreements	$222,000,000

Derivative_Instruments_Interes

Derivative Instruments - Interest-Rate Derivatives Table (Detail) (Not Designated as Hedging Instrument [Member], USD $)	12 Months Ended
	Dec. 31, 2014
Interest-Rate Swap 1 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	50,000,000
Weighted-average interest rate for interest-rate swap	5.91%
Interest-Rate Swap 1 [Member] | Minimum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	1-Sep-16
Interest-Rate Swap 1 [Member] | Maximum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	1-Sep-26
Interest-Rate Swap 2 [Member]
Derivative [Line Items]
Notional principal amount of interest-rate swap	1,850,000,000
Weighted-average interest rate for interest-rate swap	6.05%
Interest-Rate Swap 2 [Member] | Minimum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	1-Sep-16
Interest-Rate Swap 2 [Member] | Maximum [Member]
Derivative [Line Items]
Reference period for interest-rate swap	1-Sep-46

Derivative_Instruments_Effect_

Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) (Not Designated as Hedging Instrument [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives Fair Value [Line Items]
Gross derivative assets	$493	$380
Gross derivative liabilities	-1,455	-986
Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	493	380
Gross derivative liabilities	-238	-332
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	421	181
Gross derivative liabilities	-118	-102
Commodity Derivatives [Member] | Other Assets [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	1	89
Gross derivative liabilities	0	-66
Commodity Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	71	106
Gross derivative liabilities	-114	-149
Commodity Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	4
Gross derivative liabilities	-6	-15
Interest-Rate and Other Derivatives [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	-1,217	-654
Interest-Rate and Other Derivatives [Member] | Accrued Expenses [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	0	-480
Interest-Rate and Other Derivatives [Member] | Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross derivative assets	0	0
Gross derivative liabilities	($1,217)	($174)

Derivative_Instruments_Effect_1

Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Total (gains) losses on derivatives, net	$207		($392)		($308)
Commodity Derivatives [Member] | Gathering, Processing, and Marketing Sales [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	10	[1]	6	[1]	18	[1]
Commodity Derivatives [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	-589		141		-387
Interest-Rate and Other Derivatives [Member] | (Gains) Losses on Derivatives, net [Member]
Derivative [Line Items]
Total (gains) losses on derivatives, net	$786		($539)		$61
[1]	Represents the effect of Marketing and Trading Derivative Activities.

Derivative_Instruments_Fair_Va

Derivative Instruments - Fair Value Table (Detail) (Not Designated as Hedging Instrument [Member], USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	$493		$380
Gross derivative liabilities	-1,455		-986
Derivative assets netting	-189	[1]	-279	[1]
Derivative liabilities netting	189	[1]	279	[1]
Cash collateral from counterparties	-13		0
Cash collateral held by counterparties	23		7
Derivative assets	291		101
Derivative liabilities	-1,243		-700
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	493		380
Gross derivative liabilities	-238		-332
Interest-Rate and Other Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	-1,217		-654
Derivative liabilities netting	0	[1]	0	[1]
Cash collateral held by counterparties	0		0
Derivative liabilities	-1,217		-654
Financial Institutions [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	-187	[1]	-153	[1]
Derivative liabilities netting	187	[1]	153	[1]
Cash collateral from counterparties	-13		0
Cash collateral held by counterparties	23		7
Derivative assets	271		58
Derivative liabilities	-24		-40
Other Counterparties [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets netting	-2	[1]	-126	[1]
Derivative liabilities netting	2	[1]	126	[1]
Cash collateral from counterparties	0		0
Cash collateral held by counterparties	0		0
Derivative assets	20		43
Derivative liabilities	-2		-6
Fair Value, Inputs, Level 1 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 1 [Member] | Interest-Rate and Other Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 1 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 1 [Member] | Other Counterparties [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 2 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	493		380
Gross derivative liabilities	-1,455		-986
Fair Value, Inputs, Level 2 [Member] | Interest-Rate and Other Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	-1,217		-654
Fair Value, Inputs, Level 2 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	471		211
Gross derivative liabilities	-234		-200
Fair Value, Inputs, Level 2 [Member] | Other Counterparties [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	22		169
Gross derivative liabilities	-4		-132
Fair Value, Inputs, Level 3 [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 3 [Member] | Interest-Rate and Other Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 3 [Member] | Financial Institutions [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	0		0
Fair Value, Inputs, Level 3 [Member] | Other Counterparties [Member] | Commodity Derivatives [Member] | Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross derivative assets	0		0
Gross derivative liabilities	$0		$0
[1]	Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

Debt_and_Interest_Expense_Addi

Debt and Interest Expense - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2006	Dec. 31, 2013	Dec. 31, 2012	Feb. 25, 2014
Debt Instrument [Line Items]
Debt instrument, accreted value	$15,071,000,000		$13,557,000,000	$13,269,000,000
Fair Value, Inputs, Level 2 [Member] | Market Approach Valuation Technique [Member]
Debt Instrument [Line Items]
Estimated fair value of total borrowings	17,400,000,000		15,300,000,000
Senior Notes [Member] | Zero-Coupon Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Loan proceeds upon issuing debt		500,000,000
Debt instrument, maturity date	10-Oct-36
Debt instrument, principal amount	2,360,000,000		2,360,000,000
Yield to maturity	5.24%
Debt instrument, accreted value	765,000,000
Revolving Credit Facility [Member] | 5.0 billion Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	5,000,000,000
Line of credit, expiration date	2-Sep-15
Percentage of capital stock of certain wholly owned foreign subsidiaries	65.00%
Line of credit, outstanding borrowings	0
Revolving Credit Facility [Member] | Five-Year 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
Revolving Credit Facility [Member] | Five-Year Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin added	0.00%
Revolving Credit Facility [Member] | Five-Year Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin added	1.65%
Ratio of indebtedness to total capital	0.65
Revolving Credit Facility [Member] | 364-Day Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	2,000,000,000
Debt instrument, term	364 days
Revolving Credit Facility [Member] | 364-Day Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin added	0.00%
Revolving Credit Facility [Member] | 364-Day Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin added	1.68%
Ratio of indebtedness to total capital	0.65
Revolving Credit Facility [Member] | WES RCF [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	1,200,000,000				800,000,000
Line of credit, expiration date	26-Feb-19
Line of credit, outstanding borrowings	510,000,000		0
Line of credit, expandable maximum capacity	1,500,000,000
Line of credit, interest rate	1.47%
Line of credit, available borrowing capacity	677,000,000
Outstanding letters of credit	$13,000,000
Revolving Credit Facility [Member] | WES RCF [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Applicable margin added	0.98%
Revolving Credit Facility [Member] | WES RCF [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Applicable margin added	1.45%

Debt_and_Interest_Expense_Outs

Debt and Interest Expense - Outstanding Debt Table (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Debt Instrument [Line Items]
Total debt at face value	$16,687,000,000		$15,202,000,000
Net unamortized discounts and premiums (1)	-1,616,000,000	[1]	-1,645,000,000	[1]
Total borrowings	15,071,000,000		13,557,000,000		13,269,000,000
Capital lease obligation	21,000,000		8,000,000
Current portion of long-term debt	0		500,000,000
Total long-term debt	15,092,000,000		13,065,000,000
WES RCF [Member] | Western Gas Partners, LP [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, outstanding borrowings	510,000,000		0
Senior Notes [Member] | 5.750% Senior Notes due 2014 [Member]
Debt Instrument [Line Items]
Principal	0		275,000,000
Debt instrument, stated interest rate	5.75%
Debt instrument, maturity date	15-Jun-14
Senior Notes [Member] | 7.625% Senior Notes due 2014 [Member]
Debt Instrument [Line Items]
Principal	0		500,000,000
Debt instrument, stated interest rate	7.63%
Debt instrument, maturity date	15-Mar-14
Senior Notes [Member] | 5.950% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Principal	1,750,000,000		1,750,000,000
Debt instrument, stated interest rate	5.95%
Debt instrument, maturity date	15-Sep-16
Senior Notes [Member] | 6.375% Senior Notes due 2017 [Member]
Debt Instrument [Line Items]
Principal	2,000,000,000		2,000,000,000
Debt instrument, stated interest rate	6.38%
Debt instrument, maturity date	15-Sep-17
Senior Notes [Member] | 7.050% Debentures due 2018 [Member]
Debt Instrument [Line Items]
Principal	114,000,000		114,000,000
Debt instrument, stated interest rate	7.05%
Debt instrument, maturity date	15-May-18
Senior Notes [Member] | WES 2.600% Senior Notes due 2018 [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Principal	350,000,000		250,000,000
Debt instrument, stated interest rate	2.60%		2.60%
Debt instrument, maturity date	15-Aug-18		15-Aug-18
Senior Notes [Member] | 6.950% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Principal	300,000,000		300,000,000
Debt instrument, stated interest rate	6.95%
Debt instrument, maturity date	15-Jun-19
Senior Notes [Member] | 8.700% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Principal	600,000,000		600,000,000
Debt instrument, stated interest rate	8.70%
Debt instrument, maturity date	15-Mar-19
Senior Notes [Member] | WES 5.375% Senior Notes due 2021 [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Principal	500,000,000		500,000,000
Debt instrument, stated interest rate	5.38%
Debt instrument, maturity date	1-Jun-21
Senior Notes [Member] | WES 4.000% Senior Notes due 2022 [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Principal	670,000,000		670,000,000
Debt instrument, stated interest rate	4.00%
Debt instrument, maturity date	1-Jun-22
Senior Notes [Member] | 3.450% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Principal	625,000,000		0
Debt instrument, stated interest rate	3.45%
Debt instrument, maturity date	15-Jul-24
Senior Notes [Member] | 6.950% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Principal	650,000,000		650,000,000
Debt instrument, stated interest rate	6.95%
Debt instrument, maturity date	1-Jun-24
Senior Notes [Member] | 7.500% Debentures due 2026 [Member]
Debt Instrument [Line Items]
Principal	112,000,000		112,000,000
Debt instrument, stated interest rate	7.50%
Debt instrument, maturity date	15-Oct-26
Senior Notes [Member] | 7.000% Debentures due 2027 [Member]
Debt Instrument [Line Items]
Principal	54,000,000		54,000,000
Debt instrument, stated interest rate	7.00%
Debt instrument, maturity date	15-Nov-27
Senior Notes [Member] | 7.125% Debentures due 2027 [Member]
Debt Instrument [Line Items]
Principal	150,000,000		150,000,000
Debt instrument, stated interest rate	7.13%
Debt instrument, maturity date	15-Oct-27
Senior Notes [Member] | 6.625% Debentures due 2028 [Member]
Debt Instrument [Line Items]
Principal	17,000,000		17,000,000
Debt instrument, stated interest rate	6.63%
Debt instrument, maturity date	15-Jan-28
Senior Notes [Member] | 7.150% Debentures due 2028 [Member]
Debt Instrument [Line Items]
Principal	235,000,000		235,000,000
Debt instrument, stated interest rate	7.15%
Debt instrument, maturity date	15-May-28
Senior Notes [Member] | 7.200% Debentures due 2029 [Member]
Debt Instrument [Line Items]
Principal	135,000,000		135,000,000
Debt instrument, stated interest rate	7.20%
Debt instrument, maturity date	15-Mar-29
Senior Notes [Member] | 7.950% Debentures due 2029 [Member]
Debt Instrument [Line Items]
Principal	117,000,000		117,000,000
Debt instrument, stated interest rate	7.95%
Debt instrument, maturity date	15-Apr-29
Senior Notes [Member] | 7.500% Senior Notes due 2031 [Member]
Debt Instrument [Line Items]
Principal	900,000,000		900,000,000
Debt instrument, stated interest rate	7.50%
Debt instrument, maturity date	1-May-31
Senior Notes [Member] | 7.875% Senior Notes due 2031 [Member]
Debt Instrument [Line Items]
Principal	500,000,000		500,000,000
Debt instrument, stated interest rate	7.88%
Debt instrument, maturity date	15-Sep-31
Senior Notes [Member] | Zero-Coupon Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Principal	2,360,000,000		2,360,000,000
Debt instrument, maturity date	10-Oct-36
Total borrowings	765,000,000
Senior Notes [Member] | 6.450% Senior Notes due 2036 [Member]
Debt Instrument [Line Items]
Principal	1,750,000,000		1,750,000,000
Debt instrument, stated interest rate	6.45%
Debt instrument, maturity date	15-Sep-36
Senior Notes [Member] | 7.950% Senior Notes due 2039 [Member]
Debt Instrument [Line Items]
Principal	325,000,000		325,000,000
Debt instrument, stated interest rate	7.95%
Debt instrument, maturity date	15-Jun-39
Senior Notes [Member] | 6.200% Senior Notes due 2040 [Member]
Debt Instrument [Line Items]
Principal	750,000,000		750,000,000
Debt instrument, stated interest rate	6.20%
Debt instrument, maturity date	15-Mar-40
Senior Notes [Member] | 4.500% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Principal	625,000,000		0
Debt instrument, stated interest rate	4.50%
Debt instrument, maturity date	15-Jul-44
Senior Notes [Member] | WES 5.450% Senior Notes due 2044 [Member] | Western Gas Partners, LP [Member]
Debt Instrument [Line Items]
Principal	400,000,000		0
Debt instrument, stated interest rate	5.45%
Debt instrument, maturity date	1-Apr-44
Senior Notes [Member] | 7.730% Debentures due 2096 [Member]
Debt Instrument [Line Items]
Principal	61,000,000		61,000,000
Debt instrument, stated interest rate	7.73%
Debt instrument, maturity date	15-Sep-96
Senior Notes [Member] | 7.500% Debentures due 2096 [Member]
Debt Instrument [Line Items]
Principal	78,000,000		78,000,000
Debt instrument, stated interest rate	7.50%
Debt instrument, maturity date	1-Nov-96
Senior Notes [Member] | 7.250% Debentures due 2096 [Member]
Debt Instrument [Line Items]
Principal	$49,000,000		$49,000,000
Debt instrument, stated interest rate	7.25%
Debt instrument, maturity date	15-Nov-96
[1]	Unamortized discounts and premiums are amortized over the term of the related debt.

Debt_and_Interest_Expense_Debt

Debt and Interest Expense - Debt Activity Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Carrying value, beginning balance	$13,557	$13,269
Debt Instrument [Line Items]
Other, net	39	38
Carrying value, ending balance	15,071	13,557
WES 2.600% Senior Notes due 2018 [Member] | Western Gas Partners, LP [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Issuance	101	250
Debt instrument, stated interest rate	2.60%	2.60%
Debt instrument, maturity date	15-Aug-18	15-Aug-18
WES RCF [Member] | Western Gas Partners, LP [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings	1,160	710
Repayments of credit facilities	-650	-710
WES 5.450% Senior Notes due 2044 [Member] | Western Gas Partners, LP [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Issuance	394
Debt instrument, stated interest rate	5.45%
Debt instrument, maturity date	1-Apr-44
3.450% Senior Notes due 2024 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Issuance	624
Debt instrument, stated interest rate	3.45%
Debt instrument, maturity date	15-Jul-24
4.500% Senior Notes due 2044 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Issuance	621
Debt instrument, stated interest rate	4.50%
Debt instrument, maturity date	15-Jul-44
7.625% Senior Notes due 2014 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of debt	-500
Debt instrument, stated interest rate	7.63%
Debt instrument, maturity date	15-Mar-14
5.750% Senior Notes due 2014 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of debt	($275)
Debt instrument, stated interest rate	5.75%
Debt instrument, maturity date	15-Jun-14

Debt_and_Interest_Expense_Subs

Debt and Interest Expense - Subsequent Events (Detail) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Jan. 15, 2015	Jan. 30, 2015
364-Day Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity	$2,000,000,000
Debt instrument, term	364 days
Subsequent Event [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Line of credit, maximum capacity		3,000,000,000
Subsequent Event [Member] | Commercial Paper [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, term		397 days
Subsequent Event [Member] | 364-Day Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, outstanding borrowings			$1,500,000,000

Debt_and_Interest_Expense_Sche

Debt and Interest Expense - Scheduled Maturities Table (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Debt Disclosure [Abstract]
2015	$0
2016	1,750
2017	2,000
2018	464
2019	$1,410

Debt_and_Interest_Expense_Inte

Debt and Interest Expense - Interest Expense Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Debt and other	$973	$949	$963
Capitalized interest	-201	-263	-221
Total interest expense	$772	$686	$742

Stockholders_Equity_Common_Sto

Stockholders' Equity - Common Stock Rollforward (Detail)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Shares of common stock issued
Shares at January 1	522.5		519	516
Exercise of stock options	1.85	[1]	2	1
Issuance of restricted stock	1		2	2
Shares at December 31	525.9		522.5	519
Shares of common stock held in treasury
Shares at January 1	18.8		18	18
Shares received for restricted stock vested and options exercised	0		1	0
Shares at December 31	19.3		18.8	18
Shares of common stock outstanding at December 31	507		504	501
[1]	The total intrinsic value of stock options exercised was $88 million during 2014, $80 million during 2013, and $49 million during 2012, based on the difference between the market price at the exercise date and the exercise price.

Stockholders_Equity_Reconcilia

Stockholders' Equity - Reconciliation between Basic and Diluted EPS Table (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Net income (loss)
Net income (loss) attributable to common stockholders	($1,750)		$801		$2,391
Less distributions on participating securities	4		2		1
Less undistributed income allocated to participating securities	0		4		14
Basic	-1,754		795		2,376
Diluted	($1,754)		$795		$2,376
Shares
Average number of common shares outstanding—basic	506		502		500
Dilutive effect of stock options	0		3		2
Average number of common shares outstanding—diluted	506		505		502
Excluded (1)	11	[1]	4	[1]	6	[1]
Net income (loss) per common share
Basic	($3.47)		$1.58		$4.76
Diluted	($3.47)		$1.58		$4.74
Dividends per common share	$0.99		$0.54		$0.36
[1]	Inclusion of certain shares would have had an anti-dilutive effect.

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at December 31, 2013	($285)
Other comprehensive income (loss), before reclassifications	-256
Reclassifications to Consolidated Statement of Income	24
Net other comprehensive income (loss)	-232	355	-28
Balance at December 31, 2014	-517	-285
Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at December 31, 2013	-54
Other comprehensive income (loss), before reclassifications	0
Reclassifications to Consolidated Statement of Income	6
Net other comprehensive income (loss)	6
Balance at December 31, 2014	-48
Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at December 31, 2013	-231
Other comprehensive income (loss), before reclassifications	-256
Reclassifications to Consolidated Statement of Income	18
Net other comprehensive income (loss)	-238
Balance at December 31, 2014	($469)

ShareBased_Compensation_Additi

Share-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Shares available for future issuance under active share-based compensation plans	21
Shares authorized for awards under active share-based compensation plans	31
Excess tax benefits related to share-based compensation included in cash flows from financing activities	$22	$11	$51
Cash received from stock option exercises	$99	$135	$52

ShareBased_Compensation_Compen

Share-Based Compensation - Compensation Expense Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	$325	$155	$320
Income tax benefit	120	57	117
Restricted Stock [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	144	122	103
Stock Option [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	21	27	43
Other Equity-Classified Awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	1	1	1
Value Creation Plan [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	136	0	-2
Performance-Based Unit Awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	23	4	8
Other Performance-Based Awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	0	0	165
Other Liability-Classified Awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Pretax compensation expense	$0	$1	$2

ShareBased_Compensation_Equity

Share-Based Compensation - Equity-Classified Awards (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Weighted-average grant-date fair value	$87.42	$84.17	$79.97
Total fair value	$132	$110	$105
Total unrecognized compensation cost	199
Unrecognized compensation cost, weighted-average remaining period	1 year 10 months 24 days
Restricted Stock [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years
Stock Option [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation cost, weighted-average remaining period	2 years 2 months 12 days
Total unrecognized compensation cost related to stock options	$40
Stock Option [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Expiration date	7 years

ShareBased_Compensation_Restri

Share-Based Compensation - Restricted Stock Activity Table (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Restricted Stock Shares [Roll Forward]
Non-vested at January 1, 2014	3.22
Granted	2.05
Vested	-1.52
Forfeited	-0.15
Non-vested at December 31, 2014	3.6	3.22
Restricted Stock Weighted-Average Grant-Date Fair Value [Abstract]
Non-vested at January 1, 2014	$82.53
Granted	$87.42	$84.17	$79.97
Vested	$82.35
Forfeited	$84.49
Non-vested at December 31, 2014	$85.31	$82.53

ShareBased_Compensation_Stock_

Share-Based Compensation - Stock Options Assumptions Table (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted-average grant-date fair value	$23.55	$26.27	$25.84
Assumptions
Expected option life—years	4 years 10 months 24 days	4 years 9 months 18 days	4 years 10 months 24 days
Volatility	29.90%	33.90%	44.20%
Risk-free interest rate	1.60%	1.30%	0.70%
Dividend yield	1.10%	0.80%	0.50%

ShareBased_Compensation_Stock_1

Share-Based Compensation - Stock Option Activity Table (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Outstanding [Roll Forward]
Shares outstanding at January 1, 2014	7.72
Shares granted	0.95
Shares exercised	-1.85	[1]	-2	-1
Shares forfeited or expired	-0.03
Shares outstanding at December 31, 2014	6.79		7.72
Shares vested or expected to vest at December 31, 2014	6.73
Shares exercisable at December 31, 2014	4.99
Weighted-average exercise price, outstanding at January 1, 2014	$63.30
Granted weighted-average exercise price	$93.34
Exercised weighted-average exercise price	$54.03	[1]
Forfeited or expired weighted-average exercise price	$76
Weighted-average exercise price, outstanding at December 31, 2014	$69.96		$63.30
Weighted-average exercise price, vested or expected to vest at December 31, 2014	$69.79
Weighted-average exercise price, exercisable at December 31, 2014	$62.91
Weighted-average remaining contractual term, outstanding at December 31, 2014	3 years 6 months 22 days
Weighted-average remaining contractual term, vested or expected to vest at December 31, 2014	3 years 6 months 15 days
Weighted-average remaining contractual term, exercisable at December 31, 2014	2 years 7 months 6 days
Aggregate intrinsic value, outstanding at December 31, 2014	$104.30
Aggregate intrinsic value, vested or expected to vest at December 31, 2014	104.2
Aggregate intrinsic value, exercisable at December 31, 2014	101.1
Total intrinsic value of stock options exercised during the period	$88		$80	$49
[1]	The total intrinsic value of stock options exercised was $88 million during 2014, $80 million during 2013, and $49 million during 2012, based on the difference between the market price at the exercise date and the exercise price.

ShareBased_Compensation_Liabil

Share-Based Compensation - Liability-Classified Awards (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Value Creation Plan [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Liability paid	$0	$0	$24,000,000
Outstanding liability	137,000,000
Performance-Based Unit Awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Liability paid	12,000,000	15,000,000	37,000,000
Outstanding liability	26,000,000
Number of shares of common stock represented by each performance unit	1
Total unrecognized compensation cost	43,000,000
Unrecognized compensation cost, weighted-average remaining period	2 years 2 months 12 days
Performance-Based Unit Awards [Member] | Minimum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	2 years
Performance-Based Unit Awards [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years
Other Performance-Based Awards [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Liability paid			$203,000,000

Commitments_Operating_Leases_D

Commitments - Operating Leases (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	$3,061,000,000
Operating leases, residual value guarantees	53,000,000
Operating leases, residual value guarantees accrued	0
Total rent expense, net of sublease income and amounts capitalized	85,000,000	119,000,000	136,000,000
Contingent rent expense	22,000,000	24,000,000	28,000,000
Maximum [Member]
Operating Leased Assets [Line Items]
Operating leases, expiration date	31-Dec-26
Drilling Rigs [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	2,700,000,000
Other Operating Lease Agreements [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	324,000,000
Offshore Drilling Rig Commitments [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	2,500,000,000
Number of offshore drilling vessels related to operating leases	7
Onshore Drilling Rig Commitments [Member]
Operating Leased Assets [Line Items]
Operating leases, future minimum payments due	$208,000,000

Commitments_Future_Minimum_Lea

Commitments - Future Minimum Lease Payments Table (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Commitments [Abstract]
2015	$1,022
2016	833
2017	592
2018	324
2019	203
Later years	87
Total future minimum lease payments	$3,061

Commitments_Other_Commitments_

Commitments - Other Commitments (Detail) (USD $)	12 Months Ended
In Billions, unless otherwise specified	Dec. 31, 2014
Unrecorded Unconditional Purchase Obligation [Line Items]
Aggregate future payments	10.4
Aggregate future payments expected to be paid in 2015	2.2
Aggregate future payments expected to be paid in 2016	1.6
Aggregate future payments expected to be paid in 2017	1.3
Aggregate future payments expected to be paid in 2018	1.2
Aggregate future payments expected to be paid in 2019	1
Aggregate future payments expected to be paid thereafter	3.1
Maximum [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Other commitments, expiration date	31-Dec-36

Contingencies_Additional_Infor

Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Loss contingency accrual	$5,300,000,000	$854,000,000
Other Assets	2,310,000,000	2,082,000,000
Decommissioning charge	4,360,000,000	850,000,000	-250,000,000
Liability for remediation and reclamation obligations	126,000,000	126,000,000
Landfill in West Covina, California [Member]
Loss Contingencies [Line Items]
Liability for remediation and reclamation obligations	50,000,000
Third Party Bankruptcy Assignment [Member]
Loss Contingencies [Line Items]
Decommissioning charge	22,000,000	117,000,000
Decommissioning obligations included in accrued expenses	114,000,000
Pending Litigation [Member] | Peregrino Litigation [Member]
Loss Contingencies [Line Items]
Loss contingency accrual	0
Pending Litigation [Member] | Amount Of Tax Originally In Dispute [Member] | Peregrino Litigation [Member]
Loss Contingencies [Line Items]
Other Assets	128,000,000
Pending Litigation [Member] | Amount Of Tax Currently In Dispute [Member] | Peregrino Litigation [Member]
Loss Contingencies [Line Items]
Other Assets	$42,000,000

Contingencies_Tronox_Litigatio

Contingencies - Tronox Litigation (Detail) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	Apr. 03, 2014
Loss Contingencies [Line Items]
Tronox-related contingent loss	$4,360,000,000	$850,000,000	($250,000,000)
Tronox Litigation [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Litigation-related contingent liability	5,210,000,000	0		5,150,000,000
Pre Settlement Interest Rate					6.00%
Post Settlement Interest Rate First 180 Days					1.50%
Tronox-related contingent loss	4,360,000,000	850,000,000		4,300,000,000
Tronox Litigation [Member] | Pending Litigation [Member] | London Interbank Offered Rate (LIBOR) [Member]
Loss Contingencies [Line Items]
Post Settlement Interest Rate After 180 Days					1.50%
Tronox Litigation [Member] | Pending Litigation [Member] | Excluding Pre-Judgment Interest Sought and Attorneys' Fees and Costs [Member]
Loss Contingencies [Line Items]
Damages sought				18,850,000,000
Tronox Litigation [Member] | Pending Litigation [Member] | Principal Portion Of Loss Contingency Accrual [Member]
Loss Contingencies [Line Items]
Litigation-related contingent liability					3,980,000,000
Tronox Litigation [Member] | Pending Litigation [Member] | Post Settlement Interest Expense [Member]
Loss Contingencies [Line Items]
Tronox-related contingent loss	$60,000,000

Contingencies_Subsequent_Event

Contingencies - Subsequent Events (Detail) (Subsequent Event [Member], USD $)	0 Months Ended
	Jan. 23, 2015	Jan. 15, 2015
		bbl
Tronox Litigation [Member] | Judicial Ruling [Member]
Subsequent Event [Line Items]
Payment for Tronox settlement	$5,200,000,000
Deepwater Horizon [Member] | Pending Litigation [Member] | Clean Water Act [Member]
Subsequent Event [Line Items]
Barrels of oil discharged		3,190,000

Contingencies_Deepwater_Horizo

Contingencies - Deepwater Horizon Events (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Feb. 20, 2015	Jun. 30, 2014
Loss Contingencies [Line Items]
Loss contingency accrual	$5,300,000,000	$854,000,000
Accrual for environmental loss contingencies	126,000,000	126,000,000
Gain (loss) related to litigation settlement	-97,000,000	-15,000,000	-18,000,000
Macondo Exploration Well [Member]
Loss Contingencies [Line Items]
Anadarko's nonoperated interest					25.00%
Deepwater Horizon [Member] | Oil Pollution Act of 1990 [Member]
Loss Contingencies [Line Items]
Allocable percentage share of gross OPA-related environmental costs	0.00%
Accrual for environmental loss contingencies	0
Deepwater Horizon [Member] | Oil Pollution Act of 1990 [Member] | BP Exploration and Production Inc. [Member]
Loss Contingencies [Line Items]
Gross OPA-related environmental costs, excluding amounts BP has already funded, amounts that cannot reasonably be estimated by BP, non-OPA-related fines and penalties, and estimated state and local governmental claims	11,000,000,000
Deepwater Horizon [Member] | BP indemnification liability [Member]
Loss Contingencies [Line Items]
Loss contingency accrual	0
Deepwater Horizon [Member] | Settled Litigation [Member]
Loss Contingencies [Line Items]
Cash payment for Deepwater Horizon settlement				4,000,000,000
Deepwater Horizon [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Penalties or fines assessed against the Company						0
Litigation-related contingent liability	90,000,000	0
Allocation of fault assigned in Phase One Findings and Conclusions	0.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | BP and BPAP [Member]
Loss Contingencies [Line Items]
Allocation of fault assigned in Phase One Findings and Conclusions	67.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | Transocean [Member]
Loss Contingencies [Line Items]
Allocation of fault assigned in Phase One Findings and Conclusions	30.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | Halliburton Energy Services [Member]
Loss Contingencies [Line Items]
Allocation of fault assigned in Phase One Findings and Conclusions	3.00%
Deepwater Horizon [Member] | Pending Litigation [Member] | Clean Water Act [Member]
Loss Contingencies [Line Items]
Litigation-related contingent liability	90,000,000						90,000,000
Gain (loss) related to litigation settlement	($90,000,000)

Income_Taxes_Components_of_Inc

Income Taxes - Components of Income Tax Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current [Abstract]
Federal	$188	$113	$45
State	2	42	25
Foreign	1,574	873	891
Total	1,764	1,028	961
Deferred [Abstract]
Federal	-389	94	-30
State	27	-9	115
Foreign	215	52	74
Total	-147	137	159
Total income tax expense (benefit)	$1,617	$1,165	$1,120

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Tax Computed at the U.S. Federal Statutory Rate to Income Tax Expense (Benefit) Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income (loss) before income taxes
Domestic	($3,564)	$428	$132
Foreign	3,618	1,678	3,433
Income (Loss) Before Income Taxes	54	2,106	3,565
U.S. federal statutory tax rate	35.00%	35.00%	35.00%
Tax computed at the U.S. federal statutory rate	19	737	1,248
Adjustments resulting from
State income taxes (net of federal income tax benefit)	-11	23	93
Tax impact from foreign operations	62	204	215
Effective Income Tax Rate Reconciliation [Line Items]
Non-taxable Algeria exceptional profits tax settlement	0	13	-679
Net changes in uncertain tax positions	1,427	-29	28
Income attributable to noncontrolling interests	-66	-48	-24
Federal manufacturing deduction	-27	0	0
Other—net	-12	9	14
Total income tax expense (benefit)	1,617	1,165	1,120
Effective tax rate	2994.00%	55.00%	31.00%
Pending Litigation [Member] | Tronox Litigation [Member]
Effective Income Tax Rate Reconciliation [Line Items]
Non-deductible expense	-36	36	0
Pending Litigation [Member] | Deepwater Horizon [Member]
Effective Income Tax Rate Reconciliation [Line Items]
Non-deductible expense	32	0	0
Algerian Exceptional Profits Tax [Member]
Effective Income Tax Rate Reconciliation [Line Items]
Non-deductible expense	193	144	188
Deferred Tax Adjustments [Member]
Effective Income Tax Rate Reconciliation [Line Items]
Deferred tax adjustments	15	76	22
Goodwill [Member]
Effective Income Tax Rate Reconciliation [Line Items]
Non-deductible expense	$21	$0	$15

Income_Taxes_Components_of_Tot

Income Taxes - Components of Total Deferred Taxes Table (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes	($8,527)	($8,885)
Federal [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes	-7,649	-8,246
State, net of federal [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes	-341	-332
Foreign [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Total deferred taxes	($537)	($307)

Income_Taxes_Deferred_Tax_Asse

Income Taxes - Deferred Tax Assets (Liabilities) Table (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Income Tax Disclosure [Abstract]
Current deferred tax assets	$210	$412
Deferred Tax Assets (Liabilities), Net [Line Items]
Valuation allowances on deferred tax assets not expected to be realized	-78	-52
Net current deferred tax assets	722	360
Other	-351	-499
Gross long-term deferred tax liabilities	-10,792	-10,708
Oil and gas exploration and development costs	177	94
Net operating loss carryforward	558	599
Foreign tax credit carryforward and alternative minimum tax credit carryforward	166	325
Other	1,428	1,211
Gross long-term deferred tax assets	2,329	2,229
Valuation allowances on deferred tax assets not expected to be realized	-786	-766
Net long-term deferred tax assets	1,543	1,463
Net long-term deferred tax liabilities	-9,249	-9,245
Total deferred taxes	-8,527	-8,885
Oil and Gas Exploration and Development Operations
Deferred Tax Assets (Liabilities), Net [Line Items]
Deferred tax liabilities - property, plant, and equipment	-8,418	-8,213
Mineral Operations [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Deferred tax liabilities - property, plant, and equipment	-412	-410
Midstream and Other Depreciable Properties [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Deferred tax liabilities - property, plant, and equipment	-1,611	-1,586
Pending Litigation [Member] | Tronox Litigation [Member]
Deferred Tax Assets (Liabilities), Net [Line Items]
Settlement agreement related to the Tronox Adversary Proceeding	$590	$0

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	Dec. 31, 2011
Income Tax Disclosure [Line Items]
Unrecognized tax benefits	$1,687,000,000	$147,000,000	$46,000,000		$31,000,000
Deferred tax benefit	-147,000,000	137,000,000	159,000,000
Tronox-related contingent loss	4,360,000,000	850,000,000	-250,000,000
Uncertain tax position	1,568,000,000	72,000,000	1,000,000
Unrecognized tax benefits that would affect the effective tax rate on income if recognized	1,456,000,000
Unrecognized tax benefits that would be in the form of tax credits and net operating loss carryforwards	188,000,000
The lower range of unrecognized tax benefits expected to reverse within the next 12 months due to expiration of statutes of limitation and audit settlements	120,000,000
The higher range of unrecognized tax benefits expected to reverse within the next 12 months due to expiration of statutes of limitation and audit settlements	130,000,000
Accrued interest related to uncertain tax positions	9,000,000	8,000,000
Interest and penalties recognized in income tax expense (benefit)	1,000,000	-20,000,000
Internal Revenue Service (IRS) [Member] | Earliest Tax Year [Member]
Income Tax Disclosure [Line Items]
Tax year currently under routine examination	2008
Internal Revenue Service (IRS) [Member] | Latest Tax Year [Member]
Income Tax Disclosure [Line Items]
Tax year currently under routine examination	2014
Portion Of Unrecognized Tax Benefits With Highly Certain Deductibility [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits	1,679,000,000
Portion Of Unrecognized Tax Benefits With Highly Certain Deductibility And Uncertain Timing [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits	8,000,000
Tronox Litigation [Member] | Pending Litigation [Member]
Income Tax Disclosure [Line Items]
Deferred tax benefit	-316,000,000	-274,000,000
Tronox-related contingent loss	4,360,000,000	850,000,000		4,300,000,000
Total deferred tax benefit related to the Tronox-related contingent liability	590,000,000	0
Uncertain tax position	1,326,000,000
Additions [Member]
Income Tax Disclosure [Line Items]
Increase in valuation allowances	59,000,000	38,000,000	426,000,000
Reductions [Member]
Income Tax Disclosure [Line Items]
Increase in valuation allowances	-13,000,000	-142,000,000	-59,000,000
Changes in Judgment Regarding Future Realizability of Deferred Tax Assets [Member]
Income Tax Disclosure [Line Items]
Increase in valuation allowances	0
Changes in Judgment Regarding Future Realizability of Deferred Tax Assets [Member] | Additions [Member]
Income Tax Disclosure [Line Items]
Increase in valuation allowances		$2,000,000	$23,000,000

Income_Taxes_Valuation_Allowan

Income Taxes - Valuation Allowances Rollforward (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Balance at January 1				($555,000,000)
Valuation Allowance [Line Items]
Balance at December 31	-864,000,000	-818,000,000	-922,000,000	-555,000,000
Additions [Member]
Valuation Allowance [Line Items]
Change in valuation allowances	-59,000,000	-38,000,000	-426,000,000
Reductions [Member]
Valuation Allowance [Line Items]
Change in valuation allowances	$13,000,000	$142,000,000	$59,000,000

Income_Taxes_Taxes_Receivable_

Income Taxes - Taxes Receivable (Payable) Table (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes receivable	$128	$101
Net income taxes receivable (payable)	-24	19
Accounts Receivable - Other [Member]
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes receivable	93	66
Other Assets [Member]
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes receivable	35	35
Accrued Expense [Member]
Components of Income Tax Receivable (Payable) [Line Items]
Income taxes (payable)	($152)	($82)

Income_Taxes_Tax_Carryforwards

Income Taxes - Tax Carryforwards Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Foreign Tax Credits [Member]
Tax Carryforwards [Line Items]
Tax credit carryforward	167
Foreign Tax Credits [Member] | Earliest Tax Year [Member]
Tax Carryforwards [Line Items]
Tax credit carryforward, expiration date	31-Dec-22
Foreign Tax Credits [Member] | Latest Tax Year [Member]
Tax Carryforwards [Line Items]
Tax credit carryforward, expiration date	31-Dec-23
Texas Margins Tax Credit [Member]
Tax Carryforwards [Line Items]
Tax credit carryforward	34
Tax credit carryforward, expiration date	31-Dec-26
Foreign [Member]
Tax Carryforwards [Line Items]
Net operating loss carryforward	1,165
Foreign [Member] | Earliest Tax Year [Member]
Tax Carryforwards [Line Items]
Net operating loss carryforwards, expiration date	31-Dec-15
State [Member]
Tax Carryforwards [Line Items]
Net operating loss carryforward	4,477
State [Member] | Earliest Tax Year [Member]
Tax Carryforwards [Line Items]
Net operating loss carryforwards, expiration date	31-Dec-15
State [Member] | Latest Tax Year [Member]
Tax Carryforwards [Line Items]
Net operating loss carryforwards, expiration date	31-Dec-34

Income_Taxes_Unrecognized_Tax_

Income Taxes - Unrecognized Tax Benefits Rollforward (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Balance at January 1	($147)	($46)	($31)
Increases related to prior-year tax positions	-11	-54	-17
Decreases related to prior-year tax positions	39	3	3
Increases related to current-year tax positions	-1,568	-72	-1
Settlements	0	5	0
Lapse of statute of limitations	0	17	0
Balance at December 31	($1,687)	($147)	($46)

Income_Taxes_Tax_Years_Subject

Income Taxes - Tax Years Subject to Examination by Major Jurisdiction Table (Detail)	12 Months Ended
	Dec. 31, 2014
United States [Member] | Earliest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2008
United States [Member] | Latest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2014
Algeria [Member] | Earliest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2011
Algeria [Member] | Latest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2014
Ghana [Member] | Earliest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2006
Ghana [Member] | Latest Tax Year [Member]
Income TaxExamination [Line Items]
Tax year subject to examination	2014

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash paid (received)
Interest, net of amounts capitalized	$689	$627	$684
Income taxes, net of refunds	956	169	-300
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	18	62	65
Asset retirement cost additions	348	297	142
Accruals of property, plant, and equipment	1,156	1,446	1,205
Net liabilities assumed or divested in acquisitions and divestitures	-92	-80	-34
Non-cash investing and financing activities
Capital lease obligation	13	8	0
Floating production, storage, and offloading vessel construction period obligation	$149	$17	$0

Segment_Information_Additional

Segment Information - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Segment
Segment Reporting [Abstract]
Number of reporting segments	3
Segment Reporting Information [Line Items]
Revenues	$18,470,000,000	$14,581,000,000	$13,411,000,000
Major Customer [Member]
Segment Reporting Information [Line Items]
Revenues	0
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Number of operating segments	2
Oil and Gas Exploration and Production Reporting Segment [Member] | Total S.A. [Member]
Segment Reporting Information [Line Items]
Revenues		$2,000,000,000	$1,900,000,000

Segment_Information_Reconcilia

Segment Information - Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) before Income Taxes Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting [Abstract]
Income (loss) before income taxes	$54	$2,106	$3,565
Exploration expense	1,639	1,329	1,946
DD&A	4,550	3,927	3,964
Impairments	836	794	389
Interest expense	772	686	742
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	578	-307	443
Deepwater Horizon settlement and related costs	97	15	18
Algeria exceptional profits tax settlement	0	33	-1,797
Tronox-related contingent loss	4,360	850	-250
Segment Reporting Information [Line Items]
Less net income attributable to noncontrolling interests	187	140	54
Consolidated Adjusted EBITDAX	12,721	9,403	8,966
Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Certain other nonoperating items	$22	$110	$0

Segment_Information_Selected_F

Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenues	$16,375,000,000		$14,867,000,000		$13,307,000,000
Gains (losses) on divestitures and other, net	2,095,000,000		-286,000,000		104,000,000
Total revenues and other	18,470,000,000		14,581,000,000		13,411,000,000
Operating costs and expenses (1)	5,945,000,000	[1]	5,150,000,000	[1]	5,164,000,000	[1]
Net cash from settlement of commodity derivatives	-371,000,000		-85,000,000		-685,000,000
Other (income) expense, net	20,000,000		89,000,000		-4,000,000
Net income attributable to noncontrolling interests	187,000,000		140,000,000		54,000,000
Total expenses and other	5,753,000,000		5,174,000,000		4,461,000,000
Adjusted EBITDAX	12,721,000,000		9,403,000,000		8,966,000,000
Net properties and equipment	41,589,000,000		40,929,000,000		38,398,000,000
Capital expenditures	9,256,000,000		8,523,000,000		7,311,000,000
Goodwill	5,576,000,000		5,492,000,000		5,492,000,000
Gains) Losses on Derivatives, net [Member] | Commodity Derivatives [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives	-377,000,000		-95,000,000		-753,000,000
Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	-2,000,000	[2]	-21,000,000	[2]	-4,000,000	[2]
Gathering, Processing, and Marketing Sales [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	4,000,000		-4,000,000		16,000,000
Other and Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	0		0		0
Gains (losses) on divestitures and other, net	205,000,000		337,000,000		177,000,000
Total revenues and other	-587,000,000		-314,000,000		-366,000,000
Operating costs and expenses (1)	17,000,000	[1]	20,000,000	[1]	295,000,000	[1]
Total expenses and other	-362,000,000		-96,000,000		-462,000,000
Adjusted EBITDAX	-225,000,000		-218,000,000		96,000,000
Net properties and equipment	2,175,000,000		2,103,000,000		1,906,000,000
Capital expenditures	173,000,000		267,000,000		155,000,000
Goodwill	0		0		0
Other and Intersegment Eliminations [Member] | Gains) Losses on Derivatives, net [Member] | Commodity Derivatives [Member]
Segment Reporting Information [Line Items]
Net cash from settlement of commodity derivatives	-377,000,000		-95,000,000		-753,000,000
Other and Intersegment Eliminations [Member] | Excluding Certain Other Nonoperating Items [Member]
Segment Reporting Information [Line Items]
Other (income) expense, net	-2,000,000	[2]	-21,000,000	[2]	-4,000,000	[2]
Other and Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues	-792,000,000		-651,000,000		-543,000,000
Oil and Gas Exploration and Production Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues	8,603,000,000		7,090,000,000		6,752,000,000
Gains (losses) on divestitures and other, net	1,893,000,000		-622,000,000		-65,000,000
Oil and Gas Exploration and Production Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues	6,225,000,000		6,405,000,000		5,318,000,000
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues and other	16,721,000,000		12,873,000,000		12,005,000,000
Operating costs and expenses (1)	4,216,000,000	[1]	3,635,000,000	[1]	3,505,000,000	[1]
Total expenses and other	4,216,000,000		3,635,000,000		3,505,000,000
Adjusted EBITDAX	12,505,000,000		9,238,000,000		8,500,000,000
Net properties and equipment	32,717,000,000		33,409,000,000		32,024,000,000
Capital expenditures	7,934,000,000		7,008,000,000		5,906,000,000
Goodwill	5,123,000,000		5,317,000,000		5,317,000,000
Midstream Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues	484,000,000		387,000,000		325,000,000
Gains (losses) on divestitures and other, net	-3,000,000		-1,000,000		-8,000,000
Midstream Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues	1,338,000,000		1,105,000,000		959,000,000
Midstream Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues and other	1,819,000,000		1,491,000,000		1,276,000,000
Operating costs and expenses (1)	972,000,000	[1]	843,000,000	[1]	748,000,000	[1]
Net income attributable to noncontrolling interests	187,000,000		140,000,000		54,000,000
Total expenses and other	1,159,000,000		983,000,000		802,000,000
Adjusted EBITDAX	660,000,000		508,000,000		474,000,000
Net properties and equipment	6,697,000,000		5,408,000,000		4,459,000,000
Capital expenditures	1,149,000,000		1,248,000,000		1,250,000,000
Goodwill	453,000,000		175,000,000		175,000,000
Marketing Reporting Segment [Member]
Segment Reporting Information [Line Items]
Revenues	7,288,000,000		7,390,000,000		6,230,000,000
Gains (losses) on divestitures and other, net	0		0		0
Marketing Reporting Segment [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenues	-6,771,000,000		-6,859,000,000		-5,734,000,000
Marketing Reporting Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues and other	517,000,000		531,000,000		496,000,000
Operating costs and expenses (1)	740,000,000	[1]	652,000,000	[1]	616,000,000	[1]
Total expenses and other	740,000,000		652,000,000		616,000,000
Adjusted EBITDAX	-219,000,000		-125,000,000		-104,000,000
Net properties and equipment	0		9,000,000		9,000,000
Capital expenditures	0		0		0
Goodwill	0		0		0
Marketing Reporting Segment [Member] | Operating Segments [Member] | Gathering, Processing, and Marketing Sales [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	$4,000,000		($4,000,000)		$16,000,000
[1]	Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement 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.

Segment_Information_Sales_Reve

Segment Information - Sales Revenues by Geographic Area Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue from External Customer [Line Items]
Sales revenues	$16,375	$14,867	$13,307
United States [Member]
Revenue from External Customer [Line Items]
Sales revenues	13,083	11,290	9,911
Algeria [Member]
Revenue from External Customer [Line Items]
Sales revenues	2,435	2,184	2,182
Other International [Member]
Revenue from External Customer [Line Items]
Sales revenues	$857	$1,393	$1,214

Segment_Information_Net_Proper

Segment Information - Net Properties and Equipment by Geographic Area Table (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment	$41,589	$40,929	$38,398
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment	37,186	35,486
Algeria [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment	1,431	1,582
Other International [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Net properties and equipment	$2,972	$3,861

Pension_Plans_Other_Postretire3

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined-benefit plan, amortization of net actuarial loss in 2015	$49,000,000
Defined-benefit plan, health care cost trend rate assumed for next fiscal year	8.00%	8.00%
Defined-benefit plan, ultimate health care cost trend rate	5.00%
Defined benefit plan, amount of employer securities included in plan assets	0
Defined-contribution plans, recognized expense	76,000,000	78,000,000	55,000,000
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined-benefit plan, target asset-allocation range, minimum	45.00%
Defined-benefit plan, target asset-allocation range, maximum	55.00%
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined-benefit plan, target asset-allocation range, minimum	20.00%
Defined-benefit plan, target asset-allocation range, maximum	30.00%
Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined-benefit plan, target asset-allocation range, maximum	25.00%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	121,000,000	160,000,000
Pension Plans, Defined Benefit [Member] | Funded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	106,000,000
Expected employer contributions in 2015	5,000,000
Pension Plans, Defined Benefit [Member] | Unfunded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	15,000,000
Expected employer contributions in 2015	24,000,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	15,000,000	14,000,000
Other Postretirement Benefit Plans, Defined Benefit [Member] | Unfunded Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	15,000,000
Expected employer contributions in 2015	$16,000,000

Pension_Plans_Other_Postretire4

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Change in Benefit Obligation Table (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Plans, Defined Benefit [Member]
Change in benefit obligation
Benefit obligation at beginning of year	$2,158,000,000	[1]	$2,297,000,000
Service cost	99,000,000		85,000,000		76,000,000
Interest cost	99,000,000		78,000,000		85,000,000
Actuarial (gain) loss	337,000,000		-156,000,000
Participant contributions	1,000,000		0
Benefit payments	-159,000,000		-149,000,000
Foreign-currency exchange-rate changes	-7,000,000		3,000,000
Benefit obligation at end of year (1)	2,528,000,000	[1]	2,158,000,000	[1]	2,297,000,000
Accumulated benefit obligation for all defined-benefit pension plans	2,100,000,000		1,800,000,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in benefit obligation
Benefit obligation at beginning of year	294,000,000		359,000,000
Service cost	7,000,000		9,000,000		9,000,000
Interest cost	15,000,000		14,000,000		16,000,000
Actuarial (gain) loss	72,000,000		-74,000,000
Participant contributions	4,000,000		4,000,000
Benefit payments	-19,000,000		-18,000,000
Foreign-currency exchange-rate changes	0		0
Benefit obligation at end of year (1)	$373,000,000		$294,000,000		$359,000,000
[1]	The accumulated benefit obligation for all defined-benefit pension plans was $2.1 billion at December 31, 2014, and $1.8 billion at December 31, 2013.

Pension_Plans_Other_Postretire5

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Change in Plan Assets, Funded Status of the Plans, and Amounts Recognized in the Financial Statements Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Plans, Defined Benefit [Member]
Change in plan assets
Fair value of plan assets at beginning of year	$1,754	$1,462
Actual return on plan assets	111	278
Employer contributions	121	160
Participant contributions	1	0
Benefit payments	-159	-149
Foreign-currency exchange-rate changes	-10	3
Fair value of plan assets at end of year	1,818	1,754
Funded status of the plans at end of year	-710	-404
Total recognized amounts in the balance sheet consist of
Other assets	41	37
Accrued expenses	-24	-19
Other long-term liabilities—other	-727	-422
Total	-710	-404
Total recognized amounts in accumulated other comprehensive income consist of
Prior service cost (credit)	-1	-1
Net actuarial (gain) loss	740	441
Total	739	440
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	15	14
Participant contributions	4	4
Benefit payments	-19	-18
Foreign-currency exchange-rate changes	0	0
Fair value of plan assets at end of year	0	0
Funded status of the plans at end of year	-373	-294
Total recognized amounts in the balance sheet consist of
Other assets	0	0
Accrued expenses	-15	-15
Other long-term liabilities—other	-358	-279
Total	-373	-294
Total recognized amounts in accumulated other comprehensive income consist of
Prior service cost (credit)	2	2
Net actuarial (gain) loss	1	-78
Total	$3	($76)

Pension_Plans_Other_Postretire6

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Accumulated Benefit Obligations in Excess of Plan Assets Table (Detail) (Pension Plans, Defined Benefit [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$2,403	$2,047
Accumulated benefit obligation	2,024	1,742
Fair value of plan assets	$1,652	$1,606

Pension_Plans_Other_Postretire7

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Components of Net Periodic Benefit Cost and Amounts Recognized in Other Comprehensive Income (Expense) Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Amounts recognized in other comprehensive income (expense)
Net actuarial gain (loss)	($405)	$416	($155)
Amortization of net actuarial (gain) loss	27	132	93
Amortization of net prior service cost (credit)	0	1	2
Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	99	85	76
Interest cost	99	78	85
Expected return on plan assets	-106	-91	-91
Amortization of net actuarial loss (gain)	34	118	93
Amortization of net prior service cost (credit)	0	0	0
Settlement loss	0	14	0
Net periodic benefit cost	126	204	163
Amounts recognized in other comprehensive income (expense)
Net actuarial gain (loss)	-333	342	-156
Amortization of net actuarial (gain) loss	34	118	93
Amortization of net prior service cost (credit)	0	0	0
Settlement loss	0	14	0
Total amounts recognized in other comprehensive income (expense)	-299	474	-63
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost
Service cost	7	9	9
Interest cost	15	14	16
Expected return on plan assets	0	0	0
Amortization of net actuarial loss (gain)	-7	0	0
Amortization of net prior service cost (credit)	0	1	2
Settlement loss	0	0	0
Net periodic benefit cost	15	24	27
Amounts recognized in other comprehensive income (expense)
Net actuarial gain (loss)	-72	74	1
Amortization of net actuarial (gain) loss	-7	0	0
Amortization of net prior service cost (credit)	0	1	2
Settlement loss	0	0	0
Total amounts recognized in other comprehensive income (expense)	($79)	$75	$3

Pension_Plans_Other_Postretire8

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Weighted-Average Assumptions for Benefit Obligations Table (Detail)	Dec. 31, 2014	Dec. 31, 2013
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.00%	4.75%
Rates of increase in compensation levels	5.25%	5.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	5.25%
Rates of increase in compensation levels	5.25%	5.25%

Pension_Plans_Other_Postretire9

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Weighted-Average Assumptions for Net Periodic Benefit Cost Table (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.75%	3.50%	4.50%
Long-term rate of return on plan assets	6.75%	7.00%	7.00%
Rates of increase in compensation levels	5.00%	4.50%	4.50%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.25%	4.00%	4.75%
Rates of increase in compensation levels	5.25%	4.50%	4.50%

Recovered_Sheet1

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Effects of a 1% Change in the Assumed Health Care Cost Trend Rate Table (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Effect of a 1% increase on total of service and interest cost components	$3
Effect of a 1% increase on other postretirement benefit obligation	40
Effect of a 1% decrease on total of service and interest cost components	-2
Effect of a 1% decrease on other postretirement benefit obligation	($33)

Recovered_Sheet2

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Fair Value of Pension Plan Assets by Asset Class and Input Level Table (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	($3)		($17)
Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,821	[1]	1,769	[1]
Fair Value, Inputs, Level 1 [Member] | Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-3		-17
Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	630	[1]	683	[1]
Fair Value, Inputs, Level 2 [Member] | Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	887	[1]	849	[1]
Fair Value, Inputs, Level 3 [Member] | Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	304	[1]	237	[1]	219
Cash and Cash Equivalents [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56		97
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3		17
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53		80
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Mortgage-backed Securities [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	51		54
Mortgage-backed Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Mortgage-backed Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	51		54
Mortgage-backed Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
U.S. Government Securities [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56		52
U.S. Government Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
U.S. Government Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56		52
U.S. Government Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Other Fixed-Income Securities [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	260	[2]	239	[2]
Other Fixed-Income Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	48	[2]	42	[2]
Other Fixed-Income Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	212	[2]	197	[2]
Other Fixed-Income Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	[2]	0	[2]
Equity Securities Domestic [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	576		561
Equity Securities Domestic [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	446		445
Equity Securities Domestic [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	130		116
Equity Securities Domestic [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Equity Securities International [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	423		451
Equity Securities International [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	124		148
Equity Securities International [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	299		303
Equity Securities International [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Real Estate [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	150		133
Real Estate [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Real Estate [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56		47
Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	94		86		78
Private Equity [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84		72
Private Equity [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Private Equity [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Private Equity [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84		72		64
Hedge Funds and Other Alternative Strategies Asset Position [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	135		110
Hedge Funds and Other Alternative Strategies Asset Position [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9		31
Hedge Funds and Other Alternative Strategies Asset Position [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Hedge Funds and Other Alternative Strategies Asset Position [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	126		79		77
Other Pension Plan Assets [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30
Other Pension Plan Assets [Member] | Fair Value, Inputs, Level 1 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Other Pension Plan Assets [Member] | Fair Value, Inputs, Level 2 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30
Other Pension Plan Assets [Member] | Fair Value, Inputs, Level 3 [Member] | Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Hedge Funds and Other Alternative Strategies Liability Position [Member] | Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-3		-17
Hedge Funds and Other Alternative Strategies Liability Position [Member] | Fair Value, Inputs, Level 1 [Member] | Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-3		-17
Hedge Funds and Other Alternative Strategies Liability Position [Member] | Fair Value, Inputs, Level 2 [Member] | Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Hedge Funds and Other Alternative Strategies Liability Position [Member] | Fair Value, Inputs, Level 3 [Member] | Liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$0		$0
[1]	Amount excludes receivables and payables, primarily related to Level 1 investments.
[2]	Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities.

Recovered_Sheet3

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Changes in the Fair Value of Level 3 Assets Table (Detail) (Investments [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Actual return on plan assets
Fair value of plan assets at end of year	$1,821	[1]	$1,769	[1]
Hedge Funds and Other Alternative Strategies Asset Position [Member]
Actual return on plan assets
Fair value of plan assets at end of year	135		110
Private Equity [Member]
Actual return on plan assets
Fair value of plan assets at end of year	84		72
Real Estate [Member]
Actual return on plan assets
Fair value of plan assets at end of year	150		133
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	237	[1]	219
Acquisitions (dispositions), net	44		-4
Actual return on plan assets
Relating to assets sold during the reporting period	7		5
Relating to assets still held at the reporting date	16		17
Fair value of plan assets at end of year	304	[1]	237	[1]
Fair Value, Inputs, Level 3 [Member] | Hedge Funds and Other Alternative Strategies Asset Position [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	79		77
Acquisitions (dispositions), net	42		-6
Actual return on plan assets
Relating to assets sold during the reporting period	2		1
Relating to assets still held at the reporting date	3		7
Fair value of plan assets at end of year	126		79
Fair Value, Inputs, Level 3 [Member] | Private Equity [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	72		64
Acquisitions (dispositions), net	0		0
Actual return on plan assets
Relating to assets sold during the reporting period	5		4
Relating to assets still held at the reporting date	7		4
Fair value of plan assets at end of year	84		72
Fair Value, Inputs, Level 3 [Member] | Real Estate [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	86		78
Acquisitions (dispositions), net	2		2
Actual return on plan assets
Relating to assets sold during the reporting period	0		0
Relating to assets still held at the reporting date	6		6
Fair value of plan assets at end of year	$94		$86
[1]	Amount excludes receivables and payables, primarily related to Level 1 investments.

Recovered_Sheet4

Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans - Estimated Benefit Payments Table (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	$162
2016	175
2017	199
2018	194
2019	216
2020-2024	1,192
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	16
2016	17
2017	18
2018	18
2019	19
2020-2024	$109