Devon Energy (DVN) 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 in Millions, unless otherwise specified	Dec. 31, 2014	Feb. 11, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Entity Registrant Name	DEVON ENERGY CORP/DE
Entity Central Index Key	1090012
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Current Fiscal Year End Date	-19
Document Fiscal Year Focus	2014
Entity Filer Category	Large Accelerated Filer
Document Fiscal Period Focus	FY
Entity Public Float			$32.30
Entity Common Stock, Shares Outstanding		411.1

Consolidated_Comprehensive_Sta

Consolidated Comprehensive Statements Of Earnings (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated Comprehensive Statements Of Earnings [Abstract]
Oil, gas and NGL sales	$9,910	$8,522	$7,153
Oil, gas and NGL derivatives	1,989	-191	693
Marketing and midstream revenues	7,667	2,066	1,655
Total operating revenues	19,566	10,397	9,501
Lease operating expenses	2,332	2,268	2,074
Marketing and midstream operating expenses	6,815	1,553	1,246
General and administrative expenses	847	617	692
Production and property taxes	535	461	414
Depreciation, depletion and amortization	3,319	2,780	2,811
Asset impairments	1,953	1,976	2,024
Restructuring costs	46	54	74
Gains and losses on asset sales	-1,072	9	-13
Other operating items	93	112	105
Total operating expenses	14,868	9,830	9,427
Operating income	4,698	567	74
Net financing costs	526	417	370
Other nonoperating items	113	1	21
Earnings (loss) from continuing operations before income taxes	4,059	149	-317
Income tax expense (benefit)	2,368	169	-132
Earnings (loss) from continuing operations	1,691	-20	-185
Earnings (loss) from discontinued operations, net of tax			-21
Net earnings (loss)	1,691	-20	-206
Net earnings attributable to noncontrolling interests	84
Net earnings (loss) attributable to Devon	1,607	-20	-206
Net earnings (loss) per share attributable to Devon:
Basic earnings (loss) from continuing operations per share	$3.93	($0.06)	($0.47)
Basic earnings (loss) from discontinued operations per share			($0.05)
Basic net earnings (loss) per share	$3.93	($0.06)	($0.52)
Diluted earnings (loss) from continuing operations per share	$3.91	($0.06)	($0.47)
Diluted earnings (loss) from discontinued operations per share			($0.05)
Diluted net earnings (loss) per share	$3.91	($0.06)	($0.52)
Comprehensive earnings (loss):
Net earnings (loss)	1,691	-20	-206
Other comprehensive earnings (loss), net of tax:
Foreign currency translation	-465	-548	194
Pension and postretirement plans	-24	45	2
Other comprehensive earnings (loss), net of tax	-489	-503	196
Comprehensive earnings (loss)	1,202	-523	-10
Comprehensive earnings attributable to noncontrolling interests	84
Comprehensive earnings (loss) attributable to Devon	$1,118	($523)	($10)

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 earnings (loss)	$1,691	($20)	($206)
Earnings (loss) from discontinued operations, net of tax			21
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Depreciation, depletion and amortization	3,319	2,780	2,811
Asset impairments	1,953	1,976	2,024
Gains and losses on asset sales	-1,072	9	-13
Deferred income tax expense (benefit)	1,891	97	-184
Derivatives and other financial instruments	-2,070	135	-660
Cash settlements on derivatives and financial instruments	104	277	865
Other noncash charges	457	309	253
Net change in working capital	50	-298	-50
Change in long-term other assets	-421	10	-36
Change in long-term other liabilities	79	161	105
Cash from operating activities - continuing operations	5,981	5,436	4,930
Cash from operating activities - discontinued operations			26
Net cash from operating activities	5,981	5,436	4,956
Cash flows from investing activities:
Capital expenditures	-6,988	-6,758	-8,225
Acquisitions of property, equipment and businesses	-6,462
Proceeds from property and equipment divestitures	5,120	419	1,468
Purchases of short-term investments		-1,076	-4,106
Redemptions of short-term investments		3,419	3,266
Redemptions of long-term investments	57
Other	89	-3	14
Cash from investing activities - continuing operations	-8,184	-3,999	-7,583
Cash from investing activities - discontinued operations			57
Net cash from investing activities	-8,184	-3,999	-7,526
Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs	5,340	2,233	3,208
Net short-term debt repayments	-385	-1,872	-537
Long-term debt repayments	-7,189		-750
Proceeds from stock option exercises	93	3	27
Proceeds from issuance of subsidiary units	410
Dividends paid on common stock	-386	-348	-324
Distributions to noncontrolling interests	-235
Other	-2	4	5
Net cash from financing activities	-2,354	20	1,629
Effect of exchange rate changes on cash	-29	-28	23
Net change in cash and cash equivalents	-4,586	1,429	-918
Cash and cash equivalents at beginning of period	6,066	4,637	5,555
Cash and cash equivalents at end of period	$1,480	$6,066	$4,637

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$1,480		$6,066
Accounts receivable	1,959		1,520
Derivatives, at fair value	1,993		75
Income taxes receivable	522		89
Other current assets	544		255
Total current assets	6,498		8,005
Oil and gas, based on full-cost accounting:
Subject to amortization	75,738		73,995
Not subject to amortization	2,752		2,791
Total oil and gas	78,490		76,786
Midstream and other	9,695		6,195
Total property and equipment, at cost	88,185		82,981
Less accumulated depreciation, depletion and amortization	-51,889		-54,534
Property and equipment, net	36,296		28,447
Goodwill	6,303		5,858
Other long-term assets	1,540		567
Total assets	50,637		42,877
Current liabilities:
Accounts payable	1,400		1,229
Revenues and royalties payable	1,193		786
Short-term debt	1,432	[1]	4,066	[1]
Deferred income taxes	730		19
Other current liabilities	1,180		555
Total current liabilities	5,935		6,655
Long-term debt	9,830		7,956
Asset retirement obligations	1,339		2,140
Other long-term liabilities	948		834
Deferred income taxes	6,244		4,793
Stockholders' equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 409 million and 406 million shares in 2014 and 2013, respectively	41		41
Additional paid-in capital	4,088		3,780
Retained earnings	16,631		15,410
Accumulated other comprehensive earnings	779		1,268
Total stockholders' equity attributable to Devon	21,539		20,499
Noncontrolling interests	4,802
Total stockholders' equity	26,341		20,499
Commitments and contingencies (Note 18)
Total liabilities and stockholders' equity	$50,637		$42,877
[1]	2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015. 2013 short-term debt consists of $2.25 billion of senior notes issued in conjunction with the GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014.

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Consolidated Balance Sheets [Abstract]
Common stock, par value (in dollars per share)	$0.10	$0.10
Common stock, shares authorized (in shares)	1,000,000,000	1,000,000,000
Common stock, shares issued (in shares)	409,000,000	406,000,000

Consolidated_Statements_Of_Sto

Consolidated Statements Of Stockholders' Equity (USD $)	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Earnings [Member]	Treasury Stock [Member]	Noncontrolling Interests [Member]	Total
In Millions, except Share data
Balance, at Dec. 31, 2011	$40	$3,507	$16,308	$1,575			$21,430
Balance, shares, at Dec. 31, 2011	404,000,000
Net earnings (loss)			-206				-206
Other comprehensive earnings (loss), net of tax				196			196
Stock option exercises	1	49			-23		27
Stock option exercises, shares	1,000,000
Restricted stock grants, net of cancellations, shares	1,000,000
Common stock repurchased					-29		-29
Common stock retired		-52			52
Common stock dividends			-324				-324
Share-based compensation		179					179
Share-based compensation tax benefits		5					5
Balance, at Dec. 31, 2012	41	3,688	15,778	1,771			21,278
Balance, shares, at Dec. 31, 2012	406,000,000
Net earnings (loss)			-20				-20
Other comprehensive earnings (loss), net of tax				-503			-503
Stock option exercises		3					3
Common stock repurchased					-36		-36
Common stock retired		-36			36
Common stock dividends			-348				-348
Share-based compensation		121					121
Share-based compensation tax benefits		4					4
Balance, at Dec. 31, 2013	41	3,780	15,410	1,268			20,499
Balance, shares, at Dec. 31, 2013	406,000,000
Net earnings (loss)			1,607			84	1,691
Other comprehensive earnings (loss), net of tax				-489			-489
Stock option exercises		93					93
Stock option exercises, shares	1,000,000
Restricted stock grants, net of cancellations, shares	2,000,000
Common stock repurchased					-27		-27
Common stock retired		-27			27
Common stock dividends			-386				-386
Share-based compensation		151					151
Share-based compensation tax benefits		-3					-3
Acquistion of noncontrolling interests						4,670	4,670
Subsidiary equity transactions		93				277	370
Distributions to noncontrolling interests						-235	-235
Other		1				6	7
Balance, at Dec. 31, 2014	$41	$4,088	$16,631	$779		$4,802	$26,341
Balance, shares, at Dec. 31, 2014	409,000,000

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies
	1.Summary of Significant Accounting Policies
	Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities through its ownership in EnLink Midstream Partners, LP, a publicly traded MLP.
	Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the United States of America and reflect industry practices. The more significant of such policies are discussed below.
	Principles of Consolidation
	The accompanying consolidated financial statements include the accounts of Devon 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 Devon 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 Devon’s proportionate share of earnings, losses and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.
	As discussed more fully in Note 2, on March 7, 2014, Devon completed a business combination whereby Devon controls both EnLink Midstream Partners, LP (“EnLink”) and its general partner entity, EnLink Midstream, LLC (the “General Partner”). Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.
	Use of Estimates
	The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
	• proved reserves and related present value of future net revenues;
	• the carrying value of oil and gas properties and midstream assets;
	• derivative financial instruments;
	• the fair value of reporting units and related assessment of goodwill for impairment;
	• the fair value of intangible assets other than goodwill;
	• income taxes;
	• asset retirement obligations;
	• obligations related to employee pension and postretirement benefits; and
	• legal and environmental risks and exposures.
	Revenue Recognition and Gas Balancing
	Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings.
	Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is measured based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells' reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
	Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
	During 2014, 2013 and 2012, no purchaser accounted for more than 10 percent of Devon’s operating revenues from continuing operations.
	Derivative Financial Instruments
	Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.
	Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon, through EnLink, periodically enters into derivative financial instruments with respect to a portion of EnLink’s oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments typically include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.
	Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.
	All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2014, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon's derivative financial instruments are also recorded in earnings.
	By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon's policy to enter into derivative contracts only with investment-grade-rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon's derivative contracts generally require cash collateral to be posted if either its or the counterparty's credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. As of December 31, 2014, Devon held $524 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying consolidated balance sheet.
	General and Administrative Expenses
	General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
	Share-Based Compensation
	Independent of EnLink, Devon grants share-based awards to independent members of its Board of Directors and selected employees. EnLink and its General Partner also grant share-based awards to independent members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated comprehensive statements of earnings.
	Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase.
	Income Taxes
	Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
	Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
	Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
	Net Earnings (Loss) Per Share Attributable to Devon
	Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.
	Cash and Cash Equivalents
	Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
	Investments
	Devon periodically invests excess cash in United States and Canadian treasury securities and other marketable securities. Devon considers securities with original contractual maturities in excess of three months but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.
	Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. At December 31, 2013, such debt securities totaled $62 million and are included in other long-term assets in the accompanying consolidated balance sheet. Devon redeemed all these securities in the first quarter of 2014.
	Property and Equipment
	Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
	Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
	Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to four years.
	No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
	Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties.
	Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon's derivative contracts held during the three-year period ended December 31, 2014 qualified for hedge accounting treatment.
	Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
	Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
	Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
	Goodwill
	Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon's reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
	Devon performed annual impairment tests of goodwill in the fourth quarters of 2014, 2013 and 2012. No impairment of goodwill was required in 2012 and 2013. However, based on the 2014 assessment, Devon’s Canadian reporting unit goodwill was deemed impaired. See Note 12 for further discussion.
	Intangible Assets
	Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years.
	Commitments and Contingencies
	Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon's accounting policy for property and equipment.
	Fair Value Measurements
	Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:
	·	Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
	·	Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.
	·	Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.
Discontinued Operations
All amounts related to Devon's International operations that were sold in 2012 are classified as discontinued operations.
Foreign Currency Translation Adjustments
The United States dollar is the functional currency for Devon's consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to United States dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders' equity.
Noncontrolling Interests
Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.
Recently Issued Accounting Standards Not Yet Adopted
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606). The update provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The update is effective for Devon beginning on January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. Devon has not yet selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

Acquisitions_And_Divestitures

Acquisitions And Divestitures	12 Months Ended
	Dec. 31, 2014
Acquisitions And Divestitures [Abstract]
Acquisitions And Divestitures	2.Acquisitions and Divestitures
	Formation of EnLink Midstream, LLC and EnLink Midstream Partners, LP
	On March 7, 2014, Devon, Crosstex Energy, Inc. and Crosstex Energy, LP (together with Crosstex Energy, Inc., “Crosstex”) completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business consists of the General Partner and EnLink, which are both publicly traded.
	In exchange for a controlling interest in both EnLink and the General Partner, Devon contributed its equity interest in a newly formed Devon subsidiary, EnLink Midstream Holdings, LP (“EnLink Holdings”) and $100 million in cash. EnLink Holdings owns midstream assets in the Barnett Shale in north Texas and the Cana- and Arkoma-Woodford Shales in Oklahoma, as well as an economic interest in Gulf Coast Fractionators in Mont Belvieu, Texas. As of December 31, 2014, the General Partner and EnLink each own 50% of EnLink Holdings.
	As of December 31, 2014, the ownership of the General Partner is approximately:
		•		70% - Devon
		•		30% - Public unitholders
	As of December 31, 2014, the ownership of EnLink is approximately:
		•		49% - Devon
		•		43% - Public unitholders
		•		8% - General Partner
	This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, EnLink Holdings was the accounting acquirer because its parent company, Devon, obtained control of EnLink and the General Partner as a result of the business combination. Consequently, EnLink Holdings’ assets and liabilities retained their carrying values. Additionally, the Crosstex assets acquired and liabilities assumed by the General Partner and EnLink in the business combination, as well as the General Partner’s noncontrolling interest in EnLink, were recorded at their fair values which were measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of Crosstex’s net assets acquired was recorded as goodwill.
	The following table summarizes the purchase price (in millions, except unit price).
	Crosstex Energy, Inc. outstanding common shares:
	Held by public shareholders			48.0
	Restricted shares			0.4
	Total subject to conversion			48.4
	Exchange ratio			1.0	x
	Converted shares			48.4
	Crosstex Energy, Inc. common share price (1)		$	37.60
	Crosstex Energy, Inc. consideration		$	1,823
	Fair value of noncontrolling interest in E2 (2)			18
	Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests		$	1,841
	Crosstex Energy, LP outstanding units:
	Common units held by public unitholders			75.1
	Preferred units held by third party (3)			17.1
	Restricted units			0.4
	Total			92.6
	Crosstex Energy, LP common unit price (4)		$	30.51
	Crosstex Energy, LP common units value		$	2,825
	Crosstex Energy, LP outstanding unit options value		$	4
	Total fair value of noncontrolling interests in the Crosstex Energy, LP (4)			2,829
	Total consideration and fair value of noncontrolling interests		$	4,670
	__________________________
	(1) The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014.
	(2) Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2 Energy Services, LLC and E2 Appalachian Compression, LLC (collectively “E2”).
	(3) Crosstex Energy, LP converted the preferred units to common units in February 2014.
	(4) The final purchase price is based on the fair value of Crosstex Energy, LP’s common units as of the closing date, March 7, 2014.
	The allocation of the purchase price is as follows (in millions):
	Assets acquired:
	Current assets		$	437
	Property, plant and equipment, net			2,438
	Intangible assets			569
	Equity investment			222
	Goodwill (1)			3,283
	Other long-term assets			1
	Liabilities assumed:
	Current liabilities			-515
	Long-term debt			-1,454
	Deferred income taxes			-210
	Other long-term liabilities			-101
	Total consideration and fair value of noncontrolling interests		$	4,670
	__________________________
	(1)  Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.
	EnLink Acquisitions and Dropdowns
	On October 22, 2014, EnLink acquired equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) from the General Partner. The total consideration for the transaction was approximately $194 million, including a $163 million cash payment and 1.0 million EnLink units valued at $31.2 million based on the fair value of the EnLink units as of the closing date of the transaction. Furthermore, on November 1, 2014, EnLink acquired Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana for $234 million, subject to certain adjustments.
	GeoSouthern Energy Acquisition
	On February 28, 2014, Devon completed its acquisition of interests in certain affiliates of GeoSouthern Energy Corporation (“GeoSouthern”) for approximately $6.0 billion. Devon funded the acquisition with cash on hand and debt financing. In connection with the GeoSouthern transaction, Devon acquired approximately 82,000 net acres (unaudited) located in DeWitt and Lavaca counties in south Texas. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.
	The allocation of the purchase price is as follows (in millions).
	Cash and cash equivalents		$	95
	Other current assets			256
	Proved properties			5,026
	Unproved properties			1,007
	Midstream assets			86
Current liabilities			-434
Long-term liabilities			-6
Net assets acquired		$	6,030
EnLink and GeoSouthern Operating Results
The following table presents the General Partner’s and EnLink’s (acquired Crosstex operations) and GeoSouthern’s operating revenues and net earnings included in Devon’s consolidated comprehensive statements of earnings subsequent to the transactions described above.
		Year Ended December 31, 2014
		GeoSouthern			EnLink
		(In millions)
Total operating revenues		$	1,873		$	2,509
Total operating expenses			960			2,464
Operating income		$	913		$	45
Pro Forma Financial Information
The following unaudited pro forma financial information has been prepared assuming both the EnLink formation and the GeoSouthern acquisition occurred on January 1, 2013. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devon’s results of operations for any future period.
		Year Ended December 31,
		2014			2013
		(In millions)
Total operating revenues		$	20,213		$	12,979
Net earnings		$	1,716		$	35
Noncontrolling interests		$	97		$	45
Net earnings (loss) attributable to Devon		$	1,619		$	-10
Net earnings (loss) per common share attributable to Devon		$	3.94		$	-0.02
Asset Divestitures
In November 2013, Devon announced plans to divest certain properties located throughout Canada and the U.S.
Canada
In the first quarter of 2014, Devon completed minor divestiture transactions for $142 million ($155 million Canadian dollars). In the second quarter of 2014, Devon sold conventional assets to Canadian Natural Resources Limited for $2.8 billion ($3.125 billion Canadian dollars).
Under full cost accounting rules, sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost center’s capitalized costs and proved reserves, then a gain or loss must be recognized. The Canadian divestitures significantly altered such relationship. Therefore, Devon recognized gains totaling $1.1 billion ($0.6 billion after-tax) in 2014. These gains are included as a separate item in the accompanying consolidated comprehensive statements of earnings.
Included in the gain calculation noted above were asset retirement obligations of approximately $700 million assumed by the purchaser as well as the derecognition of approximately $700 million of goodwill allocated to the sold assets.
In conjunction with the divestitures noted above, Devon repatriated approximately $2.8 billion of proceeds to the U.S. in the second quarter of 2014. The proceeds were used to repay $0.7 billion of commercial paper and the $2.0 billion term loans that were drawn in the first quarter of 2014 to fund a portion of the GeoSouthern acquisition. Between collecting the divestiture proceeds and repatriating funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign exchange currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings.
U.S.
On August 29, 2014, Devon sold certain U.S. assets to LINN Energy for $2.2 billion ($2.0 billion after-tax proceeds). Additionally, approximately $200 million of asset retirement obligations were assumed by LINN Energy. No gain or loss was recognized on the sale. These proceeds were used towards the early retirement of $1.9 billion in senior notes in November 2014 as discussed in Note 13.

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2014
Derivative Financial Instruments [Abstract]
Derivative Financial Instruments	3.Derivative Financial Instruments
	Commodity Derivatives
	As of December 31, 2014, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX West Texas Intermediate futures price. The second table presents Devon’s oil derivatives that settle against the Western Canadian Select, West Texas Sour and Midland Sweet indices.
			Price Swaps					Price Collars							Call Options Sold
	Period		Volume (Bbls/d)		Weighted Average Price ($/Bbl)			Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)			Weighted Average Ceiling Price ($/Bbl)		Volume (Bbls/d)	Weighted Average Price ($/Bbl)
	Q1-Q4 2015		107,203		$	91.07		31,500		$	89.67		$	97.84	28,000	$	116.43
	Q1-Q4 2016		-		$	-		-		$	-		$	-	18,500	$	103.11
			Oil Basis Swaps
	Period		Index		Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
	Q1-Q4 2015		Western Canadian Select		22,514		$	-18.35
	Q1-Q4 2015		West Texas Sour		8,000		$	-3.68
	Q1-Q4 2015		Midland Sweet		14,247		$	-2.92
	As of December 31, 2014, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the Panhandle Eastern Pipe Line, El Paso Natural Gas and Houston Ship Channel indices.
			Price Swaps					Price Collars							Call Options Sold
	Period		Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)			Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)			Weighted Average Ceiling Price ($/MMBtu)		Volume (MMBtu/d)	Weighted Average Price ($/MMBtu)
	Q1-Q4 2015		250,000		$	4.32		328,452		$	4.05		$	4.36	550,000	$	5.09
	Q1-Q4 2016		-		$	-		-		$	-		$	-	400,000	$	5
			Natural Gas Basis Swaps
	Period		Index		Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
	Q1-Q4 2015		Panhandle Eastern Pipe Line		100,000		$	-0.28
	Q1-Q4 2015		El Paso Natural Gas		70,000		$	-0.11
	Q1-Q4 2015		Houston Ship Channel		200,000		$	0.01
	Q1-Q4 2016		Panhandle Eastern Pipe Line		30,000		$	-0.33
	Q1-Q4 2016		El Paso Natural Gas		15,000		$	-0.13
	Q1-Q4 2016		Houston Ship Channel		30,000		$	0.11
	As of December 31, 2014, the following were open derivative positions associated with gas processing and fractionation at EnLink. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index.  EnLink’s natural gas positions settle against the Henry Hub Gas Daily index as defined by the pricing dates in the derivative contracts.
	Period		Product		Volume				Weighted Average Price Paid			Weighted Average Price Received
	Q1 2015-Q4 2016		Ethane		1,168	MBbls			Index		$	0.29/gal
	Q1 2015-Q4 2016		Propane		1,171	MBbls			Index		$	1.01/gal
	Q1-Q4 2015		Normal Butane		53	MBbls			Index		$	1.14/gal
	Q1-Q4 2015		Natural Gasoline		44	MBbls			Index		$	1.81/gal
	Q1-Q4 2015		Natural Gas		1,225	MMBtu/d		$	4.08/MMBtu			Index
	Interest Rate Derivatives
	As of December 31, 2014, Devon had the following open interest rate derivative positions:
	Notional			Rate Received		Rate Paid		Expiration
	(In millions)
	$	100		Three Month LIBOR		0.92%		Dec-16
	$	100		1.76%		Three Month LIBOR		Jan-19
	Foreign Currency Derivatives
	As of December 31, 2014, Devon had the following open foreign currency derivative position:
	Forward Contract
	Currency		Contract Type		CAD Notional			Weighted Average Fixed Rate Received		Expiration
					(In millions)			(CAD-USD)
	Canadian Dollar		Sell		$	1,884		0.864		Mar-15
	Financial Statement Presentation
	The following table presents the net gains and losses recognized in the accompanying consolidated comprehensive statements of earnings associated with derivative financial instruments.
			Comprehensive Statements of		Year Ended
					December 31,
			Earnings Caption		2014			2013			2012
					(In millions)
	Oil, gas and NGL commodity derivatives		Oil, gas and NGL derivatives		$	1,989		$	-191		$	693
	Midstream commodity derivatives		Marketing and midstream revenues			22			-			-
	Interest rate derivatives		Other nonoperating items			-1			-			-15
	Foreign currency derivatives		Other nonoperating items			60			56			-18
	Net gains (losses) recognized in comprehensive statements of earnings				$	2,070		$	-135		$	660
	The following table presents the derivative fair values included in the accompanying consolidated balance sheets.
					December 31,
			Balance Sheet Caption		2014			2013
					(In millions)
	Asset derivatives:
	Oil, gas and NGL commodity derivatives		Derivatives, at fair value		$	1,967		$	75
	Oil, gas and NGL commodity derivatives		Other long-term assets			1			28
	Midstream commodity derivatives		Derivatives, at fair value			17			-
	Midstream commodity derivatives		Other long-term assets			10			-
Interest rate derivatives		Derivatives, at fair value			1			-
Foreign currency derivatives		Derivatives, at fair value			8			-
Total asset derivatives				$	2,004		$	103
Liability derivatives:
Oil, gas and NGL commodity derivatives		Other current liabilities		$	25		$	58
Oil, gas and NGL commodity derivatives		Other long-term liabilities			26			62
Midstream commodity derivatives		Other current liabilities			3			-
Midstream commodity derivatives		Other long-term liabilities			2			-
Interest rate derivatives		Other current liabilities			1			-
Foreign currency derivatives		Other current liabilities			-			1
Total liability derivatives				$	57		$	121

ShareBased_Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2014
Share-based Compensation [Abstract]
Share-Based Compensation	4.Share-Based Compensation
	On June 3, 2009, Devon's stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon's Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, performance restricted stock awards, restricted stock units, performance share units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors.
	In the second quarter of 2012, Devon’s stockholders adopted an amendment to the 2009 Long-Term Incentive Plan, which also expires June 2, 2019. This amendment increases the number of shares authorized for issuance from 21.5 million shares to 47.0 million shares. To calculate shares issued under the 2009 Long-Term Incentive Plan subsequent to this amendment, options and stock appreciation rights represent one share and other awards represent 2.38 shares.
	Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.
	Devon did not have an annual long-term incentive grant in 2013 due to revisions in the timing of the employee compensation cycle. The annual long-term incentive grant related to 2013 performance was granted in February 2014.
	The following table presents the effects of share-based compensation included in Devon's accompanying consolidated comprehensive statements of earnings. Devon’s gross general and administrative expense for the year ended December 31, 2014 includes $17 million of unit-based compensation related to grants made under EnLink’s long-term incentive plans.
	The vesting for certain share-based awards was accelerated as part of Devon’s restructuring as discussed in Note 6. The associated expense for these accelerated awards is included in restructuring costs in the accompanying consolidated comprehensive statements of earnings.
			Year Ended December 31,
			2014			2013			2012
			(In millions)
	Gross general and administrative expense		$	199		$	157		$	179
	Share-based compensation expense capitalized pursuant to the
	full cost method of accounting for oil and gas properties		$	53		$	60		$	56
	Related income tax benefit		$	30		$	23		$	34
	Stock Options
	In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zero to four years.
	The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon's common stock is based on the historical volatility of the market price of Devon's common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date of grant. The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior. The following table presents a summary of the grant-date fair values of stock options granted and the related assumptions for 2012. All such amounts represent the weighted-average amounts for the year. No stock options were granted in 2014 and 2013.
			2012
	Grant-date fair value		$	22.20
	Volatility factor			42.5%
	Dividend yield			1.2%
	Risk-free interest rate			1.1%
	Expected term (in years)			6.0
	The following table presents a summary of Devon's outstanding stock options.
							Weighted Average
				Options		Exercise Price				Remaining Term		Intrinsic Value
				(In thousands)						(In years)		(In millions)
	Outstanding at December 31, 2013			6,446		$	69.35
	Granted			-		$	-
	Exercised			-1,417		$	65.55
	Expired			-528		$	70.64
	Forfeited			-283		$	67.86
	Outstanding at December 31, 2014			4,218		$	70.56			3.11		$	1
	Vested and expected to vest at December 31, 2014			4,201		$	70.57			3.10		$	1
	Exercisable at December 31, 2014			3,969		$	70.80			3.00		$	1
	The aggregate intrinsic value of stock options that were exercised during 2014, 2013 and 2012 was $9 million, $0.3 million and $34 million, respectively. As of December 31, 2014, Devon's unrecognized compensation cost related to unvested stock options was $3 million. Such cost is expected to be recognized over a weighted-average period of 1.0 years.
	Restricted Stock Awards and Units
	Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zero to four years. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon's common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. The following table presents a summary of Devon's unvested restricted stock awards and units.
				Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
				(In thousands)
	Unvested at December 31, 2013			3,292		$	59.76
	Granted			3,487		$	62.75
	Vested			-1,767		$	60.23
	Forfeited			-708		$	60.47
	Unvested at December 31, 2014			4,304		$	60.85
	The aggregate fair value of restricted stock awards and units that vested during 2014, 2013 and 2012 was $112 million, $141 million and $112 million, respectively. As of December 31, 2014, Devon's unrecognized compensation cost related to unvested restricted stock awards and units was $194 million. Such cost is expected to be recognized over a weighted-average period of 2.5 years.
	Performance-Based Restricted Stock Awards
	Performance-based restricted stock awards are granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zero to four years. If Devon meets or exceeds the performance target, the awards vest after the recipient meets the related requisite service period. If the performance target and service period requirement are not met, the award does not vest. Once vested, recipients are entitled to dividends on the awards. Devon estimates the fair values of the awards as the closing price of Devon's common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of Devon's performance-based restricted stock awards.
				Performance Restricted Stock Awards		Weighted Average Grant-Date Fair Value
				(In thousands)
	Unvested at December 31, 2013			316		$	56.25
	Granted			234		$	61.33
	Vested			-170		$	56.18
	Unvested at December 31, 2014			380		$	59.41
	The aggregate fair value of performance-based restricted stock awards that vested during 2014 and 2013 was $10 million and $5 million, respectively. No awards vested in 2012. As of December 31, 2014, Devon's unrecognized compensation cost related to these awards was $5 million. Such cost is expected to be recognized over a weighted-average period of 2.9 years.
	Performance Share Units
	Performance share units are granted to certain members of Devon’s senior management. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s total shareholder return (“TSR”) to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200 percent of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.
	At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents a summary of the grant-date fair values of performance share units granted and the related assumptions.
		2014						2013						2012
	Grant-date fair value	$	70.18	-	$	81.05		$	61.27	-	$	63.48		$	61.27	-	$	63.48
	Risk-free interest rate	0.54%							0.26%	-		0.36%			0.26%	-		0.36%
	Volatility factor	28.80%						30.30%						30.30%
	Contractual term (in years)	2.89						3						3
	The following table presents a summary of Devon's performance share units.
			Performance Share Units		Weighted Average Grant-Date Fair Value
			(In thousands)
Unvested at December 31, 2013			925		$	66.64
Granted			708		$	77.77
Forfeited			-156		$	76.59
Unvested at December 31, 2014 (1)			1,477		$	70.90
____________________________
	-1		A maximum of 3.0 million common shares could be awarded based upon Devon’s final TSR ranking.
As of December 31, 2014, Devon's unrecognized compensation cost related to unvested units was $34 million. Such cost is expected to be recognized over a weighted-average period of 1.8 years.
EnLink Share-Based Awards
As of December 31, 2014, EnLink’s unrecognized compensation cost related to unvested restricted incentive units was $20 million. Such cost is expected to be recognized over a weighted-average period of 1.9 years.
As of December 31, 2014, the General Partner’s unrecognized compensation cost related to unvested restricted incentive units was $21 million. Such cost is expected to be recognized over a weighted-average period of 1.9 years.

Asset_Impairments

Asset Impairments	12 Months Ended
	Dec. 31, 2014
Asset Impairments [Abstract]
Asset Impairments	5. Asset Impairments
	In 2014, 2013 and 2012, Devon recognized asset impairments as presented below.
		Year Ended December 31, 2014				Year Ended December 31, 2013				Year Ended December 31, 2012
		Gross		Net of Taxes		Gross		Net of Taxes		Gross		Net of Taxes
		(In millions)
	Goodwill	$	1,941	$	1,941	$	-	$	-	$	-	$	-
	U.S. oil and gas assets		-		-		1,110		707		1,793		1,142
	Canada oil and gas assets		-		-		843		632		163		122
	Midstream assets		12		7		23		14		68		44
	Asset impairments	$	1,953	$	1,948	$	1,976	$	1,353	$	2,024	$	1,308
	Goodwill Impairment
	In 2014, Devon recognized $1.9 billion in goodwill impairment related to its Canadian reporting unit. Additional information regarding the impairment is discussed in Note 12.
	Oil and Gas Impairments
	Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.
	The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which reduced proved reserve values.
	Midstream Impairments
	Due to the significant decline in oil prices during the fourth quarter of 2014, Devon wrote down its pipeline line fill inventory, as the carrying amount exceeded its fair value, which was determined based on the West Texas Intermediate spot price at December 31, 2014.
	Due to declining natural gas production resulting from low natural gas and NGL prices in 2013 and 2012, Devon determined that the carrying amounts of certain of its midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models. The fair value of Devon’s midstream assets is considered a Level 3 fair value measurement.

Restructuring_Costs

Restructuring Costs	12 Months Ended
	Dec. 31, 2014
Restructuring Costs [Abstract]
Restructuring Costs
	6.   Restructuring Costs
	Canadian Divestitures
	During 2014, Devon recognized $46 million of employee related and other costs associated with its divestiture of certain Canadian assets. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are noncash charges.
	Office Consolidation
	In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon closed its office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation. The employee severance and retention costs included amounts related to cash severance costs and accelerated vesting of share-based grants. The lease obligations and other costs related to certain office space that is subject to non-cancellable operating lease agreements and that Devon ceased using as part of the office consolidation.
	Divestiture of Offshore Assets
	In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of December 31, 2012, Devon had divested all of its U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.
	Financial Statement Presentation
	The schedule below summarizes restructuring costs presented in the accompanying consolidated comprehensive statements of earnings.
		Year Ended December 31,
		2014			2013			2012
		(In millions)
	Canada divestitures:
	Employee severance and retention	$	42		$	-		$	-
	Lease obligations and other		4			-			-
	Office consolidation:
	Employee severance and retention		-			13			77
	Lease obligations and other		-			41			3
	Offshore divestiture:
	Employee severance and retention		-			-			-3
	Lease obligations and other		-			-			-3
	Restructuring costs	$	46		$	54		$	74
	The schedule below summarizes Devon’s restructuring liabilities.
			Other			Other
			Current			Long-term
			Liabilities			Liabilities			Total
			(In millions)
	Balance as of December 31, 2012		$	52		$	9		$	61
	Changes due to office consolidation			-22			11			-11
	Changes due to offshore divestiture			-3			-2			-5
	Balance as of December 31, 2013			27			18			45
	Changes due to Canadian divestitures			4			-			4
	Changes due to office consolidation			-15			-10			-25
	Changes due to offshore divestiture			-3			-1			-4
	Balance as of December 31, 2014		$	13		$	7		$	20

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Income Taxes	7.Income Taxes
	Income Tax Expense (Benefit)
	Devon’s income tax components are presented in the following table.
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	Current income tax expense (benefit):
	U.S. federal	$	152	$	73	$	60
	Various states		18		-5		-3
	Canada and various provinces		307		4		-5
	Total current tax expense (benefit)		477		72		52
	Deferred income tax expense (benefit):
	U.S. federal		1,610		198		-188
	Various states		93		59		34
	Canada and various provinces		188		-160		-30
	Total deferred tax expense (benefit)		1,891		97		-184
	Total income tax expense (benefit)	$	2,368	$	169	$	-132
	Total income tax expense (benefit) differed from the amounts computed by applying the United States federal income tax rate to earnings from continuing operations before income taxes as a result of the following:
		Year Ended December 31,
		2014		2013		2012
	Total income tax expense (benefit) (in millions)	$	2,368	$	169	$	-132
	U.S. statutory income tax rate		35%		35%		-35%
	Non-deductible goodwill transactions		23%		0%		0%
	Taxation on Canadian operations		-4%		9%		-6%
	State income taxes		2%		23%		6%
	Repatriations		2%		65%		0%
	Taxes on EnLink formation		1%		0%		0%
	Other		-1%		-19%		-7%
	Effective income tax rate		58%		113%		-42%
	During 2014, Devon had non-deductible goodwill transactions. Goodwill was removed in conjunction with the Canadian conventional asset divestiture to Canadian Natural Resources Limited, and there was a goodwill impairment in the Canadian reporting unit. See Note 12 for further discussion.
	Additionally, during 2014, Devon repatriated to the U.S. $2.8 billion of cash relating to the Canadian asset divestiture. In conjunction with the repatriation, Devon recognized approximately $105 million of additional income tax expense for the full year. Prior to the repatriation, Devon had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, Devon retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax. After the use of foreign tax credits, the current income tax on the repatriation was $67 million.
	Furthermore, Devon completed its divestiture program of certain assets in the U.S. In conjunction with the divestiture closing and due to the availability of additional tax deductions, Devon recognized $294 million of current income tax expense. The current tax expense was entirely offset by the recognition of deferred tax benefits.
	Devon also recorded a $46 million deferred tax liability in conjunction with the formation of EnLink in 2014.
	In the second and fourth quarters of 2013, Devon repatriated to the U.S. a total of $4.3 billion of its cash held outside of the U.S. In the fourth quarter of 2013, Devon announced plans to divest of its Canadian conventional assets. These events resulted in an incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.
	Deferred Tax Assets and Liabilities
	The tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities are presented below:
		December 31,
		2014		2013
	Deferred tax assets:	(In millions)
	Asset retirement obligations	$	458	$	673
	Foreign tax credits		-		248
	Net operating loss carryforwards		200		183
	Alternative minimum tax credits		57		105
	Pension benefit obligations		113		104
	Other		273		163
	Total deferred tax assets		1,101		1,476
	Deferred tax liabilities:
	Property and equipment		-6,940		-5,895
	Long-term debt		-115		-161
	Taxes on unremitted foreign earnings		-6		-157
	Fair value of financial instruments		-699		-7
	Other		-154		-52
	Total deferred tax liabilities		-7,914		-6,272
	Net deferred tax liability	$	-6,813	$	-4,796
	Devon has recognized $200 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The carryforwards consist of $621 million of Canadian net operating loss carryforwards, which expire between 2029 and 2034,  $180 million of state net operating loss carryforwards, which expire primarily between 2018 and 2032 and $135 million of net operating loss carryforwards related to EnLink’s operations, which expire between 2028 and 2034. Devon expects the tax benefits from the Canadian net operating loss carryforwards to be utilized between 2015 and 2017 and the state net operating loss carryforwards to be utilized between 2017 and 2029. The EnLink net operating losses are expected to be utilized during 2015.  Devon has also recognized a $57 million deferred tax asset related to alternative minimum tax credits which have no expiration date and will be available for use against tax on future taxable income.
	The expected utilization of Devon’s carryforwards and credits is based upon current estimates of taxable income, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil, gas and NGL prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon's future taxable income will more likely than not be sufficient to utilize its tax carryforwards and credits prior to their expiration.
	As of December 31, 2014, Devon’s unremitted foreign earnings totaled approximately $1.8 billion. All but $22 million of the $1.8 billion was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for United States income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to United States income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
	For the remaining $22 million of unremitted earnings deemed not to be indefinitely reinvested, Devon has recognized a $6 million deferred tax liability associated with such unremitted earnings as of December 31, 2014.
	Unrecognized Tax Benefits
	The following table presents changes in Devon's unrecognized tax benefits.
		December 31,
		2014		2013
		(In millions)
	Balance at beginning of year	$	243	$	216
Tax positions taken in prior periods		-		-17
Tax positions taken in current year		-		42
Accrual of interest related to tax positions taken		2		5
Foreign currency translation		-4		-3
Balance at end of year	$	241	$	243
Devon’s unrecognized tax benefit balance at December 31, 2014 and 2013 included $34 million and $32 million, respectively, of interest and penalties. If recognized, $223 million of Devon's unrecognized tax benefits as of December 31, 2014 would affect Devon's effective income tax rate. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
Jurisdiction	Tax Years Open
U.S. Federal	2008-2014
Various U.S. states	2008-2014
Canada Federal	2004-2014
Various Canadian provinces	2004-2014
Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.

Net_Earnings_Loss_Per_Share_At

Net Earnings (Loss) Per Share Attributable To Devon	12 Months Ended
	Dec. 31, 2014
Net earnings (loss) per share attributable to Devon:
Earnings (Loss) Per Share Attributable To Devon
	8.Net Earnings (Loss) Per Share Attributable to Devon
	The following table reconciles net earnings (loss) attributable to Devon and common shares outstanding used in the calculations of basic and diluted net earnings per share.
				Common		Earnings (loss)
		Earnings (loss)		Shares		per  Share
		(In millions, except per share amounts)
	Year Ended December 31, 2014:
	Net earnings attributable to Devon	$	1,607		409
	Attributable to participating securities		-17		-4
	Basic net earnings per share		1,590		405	$	3.93
	Dilutive effect of potential common shares issuable		-		2
	Diluted net earnings per share	$	1,590		407	$	3.91
	Year Ended December 31, 2013:
	Net loss attributable to Devon	$	-20		406
	Attributable to participating securities		-2		-4
	Basic net loss per share		-22		402	$	-0.06
	Dilutive effect of potential common shares issuable		-		-
	Diluted net loss per share	$	-22		402	$	-0.06
	Year Ended December 31, 2012:
	Net loss attributable to Devon	$	-206		404
	Attributable to participating securities		-3		-4
	Basic net loss per share		-209		400	$	-0.52
	Dilutive effect of potential common shares issuable		-		-
	Diluted net loss per share	$	-209		400	$	-0.52
	Certain options to purchase shares of Devon's common stock were excluded from the dilution calculations because the options were antidilutive. These excluded options totaled 3 million, 7 million and 9 million in 2014, 2013 and 2012, respectively.

Other_Comprehensive_Earnings

Other Comprehensive Earnings	12 Months Ended
	Dec. 31, 2014
Other Comprehensive Earnings [Abstract]
Other Comprehensive Earnings
	9.Other Comprehensive Earnings
	Components of other comprehensive earnings consist of the following:
		Year Ended December 31,
		2014			2013		2012
		(In millions)
	Foreign currency translation:
	Beginning accumulated foreign currency translation	$	1,448		$	1,996	$	1,802
	Change in cumulative translation adjustment		-499			-574		203
	Income tax benefit (expense)		34			26		-9
	Ending accumulated foreign currency translation		983			1,448		1,996
	Pension and postretirement benefit plans:
	Beginning accumulated pension and postretirement benefits		-180			-225		-227
	Net actuarial gain (loss) and prior service cost arising in current year		-57			48		-47
	Recognition of net actuarial loss and prior service cost in earnings (1)		20			24		51
	Income tax benefit (expense)		13			-27		-2
	Ending accumulated pension and postretirement benefits		-204			-180		-225
	Accumulated other comprehensive earnings, net of tax	$	779		$	1,268	$	1,771
	____________________________
		-1		These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying consolidated comprehensive statements of earnings (see Note 15 note for additional details).

Supplemental_Information_To_St

Supplemental Information To Statements Of Cash Flows	12 Months Ended
	Dec. 31, 2014
Supplemental Information To Statements Of Cash Flows [Abstract]
Supplemental Information To Statements Of Cash Flows	10.Supplemental Information to Statements of Cash Flows
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	Net change in working capital accounts:
	Accounts receivable	$	128	$	-288	$	140
	Income taxes receivable		-467		29		-55
	Other current assets		-222		20		-73
	Accounts payable		-68		26		-8
	Revenues and royalties payable		133		35		19
	Other current liabilities		546		-120		-73
	Net change in working capital	$	50	$	-298	$	-50
	Interest paid (net of capitalized interest)	$	514	$	406	$	334
	Income taxes paid	$	899	$	13	$	100
	On March 7, 2014, Devon completed a business combination to form EnLink. With the exception of a $100 million cash payment to noncontrolling interests, the business combination was a non-monetary transaction. See Note 2 for additional details.

Accounts_Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2014
Accounts Receivable [Abstract]
Accounts Receivable
	11.  Accounts Receivable
	The components of accounts receivable include the following:
		31-Dec-14		31-Dec-13
		(In millions)
	Oil, gas and NGL sales	$	723	$	851
	Joint interest billings		475		447
	Marketing and midstream revenues		706		172
	Other		71		61
	Gross accounts receivable		1,975		1,531
	Allowance for doubtful accounts		-16		-11
	Net accounts receivable	$	1,959	$	1,520

Goodwill_And_Other_Intangible_

Goodwill And Other Intangible Assets	12 Months Ended
	Dec. 31, 2014
Goodwill And Other Intangible Assets [Abstract]
Goodwill And Other Intangible Assets	12.  Goodwill and Other Intangible Assets
	Goodwill
	The table below provides a summary of Devon's goodwill by assigned reporting unit.
		U.S.		Canada		EnLink		Total
		(In millions)
	Balance as of December 31, 2012	$	2,644	$	3,033	$	402	$	6,079
	Asset divestitures		-26		-		-		-26
	Foreign currency translation adjustments		-		-195		-		-195
	Balance as of December 31, 2013	$	2,618	$	2,838	$	402	$	5,858
	Acquired during period		-		-		3,283		3,283
	Asset divestitures		-		-706		-		-706
	Impairment		-		-1,941		-		-1,941
	Foreign currency translation adjustments		-		-191		-		-191
	Balance as of December 31, 2014	$	2,618	$	-	$	3,685	$	6,303
	Acquired During Period
	Included in the assets Devon contributed to EnLink Holdings was $402 million of goodwill. The additional EnLink goodwill of $3.3 billion represents the goodwill recognized upon the formation of EnLink and General Partner as described in Note 2.
	The General Partner’s and EnLink’s goodwill was recognized and assigned to the five reporting units as follows.
			Texas		Louisiana		Oklahoma		Ohio River Valley		General Partner		Total
		(In millions)
	Balance as of December 31, 2013	$	326	$	-	$	76	$	-	$	-	$	402
	Acquired during period		842		787		114		113		1,427		3,283
	Balance as of December 31, 2014	$	1,168	$	787	$	190	$	113	$	1,427	$	3,685
	Asset Divestitures
	In conjunction with the asset divestitures in 2013 and 2014, Devon removed $26 million and $706 million of goodwill, respectively, which were allocated to these assets.
	Impairment
	Devon’s Canadian goodwill was originally recognized in 2001 as a result of a business combination consisting almost entirely of conventional gas assets that Devon no longer owns.
	As a result of performing the goodwill impairment test described in Note 1, Devon concluded the implied fair value of its Canadian goodwill was zero as of December 31, 2014. This conclusion was largely based on the significant decline in benchmark oil prices, particularly after OPEC’s decision not to reduce its production targets that was announced in late November 2014. Consequently, in the fourth quarter of 2014, Devon wrote off its remaining Canadian goodwill and recognized a $1.9 billion impairment.
	Other Intangible Assets
	As of December 31, 2014, intangible assets associated with customer relationships had a gross carrying amount of $569 million and $36 million of accumulated amortization. The weighted-average amortization period for the customer relationships is 13.7 years. Amortization expense for intangibles was approximately $36 million for the year ended December 31, 2014. Other intangible assets are reported in other long-term assets in the accompanying consolidated balance sheets.
	The following table summarizes the estimated aggregate amortization expense for the next five years.
	Year	Amortization Amount
			(In millions)
	2015	$	45
	2016	$	45
	2017	$	45
	2018	$	45
	2019	$	44

Debt_And_Related_Expenses

Debt And Related Expenses	12 Months Ended
	Dec. 31, 2014
Debt And Related Expenses [Abstract]
Debt And Related Expenses	13.Debt and Related Expenses
	A summary of Devon's debt is as follows:
		31-Dec-14			31-Dec-13
		(In millions)
	Devon debt
	Commercial paper	$	932		$	1,317
	5.625% due January 15, 2014		-			500
	Floating rate due December 15, 2015		500			500
	2.40% due July 15, 2016		-			500
	Floating rate due December 15, 2016		350			350
	1.20% due December 15, 2016		-			650
	1.875% due May 15, 2017		-			750
	8.25% due July 1, 2018		125			125
	2.25% due December 15, 2018		750			750
	6.30% due January 15, 2019		700			700
	4.00% due July 15, 2021		500			500
	3.25% due May 15, 2022		1,000			1,000
	7.50% due September 15, 2027		150			150
	7.875% due September 30, 2031		1,250			1,250
	7.95% due April 15, 2032		1,000			1,000
	5.60% due July 15, 2041		1,250			1,250
	4.75% due May 15, 2042		750			750
	Net discount on debentures and notes		-18			-20
	Total Devon debt		9,239			12,022
	EnLink debt
	Credit facilities		237			-
	2.70% due April 1, 2019		400			-
	7.125% due June 1, 2022		163			-
	4.40% due April 1, 2024		550			-
	5.60% due April 1, 2044		350			-
	5.05% due April 1, 2045		300
	Net premium on debentures and notes		23			-
	Total EnLink debt		2,023			-
	Total debt		11,262			12,022
	Less amount classified as short-term debt (1)		1,432			4,066
	Total long-term debt	$	9,830		$	7,956
	__________________________
		-1		2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015. 2013 short-term debt consists of $2.25 billion of senior notes issued in conjunction with the GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014.
	Debt maturities as of December 31, 2014, excluding premiums and discounts, are as follows (in millions):
	2015	$	1,432
	2016		350
	2017		-
	2018		875
	2019		1,337
	2020 and thereafter		7,263
	Total	$	11,257
	Credit Lines
	Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the Senior Credit Facility). The maturity date for $30 million of the Senior Credit Facility is October 24, 2017. The maturity date for $164 million of the Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019.  Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $3.8 million that is payable quarterly in arrears. As of December 31, 2014, there were no borrowings under the Senior Credit Facility.
	The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of December 31, 2014, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 20.9 percent.
	Commercial Paper
	Devon has access to $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the commercial paper market. As of December 31, 2014, Devon’s commercial paper borrowings of $932 million have a weighted-average borrowing rate of 0.44 percent.
	Retirement of Senior Notes
	On November 13, 2014, Devon redeemed $1.9 billion of senior notes prior to their scheduled maturity, primarily with proceeds received from its asset divestitures. The redemption includes the 2.4% $500 million senior notes due 2016, the 1.2% $650 million senior notes due 2016 and the 1.875% $750 million senior notes due 2017. The notes were redeemed for $1.9 billion, which included 100 percent of the principal amount and a make-whole premium of $40 million. On the date of redemption, these notes also had an unamortized discount of $2 million and unamortized debt issuance costs of $6 million. The make-whole premium, unamortized discounts and debt issuance costs are included in net financing costs on the accompanying 2014 consolidated comprehensive statement of earnings.
	Other Debentures and Notes
	Following are descriptions of the various other debentures and notes outstanding at December 31, 2014 and 2013, as listed in the table presented at the beginning of this note.
	GeoSouthern Debt
	In December 2013, in conjunction with the planned GeoSouthern acquisition, Devon issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately $2.2 billion, net of discounts and issuance costs. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45 percent, which rate will be reset quarterly. The floating rate senior notes due in 2016 bears interest at a rate equal to three-month LIBOR plus 0.54 percent, which rate will be reset quarterly. The schedule below summarizes the key terms of these notes (in millions).
	Floating rate due December 15, 2015	$	500
	Floating rate due December 15, 2016		350
	1.20% due December 15, 2016 (1)		650
	2.25% due December 15, 2018		750
	Discount and issuance costs		-2
	Net proceeds	$	2,248
	__________________________
(1)  The 1.20% $650 million note due December 15, 2016 was redeemed on November 13, 2014.
The senior notes were classified as short-term debt on Devon’s consolidated balance sheet as of December 31, 2013 due to certain redemption features in the event that the GeoSouthern acquisition was not completed on or prior to June 30, 2014. On February 28, 2014, the GeoSouthern acquisition closed and thus the senior notes were subsequently classified as long-term debt.
Additionally, during December 2013, Devon entered into a term loan agreement with a group of major financial institutions pursuant to which Devon could draw up to $2.0 billion to finance, in part, the GeoSouthern acquisition and to pay transaction costs. In February 2014, Devon drew the $2.0 billion of term loans for the GeoSouthern transaction, and the amount was subsequently repaid on June 30, 2014 with the Canadian divestiture proceeds that were repatriated to the U.S. in June 2014, at which point the term loan was terminated.
Other Notes
In 2012, 2011, 2009 and 2002, Devon issued senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper and credit facility borrowings. The schedule below summarizes the key terms of these notes (in millions).
	Date Issued
	May-12			Jul-11		Jan-09		Mar-02
1.875% due May 15, 2017 (1)	$	750		$	-	$	-	$	-
3.25% due May 15, 2022		1,000			-		-		-
4.75% due May 15, 2042		750			-		-		-
2.40% due July 15, 2016 (1)		-			500		-		-
4.00% due July 15, 2021		-			500		-		-
5.60% due July 15, 2041		-			1,250		-		-
5.625% due January 15, 2014 (2)		-			-		500		-
6.30% due January 15, 2019		-			-		700		-
7.95% due April 15, 2032		-			-		-		1,000
Discount and issuance costs		-35			-29		-13		-14
Net proceeds	$	2,465		$	2,221	$	1,187	$	986
__________________________
(1)  The 1.875% $750 million note due May 15, 2017 and 2.4% $500 million note due July 15, 2016 were redeemed on November 13, 2014.
(2) The 5.625% $500 million note due January 15, 2014 was redeemed upon maturity.
Ocean Debt
On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2014, including the fair value of the debt at April 25, 2003 and the effective interest rate of the debt after determining the fair values using April 25, 2003 market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.
	Fair Value of Debt Assumed			Effective Rate of Debt Assumed
Debt Assumed		(In millions)
8.250% due July 2018 (principal of $125 million)	$	147			5.5%
7.500% due September 2027 (principal of $150 million)	$	169			6.5%
7.875% Debentures due September 30, 2031
In October 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly owned finance subsidiary, sold debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed, on an unsecured and unsubordinated basis, the obligations of Devon Financing under the debt securities. The proceeds were used to fund a portion of the acquisition of Anderson Exploration.
EnLink Debt
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
The table below summarizes the fair value of EnLink’s debt as of March 7, 2014, the formation date of EnLink. The premiums are being amortized using the effective interest method.
	March 7, 2014 Fair Value			Effective
	of Debt			Rate of Debt
	(In millions)
8.875% due February 15, 2018 (principal of $725 million) (1)	$	760		7.70%
7.125% due June 1, 2022 (principal of $197 million)		226		5.30%
Credit facilities		468
Total long-term debt	$	1,454
__________________________
(1)  The 2018 senior notes were redeemed on April 18, 2014.
EnLink has a $1.0 billion unsecured revolving credit facility. As of December 31, 2014, there were $14 million in outstanding letters of credit and $237 million outstanding borrowings under the $1.0 billion credit facility, leaving $749 million available for future borrowing.
The $1.0 billion credit facility matures on the fifth anniversary of the initial funding date, which was March 7, 2014, unless EnLink requests, and the requisite lenders agree, to extend it pursuant to its terms. On February 5, 2015, the commitments under EnLink’s credit facility were increased to $1.5 billion, and the maturity date was extended by a year to March 7, 2020.
The credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of EnLink’s consolidated indebtedness to consolidated EBITDA (as defined in the credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If EnLink consummates one or more acquisitions in which the aggregate purchase price is $50 million or more, the maximum allowed ratio of EnLink’s consolidated indebtedness to consolidated EBITDA may increase to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.
Additionally, as of December 31, 2014, E2 Energy Services, LLC had certain promissory notes outstanding related to its vehicle fleet in the amount of $0.4 million due in increments through July 2017.
The General Partner also has a $250 million revolving credit facility. As of December 31, 2014, the General Partner had no outstanding borrowings under the $250 million credit facility.
The $250 million credit facility will mature on March 7, 2019. The credit facility contains certain financial, operational and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other noncash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other noncash charges to consolidated interest charges) of 2.50 to 1.00 at all times unless an investment grade event (as defined in the credit facility) occurs. EnLink and the General Partner are in compliance with all such covenants as of December 31, 2014.
On March 19, 2014, EnLink issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400 million aggregate principal amount of its 2.70% senior notes due 2019, $450 million aggregate principal amount of its 4.40% senior notes due 2024 and $350 million aggregate principal amount of its 5.60% senior notes due 2044, at discounts of their face value. The 2019 notes mature on April 1, 2019, the 2024 notes mature on April 1, 2024 and the 2044 notes mature on April 1, 2044. The interest payments on the notes are due semi-annually in arrears in April and October.
On November 12, 2014, EnLink issued $100 million aggregate principal amount of its 4.40% senior notes due 2024 and $300 million aggregate principal amount of its 5.05% senior notes due 2045, at a premium and discount, respectively, of their face value. The 2024 notes were offered as an additional issue of EnLink’s outstanding 4.40% senior notes due 2024, issued in an aggregate principal amount of $450 million on March 19, 2014. The 2024 notes and the notes issued March 19, 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. The 2045 notes mature on April 1, 2045, and interest payments on the 2045 notes are due semi-annually in arrears in April and October.
Net Financing Costs
The following schedule includes the components of net financing costs.
	Year Ended December 31,
	2014			2013		2012
	(In millions)
Interest based on debt outstanding	$	546		$	466	$	440
Early retirement of debt		48			-		-
Capitalized interest		-70			-56		-48
Other fees and expenses		12			27		14
Interest expense		536			437		406
Interest income		-10			-20		-36
Net financing costs	$	526		$	417	$	370

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations
	14.Asset Retirement Obligations
	The schedule below summarizes changes in asset retirement obligations.
		Year Ended December 31,
		2014		2013
		(In millions)
	Asset retirement obligations as of beginning of period	$	2,228	$	2,095
	Liabilities incurred		97		112
	Liabilities settled		-56		-83
	Revision of estimated obligation		70		104
	Liabilities assumed by others		-953		-28
	Accretion expense on discounted obligation		89		115
	Foreign currency translation adjustment		-76		-87
	Asset retirement obligations as of end of period		1,399		2,228
	Less current portion		60		88
	Asset retirement obligations, long-term	$	1,339	$	2,140
	During 2014, Devon reduced its asset retirement obligation by $953 million for those obligations that were assumed by purchasers of Devon’s Canadian and U.S. divested oil and gas properties.

Retirement_Plans

Retirement Plans	12 Months Ended
	Dec. 31, 2014
Retirement Plans [Abstract]
Retirement Plans	15.Retirement Plans
	Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the qualified plans are based on the employees' years of service and compensation and are funded from assets held in the plans' trusts.
	The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans' benefits are based on the employees' years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans' benefit obligations. The total value of these trusts was $25 million and $27 million at December 31, 2014 and 2013, respectively and is included in other long-term assets in the accompanying consolidated balance sheets. For the remaining nonqualified plans for which trusts have not been established, benefits are funded from Devon's available cash and cash equivalents.
	Devon also has defined benefit postretirement plans that provide benefits for substantially all U.S. employees. The plans provide medical and, in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon's future cost-sharing intentions. Devon's funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.
	Benefit Obligations and Funded Status
	The following table presents the funded status of Devon's qualified and nonqualified pension and postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans was $1.2 billion and $1.1 billion at December 31, 2014 and 2013, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31. The projected benefit obligation for Devon’s qualified plans was fully funded as of December 31, 2014 and 2013.
		Pension Benefits				Postretirement Benefits
		2014		2013		2014		2013
		(In millions)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	1,177	$	1,360	$	24	$	34
	Service cost		30		36		1		1
	Interest cost		55		51		1		1
	Actuarial loss (gain)		203		-158		-		-3
	Plan amendments		-		2		-		-8
	Plan settlements		-4		-		-		-
	Foreign exchange rate changes		-3		-2		-		-
	Participant contributions		-		-		2		3
	Benefits paid		-81		-112		-4		-4
	Benefit obligation at end of year		1,377		1,177		24		24
	Change in plan assets:
	Fair value of plan assets at beginning of year		1,006		1,165		-		-
	Actual return on plan assets		200		-57		-		-
	Employer contributions		29		11		2		1
	Participant contributions		-		-		2		3
	Plan settlements		-4		-		-		-
	Benefits paid		-81		-112		-4		-4
	Foreign exchange rate changes		-1		-1		-		-
	Fair value of plan assets at end of year		1,149		1,006		-		-
	Funded status at end of year	$	-228	$	-171	$	-24	$	-24
	Amounts recognized in balance sheet:
	Other long-term assets	$	22	$	47	$	-	$	-
	Other current liabilities		-10		-12		-3		-3
	Other long-term liabilities		-240		-206		-21		-21
	Net amount	$	-228	$	-171	$	-24	$	-24
	Amounts recognized in accumulated other comprehensive earnings:
	Net actuarial loss (gain)	$	317	$	279	$	-11	$	-13
	Prior service cost (credit)		19		23		-9		-11
	Total	$	336	$	302	$	-20	$	-24
	The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $10 million and $11 million for 2014 and 2013, respectively, which were transferred from the trusts established for the nonqualified plans.
	Certain of Devon's pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2014 and 2013, as presented in the table below.
		December 31,
		2014		2013
		(In millions)
	Projected benefit obligation	$	250	$	218
	Accumulated benefit obligation	$	191	$	179
	Fair value of plan assets	$	-	$	-
	Net Periodic Benefit Cost and Other Comprehensive Earnings
	The following table presents the components of net periodic benefit cost and other comprehensive earnings.
		Pension Benefits						Postretirement Benefits
		2014		2013		2012		2014		2013		2012
		(In millions)
	Net periodic benefit cost:
	Service cost	$	30	$	36	$	43	$	1	$	1	$	1
	Interest cost		55		51		60		1		1		1
	Expected return on plan assets		-54		-62		-64		-		-		-
	Curtailment and settlement expense		1		-		26		-		-		1
	Recognition of net actuarial loss (gain) (1)		18		22		24		-1		-1		-1
	Recognition of prior service cost (1)		4		4		3		-2		-1		-1
	Total net periodic benefit cost (2)		54		51		92		-1		-		1
	Other comprehensive loss (earnings):
	Actuarial loss (gain) arising in current year		57		-39		37		-		-3		-4
	Prior service cost (credit) arising in current year		-		2		14		-		-8		-
	Recognition of net actuarial loss, including settlement
expense, in net periodic benefit cost		-19		-22		-45		1		1		1
Recognition of prior service cost, including curtailment,
in net periodic benefit cost		-4		-4		-8		2		1		1
Total other comprehensive loss (earnings)		34		-63		-2		3		-9		-2
Total recognized	$	88	$	-12	$	90	$	2	$	-9	$	-1
__________________________
(1)  These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
(2)  Net periodic benefit cost is a component of general and administrative expenses on the accompanying consolidated comprehensive statements of earnings.
The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2015.
	Pension Benefits		Postretirement Benefits
	(In millions)
Net actuarial loss (gain)	$	21	$	-1
Prior service cost (credit)		4		-2
Total	$	25	$	-3
Assumptions
The following table presents the weighted-average actuarial assumptions used to determine obligations and periodic costs.
	Pension Benefits						Postretirement Benefits
	2014		2013		2012		2014		2013		2012
Assumptions to determine benefit obligations:
Discount rate		3.90%		4.80%		3.85%		3.25%		3.65%		3.30%
Rate of compensation increase		4.49%		4.48%		4.48%		N/A		N/A		N/A
Assumptions to determine net periodic benefit cost:
Discount rate		4.80%		3.85%		4.65%		3.65%		3.30%		4.25%
Rate of compensation increase		4.49%		4.48%		4.97%		N/A		N/A		N/A
Expected return on plan assets		5.42%		5.48%		5.48%		N/A		N/A		N/A
Discount rate – Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. As a result of the discount rate decrease, Devon’s benefit obligations increased approximately $135 million for the year ended December 31, 2014.
Rate of compensation increase – For measurement of the 2014 benefit obligation for the pension plans, a 4.49 percent compensation increase was assumed.
Expected return on plan assets – The expected rate of return on plan assets was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types. See the pension plan assets section below for more information on Devon's target allocations.
Mortality rate assumptions – In 2014, the Society of Actuaries issued updated versions of its mortality tables and mortality improvement scale, reflecting the increasing life expectancies in the United States. While not required to strictly adhere to this data, Devon utilized actuary-produced mortality tables and an improvement scale derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in Devon’s plans. As a result of the mortality rate assumption update, Devon’s benefit obligation increased approximately $61 million for the year ended December 31, 2014.
Other assumptions – For measurement of the 2014 benefit obligation for the other postretirement medical plans, a 7.7 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015. The rate was assumed to decrease annually to an ultimate rate of 5 percent in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2014 by less than $1 million and would change the 2014 service and interest cost components of net periodic benefit cost by less than $1 million.
Pension Plan Assets
Devon's overall investment objective for its pension plans' assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocation for its pension plan assets.
	December 31,
	2014		2013
Fixed income		70%		70%
Equity		20%		20%
Other		10%		10%
The fair values of Devon's pension assets are presented by asset class in the following tables.
	As of December 31, 2014
					Fair Value Measurements Using:
	Actual Allocation		Total		Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
	(In millions)
Fixed-income securities:
U.S. Treasury obligations		35.2%	$	405	$	50	$	355	$	-
Corporate bonds		31.7%		364		269		95		-
Other bonds		2.6%		30		30		-		-
Total fixed-income securities		69.5%		799		349		450		-
Equity securities:
Global (large, mid, small cap)		17.2%		197		-		197		-
Other securities:
Hedge fund and alternative investments		9.7%		112		-		-		112
Short-term investments		3.6%		41		15		26		-
Total other securities		13.3%		153		15		26		112
Total investments		100.0%	$	1,149	$	364	$	673	$	112
	As of December 31, 2013
					Fair Value Measurements Using:
	Actual Allocation		Total		Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
	(In millions)
Fixed-income securities:
U.S. Treasury obligations		24.0%	$	241	$	69	$	172	$	-
Corporate bonds		39.5%		398		286		112		-
Other bonds		3.1%		31		31		-		-
Total fixed-income securities		66.6%		670		386		284		-
Equity securities:
Global (large, mid, small cap)		19.0%		190		-		190		-
Other securities:
Hedge fund and alternative investments		12.5%		127		15		-		112
Short-term investments		1.9%		19		-		19		-
Total other securities		14.4%		146		15		19		112
Total investments		100.0%	$	1,006	$	401	$	493	$	112
The following methods and assumptions were used to estimate the fair values in the tables above.
Fixed-income securities – Devon's fixed-income securities consist of United States Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Devon’s fixed income securities also include commingled funds that primarily invest in long-term bonds and United States Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Equity securities – Devon’s equity securities include a commingled global equity fund that invests in large, mid and small capitalization stocks across the world’s developed and emerging markets. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Other securities – Devon's other securities include cash and commingled, short-term investment funds. The short-term investment funds’ securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.
Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategies and a hedge fund of funds that invests both long and short using a variety of investment strategies. Devon's hedge fund of funds is not actively traded, and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.
Included below is a summary of the changes in Devon's Level 3 plan assets (in millions).
31-Dec-12	$	103
Investment returns		9
31-Dec-13		112
Disbursements		-6
Investment returns		6
31-Dec-14	$	112
Expected Cash Flows
The following table presents expected cash flow information for Devon's pension and postretirement benefit plans.
	Pension Benefits		Postretirement Benefits
	(In millions)
Devon's 2015 contributions	$	10	$	3
Benefit payments:
2015	$	73	$	3
2016	$	75	$	3
2017	$	79	$	3
2018	$	82	$	3
2019	$	86	$	2
2020 to 2024	$	466	$	8
Expected contributions included in the table above include amounts related to Devon's qualified plans, nonqualified plans and postretirement plans. Of the benefits expected to be paid in 2015, the $10 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans, and the $3 million of postretirement benefits is expected to be funded from Devon's available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
Defined Contribution Plans
Independent of EnLink, Devon maintains several defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. EnLink also maintains a 401(k) plan covering eligible employees. The following table presents expense related to these defined contribution plans.
	Year Ended December 31,
	2014		2013		2012
	(In millions)
401(k) and enhanced contribution plans	$	49	$	41	$	36
Canadian pension and savings plans		20		26		23
Total	$	69	$	67	$	59

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity [Abstract]
Stockholders' Equity	16.Stockholders' Equity
	The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per share and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
	Dividends
	Devon paid common stock dividends of $386 million, $348 million and $324 million in 2014, 2013 and 2012, respectively. The quarterly cash dividend was $0.20 per share in the first quarter of 2012. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013 and to $0.24 per share in the second quarter of 2014.
	Stock Option Proceeds
	Devon received $93 million, $3 million and $27 million from stock option proceeds in 2014, 2013 and 2012, respectively.

Noncontrolling_Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2014
Noncontrolling Interests [Abstract]
Noncontrolling interests	17.Noncontrolling Interests
	Acquisition of Noncontrolling Interests
	In March 2014, EnLink was formed as a publicly traded consolidated subsidiary of Devon to provide midstream services to Devon and third parties. Devon obtained approximately 120.5 million units, or a 52% ownership interest, as a result of this transaction. Approximately 92.7 million units were issued to the public for a 41% ownership interest, with the remaining 7% ownership interest held by the General Partner.
	Distributions to Noncontrolling Interests
	In conjunction with the formation of the General Partner in the first quarter of 2014, Devon made a payment of $100 million to noncontrolling interests. Further, EnLink and the General Partner distributed $135 million to non-Devon unitholders during 2014.
	Subsidiary  Equity Transactions
	Periodically, EnLink enters into Equity Distribution Agreements (“EDAs”) facilitating the selling of common units representing limited partner interests.  In 2014, EnLink sold approximately 14.8 million common units under these EDAs, generating net proceeds of approximately $410 million. EnLink used the net proceeds for general partnership purposes, to fund working capital, capital expenditures and debt repayments. Subsequent to these sales,  Devon’s ownership interest in EnLink was 49%.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies [Abstract]
Commitments And Contingencies
	18.Commitments and Contingencies
	Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon's estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon's financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management's estimates.
	Royalty Matters
	Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
	Environmental Matters
	Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon's monetary exposure for environmental matters is not expected to be material.
	Other Matters
	Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
	Commitments
	The following is a schedule by year of Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2014.
	Year Ending December 31,	Purchase Obligations	Drilling and Facility Obligations	Operational Agreements	Office and Equipment Leases
		(In millions)
	2015	$                    663	$                      234	$                      943	$                        72
	2016	809	116	919	50
	2017	885	77	890	50
	2018	920	13	856	45
	2019	895	1	334	39
	Thereafter	1,134	5	1,142	149
	Total	$                 5,306	$                      446	$                   5,084	$                      405
	Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.
	Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. The value of the drilling obligations reported is based on gross contractual value.
	Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.
	Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $64 million, $26 million and $42 million in 2014, 2013 and 2012, respectively.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Fair Value Measurements	19.Fair Value Measurements
	The following tables provide carrying value and fair value measurement information for certain of Devon's financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at December 31, 2014 and December 31, 2013. Therefore, such financial assets and liabilities are not presented in the following tables. Additionally, information regarding the fair values of midstream, goodwill and pension plan assets is provided in Note 5, Note 12 and Note 15, respectively.
						Fair Value Measurements Using:
		Carrying		Total Fair		Level 1		Level 2		Level 3
		Amount		Value		Inputs		Inputs		Inputs
			(In millions)
	December 31, 2014 assets (liabilities):
	Cash equivalents	$	950	$	950	$	340	$	610	$	-
	Oil, gas and NGL commodity derivatives	$	1,968	$	1,968	$	-	$	1,968	$	-
	Oil, gas and NGL commodity derivatives	$	-51	$	-51	$	-	$	-51	$	-
	Midstream commodity derivatives	$	27	$	27	$	-	$	27	$	-
	Midstream commodity derivatives	$	-5	$	-5	$	-	$	-5	$	-
	Interest rate derivatives	$	1	$	1	$	-	$	1	$	-
	Interest rate derivatives	$	-1	$	-1	$	-	$	-1	$	-
	Foreign currency derivatives	$	8	$	8	$	-	$	8	$	-
	Debt	$	-11,262	$	-12,472	$	-	$	-12,472	$	-
	Capital lease obligations	$	-20	$	-20	$	-	$	-20	$	-
	December 31, 2013 assets (liabilities):
	Cash equivalents	$	5,305	$	5,305	$	4,191	$	1,114	$	-
	Long-term investments	$	62	$	62	$	-	$	-	$	62
	Oil, gas and NGL commodity derivatives	$	103	$	103	$	-	$	103	$	-
	Oil, gas and NGL commodity derivatives	$	-120	$	-120	$	-	$	-120	$	-
	Foreign currency derivatives	$	-1	$	-1	$	-	$	-1	$	-
	Debt	$	-12,022	$	-12,908	$	-	$	-12,908	$	-
	The following methods and assumptions were used to estimate the fair values in the tables above.
	Level 1 Fair Value Measurements
	Cash equivalents —  Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value.
	Level 2 Fair Value Measurements
	Cash equivalents —  Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value approximates the carrying value.
	Commodity, interest rate and foreign currency derivatives — The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
	Debt — Devon's debt instruments do not actively trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s commercial paper and credit facility are the carrying values.
	Capital lease obligations —  The fair value was calculated using inputs from third-party banks.
	Level 3 Fair Value Measurements
	Long-term investments — Devon’s long-term investments as of December 31, 2013 consisted entirely of auction rate securities. In the first quarter of 2014, Devon redeemed all these securities for approximately $57 million, or $5 million below their carrying value.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2014
Discontinued Operations [Abstract]
Discontinued Operations	20.Discontinued Operations
	In 2012, Devon incurred a loss related to discontinued operations of $16 million ($21 million net of taxes) for the sale of assets in Angola. Devon did not have operating revenues related to discontinued operations during 2012.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2014
Segment Information [Abstract]
Segment Information	21.Segment Information
	Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon's Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon's U.S. and Canadian segments are both primarily engaged in oil and gas exploration and production activities, and certain information regarding such activities for each segment is included in Note 22.
	With the formation of EnLink in the first quarter of 2014, Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from its existing operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment. For the reporting periods prior to the formation of EnLink, Devon has reclassified, from its U.S. segment to the EnLink segment, all asset-level amounts related to the midstream assets that it contributed to EnLink.
		U.S.		Canada		EnLink		Eliminations		Total
		(In millions)
	Year Ended December 31, 2014:
	Revenues from external customers	$	14,862	$	2,063	$	2,641	$	-	$	19,566
	Intersegment revenues	$	-	$	-	$	859	$	-859	$	-
	Depreciation, depletion and amortization	$	2,479	$	560	$	280	$	-	$	3,319
	Asset impairments	$	12	$	1,941	$	-	$	-	$	1,953
	Gains and losses on asset sales	$	5	$	-1,077	$	-	$	-	$	-1,072
	Interest expense	$	441	$	85	$	54	$	-44	$	536
	Earnings (loss) before income taxes	$	4,388	$	-657	$	328	$	-	$	4,059
	Income tax expense	$	1,797	$	495	$	76	$	-	$	2,368
	Net earnings (loss)	$	2,591	$	-1,152	$	252	$	-	$	1,691
	Net earnings attributable to noncontrolling interests	$	1	$	-	$	83	$	-	$	84
	Net earnings (loss) attributable to Devon	$	2,590	$	-1,152	$	169	$	-	$	1,607
	Property and equipment, net	$	24,572	$	6,790	$	4,934	$	-	$	36,296
	Total assets	$	32,147	$	8,517	$	10,097	$	-124	$	50,637
	Capital expenditures	$	11,245	$	1,344	$	970	$	-	$	13,559
	Year Ended December 31, 2013:
	Revenues from external customers	$	6,807	$	2,656	$	934	$	-	$	10,397
	Intersegment revenues	$	-	$	-	$	1,362	$	-1,362	$	-
	Depreciation, depletion and amortization	$	1,744	$	849	$	187	$	-	$	2,780
	Asset impairments	$	1,133	$	843	$	-	$	-	$	1,976
	Interest expense	$	392	$	80	$	-	$	-35	$	437
	Earnings (loss) before income taxes	$	495	$	-532	$	186	$	-	$	149
	Income tax expense (benefit)	$	258	$	-156	$	67	$	-	$	169
	Net earnings (loss)	$	237	$	-376	$	119	$	-	$	-20
	Property and equipment, net	$	18,201	$	8,478	$	1,768	$	-	$	28,447
	Total assets	$	27,080	$	13,560	$	2,237	$	-	$	42,877
	Capital expenditures	$	4,589	$	1,841	$	213	$	-	$	6,643
	Year Ended December 31, 2012:
	Revenues from external customers	$	6,098	$	2,600	$	803	$	-	$	9,501
	Intersegment revenues	$	-	$	-	$	1,105	$	-1,105	$	-
	Depreciation, depletion and amortization	$	1,679	$	987	$	145	$	-	$	2,811
	Asset impairments	$	1,845	$	163	$	16	$	-	$	2,024
	Interest expense	$	343	$	82	$	-	$	-19	$	406
	Earnings (loss) before income taxes	$	-372	$	-73	$	128	$	-	$	-317
	Income tax expense (benefit)	$	-143	$	-35	$	46	$	-	$	-132
	Net earnings (loss)	$	-229	$	-38	$	82	$	-	$	-185
	Property and equipment, net	$	16,622	$	8,955	$	1,739	$	-	$	27,316
	Total assets	$	22,050	$	19,070	$	2,206	$	-	$	43,326
	Capital expenditures	$	6,159	$	1,963	$	352	$	-	$	8,474

Supplemental_Information_On_Oi

Supplemental Information On Oil And Gas Operations	12 Months Ended
	Dec. 31, 2014
Supplemental Information On Oil And Gas Operations [Abstract]
Supplemental Information On Oil And Gas Operations	22.Supplemental Information on Oil and Gas Operations (Unaudited)
	Supplemental unaudited information regarding Devon's oil and gas activities is presented in this note. The information is provided separately by country. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon's discontinued operations.
	Costs Incurred
	The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.
		Year Ended December 31, 2014
		U.S.		Canada		Total
		(In millions)
	Property acquisition costs:
	Proved properties	$	5,210	$	-	$	5,210
	Unproved properties		1,176		1		1,177
	Exploration costs		270		52		322
	Development costs		4,400		1,063		5,463
	Costs incurred	$	11,056	$	1,116	$	12,172
		Year Ended December 31, 2013
		U.S.		Canada		Total
		(In millions)
	Property acquisition costs:
	Proved properties	$	19	$	3	$	22
	Unproved properties		213		3		216
	Exploration costs		443		152		595
	Development costs		3,838		1,251		5,089
	Costs incurred	$	4,513	$	1,409	$	5,922
		Year Ended December 31, 2012
		U.S.		Canada		Total
		(In millions)
	Property acquisition costs:
	Proved properties	$	2	$	71	$	73
	Unproved properties		1,135		32		1,167
	Exploration costs		351		315		666
	Development costs		4,408		1,691		6,099
	Costs incurred	$	5,896	$	2,109	$	8,005
	Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations. The proceeds received from our joint venture transactions at closing have not been netted against the costs incurred. At December 31, 2014, our partners’ remaining commitments to fund our future costs associated with these joint venture transactions totaled approximately $250 million.
	Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $376 million,  $368 million and $359 million in the years 2014, 2013 and 2012, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $45 million, $42 million and $36 million in the years 2014, 2013 and 2012, respectively.
	Capitalized Costs
	The following tables reflect the aggregate capitalized costs related to oil and gas activities.
		31-Dec-14
		U.S.		Canada		Total
		(In millions)
	Proved properties	$	59,849	$	15,889	$	75,738
	Unproved properties		1,460		1,292		2,752
	Total oil & gas properties		61,309		17,181		78,490
	Accumulated DD&A		-38,213		-11,347		-49,560
	Net capitalized costs	$	23,096	$	5,834	$	28,930
		31-Dec-13
		U.S.		Canada		Total
		(In millions)
	Proved properties	$	51,366	$	22,629	$	73,995
	Unproved properties		1,277		1,514		2,791
	Total oil & gas properties		52,643		24,143		76,786
	Accumulated DD&A		-35,848		-16,613		-52,461
	Net capitalized costs	$	16,795	$	7,530	$	24,325
	The following is a summary of Devon's oil and gas properties not subject to amortization as of December 31, 2014.
		Costs Incurred In
		2014		2013		2012		Prior to 2012		Total
		(In millions)
	Acquisition costs	$	973	$	127	$	140	$	650	$	1,890
	Exploration costs		111		76		68		107		362
	Development costs		103		48		121		69		341
	Capitalized interest		43		38		30		48		159
	Total oil and gas properties not subject to amortization	$	1,230	$	289	$	359	$	874	$	2,752
	Included in the $2.8 billion of oil and gas properties not subject to amortization are approximately $2.2 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada and the Eagle Ford in Texas. Based on Devon’s development plans, Pike costs will begin to be included in the amortization computation when the first phase of this project is fully approved and Devon subsequently begins recognizing the associated proved reserves. Devon is evaluating and developing the newly acquired Eagle Ford properties over the next four to five years.
	Results of Operations
	The following tables include revenues and expenses associated with Devon's oil and gas producing activities. They do not include any allocation of Devon's interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon's oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
		31-Dec-14
	U.S.		Canada		Total
	(In millions)
Oil, gas and NGL sales	$	7,867	$	2,043	$	9,910
Lease operating expenses		-1,559		-773		-2,332
General and administrative expenses		-153		-57		-210
Production and property taxes		-466		-37		-503
Depreciation, depletion and amortization		-2,365		-531		-2,896
Gain on sale of assets		-		1,077		1,077
Accretion of asset retirement obligations		-49		-39		-88
Income tax expense		-1,199		-568		-1,767
Results of operations(1)	$	2,076	$	1,115	$	3,191
Depreciation, depletion and amortization per Boe	$	11.41	$	13.80	$	11.79
-1
In the fourth quarter of 2014, Devon recognized a $1.9 billion Canadian goodwill impairment that is not reflected in
this table.
	31-Dec-13
	U.S.		Canada		Total
	(In millions)
Oil, gas and NGL sales	$	5,964	$	2,558	$	8,522
Lease operating expenses		-1,257		-1,011		-2,268
General and administrative expenses		-125		-77		-202
Production and property taxes		-380		-59		-439
Depreciation, depletion and amortization		-1,640		-825		-2,465
Asset impairments		-1,110		-843		-1,953
Accretion of asset retirement obligations		-47		-64		-111
Income tax benefit (expense)		-510		88		-422
Results of operations	$	895	$	-233	$	662
Depreciation, depletion and amortization per Boe	$	8.69	$	12.87	$	9.75
	31-Dec-12
	U.S.		Canada		Total
	(In millions)
Oil, gas and NGL sales	$	4,679	$	2,474	$	7,153
Lease operating expenses		-1,059		-1,015		-2,074
General and administrative expenses		-159		-137		-296
Production and property taxes		-340		-55		-395
Depreciation, depletion and amortization		-1,563		-963		-2,526
Asset impairments		-1,793		-163		-1,956
Accretion of asset retirement obligations		-40		-69		-109
Income tax benefit (expense)		99		-3		96
Results of operations	$	-176	$	69	$	-107
Depreciation, depletion and amortization per Boe	$	8.55	$	14.41	$	10.12
Proved Reserves
The following tables present Devon’s estimated proved reserves by product by country.
	Oil (MMBbls)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		168		80		248
Revisions due to prices		-1		-5		-6
Revisions other than price		-6		-2		-8
Extensions and discoveries		65		7		72
Production		-21		-15		-36
31-Dec-12		205		65		270
Revisions due to prices		1		-1		-
Revisions other than price		-18		-		-18
Extensions and discoveries		69		7		76
Purchase of reserves		1		-		1
Production		-28		-15		-43
Sale of reserves		-1		-		-1
31-Dec-13		229		56		285
Revisions due to prices		-1		-		-1
Revisions other than price		-38		1		-37
Extensions and discoveries		94		5		99
Purchase of reserves		132		-		132
Production		-48		-10		-58
Sale of reserves		-17		-29		-46
31-Dec-14		351		23		374
Proved developed reserves as of:
31-Dec-11		146		73		219
31-Dec-12		166		62		228
31-Dec-13		194		56		250
31-Dec-14		255		23		278
Proved developed-producing reserves as of:
31-Dec-11		139		65		204
31-Dec-12		155		56		211
31-Dec-13		178		51		229
31-Dec-14		224		19		243
Proved undeveloped reserves as of:
31-Dec-11		22		7		29
31-Dec-12		39		3		42
31-Dec-13		35		-		35
31-Dec-14		96		-		96
	Bitumen (MMBbls)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		-		457		457
Revisions due to prices		-		14		14
Revisions other than price		-		7		7
Extensions and discoveries		-		67		67
Production		-		-17		-17
31-Dec-12		-		528		528
Revisions due to prices		-		-11		-11
Revisions other than price		-		16		16
Extensions and discoveries		-		38		38
Production		-		-19		-19
31-Dec-13		-		552		552
Revisions due to prices		-		-37		-37
Revisions other than price		-		18		18
Extensions and discoveries		-		8		8
Production		-		-20		-20
31-Dec-14		-		521		521
Proved developed reserves as of:
31-Dec-11		-		90		90
31-Dec-12		-		99		99
31-Dec-13		-		111		111
31-Dec-14		-		137		137
Proved developed-producing reserves as of:
31-Dec-11		-		90		90
31-Dec-12		-		99		99
31-Dec-13		-		111		111
31-Dec-14		-		137		137
Proved undeveloped reserves as of:
31-Dec-11		-		367		367
31-Dec-12		-		429		429
31-Dec-13		-		441		441
31-Dec-14		-		384		384
	Gas (Bcf)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		9,507		979		10,486
Revisions due to prices		-831		-99		-930
Revisions other than price		-287		-33		-320
Extensions and discoveries		1,124		34		1,158
Purchase of reserves		2		-		2
Production		-752		-186		-938
Sale of reserves		-1		-11		-12
31-Dec-12		8,762		684		9,446
Revisions due to prices		405		161		566
Revisions other than price		-299		67		-232
Extensions and discoveries		471		19		490
Purchase of reserves		1		-		1
Production		-709		-165		-874
Sale of reserves		-81		-8		-89
31-Dec-13		8,550		758		9,308
Revisions due to prices		191		45		236
Revisions other than price		-299		4		-295
Extensions and discoveries		335		8		343
Purchase of reserves		457		-		457
Production		-660		-41		-701
Sale of reserves		-923		-738		-1,661
31-Dec-14		7,651		36		7,687
Proved developed reserves as of:
31-Dec-11		7,957		951		8,908
31-Dec-12		7,391		679		8,070
31-Dec-13		7,707		752		8,459
31-Dec-14		6,948		36		6,984
Proved developed-producing reserves as of:
31-Dec-11		7,409		862		8,271
31-Dec-12		7,091		624		7,715
31-Dec-13		7,425		680		8,105
31-Dec-14		6,746		34		6,780
Proved undeveloped reserves as of:
31-Dec-11		1,550		28		1,578
31-Dec-12		1,371		5		1,376
31-Dec-13		843		6		849
31-Dec-14		703		-		703
	Natural Gas Liquids (MMBbls)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		525		27		552
Revisions due to prices		-19		-5		-24
Revisions other than price		-13		-		-13
Extensions and discoveries		114		2		116
Production		-36		-4		-40
31-Dec-12		571		20		591
Revisions due to prices		8		3		11
Revisions other than price		-50		3		-47
Extensions and discoveries		64		1		65
Production		-41		-4		-45
31-Dec-13		552		23		575
Revisions due to prices		7		1		8
Revisions other than price		2		-		2
Extensions and discoveries		47		-		47
Purchase of reserves		57		-		57
Production		-50		-1		-51
Sale of reserves		-37		-23		-60
31-Dec-14		578		-		578
Proved developed reserves as of:
31-Dec-11		402		26		428
31-Dec-12		431		20		451
31-Dec-13		468		23		491
31-Dec-14		486		-		486
Proved developed-producing reserves as of:
31-Dec-11		372		24		396
31-Dec-12		406		19		425
31-Dec-13		442		21		463
31-Dec-14		467		-		467
Proved undeveloped reserves as of:
31-Dec-11		123		1		124
31-Dec-12		140		-		140
31-Dec-13		84		-		84
31-Dec-14		92		-		92
	Total (MMBoe) (1)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		2,278		727		3,005
Revisions due to prices		-159		-12		-171
Revisions other than price		-67		-1		-68
Extensions and discoveries		367		82		449
Production		-183		-67		-250
Sale of reserves		-		-2		-2
31-Dec-12		2,236		727		2,963
Revisions due to prices		76		18		94
Revisions other than price		-117		29		-88
Extensions and discoveries		212		49		261
Purchase of reserves		1		-		1
Production		-189		-64		-253
Sale of reserves		-14		-1		-15
31-Dec-13		2,205		758		2,963
Revisions due to prices		38		-29		9
Revisions other than price		-86		21		-65
Extensions and discoveries		197		14		211
Purchase of reserves		265		-		265
Production		-207		-39		-246
Sale of reserves		-207		-176		-383
31-Dec-14		2,205		549		2,754
Proved developed reserves as of:
31-Dec-11		1,875		348		2,223
31-Dec-12		1,829		294		2,123
31-Dec-13		1,947		315		2,262
31-Dec-14		1,900		165		2,065
Proved developed-producing reserves as of:
31-Dec-11		1,746		323		2,069
31-Dec-12		1,743		278		2,021
31-Dec-13		1,857		297		2,154
31-Dec-14		1,815		162		1,977
Proved undeveloped reserves as of:
31-Dec-11		403		379		782
31-Dec-12		407		433		840
31-Dec-13		258		443		701
31-Dec-14		305		384		689
_______________________
(1)Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
Proved Undeveloped Reserves
The following table presents the changes in Devon’s total proved undeveloped reserves during 2014 (in MMBoe).
	U.S.		Canada		Total
Proved undeveloped reserves as of December 31, 2013		258		443		701
Extensions and discoveries		153		8		161
Revisions due to prices		-1		-34		-35
Revisions other than price		-61		18		-43
Sale of reserves		-4		-2		-6
Conversion to proved developed reserves		-40		-49		-89
Proved undeveloped reserves as of December 31, 2014		305		384		689
At December 31, 2014, Devon had 689 MMBoe of proved undeveloped reserves. This represents a 2 percent decrease as compared to 2013 and represents 25 percent of total proved reserves. Drilling and development activities increased Devon’s proved undeveloped reserves 161 MMBoe and resulted in the conversion of 89 MMBoe, or 13 percent, of the 2013 proved undeveloped reserves to proved developed reserves. Costs incurred related to the development and conversion of Devon’s proved undeveloped reserves were approximately $1.0 billion for 2014. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 43 MMBoe primarily due to evaluations of certain U.S. onshore dry-gas areas, which Devon does not expect to develop in the next five years. The largest revisions, which were approximately 69 MMBoe, relate to the dry-gas areas in the Barnett Shale in north Texas.
A significant amount of Devon’s proved undeveloped reserves at the end of 2014 related to its Jackfish operations. At December 31, 2014 and 2013, Devon’s Jackfish proved undeveloped reserves were 384 MMBoe and 441 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than 5 years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2031.
Price Revisions
2014 - Reserves increased 9 MMBoe primarily due to higher gas prices in the Barnett Shale and the Anadarko Basin, partially offset by higher bitumen prices, which result in lower after-royalty volumes, in Canada.
2013 - Reserves increased 94 MMBoe primarily due to higher gas prices. Of this increase, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area.
2012 - Reserves decreased 171 MMBoe primarily due to lower gas prices. Of this decrease, 100 MMBoe related to the Barnett Shale and 25 MMBoe related to the Rocky Mountain area.
Revisions Other Than Price
Total revisions other than price for 2014, 2013 and 2012 primarily related to Devon’s evaluation of certain dry gas regions, with the largest revisions being made in the Cana-Woodford Shale and Barnett Shale.
Extensions and Discoveries
2014 – Of the 211 MMBoe of extensions and discoveries, 70 MMBoe related to the Permian Basin in west Texas and southeast New Mexico, 54 MMBoe related to the Eagle Ford in south Texas, 36 MMBoe related to the Barnett Shale, 14 MMBoe related to the Anadarko Basin, 8 MMBoe related to Jackfish and 14 MMBoe related to the Mississippian-Woodford Trend in north Oklahoma.
The 2014 extensions and discoveries included 5 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 4 MMBoe at the Permian Basin.
2013 – Of the 261 MMBoe of extensions and discoveries, 76 MMBoe related to the Permian Basin, 54 MMBoe related to the Barnett Shale, 42 MMBoe related to the Anadarko Basin, 38 MMBoe related to Jackfish and 32 MMBoe related to the Mississippian-Woodford Trend.
The 2013 extensions and discoveries included 175 MMBoe related to additions from Devon’s infill drilling activities, including 23 MMBoe at the Cana-Woodford Shale, 54 MMBoe at the Barnett Shale, 38 MMBoe at Jackfish, 33 MMBoe at the Permian Basin and 20 MMBoe at the Mississippian-Woodford Trend.
2012 – Of the 449 MMBoe of extensions and discoveries, 151 MMBoe related to the Cana-Woodford Shale, 95 MMBoe related to the Barnett Shale, 72 MMBoe related to the Permian Basin, 67 MMBoe related to Jackfish, 16 MMBoe related to the Rocky Mountain area and 18 MMBoe related to the Granite Wash area.
The 2012 extensions and discoveries included 229 MMBoe related to additions from Devon’s infill drilling activities, including 134 MMBoe at the Cana-Woodford Shale and 82 MMBoe at the Barnett Shale.
Purchase of Reserves
2014 – Of the 265 MMBoe of reserves purchases, 246 MMBoe related to Devon’s GeoSouthern acquisition in the Eagle Ford.
Sale of Reserves
2014 – The total 383 MMBoe of reserves sales related to Devon’s asset divestitures in the U.S. and Canada.
Standardized Measure
The tables below reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.
	Year Ended December 31, 2014
	U.S.		Canada		Total
	(In millions)
Future cash inflows	$	75,847	$	31,371	$	107,218
Future costs:
Development		-7,168		-3,619		-10,787
Production		-29,740		-14,232		-43,972
Future income tax expense		-11,021		-3,026		-14,047
Future net cash flow		27,918		10,494		38,412
10% discount to reflect timing of cash flows		-12,819		-5,119		-17,938
Standardized measure of discounted future net cash flows	$	15,099	$	5,375	$	20,474
	Year Ended December 31, 2013
	U.S.		Canada		Total
	(In millions)
Future cash inflows	$	61,983	$	33,305	$	95,288
Future costs:
Development		-5,448		-5,308		-10,756
Production		-26,663		-15,709		-42,372
Future income tax expense		-9,046		-2,327		-11,373
Future net cash flow		20,826		9,961		30,787
10% discount to reflect timing of cash flows		-10,346		-4,700		-15,046
Standardized measure of discounted future net cash flows	$	10,480	$	5,261	$	15,741
	Year Ended December 31, 2012
	U.S.		Canada		Total
	(In millions)
Future cash inflows	$	55,297	$	33,570	$	88,867
Future costs:
Development		-6,556		-6,211		-12,767
Production		-24,265		-16,611		-40,876
Future income tax expense		-6,542		-1,992		-8,534
Future net cash flow		17,934		8,756		26,690
10% discount to reflect timing of cash flows		-9,036		-4,433		-13,469
Standardized measure of discounted future net cash flows	$	8,898	$	4,323	$	13,221
Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2014 estimates,  Devon’s future realized prices were assumed to be $87.14 per barrel of oil, $57.25 per barrel of bitumen, $3.94 per Mcf of gas and $25.05 per barrel of natural gas liquids. Of the $10.8 billion of future development costs as of the end of 2014,  $2.2 billion, $1.9 billion and $1.0 billion are estimated to be spent in 2015, 2016 and 2017, respectively.
Future development costs include not only development costs but also future asset retirement costs. Included as part of the $10.8 billion of future development costs are $1.5 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
	Year Ended December 31,
	2014		2013		2012
	(In millions)
Beginning balance	$	15,741	$	13,221	$	17,844
Net changes in prices and production costs		2,561		3,018		-9,889
Oil, bitumen, gas and NGL sales, net of production costs		-6,865		-5,613		-4,388
Changes in estimated future development costs		-768		399		-1,094
Extensions and discoveries, net of future development costs		4,836		4,047		4,669
Purchase of reserves		6,422		14		18
Sales of reserves in place		-2,384		-44		-25
Revisions of quantity estimates		-746		-1,040		162
Previously estimated development costs incurred during the period		1,933		1,986		1,321
Accretion of discount		1,746		1,940		1,420
Other, primarily changes in timing and foreign exchange rates		-107		-583		113
Net change in income taxes		-1,895		-1,604		3,070
Ending balance	$	20,474	$	15,741	$	13,221

Supplemental_Quarterly_Financi

Supplemental Quarterly Financial Information	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Supplemental Quarterly Financial Information (Unaudited)	23.Supplemental Quarterly Financial Information (Unaudited)
	Following is a summary of Devon’s unaudited interim results of operations.
		2014
		First		Second		Third		Fourth		Full
		Quarter		Quarter		Quarter		Quarter		Year
		(In millions, except per share amounts)
	Operating revenues	$	3,725	$	4,510	$	5,336	$	5,995	$	19,566
	Earnings (loss) before income taxes	$	560	$	1,554	$	1,654	$	291	$	4,059
	Net earnings (loss) attributable to Devon	$	324	$	675	$	1,016	$	-408	$	1,607
	Basic net earnings (loss) per share attributable to Devon	$	0.80	$	1.65	$	2.48	$	-1.01	$	3.93
	Diluted net earnings (loss) per share attributable to Devon	$	0.79	$	1.64	$	2.47	$	-1.01	$	3.91
		2013
		First		Second		Third		Fourth		Full
		Quarter		Quarter		Quarter		Quarter		Year
		(In millions, except per share amounts)
	Operating revenues	$	1,971	$	3,088	$	2,714	$	2,624	$	10,397
	Earnings (loss) before income taxes	$	-1,962	$	997	$	639	$	475	$	149
	Net earnings (loss) attributable to Devon	$	-1,339	$	683	$	429	$	207	$	-20
	Basic net earnings (loss) per share attributable to Devon	$	-3.34	$	1.69	$	1.06	$	0.51	$	-0.06
	Diluted net earnings (loss) per share attributable to Devon	$	-3.34	$	1.68	$	1.05	$	0.51	$	-0.06
	Net Earnings (Loss) Attributable to Devon
	The fourth quarter of 2014 includes asset impairments of $1.9 billion (or $4.79 per diluted share) as discussed in Note 5.
	The first quarter of 2013 includes U.S. and Canadian property and equipment impairments totaling $1.9 billion ($1.3 billion after income taxes, or $3.25 per diluted share).

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Principles Of Consolidation	Principles of Consolidation
	The accompanying consolidated financial statements include the accounts of Devon 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 Devon 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 Devon’s proportionate share of earnings, losses and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.
	As discussed more fully in Note 2, on March 7, 2014, Devon completed a business combination whereby Devon controls both EnLink Midstream Partners, LP (“EnLink”) and its general partner entity, EnLink Midstream, LLC (the “General Partner”). Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.
Use Of Estimates	Use of Estimates
	The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
	• proved reserves and related present value of future net revenues;
	• the carrying value of oil and gas properties and midstream assets;
	• derivative financial instruments;
	• the fair value of reporting units and related assessment of goodwill for impairment;
	• the fair value of intangible assets other than goodwill;
	• income taxes;
	• asset retirement obligations;
	• obligations related to employee pension and postretirement benefits; and
	• legal and environmental risks and exposures.
Revenue Recognition And Gas Balancing	Revenue Recognition and Gas Balancing
	Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings.
	Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is measured based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells' reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
	Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
	During 2014, 2013 and 2012, no purchaser accounted for more than 10 percent of Devon’s operating revenues from continuing operations.
Derivative Financial Instruments	Derivative Financial Instruments
	Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.
	Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon, through EnLink, periodically enters into derivative financial instruments with respect to a portion of EnLink’s oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments typically include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.
	Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.
	All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2014, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon's derivative financial instruments are also recorded in earnings.
	By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon's policy to enter into derivative contracts only with investment-grade-rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon's derivative contracts generally require cash collateral to be posted if either its or the counterparty's credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. As of December 31, 2014, Devon held $524 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying consolidated balance sheet.
General And Administrative Expenses	General and Administrative Expenses
	General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Share Based Compensation	Share-Based Compensation
	Independent of EnLink, Devon grants share-based awards to independent members of its Board of Directors and selected employees. EnLink and its General Partner also grant share-based awards to independent members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated comprehensive statements of earnings.
	Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase.
Income Taxes	Income Taxes
	Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
	Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
	Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
Net Earnings (Loss) Per Share Attributable To Devon	Net Earnings (Loss) Per Share Attributable to Devon
	Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.
Cash And Cash Equivalents	Cash and Cash Equivalents
	Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
Investments	Investments
	Devon periodically invests excess cash in United States and Canadian treasury securities and other marketable securities. Devon considers securities with original contractual maturities in excess of three months but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.
	Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. At December 31, 2013, such debt securities totaled $62 million and are included in other long-term assets in the accompanying consolidated balance sheet. Devon redeemed all these securities in the first quarter of 2014.
Property And Equipment	Property and Equipment
	Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
	Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
	Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to four years.
	No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
	Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties.
	Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon's derivative contracts held during the three-year period ended December 31, 2014 qualified for hedge accounting treatment.
	Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
	Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
	Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Goodwill	Goodwill
	Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon's reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
	Devon performed annual impairment tests of goodwill in the fourth quarters of 2014, 2013 and 2012. No impairment of goodwill was required in 2012 and 2013. However, based on the 2014 assessment, Devon’s Canadian reporting unit goodwill was deemed impaired. See Note 12 for further discussion.
Intangible Assets	Intangible Assets
	Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years.
Commitments And Contingencies	Commitments and Contingencies
	Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon's accounting policy for property and equipment.
Fair Value Measurements	Fair Value Measurements
	Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:
		·	Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
		·	Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.
		·	Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.
Discontinued Operations	Discontinued Operations
	All amounts related to Devon's International operations that were sold in 2012 are classified as discontinued operations.
Foreign Currency Translation Adjustments	Foreign Currency Translation Adjustments
	The United States dollar is the functional currency for Devon's consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to United States dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders' equity.
Noncontrolling Interests	Noncontrolling Interests
	Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.
Recently Issued Accounting Standards Not Yet Adopted	Recently Issued Accounting Standards Not Yet Adopted
	In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606). The update provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The update is effective for Devon beginning on January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. Devon has not yet selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

Acquisitions_And_Divestitures_

Acquisitions And Divestitures (Tables)	12 Months Ended
	Dec. 31, 2014
Business Acquisition [Line Items]
Schedule Of Operating Revenue And Net Earnings For General Partner And GeoSouthern
		Year Ended December 31, 2014
		GeoSouthern			EnLink
		(In millions)
	Total operating revenues	$	1,873		$	2,509
	Total operating expenses		960			2,464
	Operating income	$	913		$	45
Schedule Of Unaudited Proforma Information For General Partner And GeoSouthern
		Year Ended December 31,
		2014			2013
		(In millions)
	Total operating revenues	$	20,213		$	12,979
	Net earnings	$	1,716		$	35
	Noncontrolling interests	$	97		$	45
	Net earnings (loss) attributable to Devon	$	1,619		$	-10
	Net earnings (loss) per common share attributable to Devon	$	3.94		$	-0.02
General Partner And Enlink [Member]
Business Acquisition [Line Items]
Schedule Of Purchase Price Allocation
	Crosstex Energy, Inc. outstanding common shares:
	Held by public shareholders		48.0
	Restricted shares		0.4
	Total subject to conversion		48.4
	Exchange ratio		1.0	x
	Converted shares		48.4
	Crosstex Energy, Inc. common share price (1)	$	37.60
	Crosstex Energy, Inc. consideration	$	1,823
	Fair value of noncontrolling interest in E2 (2)		18
	Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests	$	1,841
	Crosstex Energy, LP outstanding units:
	Common units held by public unitholders		75.1
	Preferred units held by third party (3)		17.1
	Restricted units		0.4
	Total		92.6
	Crosstex Energy, LP common unit price (4)	$	30.51
	Crosstex Energy, LP common units value	$	2,825
	Crosstex Energy, LP outstanding unit options value	$	4
	Total fair value of noncontrolling interests in the Crosstex Energy, LP (4)		2,829
	Total consideration and fair value of noncontrolling interests	$	4,670
	__________________________
	(1) The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014.
	(2) Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2 Energy Services, LLC and E2 Appalachian Compression, LLC (collectively “E2”).
	(3) Crosstex Energy, LP converted the preferred units to common units in February 2014.
	(4) The final purchase price is based on the fair value of Crosstex Energy, LP’s common units as of the closing date, March 7, 2014.
General Partner [Member]
Business Acquisition [Line Items]
Schedule Of Purchase Price Allocation
	Assets acquired:
	Current assets	$	437
	Property, plant and equipment, net		2,438
	Intangible assets		569
	Equity investment		222
	Goodwill (1)		3,283
	Other long-term assets		1
	Liabilities assumed:
	Current liabilities		-515
	Long-term debt		-1,454
	Deferred income taxes		-210
	Other long-term liabilities		-101
	Total consideration and fair value of noncontrolling interests	$	4,670
	__________________________
	(1)  Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.
GeoSouthern Intermediate Holdings, LLC [Member]
Business Acquisition [Line Items]
Schedule Of Purchase Price Allocation
	Cash and cash equivalents	$	95
	Other current assets		256
	Proved properties		5,026
	Unproved properties		1,007
	Midstream assets		86
	Current liabilities		-434
	Long-term liabilities		-6
	Net assets acquired	$	6,030

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative [Line Items]
Schedule of Derivative Financial Instruments Included In the Consolidating Comprehensive Statements of Earnings
			Comprehensive Statements of		Year Ended
					December 31,
			Earnings Caption		2014			2013			2012
					(In millions)
	Oil, gas and NGL commodity derivatives		Oil, gas and NGL derivatives		$	1,989		$	-191		$	693
	Midstream commodity derivatives		Marketing and midstream revenues			22			-			-
	Interest rate derivatives		Other nonoperating items			-1			-			-15
	Foreign currency derivatives		Other nonoperating items			60			56			-18
	Net gains (losses) recognized in comprehensive statements of earnings				$	2,070		$	-135		$	660
Schedule of Derivative Financial Instruments Included in Consolidating Balance Sheets
					December 31,
			Balance Sheet Caption		2014			2013
					(In millions)
	Asset derivatives:
	Oil, gas and NGL commodity derivatives		Derivatives, at fair value		$	1,967		$	75
	Oil, gas and NGL commodity derivatives		Other long-term assets			1			28
	Midstream commodity derivatives		Derivatives, at fair value			17			-
	Midstream commodity derivatives		Other long-term assets			10			-
	Interest rate derivatives		Derivatives, at fair value			1			-
	Foreign currency derivatives		Derivatives, at fair value			8			-
	Total asset derivatives				$	2,004		$	103
	Liability derivatives:
	Oil, gas and NGL commodity derivatives		Other current liabilities		$	25		$	58
	Oil, gas and NGL commodity derivatives		Other long-term liabilities			26			62
	Midstream commodity derivatives		Other current liabilities			3			-
	Midstream commodity derivatives		Other long-term liabilities			2			-
	Interest rate derivatives		Other current liabilities			1			-
	Foreign currency derivatives		Other current liabilities			-			1
	Total liability derivatives				$	57		$	121
Open Oil Derivative Positions [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions			Price Swaps					Price Collars							Call Options Sold
	Period		Volume (Bbls/d)		Weighted Average Price ($/Bbl)			Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)			Weighted Average Ceiling Price ($/Bbl)		Volume (Bbls/d)	Weighted Average Price ($/Bbl)
	Q1-Q4 2015		107,203		$	91.07		31,500		$	89.67		$	97.84	28,000	$	116.43
	Q1-Q4 2016		-		$	-		-		$	-		$	-	18,500	$	103.11
			Oil Basis Swaps
	Period		Index		Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
	Q1-Q4 2015		Western Canadian Select		22,514		$	-18.35
	Q1-Q4 2015		West Texas Sour		8,000		$	-3.68
	Q1-Q4 2015		Midland Sweet		14,247		$	-2.92
Open Natural Gas Derivative Positions [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions
			Price Swaps					Price Collars							Call Options Sold
	Period		Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)			Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)			Weighted Average Ceiling Price ($/MMBtu)		Volume (MMBtu/d)	Weighted Average Price ($/MMBtu)
	Q1-Q4 2015		250,000		$	4.32		328,452		$	4.05		$	4.36	550,000	$	5.09
	Q1-Q4 2016		-		$	-		-		$	-		$	-	400,000	$	5
			Natural Gas Basis Swaps
	Period		Index		Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
	Q1-Q4 2015		Panhandle Eastern Pipe Line		100,000		$	-0.28
	Q1-Q4 2015		El Paso Natural Gas		70,000		$	-0.11
	Q1-Q4 2015		Houston Ship Channel		200,000		$	0.01
	Q1-Q4 2016		Panhandle Eastern Pipe Line		30,000		$	-0.33
	Q1-Q4 2016		El Paso Natural Gas		15,000		$	-0.13
	Q1-Q4 2016		Houston Ship Channel		30,000		$	0.11
Gas Processing and Fractionation Open Position [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions
	Period		Product		Volume				Weighted Average Price Paid			Weighted Average Price Received
	Q1 2015-Q4 2016		Ethane		1,168	MBbls			Index		$	0.29/gal
	Q1 2015-Q4 2016		Propane		1,171	MBbls			Index		$	1.01/gal
	Q1-Q4 2015		Normal Butane		53	MBbls			Index		$	1.14/gal
	Q1-Q4 2015		Natural Gasoline		44	MBbls			Index		$	1.81/gal
	Q1-Q4 2015		Natural Gas		1,225	MMBtu/d		$	4.08/MMBtu			Index
Interest Rate Derivatives [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions
	Notional			Rate Received		Rate Paid		Expiration
	(In millions)
	$	100		Three Month LIBOR		0.92%		Dec-16
	$	100		1.76%		Three Month LIBOR		Jan-19
Foreign Currency Derivatives [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions
	Forward Contract
	Currency		Contract Type		CAD Notional			Weighted Average Fixed Rate Received		Expiration
					(In millions)			(CAD-USD)
	Canadian Dollar		Sell		$	1,884		0.864		Mar-15

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation [Abstract]
Schedule Of The Effects Of Share-Based Compensation Included In The Consolidated Comprehensive Statements Of Earnings
			Year Ended December 31,
			2014			2013			2012
			(In millions)
	Gross general and administrative expense		$	199		$	157		$	179
	Share-based compensation expense capitalized pursuant to the
	full cost method of accounting for oil and gas properties		$	53		$	60		$	56
	Related income tax benefit		$	30		$	23		$	34
Summary Of the Grant-Date Fair Values Of Stock Options Granted And Their Related Assumptions, Represented By The Weighted-Average Amounts
			2012
	Grant-date fair value		$	22.20
	Volatility factor			42.5%
	Dividend yield			1.2%
	Risk-free interest rate			1.1%
	Expected term (in years)			6.0
Summary Of Outstanding Stock Options, Including Changes During The Year
							Weighted Average
				Options		Exercise Price				Remaining Term		Intrinsic Value
				(In thousands)						(In years)		(In millions)
	Outstanding at December 31, 2013			6,446		$	69.35
	Granted			-		$	-
	Exercised			-1,417		$	65.55
	Expired			-528		$	70.64
	Forfeited			-283		$	67.86
	Outstanding at December 31, 2014			4,218		$	70.56			3.11		$	1
	Vested and expected to vest at December 31, 2014			4,201		$	70.57			3.10		$	1
	Exercisable at December 31, 2014			3,969		$	70.80			3.00		$	1
Summary of Unvested Restricted Stock Awards And Units, Including Changes During the Year
				Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
				(In thousands)
	Unvested at December 31, 2013			3,292		$	59.76
	Granted			3,487		$	62.75
	Vested			-1,767		$	60.23
	Forfeited			-708		$	60.47
	Unvested at December 31, 2014			4,304		$	60.85
Summary Of Unvested Performance Stock Awards, Including Changes During The Year
				Performance Restricted Stock Awards		Weighted Average Grant-Date Fair Value
				(In thousands)
	Unvested at December 31, 2013			316		$	56.25
	Granted			234		$	61.33
	Vested			-170		$	56.18
	Unvested at December 31, 2014			380		$	59.41
Summary Of Performance-Based Share Units Grant-Date Fair Values And Their Related Assumptions
		2014						2013						2012
	Grant-date fair value	$	70.18	-	$	81.05		$	61.27	-	$	63.48		$	61.27	-	$	63.48
	Risk-free interest rate	0.54%							0.26%	-		0.36%			0.26%	-		0.36%
	Volatility factor	28.80%						30.30%						30.30%
	Contractual term (in years)	2.89						3						3
Summary of Performance Share Units, Including Changes During the Year
				Performance Share Units		Weighted Average Grant-Date Fair Value
				(In thousands)
	Unvested at December 31, 2013			925		$	66.64
	Granted			708		$	77.77
	Forfeited			-156		$	76.59
	Unvested at December 31, 2014 (1)			1,477		$	70.90
	____________________________
		-1		A maximum of 3.0 million common shares could be awarded based upon Devon’s final TSR ranking.

Asset_Impairments_Tables

Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Impairments [Abstract]
Schedule Of Asset Impairments
		Year Ended December 31, 2014				Year Ended December 31, 2013				Year Ended December 31, 2012
		Gross		Net of Taxes		Gross		Net of Taxes		Gross		Net of Taxes
		(In millions)
	Goodwill	$	1,941	$	1,941	$	-	$	-	$	-	$	-
	U.S. oil and gas assets		-		-		1,110		707		1,793		1,142
	Canada oil and gas assets		-		-		843		632		163		122
	Midstream assets		12		7		23		14		68		44
	Asset impairments	$	1,953	$	1,948	$	1,976	$	1,353	$	2,024	$	1,308

Restructuring_Costs_Tables

Restructuring Costs (Tables)	12 Months Ended
	Dec. 31, 2014
Restructuring Costs [Abstract]
Schedule Of The Components Of Restructuring Costs Included In The Consolidated Comprehensive Statements Of Earnings
		Year Ended December 31,
		2014			2013			2012
		(In millions)
	Canada divestitures:
	Employee severance and retention	$	42		$	-		$	-
	Lease obligations and other		4			-			-
	Office consolidation:
	Employee severance and retention		-			13			77
	Lease obligations and other		-			41			3
	Offshore divestiture:
	Employee severance and retention		-			-			-3
	Lease obligations and other		-			-			-3
	Restructuring costs	$	46		$	54		$	74
Schedule Of The Activity And Balances Associated With Restructuring Liabilities
			Other			Other
			Current			Long-term
			Liabilities			Liabilities			Total
			(In millions)
	Balance as of December 31, 2012		$	52		$	9		$	61
	Changes due to office consolidation			-22			11			-11
	Changes due to offshore divestiture			-3			-2			-5
	Balance as of December 31, 2013			27			18			45
	Changes due to Canadian divestitures			4			-			4
	Changes due to office consolidation			-15			-10			-25
	Changes due to offshore divestiture			-3			-1			-4
	Balance as of December 31, 2014		$	13		$	7		$	20

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Schedule Of Income Tax Expense (Benefit)
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	Current income tax expense (benefit):
	U.S. federal	$	152	$	73	$	60
	Various states		18		-5		-3
	Canada and various provinces		307		4		-5
	Total current tax expense (benefit)		477		72		52
	Deferred income tax expense (benefit):
	U.S. federal		1,610		198		-188
	Various states		93		59		34
	Canada and various provinces		188		-160		-30
	Total deferred tax expense (benefit)		1,891		97		-184
	Total income tax expense (benefit)	$	2,368	$	169	$	-132
Schedule Of Effective Income Tax Reconciliation
		Year Ended December 31,
		2014		2013		2012
	Total income tax expense (benefit) (in millions)	$	2,368	$	169	$	-132
	U.S. statutory income tax rate		35%		35%		-35%
	Non-deductible goodwill transactions		23%		0%		0%
	Taxation on Canadian operations		-4%		9%		-6%
	State income taxes		2%		23%		6%
	Repatriations		2%		65%		0%
	Taxes on EnLink formation		1%		0%		0%
	Other		-1%		-19%		-7%
	Effective income tax rate		58%		113%		-42%
Schedule Of Deferred Tax Assets And Liabilities
		December 31,
		2014		2013
	Deferred tax assets:	(In millions)
	Asset retirement obligations	$	458	$	673
	Foreign tax credits		-		248
	Net operating loss carryforwards		200		183
	Alternative minimum tax credits		57		105
	Pension benefit obligations		113		104
	Other		273		163
	Total deferred tax assets		1,101		1,476
	Deferred tax liabilities:
	Property and equipment		-6,940		-5,895
	Long-term debt		-115		-161
	Taxes on unremitted foreign earnings		-6		-157
	Fair value of financial instruments		-699		-7
	Other		-154		-52
	Total deferred tax liabilities		-7,914		-6,272
	Net deferred tax liability	$	-6,813	$	-4,796
Schedule Of Changes In Unrecognized Tax Benefits
		December 31,
		2014		2013
		(In millions)
	Balance at beginning of year	$	243	$	216
	Tax positions taken in prior periods		-		-17
	Tax positions taken in current year		-		42
	Accrual of interest related to tax positions taken		2		5
	Foreign currency translation		-4		-3
	Balance at end of year	$	241	$	243
Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities
	Jurisdiction	Tax Years Open
	U.S. Federal	2008-2014
	Various U.S. states	2008-2014
	Canada Federal	2004-2014
	Various Canadian provinces	2004-2014

Net_Earnings_Loss_Per_Share_At1

Net Earnings (Loss) Per Share Attributable To Devon (Tables)	12 Months Ended
	Dec. 31, 2014
Net earnings (loss) per share attributable to Devon:
Earnings (Loss) Per Share Computations
				Common		Earnings (loss)
		Earnings (loss)		Shares		per  Share
		(In millions, except per share amounts)
	Year Ended December 31, 2014:
	Net earnings attributable to Devon	$	1,607		409
	Attributable to participating securities		-17		-4
	Basic net earnings per share		1,590		405	$	3.93
	Dilutive effect of potential common shares issuable		-		2
	Diluted net earnings per share	$	1,590		407	$	3.91
	Year Ended December 31, 2013:
	Net loss attributable to Devon	$	-20		406
	Attributable to participating securities		-2		-4
	Basic net loss per share		-22		402	$	-0.06
	Dilutive effect of potential common shares issuable		-		-
	Diluted net loss per share	$	-22		402	$	-0.06
	Year Ended December 31, 2012:
	Net loss attributable to Devon	$	-206		404
	Attributable to participating securities		-3		-4
	Basic net loss per share		-209		400	$	-0.52
	Dilutive effect of potential common shares issuable		-		-
	Diluted net loss per share	$	-209		400	$	-0.52

Other_Comprehensive_Earnings_T

Other Comprehensive Earnings (Tables)	12 Months Ended
	Dec. 31, 2014
Other Comprehensive Earnings [Abstract]
Components Of Other Comprehensive Earnings
		Year Ended December 31,
		2014			2013		2012
		(In millions)
	Foreign currency translation:
	Beginning accumulated foreign currency translation	$	1,448		$	1,996	$	1,802
	Change in cumulative translation adjustment		-499			-574		203
	Income tax benefit (expense)		34			26		-9
	Ending accumulated foreign currency translation		983			1,448		1,996
	Pension and postretirement benefit plans:
	Beginning accumulated pension and postretirement benefits		-180			-225		-227
	Net actuarial gain (loss) and prior service cost arising in current year		-57			48		-47
	Recognition of net actuarial loss and prior service cost in earnings (1)		20			24		51
	Income tax benefit (expense)		13			-27		-2
	Ending accumulated pension and postretirement benefits		-204			-180		-225
	Accumulated other comprehensive earnings, net of tax	$	779		$	1,268	$	1,771
	____________________________
		-1		These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying consolidated comprehensive statements of earnings (see Note 15 note for additional details).

Supplemental_Information_To_St1

Supplemental Information To Statements Of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Information To Statements Of Cash Flows [Abstract]
Schedule Of Supplemental To Cash Flow Information
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	Net change in working capital accounts:
	Accounts receivable	$	128	$	-288	$	140
	Income taxes receivable		-467		29		-55
	Other current assets		-222		20		-73
	Accounts payable		-68		26		-8
	Revenues and royalties payable		133		35		19
	Other current liabilities		546		-120		-73
	Net change in working capital	$	50	$	-298	$	-50
	Interest paid (net of capitalized interest)	$	514	$	406	$	334
	Income taxes paid	$	899	$	13	$	100

Accounts_Receivable_Tables

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2014
Accounts Receivable [Abstract]
Schedule Of Components Of Accounts Receivable
		31-Dec-14		31-Dec-13
		(In millions)
	Oil, gas and NGL sales	$	723	$	851
	Joint interest billings		475		447
	Marketing and midstream revenues		706		172
	Other		71		61
	Gross accounts receivable		1,975		1,531
	Allowance for doubtful accounts		-16		-11
	Net accounts receivable	$	1,959	$	1,520

Goodwill_And_Other_Intangible_1

Goodwill And Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule Of Goodwill By Reporting Segment
		U.S.		Canada		EnLink		Total
		(In millions)
	Balance as of December 31, 2012	$	2,644	$	3,033	$	402	$	6,079
	Asset divestitures		-26		-		-		-26
	Foreign currency translation adjustments		-		-195		-		-195
	Balance as of December 31, 2013	$	2,618	$	2,838	$	402	$	5,858
	Acquired during period		-		-		3,283		3,283
	Asset divestitures		-		-706		-		-706
	Impairment		-		-1,941		-		-1,941
	Foreign currency translation adjustments		-		-191		-		-191
	Balance as of December 31, 2014	$	2,618	$	-	$	3,685	$	6,303
Schedule Of Estimated Future Amortization Expense
	Year	Amortization Amount
			(In millions)
	2015	$	45
	2016	$	45
	2017	$	45
	2018	$	45
	2019	$	44
General Partner And Enlink [Member]
Schedule Of Goodwill By Reporting Segment
			Texas		Louisiana		Oklahoma		Ohio River Valley		General Partner		Total
		(In millions)
	Balance as of December 31, 2013	$	326	$	-	$	76	$	-	$	-	$	402
	Acquired during period		842		787		114		113		1,427		3,283
	Balance as of December 31, 2014	$	1,168	$	787	$	190	$	113	$	1,427	$	3,685

Debt_And_Related_Expenses_Tabl

Debt And Related Expenses (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Instrument [Line Items]
Schedule Of Debt Instruments
		31-Dec-14		31-Dec-13
		(In millions)
	Devon debt
	Commercial paper	$	932	$	1,317
	5.625% due January 15, 2014		-		500
	Floating rate due December 15, 2015		500		500
	2.40% due July 15, 2016		-		500
	Floating rate due December 15, 2016		350		350
	1.20% due December 15, 2016		-		650
	1.875% due May 15, 2017		-		750
	8.25% due July 1, 2018		125		125
	2.25% due December 15, 2018		750		750
	6.30% due January 15, 2019		700		700
	4.00% due July 15, 2021		500		500
	3.25% due May 15, 2022		1,000		1,000
	7.50% due September 15, 2027		150		150
	7.875% due September 30, 2031		1,250		1,250
	7.95% due April 15, 2032		1,000		1,000
	5.60% due July 15, 2041		1,250		1,250
	4.75% due May 15, 2042		750		750
	Net discount on debentures and notes		-18		-20
	Total Devon debt		9,239		12,022
	EnLink debt
	Credit facilities		237		-
	2.70% due April 1, 2019		400		-
	7.125% due June 1, 2022		163		-
	4.40% due April 1, 2024		550		-
	5.60% due April 1, 2044		350		-
	5.05% due April 1, 2045		300
	Net premium on debentures and notes		23		-
	Total EnLink debt		2,023		-
	Total debt		11,262		12,022
	Less amount classified as short-term debt (1)		1,432		4,066
	Total long-term debt	$	9,830	$	7,956
	__________________________
	2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015. 2013 short-term debt consists of $2.25 billion of senior notes issued in conjunction with the GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014.
Schedule of Debt Maturities
	2015	$	1,432
	2016		350
	2017		-
	2018		875
	2019		1,337
	2020 and thereafter		7,263
	Total	$	11,257
Schedule Of Debt Assumed Upon Acquisition Of Business
		Fair Value of Debt Assumed		Effective Rate of Debt Assumed
	Debt Assumed		(In millions)
	8.250% due July 2018 (principal of $125 million)	$	147		5.5%
	7.500% due September 2027 (principal of $150 million)	$	169		6.5%
Schedule Of Fair Value Of Enlink's Debt		March 7, 2014 Fair Value		Effective
		of Debt		Rate of Debt
		(In millions)
	8.875% due February 15, 2018 (principal of $725 million) (1)	$	760	7.70%
	7.125% due June 1, 2022 (principal of $197 million)		226	5.30%
	Credit facilities		468
	Total long-term debt	$	1,454
	__________________________
	(1)  The 2018 senior notes were redeemed on April 18, 2014.
Schedule Of Net Financing Cost Components
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	Interest based on debt outstanding	$	546	$	466	$	440
	Early retirement of debt		48		-		-
	Capitalized interest		-70		-56		-48
	Other fees and expenses		12		27		14
	Interest expense		536		437		406
	Interest income		-10		-20		-36
	Net financing costs	$	526	$	417	$	370
Other Debentures And Notes [Member]
Debt Instrument [Line Items]
Schedule Of Debt Instruments
		Date Issued
		May-12		Jul-11		Jan-09		Mar-02
	1.875% due May 15, 2017 (1)	$	750	$	-	$	-	$	-
	3.25% due May 15, 2022		1,000		-		-		-
	4.75% due May 15, 2042		750		-		-		-
	2.40% due July 15, 2016 (1)		-		500		-		-
	4.00% due July 15, 2021		-		500		-		-
	5.60% due July 15, 2041		-		1,250		-		-
	5.625% due January 15, 2014 (2)		-		-		500		-
	6.30% due January 15, 2019		-		-		700		-
	7.95% due April 15, 2032		-		-		-		1,000
	Discount and issuance costs		-35		-29		-13		-14
	Net proceeds	$	2,465	$	2,221	$	1,187	$	986
	__________________________
	(1)  The 1.875% $750 million note due May 15, 2017 and 2.4% $500 million note due July 15, 2016 were redeemed on November 13, 2014.
	(2) The 5.625% $500 million note due January 15, 2014 was redeemed upon maturity.
GeoSouthern Intermediate Holdings, LLC [Member]
Debt Instrument [Line Items]
Schedule Of Debt Instruments
	Floating rate due December 15, 2015	$	500
	Floating rate due December 15, 2016		350
	1.20% due December 15, 2016 (1)		650
	2.25% due December 15, 2018		750
	Discount and issuance costs		-2
	Net proceeds	$	2,248
	__________________________
	(1)  The 1.20% $650 million note due December 15, 2016 was redeemed on November 13, 2014.

Asset_Retirement_Obligations_T

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule Of Changes In Defined Benefit Plan Obligations
		Pension Benefits				Postretirement Benefits
		2014		2013		2014		2013
		(In millions)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	1,177	$	1,360	$	24	$	34
	Service cost		30		36		1		1
	Interest cost		55		51		1		1
	Actuarial loss (gain)		203		-158		-		-3
	Plan amendments		-		2		-		-8
	Plan settlements		-4		-		-		-
	Foreign exchange rate changes		-3		-2		-		-
	Participant contributions		-		-		2		3
	Benefits paid		-81		-112		-4		-4
	Benefit obligation at end of year		1,377		1,177		24		24
	Change in plan assets:
	Fair value of plan assets at beginning of year		1,006		1,165		-		-
	Actual return on plan assets		200		-57		-		-
	Employer contributions		29		11		2		1
	Participant contributions		-		-		2		3
	Plan settlements		-4		-		-		-
	Benefits paid		-81		-112		-4		-4
	Foreign exchange rate changes		-1		-1		-		-
	Fair value of plan assets at end of year		1,149		1,006		-		-
	Funded status at end of year	$	-228	$	-171	$	-24	$	-24
	Amounts recognized in balance sheet:
	Other long-term assets	$	22	$	47	$	-	$	-
	Other current liabilities		-10		-12		-3		-3
	Other long-term liabilities		-240		-206		-21		-21
	Net amount	$	-228	$	-171	$	-24	$	-24
	Amounts recognized in accumulated other comprehensive earnings:
	Net actuarial loss (gain)	$	317	$	279	$	-11	$	-13
	Prior service cost (credit)		19		23		-9		-11
	Total	$	336	$	302	$	-20	$	-24
Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets
		December 31,
		2014		2013
		(In millions)
	Projected benefit obligation	$	250	$	218
	Accumulated benefit obligation	$	191	$	179
	Fair value of plan assets	$	-	$	-
Schedule Of Net Periodic Benefit Cost And Other Comprehensive Income For Pension And Other Postretirement Benefit Plans
		Pension Benefits						Postretirement Benefits
		2014		2013		2012		2014		2013		2012
		(In millions)
	Net periodic benefit cost:
	Service cost	$	30	$	36	$	43	$	1	$	1	$	1
	Interest cost		55		51		60		1		1		1
	Expected return on plan assets		-54		-62		-64		-		-		-
	Curtailment and settlement expense		1		-		26		-		-		1
	Recognition of net actuarial loss (gain) (1)		18		22		24		-1		-1		-1
	Recognition of prior service cost (1)		4		4		3		-2		-1		-1
	Total net periodic benefit cost (2)		54		51		92		-1		-		1
	Other comprehensive loss (earnings):
	Actuarial loss (gain) arising in current year		57		-39		37		-		-3		-4
	Prior service cost (credit) arising in current year		-		2		14		-		-8		-
	Recognition of net actuarial loss, including settlement
	expense, in net periodic benefit cost		-19		-22		-45		1		1		1
	Recognition of prior service cost, including curtailment,
	in net periodic benefit cost		-4		-4		-8		2		1		1
	Total other comprehensive loss (earnings)		34		-63		-2		3		-9		-2
	Total recognized	$	88	$	-12	$	90	$	2	$	-9	$	-1
	__________________________
	(1)  These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
	(2)  Net periodic benefit cost is a component of general and administrative expenses on the accompanying consolidated comprehensive statements of earnings.
Schedule Of Estimated Net Actuarial Loss And Prior Service Cost For The Pension And Other Postretirement Plans That Will Be Amortized From Accumulated Other Comprehensive Income Into Net Periodic Benefit Cost During 2015
		Pension Benefits		Postretirement Benefits
		(In millions)
	Net actuarial loss (gain)	$	21	$	-1
	Prior service cost (credit)		4		-2
	Total	$	25	$	-3
Schedule Of Weighted Average Actuarial Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Costs
		Pension Benefits						Postretirement Benefits
		2014		2013		2012		2014		2013		2012
	Assumptions to determine benefit obligations:
	Discount rate		3.90%		4.80%		3.85%		3.25%		3.65%		3.30%
	Rate of compensation increase		4.49%		4.48%		4.48%		N/A		N/A		N/A
	Assumptions to determine net periodic benefit cost:
	Discount rate		4.80%		3.85%		4.65%		3.65%		3.30%		4.25%
	Rate of compensation increase		4.49%		4.48%		4.97%		N/A		N/A		N/A
	Expected return on plan assets		5.42%		5.48%		5.48%		N/A		N/A		N/A
Schedule Of Fair Value of Pension Assets By Asset Class
		As of December 31, 2014
						Fair Value Measurements Using:
		Actual Allocation		Total		Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
		(In millions)
	Fixed-income securities:
	U.S. Treasury obligations		35.2%	$	405	$	50	$	355	$	-
	Corporate bonds		31.7%		364		269		95		-
	Other bonds		2.6%		30		30		-		-
	Total fixed-income securities		69.5%		799		349		450		-
	Equity securities:
	Global (large, mid, small cap)		17.2%		197		-		197		-
	Other securities:
	Hedge fund and alternative investments		9.7%		112		-		-		112
	Short-term investments		3.6%		41		15		26		-
	Total other securities		13.3%		153		15		26		112
	Total investments		100.0%	$	1,149	$	364	$	673	$	112
		As of December 31, 2013
						Fair Value Measurements Using:
		Actual Allocation		Total		Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
		(In millions)
	Fixed-income securities:
	U.S. Treasury obligations		24.0%	$	241	$	69	$	172	$	-
	Corporate bonds		39.5%		398		286		112		-
	Other bonds		3.1%		31		31		-		-
	Total fixed-income securities		66.6%		670		386		284		-
	Equity securities:
	Global (large, mid, small cap)		19.0%		190		-		190		-
	Other securities:
	Hedge fund and alternative investments		12.5%		127		15		-		112
	Short-term investments		1.9%		19		-		19		-
	Total other securities		14.4%		146		15		19		112
	Total investments		100.0%	$	1,006	$	401	$	493	$	112
Schedule of Changes In Level 3 Plan Assets
	31-Dec-12	$	103
	Investment returns		9
	31-Dec-13		112
	Disbursements		-6
	Investment returns		6
	31-Dec-14	$	112
Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans
		Pension Benefits		Postretirement Benefits
		(In millions)
	Devon's 2015 contributions	$	10	$	3
	Benefit payments:
	2015	$	73	$	3
	2016	$	75	$	3
	2017	$	79	$	3
	2018	$	82	$	3
	2019	$	86	$	2
	2020 to 2024	$	466	$	8
Schedule Of Expense Related To These Defined Contribution Plans
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	401(k) and enhanced contribution plans	$	49	$	41	$	36
	Canadian pension and savings plans		20		26		23
	Total	$	69	$	67	$	59
Target Allocation [Member]
Schedule Of Fair Value of Pension Assets By Asset Class
		December 31,
		2014		2013
	Fixed income		70%		70%
	Equity		20%		20%
	Other		10%		10%

Retirement_Plans_Tables

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule Of Changes In Defined Benefit Plan Obligations
		Pension Benefits				Postretirement Benefits
		2014		2013		2014		2013
		(In millions)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	1,177	$	1,360	$	24	$	34
	Service cost		30		36		1		1
	Interest cost		55		51		1		1
	Actuarial loss (gain)		203		-158		-		-3
	Plan amendments		-		2		-		-8
	Plan settlements		-4		-		-		-
	Foreign exchange rate changes		-3		-2		-		-
	Participant contributions		-		-		2		3
	Benefits paid		-81		-112		-4		-4
	Benefit obligation at end of year		1,377		1,177		24		24
	Change in plan assets:
	Fair value of plan assets at beginning of year		1,006		1,165		-		-
	Actual return on plan assets		200		-57		-		-
	Employer contributions		29		11		2		1
	Participant contributions		-		-		2		3
	Plan settlements		-4		-		-		-
	Benefits paid		-81		-112		-4		-4
	Foreign exchange rate changes		-1		-1		-		-
	Fair value of plan assets at end of year		1,149		1,006		-		-
	Funded status at end of year	$	-228	$	-171	$	-24	$	-24
	Amounts recognized in balance sheet:
	Other long-term assets	$	22	$	47	$	-	$	-
	Other current liabilities		-10		-12		-3		-3
	Other long-term liabilities		-240		-206		-21		-21
	Net amount	$	-228	$	-171	$	-24	$	-24
	Amounts recognized in accumulated other comprehensive earnings:
	Net actuarial loss (gain)	$	317	$	279	$	-11	$	-13
	Prior service cost (credit)		19		23		-9		-11
	Total	$	336	$	302	$	-20	$	-24
Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets
		December 31,
		2014		2013
		(In millions)
	Projected benefit obligation	$	250	$	218
	Accumulated benefit obligation	$	191	$	179
	Fair value of plan assets	$	-	$	-
Schedule Of Net Periodic Benefit Cost And Other Comprehensive Income For Pension And Other Postretirement Benefit Plans
		Pension Benefits						Postretirement Benefits
		2014		2013		2012		2014		2013		2012
		(In millions)
	Net periodic benefit cost:
	Service cost	$	30	$	36	$	43	$	1	$	1	$	1
	Interest cost		55		51		60		1		1		1
	Expected return on plan assets		-54		-62		-64		-		-		-
	Curtailment and settlement expense		1		-		26		-		-		1
	Recognition of net actuarial loss (gain) (1)		18		22		24		-1		-1		-1
	Recognition of prior service cost (1)		4		4		3		-2		-1		-1
	Total net periodic benefit cost (2)		54		51		92		-1		-		1
	Other comprehensive loss (earnings):
	Actuarial loss (gain) arising in current year		57		-39		37		-		-3		-4
	Prior service cost (credit) arising in current year		-		2		14		-		-8		-
	Recognition of net actuarial loss, including settlement
	expense, in net periodic benefit cost		-19		-22		-45		1		1		1
	Recognition of prior service cost, including curtailment,
	in net periodic benefit cost		-4		-4		-8		2		1		1
	Total other comprehensive loss (earnings)		34		-63		-2		3		-9		-2
	Total recognized	$	88	$	-12	$	90	$	2	$	-9	$	-1
	__________________________
	(1)  These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
	(2)  Net periodic benefit cost is a component of general and administrative expenses on the accompanying consolidated comprehensive statements of earnings.
Schedule Of Estimated Net Actuarial Loss And Prior Service Cost For The Pension And Other Postretirement Plans That Will Be Amortized From Accumulated Other Comprehensive Income Into Net Periodic Benefit Cost During 2015
		Pension Benefits		Postretirement Benefits
		(In millions)
	Net actuarial loss (gain)	$	21	$	-1
	Prior service cost (credit)		4		-2
	Total	$	25	$	-3
Schedule Of Weighted Average Actuarial Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Costs
		Pension Benefits						Postretirement Benefits
		2014		2013		2012		2014		2013		2012
	Assumptions to determine benefit obligations:
	Discount rate		3.90%		4.80%		3.85%		3.25%		3.65%		3.30%
	Rate of compensation increase		4.49%		4.48%		4.48%		N/A		N/A		N/A
	Assumptions to determine net periodic benefit cost:
	Discount rate		4.80%		3.85%		4.65%		3.65%		3.30%		4.25%
	Rate of compensation increase		4.49%		4.48%		4.97%		N/A		N/A		N/A
	Expected return on plan assets		5.42%		5.48%		5.48%		N/A		N/A		N/A
Schedule Of Fair Value of Pension Assets By Asset Class
		As of December 31, 2014
						Fair Value Measurements Using:
		Actual Allocation		Total		Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
		(In millions)
	Fixed-income securities:
	U.S. Treasury obligations		35.2%	$	405	$	50	$	355	$	-
	Corporate bonds		31.7%		364		269		95		-
	Other bonds		2.6%		30		30		-		-
	Total fixed-income securities		69.5%		799		349		450		-
	Equity securities:
	Global (large, mid, small cap)		17.2%		197		-		197		-
	Other securities:
	Hedge fund and alternative investments		9.7%		112		-		-		112
	Short-term investments		3.6%		41		15		26		-
	Total other securities		13.3%		153		15		26		112
	Total investments		100.0%	$	1,149	$	364	$	673	$	112
		As of December 31, 2013
						Fair Value Measurements Using:
		Actual Allocation		Total		Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
		(In millions)
	Fixed-income securities:
	U.S. Treasury obligations		24.0%	$	241	$	69	$	172	$	-
	Corporate bonds		39.5%		398		286		112		-
	Other bonds		3.1%		31		31		-		-
	Total fixed-income securities		66.6%		670		386		284		-
	Equity securities:
	Global (large, mid, small cap)		19.0%		190		-		190		-
	Other securities:
	Hedge fund and alternative investments		12.5%		127		15		-		112
	Short-term investments		1.9%		19		-		19		-
	Total other securities		14.4%		146		15		19		112
	Total investments		100.0%	$	1,006	$	401	$	493	$	112
Schedule of Changes In Level 3 Plan Assets
	31-Dec-12	$	103
	Investment returns		9
	31-Dec-13		112
	Disbursements		-6
	Investment returns		6
	31-Dec-14	$	112
Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans
		Pension Benefits		Postretirement Benefits
		(In millions)
	Devon's 2015 contributions	$	10	$	3
	Benefit payments:
	2015	$	73	$	3
	2016	$	75	$	3
	2017	$	79	$	3
	2018	$	82	$	3
	2019	$	86	$	2
	2020 to 2024	$	466	$	8
Schedule Of Expense Related To These Defined Contribution Plans
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	401(k) and enhanced contribution plans	$	49	$	41	$	36
	Canadian pension and savings plans		20		26		23
	Total	$	69	$	67	$	59
Target Allocation [Member]
Schedule Of Fair Value of Pension Assets By Asset Class
		December 31,
		2014		2013
	Fixed income		70%		70%
	Equity		20%		20%
	Other		10%		10%

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies [Abstract]
Schedule Of Commitments And Contingencies
	Year Ending December 31,	Purchase Obligations	Drilling and Facility Obligations	Operational Agreements	Office and Equipment Leases
		(In millions)
	2015	$                    663	$                      234	$                      943	$                        72
	2016	809	116	919	50
	2017	885	77	890	50
	2018	920	13	856	45
	2019	895	1	334	39
	Thereafter	1,134	5	1,142	149
	Total	$                 5,306	$                      446	$                   5,084	$                      405

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities
						Fair Value Measurements Using:
		Carrying		Total Fair		Level 1		Level 2		Level 3
		Amount		Value		Inputs		Inputs		Inputs
			(In millions)
	December 31, 2014 assets (liabilities):
	Cash equivalents	$	950	$	950	$	340	$	610	$	-
	Oil, gas and NGL commodity derivatives	$	1,968	$	1,968	$	-	$	1,968	$	-
	Oil, gas and NGL commodity derivatives	$	-51	$	-51	$	-	$	-51	$	-
	Midstream commodity derivatives	$	27	$	27	$	-	$	27	$	-
	Midstream commodity derivatives	$	-5	$	-5	$	-	$	-5	$	-
	Interest rate derivatives	$	1	$	1	$	-	$	1	$	-
	Interest rate derivatives	$	-1	$	-1	$	-	$	-1	$	-
	Foreign currency derivatives	$	8	$	8	$	-	$	8	$	-
	Debt	$	-11,262	$	-12,472	$	-	$	-12,472	$	-
	Capital lease obligations	$	-20	$	-20	$	-	$	-20	$	-
	December 31, 2013 assets (liabilities):
	Cash equivalents	$	5,305	$	5,305	$	4,191	$	1,114	$	-
	Long-term investments	$	62	$	62	$	-	$	-	$	62
	Oil, gas and NGL commodity derivatives	$	103	$	103	$	-	$	103	$	-
	Oil, gas and NGL commodity derivatives	$	-120	$	-120	$	-	$	-120	$	-
	Foreign currency derivatives	$	-1	$	-1	$	-	$	-1	$	-
	Debt	$	-12,022	$	-12,908	$	-	$	-12,908	$	-

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Information [Abstract]
Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments
		U.S.		Canada		EnLink		Eliminations		Total
		(In millions)
	Year Ended December 31, 2014:
	Revenues from external customers	$	14,862	$	2,063	$	2,641	$	-	$	19,566
	Intersegment revenues	$	-	$	-	$	859	$	-859	$	-
	Depreciation, depletion and amortization	$	2,479	$	560	$	280	$	-	$	3,319
	Asset impairments	$	12	$	1,941	$	-	$	-	$	1,953
	Gains and losses on asset sales	$	5	$	-1,077	$	-	$	-	$	-1,072
	Interest expense	$	441	$	85	$	54	$	-44	$	536
	Earnings (loss) before income taxes	$	4,388	$	-657	$	328	$	-	$	4,059
	Income tax expense	$	1,797	$	495	$	76	$	-	$	2,368
	Net earnings (loss)	$	2,591	$	-1,152	$	252	$	-	$	1,691
	Net earnings attributable to noncontrolling interests	$	1	$	-	$	83	$	-	$	84
	Net earnings (loss) attributable to Devon	$	2,590	$	-1,152	$	169	$	-	$	1,607
	Property and equipment, net	$	24,572	$	6,790	$	4,934	$	-	$	36,296
	Total assets	$	32,147	$	8,517	$	10,097	$	-124	$	50,637
	Capital expenditures	$	11,245	$	1,344	$	970	$	-	$	13,559
	Year Ended December 31, 2013:
	Revenues from external customers	$	6,807	$	2,656	$	934	$	-	$	10,397
	Intersegment revenues	$	-	$	-	$	1,362	$	-1,362	$	-
	Depreciation, depletion and amortization	$	1,744	$	849	$	187	$	-	$	2,780
	Asset impairments	$	1,133	$	843	$	-	$	-	$	1,976
	Interest expense	$	392	$	80	$	-	$	-35	$	437
	Earnings (loss) before income taxes	$	495	$	-532	$	186	$	-	$	149
	Income tax expense (benefit)	$	258	$	-156	$	67	$	-	$	169
	Net earnings (loss)	$	237	$	-376	$	119	$	-	$	-20
	Property and equipment, net	$	18,201	$	8,478	$	1,768	$	-	$	28,447
	Total assets	$	27,080	$	13,560	$	2,237	$	-	$	42,877
	Capital expenditures	$	4,589	$	1,841	$	213	$	-	$	6,643
	Year Ended December 31, 2012:
	Revenues from external customers	$	6,098	$	2,600	$	803	$	-	$	9,501
	Intersegment revenues	$	-	$	-	$	1,105	$	-1,105	$	-
	Depreciation, depletion and amortization	$	1,679	$	987	$	145	$	-	$	2,811
	Asset impairments	$	1,845	$	163	$	16	$	-	$	2,024
	Interest expense	$	343	$	82	$	-	$	-19	$	406
	Earnings (loss) before income taxes	$	-372	$	-73	$	128	$	-	$	-317
	Income tax expense (benefit)	$	-143	$	-35	$	46	$	-	$	-132
	Net earnings (loss)	$	-229	$	-38	$	82	$	-	$	-185
	Property and equipment, net	$	16,622	$	8,955	$	1,739	$	-	$	27,316
	Total assets	$	22,050	$	19,070	$	2,206	$	-	$	43,326
	Capital expenditures	$	6,159	$	1,963	$	352	$	-	$	8,474

Supplemental_Information_On_Oi1

Supplemental Information On Oil And Gas Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Information On Oil And Gas Operations [Abstract]
Costs Incurred
		Year Ended December 31, 2014
		U.S.		Canada		Total
		(In millions)
	Property acquisition costs:
	Proved properties	$	5,210	$	-	$	5,210
	Unproved properties		1,176		1		1,177
	Exploration costs		270		52		322
	Development costs		4,400		1,063		5,463
	Costs incurred	$	11,056	$	1,116	$	12,172
		Year Ended December 31, 2013
		U.S.		Canada		Total
		(In millions)
	Property acquisition costs:
	Proved properties	$	19	$	3	$	22
	Unproved properties		213		3		216
	Exploration costs		443		152		595
	Development costs		3,838		1,251		5,089
	Costs incurred	$	4,513	$	1,409	$	5,922
		Year Ended December 31, 2012
		U.S.		Canada		Total
		(In millions)
	Property acquisition costs:
	Proved properties	$	2	$	71	$	73
	Unproved properties		1,135		32		1,167
	Exploration costs		351		315		666
	Development costs		4,408		1,691		6,099
	Costs incurred	$	5,896	$	2,109	$	8,005
Capitalized Costs
		31-Dec-14
		U.S.		Canada		Total
		(In millions)
	Proved properties	$	59,849	$	15,889	$	75,738
	Unproved properties		1,460		1,292		2,752
	Total oil & gas properties		61,309		17,181		78,490
	Accumulated DD&A		-38,213		-11,347		-49,560
	Net capitalized costs	$	23,096	$	5,834	$	28,930
		31-Dec-13
		U.S.		Canada		Total
		(In millions)
	Proved properties	$	51,366	$	22,629	$	73,995
	Unproved properties		1,277		1,514		2,791
	Total oil & gas properties		52,643		24,143		76,786
	Accumulated DD&A		-35,848		-16,613		-52,461
	Net capitalized costs	$	16,795	$	7,530	$	24,325
Oil And Gas Properties Not Subject To Amortization
		Costs Incurred In
		2014		2013		2012		Prior to 2012		Total
		(In millions)
	Acquisition costs	$	973	$	127	$	140	$	650	$	1,890
	Exploration costs		111		76		68		107		362
	Development costs		103		48		121		69		341
	Capitalized interest		43		38		30		48		159
	Total oil and gas properties not subject to amortization	$	1,230	$	289	$	359	$	874	$	2,752
Results Of Operations
		31-Dec-14
		U.S.		Canada		Total
		(In millions)
	Oil, gas and NGL sales	$	7,867	$	2,043	$	9,910
	Lease operating expenses		-1,559		-773		-2,332
	General and administrative expenses		-153		-57		-210
	Production and property taxes		-466		-37		-503
	Depreciation, depletion and amortization		-2,365		-531		-2,896
	Gain on sale of assets		-		1,077		1,077
	Accretion of asset retirement obligations		-49		-39		-88
	Income tax expense		-1,199		-568		-1,767
	Results of operations(1)	$	2,076	$	1,115	$	3,191
	Depreciation, depletion and amortization per Boe	$	11.41	$	13.80	$	11.79
	-1
	In the fourth quarter of 2014, Devon recognized a $1.9 billion Canadian goodwill impairment that is not reflected in
	this table.
		31-Dec-13
		U.S.		Canada		Total
		(In millions)
	Oil, gas and NGL sales	$	5,964	$	2,558	$	8,522
	Lease operating expenses		-1,257		-1,011		-2,268
	General and administrative expenses		-125		-77		-202
	Production and property taxes		-380		-59		-439
	Depreciation, depletion and amortization		-1,640		-825		-2,465
	Asset impairments		-1,110		-843		-1,953
	Accretion of asset retirement obligations		-47		-64		-111
	Income tax benefit (expense)		-510		88		-422
	Results of operations	$	895	$	-233	$	662
	Depreciation, depletion and amortization per Boe	$	8.69	$	12.87	$	9.75
		31-Dec-12
		U.S.		Canada		Total
		(In millions)
	Oil, gas and NGL sales	$	4,679	$	2,474	$	7,153
	Lease operating expenses		-1,059		-1,015		-2,074
	General and administrative expenses		-159		-137		-296
	Production and property taxes		-340		-55		-395
	Depreciation, depletion and amortization		-1,563		-963		-2,526
	Asset impairments		-1,793		-163		-1,956
	Accretion of asset retirement obligations		-40		-69		-109
	Income tax benefit (expense)		99		-3		96
	Results of operations	$	-176	$	69	$	-107
	Depreciation, depletion and amortization per Boe	$	8.55	$	14.41	$	10.12
Proved Reserves
		Oil (MMBbls)
		U.S.		Canada		Total
	Proved developed and undeveloped reserves:
	31-Dec-11		168		80		248
	Revisions due to prices		-1		-5		-6
	Revisions other than price		-6		-2		-8
	Extensions and discoveries		65		7		72
	Production		-21		-15		-36
	31-Dec-12		205		65		270
	Revisions due to prices		1		-1		-
	Revisions other than price		-18		-		-18
	Extensions and discoveries		69		7		76
	Purchase of reserves		1		-		1
	Production		-28		-15		-43
	Sale of reserves		-1		-		-1
	31-Dec-13		229		56		285
	Revisions due to prices		-1		-		-1
	Revisions other than price		-38		1		-37
	Extensions and discoveries		94		5		99
	Purchase of reserves		132		-		132
	Production		-48		-10		-58
	Sale of reserves		-17		-29		-46
	31-Dec-14		351		23		374
	Proved developed reserves as of:
	31-Dec-11		146		73		219
	31-Dec-12		166		62		228
	31-Dec-13		194		56		250
	31-Dec-14		255		23		278
	Proved developed-producing reserves as of:
	31-Dec-11		139		65		204
	31-Dec-12		155		56		211
	31-Dec-13		178		51		229
	31-Dec-14		224		19		243
	Proved undeveloped reserves as of:
	31-Dec-11		22		7		29
	31-Dec-12		39		3		42
	31-Dec-13		35		-		35
	31-Dec-14		96		-		96
		Bitumen (MMBbls)
		U.S.		Canada		Total
	Proved developed and undeveloped reserves:
	31-Dec-11		-		457		457
	Revisions due to prices		-		14		14
	Revisions other than price		-		7		7
	Extensions and discoveries		-		67		67
	Production		-		-17		-17
	31-Dec-12		-		528		528
	Revisions due to prices		-		-11		-11
	Revisions other than price		-		16		16
	Extensions and discoveries		-		38		38
	Production		-		-19		-19
	31-Dec-13		-		552		552
	Revisions due to prices		-		-37		-37
	Revisions other than price		-		18		18
	Extensions and discoveries		-		8		8
	Production		-		-20		-20
	31-Dec-14		-		521		521
	Proved developed reserves as of:
	31-Dec-11		-		90		90
	31-Dec-12		-		99		99
	31-Dec-13		-		111		111
	31-Dec-14		-		137		137
	Proved developed-producing reserves as of:
31-Dec-11		-		90		90
31-Dec-12		-		99		99
31-Dec-13		-		111		111
31-Dec-14		-		137		137
Proved undeveloped reserves as of:
31-Dec-11		-		367		367
31-Dec-12		-		429		429
31-Dec-13		-		441		441
31-Dec-14		-		384		384
	Gas (Bcf)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		9,507		979		10,486
Revisions due to prices		-831		-99		-930
Revisions other than price		-287		-33		-320
Extensions and discoveries		1,124		34		1,158
Purchase of reserves		2		-		2
Production		-752		-186		-938
Sale of reserves		-1		-11		-12
31-Dec-12		8,762		684		9,446
Revisions due to prices		405		161		566
Revisions other than price		-299		67		-232
Extensions and discoveries		471		19		490
Purchase of reserves		1		-		1
Production		-709		-165		-874
Sale of reserves		-81		-8		-89
31-Dec-13		8,550		758		9,308
Revisions due to prices		191		45		236
Revisions other than price		-299		4		-295
Extensions and discoveries		335		8		343
Purchase of reserves		457		-		457
Production		-660		-41		-701
Sale of reserves		-923		-738		-1,661
31-Dec-14		7,651		36		7,687
Proved developed reserves as of:
31-Dec-11		7,957		951		8,908
31-Dec-12		7,391		679		8,070
31-Dec-13		7,707		752		8,459
31-Dec-14		6,948		36		6,984
Proved developed-producing reserves as of:
31-Dec-11		7,409		862		8,271
31-Dec-12		7,091		624		7,715
31-Dec-13		7,425		680		8,105
31-Dec-14		6,746		34		6,780
Proved undeveloped reserves as of:
31-Dec-11		1,550		28		1,578
31-Dec-12		1,371		5		1,376
31-Dec-13		843		6		849
31-Dec-14		703		-		703
	Natural Gas Liquids (MMBbls)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		525		27		552
Revisions due to prices		-19		-5		-24
Revisions other than price		-13		-		-13
Extensions and discoveries		114		2		116
Production		-36		-4		-40
31-Dec-12		571		20		591
Revisions due to prices		8		3		11
Revisions other than price		-50		3		-47
Extensions and discoveries		64		1		65
Production		-41		-4		-45
31-Dec-13		552		23		575
Revisions due to prices		7		1		8
Revisions other than price		2		-		2
Extensions and discoveries		47		-		47
Purchase of reserves		57		-		57
Production		-50		-1		-51
Sale of reserves		-37		-23		-60
31-Dec-14		578		-		578
Proved developed reserves as of:
31-Dec-11		402		26		428
31-Dec-12		431		20		451
31-Dec-13		468		23		491
31-Dec-14		486		-		486
Proved developed-producing reserves as of:
31-Dec-11		372		24		396
31-Dec-12		406		19		425
31-Dec-13		442		21		463
31-Dec-14		467		-		467
Proved undeveloped reserves as of:
31-Dec-11		123		1		124
31-Dec-12		140		-		140
31-Dec-13		84		-		84
31-Dec-14		92		-		92
	Total (MMBoe) (1)
	U.S.		Canada		Total
Proved developed and undeveloped reserves:
31-Dec-11		2,278		727		3,005
Revisions due to prices		-159		-12		-171
Revisions other than price		-67		-1		-68
Extensions and discoveries		367		82		449
Production		-183		-67		-250
Sale of reserves		-		-2		-2
31-Dec-12		2,236		727		2,963
Revisions due to prices		76		18		94
Revisions other than price		-117		29		-88
Extensions and discoveries		212		49		261
Purchase of reserves		1		-		1
Production		-189		-64		-253
Sale of reserves		-14		-1		-15
31-Dec-13		2,205		758		2,963
Revisions due to prices		38		-29		9
Revisions other than price		-86		21		-65
Extensions and discoveries		197		14		211
Purchase of reserves		265		-		265
Production		-207		-39		-246
Sale of reserves		-207		-176		-383
31-Dec-14		2,205		549		2,754
Proved developed reserves as of:
31-Dec-11		1,875		348		2,223
31-Dec-12		1,829		294		2,123
31-Dec-13		1,947		315		2,262
31-Dec-14		1,900		165		2,065
Proved developed-producing reserves as of:
31-Dec-11		1,746		323		2,069
31-Dec-12		1,743		278		2,021
31-Dec-13		1,857		297		2,154
31-Dec-14		1,815		162		1,977
Proved undeveloped reserves as of:
31-Dec-11		403		379		782
31-Dec-12		407		433		840
31-Dec-13		258		443		701
31-Dec-14		305		384		689
_______________________
(1)Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
Proved Undeveloped Reserves
		U.S.		Canada		Total
	Proved undeveloped reserves as of December 31, 2013		258		443		701
	Extensions and discoveries		153		8		161
	Revisions due to prices		-1		-34		-35
	Revisions other than price		-61		18		-43
	Sale of reserves		-4		-2		-6
	Conversion to proved developed reserves		-40		-49		-89
	Proved undeveloped reserves as of December 31, 2014		305		384		689
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves
		Year Ended December 31, 2014
		U.S.		Canada		Total
		(In millions)
	Future cash inflows	$	75,847	$	31,371	$	107,218
	Future costs:
	Development		-7,168		-3,619		-10,787
	Production		-29,740		-14,232		-43,972
	Future income tax expense		-11,021		-3,026		-14,047
	Future net cash flow		27,918		10,494		38,412
	10% discount to reflect timing of cash flows		-12,819		-5,119		-17,938
	Standardized measure of discounted future net cash flows	$	15,099	$	5,375	$	20,474
		Year Ended December 31, 2013
		U.S.		Canada		Total
		(In millions)
	Future cash inflows	$	61,983	$	33,305	$	95,288
	Future costs:
	Development		-5,448		-5,308		-10,756
	Production		-26,663		-15,709		-42,372
	Future income tax expense		-9,046		-2,327		-11,373
	Future net cash flow		20,826		9,961		30,787
	10% discount to reflect timing of cash flows		-10,346		-4,700		-15,046
	Standardized measure of discounted future net cash flows	$	10,480	$	5,261	$	15,741
		Year Ended December 31, 2012
		U.S.		Canada		Total
		(In millions)
	Future cash inflows	$	55,297	$	33,570	$	88,867
	Future costs:
	Development		-6,556		-6,211		-12,767
	Production		-24,265		-16,611		-40,876
	Future income tax expense		-6,542		-1,992		-8,534
	Future net cash flow		17,934		8,756		26,690
	10% discount to reflect timing of cash flows		-9,036		-4,433		-13,469
	Standardized measure of discounted future net cash flows	$	8,898	$	4,323	$	13,221
Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves
		Year Ended December 31,
		2014		2013		2012
		(In millions)
	Beginning balance	$	15,741	$	13,221	$	17,844
	Net changes in prices and production costs		2,561		3,018		-9,889
	Oil, bitumen, gas and NGL sales, net of production costs		-6,865		-5,613		-4,388
	Changes in estimated future development costs		-768		399		-1,094
	Extensions and discoveries, net of future development costs		4,836		4,047		4,669
	Purchase of reserves		6,422		14		18
	Sales of reserves in place		-2,384		-44		-25
	Revisions of quantity estimates		-746		-1,040		162
	Previously estimated development costs incurred during the period		1,933		1,986		1,321
	Accretion of discount		1,746		1,940		1,420
	Other, primarily changes in timing and foreign exchange rates		-107		-583		113
	Net change in income taxes		-1,895		-1,604		3,070
	Ending balance	$	20,474	$	15,741	$	13,221

Supplemental_Quarterly_Financi1

Supplemental Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Schedule Of Unaudited Interim Results Of Operations
		2014
		First		Second		Third		Fourth		Full
		Quarter		Quarter		Quarter		Quarter		Year
		(In millions, except per share amounts)
	Operating revenues	$	3,725	$	4,510	$	5,336	$	5,995	$	19,566
	Earnings (loss) before income taxes	$	560	$	1,554	$	1,654	$	291	$	4,059
	Net earnings (loss) attributable to Devon	$	324	$	675	$	1,016	$	-408	$	1,607
	Basic net earnings (loss) per share attributable to Devon	$	0.80	$	1.65	$	2.48	$	-1.01	$	3.93
	Diluted net earnings (loss) per share attributable to Devon	$	0.79	$	1.64	$	2.47	$	-1.01	$	3.91
		2013
		First		Second		Third		Fourth		Full
		Quarter		Quarter		Quarter		Quarter		Year
		(In millions, except per share amounts)
	Operating revenues	$	1,971	$	3,088	$	2,714	$	2,624	$	10,397
	Earnings (loss) before income taxes	$	-1,962	$	997	$	639	$	475	$	149
	Net earnings (loss) attributable to Devon	$	-1,339	$	683	$	429	$	207	$	-20
	Basic net earnings (loss) per share attributable to Devon	$	-3.34	$	1.69	$	1.06	$	0.51	$	-0.06
	Diluted net earnings (loss) per share attributable to Devon	$	-3.34	$	1.68	$	1.05	$	0.51	$	-0.06

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	customer	customer	customer
Summary Of Significant Accounting Policies [Line Items]
Number of purchasers attributing more than 10% operating revenues	0	0	0
Derivative collateral	$524
Held-to-maturity securities		$62
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite lived intangible asset useful life	10 years
Depletion calculation holding period	3 years
Property, plant and equipment, useful life	3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite lived intangible asset useful life	20 years
Depletion calculation holding period	4 years
Property, plant and equipment, useful life	60 years

Acquisitions_And_Divestitures_1

Acquisitions And Divestitures (Narrative) (Details)

0 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

Share data in Millions, unless otherwise specified

Nov. 13, 2014

Jun. 30, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Aug. 29, 2014

Mar. 07, 2014

Dec. 31, 2014

Feb. 28, 2014

Dec. 31, 2014

Nov. 02, 2014

Oct. 22, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Jun. 30, 2014

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Foreign Currency Derivatives [Member]

Canadian Conventional Assets Divestiture [Member]

Canadian Conventional Assets Divestiture [Member]

Canadian Conventional Assets Divestiture [Member]

Canadian Conventional Assets Divestiture [Member]

Canadian Conventional Assets Divestiture [Member]

LINN Energy [Member]

General Partner And Enlink [Member]

General Partner And Enlink [Member]

GeoSouthern Intermediate Holdings, LLC [Member]

GeoSouthern Intermediate Holdings, LLC [Member]

EnLink [Member]

EnLink [Member]

General Partner [Member]

General Partner [Member]

EnLink [Member]

EnLink [Member]

EnLink [Member]

EnLink [Member]

EnLink [Member]

EnLink [Member]

EnLink Holdings [Member]

EnLink Holdings [Member]

Term Loan [Member]

USD ($)

USD ($)

CAD

USD ($)

CAD

USD ($)

USD ($)

USD ($)

USD ($)

Gulf Coast Natural Gas Pipeline [Member]

Appalachian Compression, LLC and E2 Energy Services, LLC [Member]

Public Unitholders [Member]

Public Unitholders [Member]

Public Unitholders [Member]

General Partner [Member]

General Partner [Member]

EnLink [Member]

General Partner [Member]

USD ($)

acre

USD ($)

USD ($)

Business Acquisition [Line Items]

Cash payment to acquire interest

$100,000,000

$163,000,000

Ownership percentage

70.00%

30.00%

49.00%

52.00%

43.00%

41.00%

8.00%

7.00%

50.00%

50.00%

Close date of acquisition

7-Mar-14

28-Feb-14

Aggregate purchase price

6,000,000,000

234,000,000

194,000,000

Common units value

31,200,000

Units issued for acquisition

1

Number of acres acquired

82,000

Gains and losses on asset sales

1,072,000,000

-9,000,000

13,000,000

1,100,000,000

0

Gains and losses on assets sales after tax

600,000,000

Derecognition in goodwill allocated to sold assets

-700,000,000

Foreign currency exchange loss

-84,000,000

Loss on derivative

29,000,000

Foreign earnings repatriated

2,800,000,000

2,800,000,000

4,300,000,000

Proceeds from property and equipment divestitures

5,120,000,000

419,000,000

1,468,000,000

2,800,000,000

3,125,000,000

142,000,000

155,000,000

2,200,000,000

Proceeds after tax from property and equipment divestitures

2,000,000,000

Asset retirement obligation transferred

953,000,000

28,000,000

700,000,000

200,000,000

Repayment of commercial paper

700,000,000

Long term debt repayment

7,189,000,000

750,000,000

2,000,000,000

Early retirement of senior notes

$1,900,000,000

Acquisitions_And_Divestitures_2

Acquisitions And Divestitures (Schedule Of Purchase Price Allocation For General Partner And EnLink) (Details) (General Partner And Enlink [Member], USD $)	0 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 07, 2014
	item
Business Acquisition [Line Items]
Total consideration and fair value of noncontrolling interests	$4,670
Current Crosstex Energy, Inc. [Member]
Business Acquisition [Line Items]
Held by public shareholders	48
Restricted shares	0.4
Total	48.4
Exchange ratio	1
Converted shares	48.4
Common share or unit price	$37.60	[1]
Crosstex Energy, Inc. consideration	1,823
Fair value of noncontrolling interests	18	[2]
Total consideration and fair value of noncontrolling interests	1,841
Crosstex Energy, LP [Member]
Business Acquisition [Line Items]
Total	92.6
Common share or unit price	$30.51	[3]
Common units held by public unitholders	75.1
Preferred units held by third party	17.1	[4]
Restricted units	0.4
Common units value	2,825
Outstanding unit options value	4
Fair value of noncontrolling interests	$2,829	[3]
[1]	The final purchase price is based on the fair value of Crosstex Energy, Inc.bs common shares as of the closing date, March 7, 2014.
[2]	Represents the value of noncontrolling interests related to the General Partnerbs equity investment in E2 Energy Services, LLC and E2 Appalachian Compression, LLC (collectively bE2b).
[3]	The final purchase price is based on the fair value of Crosstex Energy, LPbs common units as of the closing date, March 7, 2014.
[4]	Crosstex Energy, LP converted the preferred units to common units in February 2014.

Acquisitions_And_Divestitures_3

Acquisitions And Divestitures (Schedule Of Purchase Price Allocation For General Partner) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 07, 2014
In Millions, unless otherwise specified
Assets acquired:
Goodwill	$6,303	$5,858	$6,079
General Partner [Member]
Assets acquired:
Current assets				437
Property, plant and equipment, net				2,438
Intangible assets				569
Equity investment				222
Goodwill				3,283	[1]
Other long-term assets				1
Liabilities assumed:
Current liabilities				-515
Long-term debt				-1,454
Deferred income taxes				-210
Other long-term liabilities				-101
Total consideration and fair value of noncontrolling interests				$4,670
[1]	Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.

Acquisitions_And_Divestitures_4

Acquisitions And Divestitures (Schedule Of Purchase Price Allocation For GeoSouthern Intermediate Holdings) (Details) (GeoSouthern Intermediate Holdings, LLC [Member], USD $)	Feb. 28, 2014
In Millions, unless otherwise specified
GeoSouthern Intermediate Holdings, LLC [Member]
Business Acquisition [Line Items]
Cash and cash equivalents	$95
Other current assets	256
Proved properties	5,026
Unproved properties	1,007
Midstream assets	86
Current liabilities	-434
Long-term liabilities	-6
Net assets acquired	$6,030

Acquisitions_And_Divestitures_5

Acquisitions And Divestitures (Schedule Of Revenue And Earnings For General Partner and GeoSouthern) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Total operating revenues	$5,995	$5,336	$4,510	$3,725	$2,624	$2,714	$3,088	$1,971	$19,566	$10,397	$9,501
Total operating expenses									14,868	9,830	9,427
Operating income									4,698	567	74
GeoSouthern Intermediate Holdings, LLC [Member]
Business Acquisition [Line Items]
Total operating revenues									1,873
Total operating expenses									960
Operating income									913
General Partner [Member]
Business Acquisition [Line Items]
Total operating revenues									2,509
Total operating expenses									2,464
Operating income									$45

Acquisitions_And_Divestitures_6

Acquisitions And Divestitures (Schedule Of Unaudited Proforma Information For General Partner And GeoSouthern) (Details) (General Partner And GeoSouthern [Member], USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
General Partner And GeoSouthern [Member]
Business Acquisition [Line Items]
Total operating revenues	$20,213	$12,979
Net earnings (loss)	1,716	35
Noncontrolling interests	97	45
Net earnings (loss) attributable to Devon	$1,619	($10)
Net earnings (loss) per common share attributable to Devon	$3.94	($0.02)

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Schedule Of Open Oil Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2014
	bbl
NYMEX West Texas Intermediate Price Swaps Oil Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d)	107,203
Weighted Average Price Swap	91.07
NYMEX West Texas Intermediate Price Collars Oil Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d)	31,500
Weighted Average Floor Price	89.67
Weighted Average Ceiling Price	97.84
NYMEX West Texas Intermediate Call Options Sold Oil Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d)	28,000
Weighted Average Call Option Sold Price	116.43
NYMEX West Texas Intermediate Call Options Sold Oil Q1 - Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d)	18,500
Weighted Average Call Option Sold Price	103.11
Western Canadian Select Basis Swaps Oil Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d)	22,514
Weighted Average Differential To WTI	-18.35
West Texas Sour Basis Swaps Oil Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d)	8,000
Weighted Average Differential To WTI	-3.68
Midland Sweet Basis Swaps Oil Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d)	14,247
Weighted Average Differential To WTI	-2.92

Derivative_Financial_Instrumen3

Derivative Financial Instruments (Schedule Of Open Natural Gas Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2014
	MMBTU
FERC Henry Hub Price Swaps Natural Gas Q1- Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	250,000
Weighted Average Price Swap	4.32
FERC Henry Hub Price Collars Natural Gas Q1- Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	328,452
Weighted Average Floor Price	4.05
Weighted Average Ceiling Price	4.36
FERC Henry Hub Call Options Sold Natural Gas Q1- Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	550,000
Weighted Average Call Option Sold Price	5.09
FERC Henry Hub Call Options Sold Natural Gas Q1- Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	400,000
Weighted Average Call Option Sold Price	5
PEPL Basis Swaps Natural Gas Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	100,000
Weighted Average Differential To Henry Hub	-0.28
El Paso Natural Gas Basis Swaps Natural Gas Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	70,000
Weighted Average Differential To Henry Hub	-0.11
Houston Ship Channel Natural Gas Basis Swaps Natural Gas Q1 - Q4 2015 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	200,000
Weighted Average Differential To Henry Hub	0.01
PEPL Basis Swaps Natural Gas Q1 - Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	30,000
Weighted Average Differential To Henry Hub	-0.33
El Paso Natural Gas Basis Swaps Natural Gas Q1- Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	15,000
Weighted Average Differential To Henry Hub	-0.13
Houston Ship Channel Natural Gas Basis Swaps Natural Gas Q1 - Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d)	30,000
Weighted Average Differential To Henry Hub	0.11

Derivative_Financial_Instrumen4

Derivative Financial Instruments (Schedule Of Gas Processing and Fractionation Open Positions) (Details)	12 Months Ended
	Dec. 31, 2014
	MBbls
OPIS Mont Belvieu Texas Ethane Basis Swap Q1 2015 - Q4 2016 [Member]
Derivative [Line Items]
Volume (MBbls)	1,168
Weighted average price paid	Index
Weighted average price received	$0.29/gal
OPIS Mont Belvieu Texas Propane Basis Swap Q1 2015 - Q4 2016 [Member]
Derivative [Line Items]
Volume (MBbls)	1,171
Weighted average price paid	Index
Weighted average price received	$1.01/gal
OPIS Mont Belvieu Texas Normal Butane Basis Swap Q1 - Q4 2015 [Member]
Derivative [Line Items]
Volume (MBbls)	53
Weighted average price paid	Index
Weighted average price received	$1.14/gal
OPIS Mont Belvieu Texas Natural Gasoline Basis Swap Q1 - Q4 2015 [Member]
Derivative [Line Items]
Volume (MBbls)	44
Weighted average price paid	Index
Weighted average price received	$1.81/gal
Henry Hub Natural Gas Basis Swap Q1 - Q4 2015 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d)	1,225
Weighted average price paid	$4.08/MMBtu
Weighted average price received	Index

Derivative_Financial_Instrumen5

Derivative Financial Instruments (Schedule Of Open Interest Rate Swap Derivative Positions) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Interest Rate Contract Expiration December 2016 [Member]
Derivative [Line Items]
Notional	$100
Rate Received	Three Month LIBOR
Rate Paid	0.92%
Expiration	1-Dec-16
Interest Rate Contract Expiration January 2019 [Member]
Derivative [Line Items]
Notional	$100
Rate Received	1.76%
Rate Paid	Three Month LIBOR
Expiration	1-Jan-19

Derivative_Financial_Instrumen6

Derivative Financial Instruments (Schedule Of Open Foreign Exchange Rate Derivative Positions) (Details) (Forward Contract [Member], CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Forward Contract [Member]
Derivative [Line Items]
Currency	Canadian Dollar
Contract Type	Sell
CAD Notional	1,884
Weighted Average Fixed Rate Received	0.864
Expiration	1-Mar-15

Derivative_Financial_Instrumen7

Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Comprehensive Statements Of Earnings) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Net gain (losses) recognized in comprehensive statements of earnings	$2,070	($135)	$660
Oil, Gas And NGL Commodity Derivatives [Member]
Derivatives, Fair Value [Line Items]
Net gain (losses) recognized in comprehensive statements of earnings	1,989	-191	693
Midstream Commodity Derivatives [Member]
Derivatives, Fair Value [Line Items]
Net gain (losses) recognized in comprehensive statements of earnings	22
Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Net gain (losses) recognized in comprehensive statements of earnings	-1		-15
Foreign Currency Derivatives [Member]
Derivatives, Fair Value [Line Items]
Net gain (losses) recognized in comprehensive statements of earnings	$60	$56	($18)

Derivative_Financial_Instrumen8

Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	$2,004	$103
Fair value of derivative liabilities	57	121
Oil, Gas And NGL Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	1,967	75
Oil, Gas And NGL Commodity Derivatives [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	1	28
Oil, Gas And NGL Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	25	58
Oil, Gas And NGL Commodity Derivatives [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	26	62
Midstream Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	17
Midstream Commodity Derivatives [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	10
Midstream Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	3
Midstream Commodity Derivatives [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	2
Interest Rate Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	1
Interest Rate Derivatives [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	1
Foreign Currency Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	8
Foreign Currency Derivatives [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities		$1

ShareBased_Compensation_Narrat

Share-Based Compensation (Narrative) (Details) (USD $)	12 Months Ended			3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation	$199	$157	$179
Options, Granted	0	0
2009 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Plan expiration date	2-Jun-19
Shares authorized for issuance				21,500,000
2009 Plan Amendment [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance				47,000,000
Stock Options And Stock Appreciation Rights [Member] | 2009 Plan Amendment [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares used to calculate shares issued under the 2009 Long-Term Incentive Plan, options and stock appreciation rights				1
Other Awards [Member] | 2009 Plan Amendment [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares used to calculate shares issued under the 2009 Long-Term Incentive Plan, other awards				2.38
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards and units	3
Weighted average period for recognition of cost of unvested awards and units	1 year
Expiration duration of options	8 years
Aggregate intrinsic value	9	0.3	34
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards and units	194
Weighted average period for recognition of cost of unvested awards and units	2 years 6 months
Total aggregate fair value of vested restricted awards and units	112	141	112
Vested awards	1,767,000
Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards and units	5
Weighted average period for recognition of cost of unvested awards and units	2 years 10 months 24 days
Total aggregate fair value of vested restricted awards and units	10	5
Vested awards	170,000		0
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards and units	34
Weighted average period for recognition of cost of unvested awards and units	1 year 9 months 18 days
Number of predetermined peer companies to compare against Devon's total shareholder's return for Performance awards	14
Minimum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	0 years
Minimum [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	0 years
Minimum [Member] | Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	0 years
Minimum [Member] | Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Comparison period of peer companies for performance awards	2 years
Percentage of vesting units to units granted	0.00%
Maximum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	4 years
Maximum [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	4 years
Maximum [Member] | Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	4 years
Maximum [Member] | Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Comparison period of peer companies for performance awards	3 years
Percentage of vesting units to units granted	200.00%
EnLink [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation	17
Unrecognized compensation cost related to unvested awards and units	20
Weighted average period for recognition of cost of unvested awards and units	1 year 10 months 24 days
General Partner [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards and units	$21
Weighted average period for recognition of cost of unvested awards and units	1 year 10 months 24 days

ShareBased_Compensation_Schedu

Share-Based Compensation (Schedule Of The Effects Of Share Based Compensation Included In The Consolidated Comprehensive Statement Of Earnings) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation [Abstract]
Gross general and administrative expense	$199	$157	$179
Share-based compensation expense capitalized pursuant to the full-cost method of accounting for oil and gas properties	53	60	56
Related income tax benefit	$30	$23	$34

ShareBased_Compensation_Summar

Share-Based Compensation (Summary Of the Grant-Date Fair Values Of Stock Options Granted And Their Related Assumptions, Represented By The Weighted-Average Amounts) (Details) (Stock Options [Member], USD $)	12 Months Ended
	Dec. 31, 2012
Stock Options [Member]
Grant-date fair value	$22.20
Volatility factor	42.50%
Dividend Yield	1.20%
Risk-free interest rate	1.10%
Expected term (in years)	6 years

ShareBased_Compensation_Summar1

Share-Based Compensation (Summary Of Outstanding Stock Options, Including Changes During The Year) (Details) (Stock Options [Member], USD $)	12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2014
Stock Options [Member]
Outstanding at December 31, 2013	6,446
Options, Exercised	-1,417
Options, Expired	-528
Options, Forfeited	-283
Outstanding at December 31, 2014	4,218
Vested and expected to vest, options	4,201
Exercisable, options	3,969
Weighted average exercise price, Outstanding, December 31, 2013	$69.35
Exercised, weighted average exercise price	$65.55
Expired, weighted average exercise price	$70.64
Forfeited, weighted average exercise price	$67.86
Weighted average exercise price, Outstanding, December 31, 2014	$70.56
Vested and expected to vest, weighted average exercise price	$70.57
Exercisable, weighted average exercise price	$70.80
Outstanding, weighted average remaining term	3 years 1 month 10 days
Vested and expected to vest, weighted average remaining term	3 years 1 month 6 days
Exercisable, weighted average remaining term	3 years
Outstanding, intrinsic value	$1
Vested and expected to vest, intrinsic value	1
Exercisable, intrinsic value	$1

ShareBased_Compensation_Summar2

Share-Based Compensation (Summary Of Unvested Restricted Stock Awards And Units, Including Changes During The Year) (Details) (Restricted Stock Awards And Units [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2013	3,292
Granted, awards and units	3,487
Vested, awards and units	-1,767
Forfeited, awards and units	-708
Unvested at December 31, 2014	4,304
Unvested weighted average grant-date fair value at December 31, 2013	$59.76
Granted, weighted average grant-date fair value	$62.75
Vested, weighted average grant-date fair value	$60.23
Forfeited, weighted average grant-date fair value	$60.47
Unvested weighted average grant-date fair value at December 31, 2014	$60.85

ShareBased_Compensation_Summar3

Share-Based Compensation (Summary Of Performance-Based Restricted Stock Awards) (Details) (Performance-Based Restricted Stock Awards [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2012
Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2013	316
Granted, awards	234
Vested, awards	-170	0
Unvested at December 31, 2014	380
Unvested weighted average grant-date fair value at December 31, 2013	$56.25
Granted, weighted average grant-date fair value	$61.33
Vested, weighted average grant-date fair value	$56.18
Unvested weighted average grant-date fair value at December 31, 2014	$59.41

ShareBased_Compensation_Summar4

Share-Based Compensation (Summary Of The Grant Date Fair Values Of Performance Share Units) (Details) (Performance Share Units [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, weighted average grant-date fair value	$77.77
Volatility factor	28.80%	30.30%	30.30%
Contractual term (in years)	2 years 10 months 21 days	3 years	3 years
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, weighted average grant-date fair value	$70.18	61.27	61.27
Risk-free interest rate		0.26%	0.26%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, weighted average grant-date fair value	$81.05	63.48	63.48
Risk-free interest rate	0.54%	0.36%	0.36%

ShareBased_Compensation_Summar5

Share-Based Compensation (Summary of Performance Share Units, Including Changes During the Year) (Details) (Performance Share Units [Member], USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2013	925,000
Granted, units	708,000
Forfeited, units	-156,000
Unvested at December 31, 2014	1,477,000	[1]
Unvested weighted average grant-date fair value at December 31, 2013	$66.64
Granted, weighted average grant-date fair value	$77.77
Forfeited, weighted average grant-date fair value	$76.59
Unvested weighted average grant-date fair value at December 31, 2014	$70.90	[1]
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, weighted average grant-date fair value	$81.05		$63.48	$63.48
Maximum common shares awarded based upon total shareholder return	3,000,000
[1]	A maximum of 3.0 millionB common shares could be awarded based upon Devonbs final TSR ranking.

Asset_Impairments_Summary_of_A

Asset Impairments (Summary of Asset Impairments) (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill, Impairment Loss		$1,941	$0	$0
Goodwill, Impairment Loss, Net of Tax		1,941
Asset impairment charges, gross	1,900	1,953	1,976	2,024
Asset impairment charges, after taxes		1,948	1,353	1,308
U.S. Oil And Gas Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges, gross			1,110	1,793
Asset impairment charges, after taxes			707	1,142
Canada Oil And Gas Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges, gross			843	163
Asset impairment charges, after taxes			632	122
Midstream Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges, gross		12	23	68
Asset impairment charges, after taxes		$7	$14	$44

Restructuring_Costs_Narrative_

Restructuring Costs (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$46	$54	$74
Office Consolidation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred to date		134
Offshore Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred to date			196
Employee Related And Other Costs [Member] | Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges	46
Accelerated Vesting Of Share-Based Grants For Employees [Member] | Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$15

Restructuring_Costs_Schedule_O

Restructuring Costs (Schedule Of The Components Of Restructuring Costs Included In The Comprehensive Consolidated Statements Of Earnings) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restructuring Cost and Reserve [Line Items]
Restructuring costs	$46	$54	$74
Employee Severance And Retention [Member] | Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	42
Employee Severance And Retention [Member] | Office Consolidation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs		13	77
Employee Severance And Retention [Member] | Offshore Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs			-3
Lease Obligations And Other [Member] | Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	4
Lease Obligations And Other [Member] | Office Consolidation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs		41	3
Lease Obligations And Other [Member] | Offshore Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs			($3)

Restructuring_Costs_Schedule_O1

Restructuring Costs (Schedule Of The Activity And Balances Associated With Restructuring Liabilities) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restructuring Cost and Reserve [Line Items]
Beginning balance			$61
Ending balance	20	45	61
Other Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Beginning balance			52
Ending balance	13	27	52
Other Long-Term Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Beginning balance			9
Ending balance	7	18	9
Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	4
Canadian Divestitures [Member] | Other Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	4
Office Consolidation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	-25	-11
Office Consolidation [Member] | Other Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	-15	-22
Office Consolidation [Member] | Other Long-Term Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	-10	11
Offshore Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	-4	-5
Offshore Divestiture [Member] | Other Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	-3	-3
Offshore Divestiture [Member] | Other Long-Term Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	($1)	($2)

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax [Line Items]
Current income tax expense (benefit)		$477,000,000	$72,000,000	$52,000,000
Current income tax expense (benefit) on repatriation after foreign tax credits		67,000,000
Foreign earnings repatriated	2,800,000,000	2,800,000,000	4,300,000,000
Deferred income tax expense (benefit)		1,891,000,000	97,000,000	-184,000,000
Deferred tax liabilities, taxes on unremitted foreign earnings		6,000,000	157,000,000
Deferred tax liability on formation of EnLink		154,000,000	52,000,000
Income tax expense (benefit)		2,368,000,000	169,000,000	-132,000,000
Unremitted foreign earnings		1,800,000,000
Unremitted earnings from subsidiaries not to be permanently reinvested		22,000,000
Deferred tax assets, net operating loss carryforwards		200,000,000	183,000,000
Deferred tax assets, foreign tax credits			248,000,000
Deferred tax assets, alternative minimum tax credits		57,000,000	105,000,000
Unrecognized tax benefits, interest and penalties		34,000,000	32,000,000
Unrecognized tax benefit that would impact effective tax rate		223,000,000
Tax Scenario One [Member]
Income Tax [Line Items]
Deferred income tax expense (benefit)			-83,000,000
Tax Scenario Two [Member]
Income Tax [Line Items]
Deferred income tax expense (benefit)			-180,000,000
Tax Scenario Three [Member]
Income Tax [Line Items]
Deferred income tax expense (benefit)			97,000,000
Assumed Repatriations Of Foreign Earnings [Member]
Income Tax [Line Items]
Deferred tax liabilities, taxes on unremitted foreign earnings		143,000,000
Repatriated Foreign Earnings [Member]
Income Tax [Line Items]
Current income tax expense (benefit)		105,000,000	180,000,000
Deferred income tax expense (benefit)			-83,000,000
Income tax expense (benefit)			97,000,000
Canada Federal [Member]
Income Tax [Line Items]
Deferred tax assets, Canadian net operating loss carryforward		621,000,000
Various U.S. States [Member]
Income Tax [Line Items]
Deferred tax assets, State net operating loss carryforward		180,000,000
Minimum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date		31-Dec-29
Operating loss carryforward, utilization period		31-Dec-15
Minimum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date		31-Dec-18
Operating loss carryforward, utilization period		31-Dec-17
Maximum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date		31-Dec-34
Operating loss carryforward, utilization period		31-Dec-17
Maximum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date		31-Dec-32
Operating loss carryforward, utilization period		31-Dec-29
U.S. Asset Divestiture [Member]
Income Tax [Line Items]
Current income tax expense (benefit)		294,000,000
EnLink [Member]
Income Tax [Line Items]
Deferred tax liability on formation of EnLink		46,000,000
Deferred tax assets, net operating loss carryforwards		$135,000,000
Operating loss carryforward, utilization period		31-Dec-15
EnLink [Member] | Minimum [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date		31-Dec-28
EnLink [Member] | Maximum [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date		31-Dec-34

Income_Taxes_Schedule_Of_Incom

Income Taxes (Schedule Of Income Tax Expense (Benefit)) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current income tax expense (benefit):
United States federal, current income tax expense (benefit)	$152	$73	$60
Various states, current income tax expense (benefit)	18	-5	-3
Canada and various provinces, current income tax expense (benefit)	307	4	-5
Total current tax (benefit) expense	477	72	52
Deferred income tax expense (benefit):
United States federal, deferred income tax expense (benefit)	1,610	198	-188
Various states, deferred income tax expense (benefit)	93	59	34
Canada and various provinces, deferred income tax expense (benefit)	188	-160	-30
Total deferred tax expense (benefit)	1,891	97	-184
Total income tax expense (benefit)	$2,368	$169	($132)

Income_Taxes_Schedule_Of_Effec

Income Taxes (Schedule Of Effective Income Tax Reconciliation) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
Total income tax expense (benefit)	$2,368	$169	($132)
U.S. statutory income tax rate	35.00%	35.00%	-35.00%
Non-deductible goodwill transactions	23.00%	0.00%	0.00%
Taxation on Canadian operations	-4.00%	9.00%	-6.00%
State income taxes	2.00%	23.00%	6.00%
Repatriations	2.00%	65.00%	0.00%
Taxes on EnLink formation	1.00%	0.00%	0.00%
Other	-1.00%	-19.00%	-7.00%
Effective income tax rate	58.00%	113.00%	-42.00%

Income_Taxes_Schedule_Of_Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Income Taxes [Abstract]
Deferred tax assets, asset retirement obligations	$458	$673
Deferred tax assets, foreign tax credits		248
Deferred tax assets, net operating loss carryforwards	200	183
Deferred tax assets, alternative minimum tax credits	57	105
Deferred tax assets, pension benefit obligations	113	104
Deferred tax assets, other	273	163
Total deferred tax assets	1,101	1,476
Deferred tax liabilities, property and equipment	-6,940	-5,895
Deferred tax liabilities, long-term debt	-115	-161
Deferred tax liabilities, taxes on unremitted foreign earnings	-6	-157
Deferred tax liabilities, fair value of financial instruments	-699	-7
Deferred tax liabilities, other	-154	-52
Total deferred tax liabilities	-7,914	-6,272
Net deferred tax liability	($6,813)	($4,796)

Income_Taxes_Schedule_Of_Chang

Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Abstract]
Unrecognized tax benefits, Balance at beginning year	$243	$216
Unrecognized tax benefits, Tax positions taken in prior periods		-17
Unrecognized tax benefits, Tax positions taken in current year		42
Unrecognized tax benefits, Accrual of interest related to tax positions taken	2	5
Unrecognized tax benefits, Foreign currency translation	-4	-3
Unrecognized tax benefits, Balance at end of year	$241	$243

Income_Taxes_Summary_Of_The_Ta

Income Taxes (Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities) (Details)	12 Months Ended
	Dec. 31, 2014
United States Federal [Member] | Minimum [Member]
Tax years open	2008
United States Federal [Member] | Maximum [Member]
Tax years open	2014
Various U.S. States [Member] | Minimum [Member]
Tax years open	2008
Various U.S. States [Member] | Maximum [Member]
Tax years open	2014
Canada Federal [Member] | Minimum [Member]
Tax years open	2004
Canada Federal [Member] | Maximum [Member]
Tax years open	2014
Various Canadian Provinces [Member] | Minimum [Member]
Tax years open	2004
Various Canadian Provinces [Member] | Maximum [Member]
Tax years open	2014

Net_Earnings_Loss_Per_Share_At2

Net Earnings (Loss) Per Share Attributable To Devon (Earnings Per Share Computations) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net earnings (loss) per share attributable to Devon:
Net earnings (loss) attributable to Devon	($408)	$1,016	$675	$324	$207	$429	$683	($1,339)	$1,607	($20)	($206)
Net earnings (loss) attributable to Devon, Common Shares									409	406	404
Attributable to participating securities, Earnings (loss)									-17	-2	-3
Attributable to participating securities, Common Shares									-4	-4	-4
Basic net earnings (loss) per share, Earnings (loss)									1,590	-22	-209
Basic net earnings (loss) per share, Common Shares									405	402	400
Basic net earnings (loss) per share	($1.01)	$2.48	$1.65	$0.80	$0.51	$1.06	$1.69	($3.34)	$3.93	($0.06)	($0.52)
Dilutive effect of potential common shares issuable, Common Shares									2
Diluted net earnings (loss) per share, Earnings (loss)									$1,590	($22)	($209)
Diluted net earnings (loss) per share, Common Shares									407	402	400
Diluted net earnings (loss) per share	($1.01)	$2.47	$1.64	$0.79	$0.51	$1.05	$1.68	($3.34)	$3.91	($0.06)	($0.52)
Antidilutive securities excluded from computation of earnings per share, amount									3	7	9

Other_Comprehensive_Earnings_C

Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Foreign currency translation:
Beginning accumulated foreign currency translation	$1,448		$1,996		$1,802
Change in cumulative translation adjustment	-499		-574		203
Income tax benefit (expense)	34		26		-9
Ending accumulated foreign currency translation	983		1,448		1,996
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits	-180		-225		-227
Net actuarial gain (loss) and prior service cost arising in current year	-57		48		-47
Recognition of net actuarial loss and prior service cost in earnings	20	[1]	24	[1]	51	[1]
Income tax benefit (expense)	13		-27		-2
Ending accumulated pension and postretirement benefits	-204		-180		-225
Accumulated other comprehensive earnings, net of tax	$779		$1,268		$1,771
[1]	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying consolidated comprehensive statements of earnings (see Note 15 note for additional details).

Supplemental_Information_To_Ca

Supplemental Information To Cash Flows (Schedule Of Supplemental To Cash Flow Information) (Details) (USD $)	12 Months Ended			0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 07, 2014
Net change in working capital accounts:
Accounts receivable	$128	($288)	$140
Income taxes receivable	-467	29	-55
Other current assets	-222	20	-73
Accounts payable	-68	26	-8
Revenues and royalties payable	133	35	19
Other current liabilities	546	-120	-73
Net change in working capital	50	-298	-50
Interest paid (net of capitalized interest)	514	406	334
Income taxes paid (received)	899	13	100
General Partner And Enlink [Member]
Net change in working capital accounts:
Cash payment to acquire interest				$100

Accounts_Receivable_Schedule_O

Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	$1,975	$1,531
Joint interest billings	475	447
Other	71	61
Allowance for doubtful accounts	-16	-11
Net accounts receivable	1,959	1,520
Oil, Gas And NGL Sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	723	851
Marketing And Midstream Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	$706	$172

Goodwill_And_Other_Intangible_2

Goodwill And Other Intangible Assets (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Goodwill	$6,303	$5,858	$6,079
Acquired during period	3,283
Removal of goodwill for asset divestitures	706	26
Goodwill impairments	1,941	0	0
Customer Relationships [Member]
Goodwill [Line Items]
Customer relationships, Gross amount	569
Customer relationships, Accumulated amortization	36
Weighted average amortization period	13 years 8 months 12 days
Amortization expense of intangible assets	36
Canada [Member]
Goodwill [Line Items]
Goodwill		2,838	3,033
Removal of goodwill for asset divestitures	706
Goodwill impairments	1,941
EnLink [Member]
Goodwill [Line Items]
Goodwill	3,685	402	402
Acquired during period	$3,283

Goodwill_And_Other_Intangible_3

Goodwill And Other Intangible Assets (Schedule Of Goodwill By Reporting Segment) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Goodwill	$6,303	$5,858	$6,079
Acquired during period	3,283
Impairment loss	-1,941	0	0
Written off related to sale of assets	-706	-26
Translation adjustments	-191	-195
United States [Member]
Goodwill [Line Items]
Goodwill	2,618	2,618	2,644
Written off related to sale of assets		-26
Canada [Member]
Goodwill [Line Items]
Goodwill		2,838	3,033
Impairment loss	-1,941
Written off related to sale of assets	-706
Translation adjustments	-191	-195
EnLink [Member]
Goodwill [Line Items]
Goodwill	3,685	402	402
Acquired during period	$3,283

Goodwill_And_Other_Intangible_4

Goodwill And Other Intangible Assets (Schedule Of Goodwill By Reporting Units) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2012
Goodwill [Line Items]
Goodwill, Beginning Balance	$5,858	$6,079
Acquired during period	3,283
Goodwill, Ending Balance	6,303	6,079
General Partner And Enlink [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	402
Acquired during period	3,283
Goodwill, Ending Balance	3,685
General Partner And Enlink [Member] | Texas [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	326
Acquired during period	842
Goodwill, Ending Balance	1,168
General Partner And Enlink [Member] | Louisiana [Member]
Goodwill [Line Items]
Acquired during period	787
Goodwill, Ending Balance	787
General Partner And Enlink [Member] | Oklahoma [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	76
Acquired during period	114
Goodwill, Ending Balance	190
General Partner And Enlink [Member] | Ohio River Valley [Member]
Goodwill [Line Items]
Acquired during period	113
Goodwill, Ending Balance	113
General Partner And Enlink [Member] | General Partner [Member]
Goodwill [Line Items]
Acquired during period	1,427
Goodwill, Ending Balance	$1,427

Goodwill_And_Other_Intangible_5

Goodwill And Other Intangible Assets (Schedule Of Future Amortization Expense) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Goodwill And Other Intangible Assets [Abstract]
2015	$45
2016	45
2017	45
2018	45
2019	$44

Debt_And_Related_Expenses_Narr

Debt And Related Expenses (Narrative) (Details) (USD $)

0 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

Nov. 13, 2014

31-May-12

Jul. 31, 2011

Jan. 31, 2009

Mar. 31, 2002

Jun. 30, 2014

Dec. 31, 2014

Dec. 31, 2013

Nov. 30, 2014

Feb. 28, 2014

Mar. 07, 2014

Mar. 19, 2014

Nov. 12, 2014

Feb. 05, 2015

Debt Instrument [Line Items]

Outstanding commercial paper

$932,000,000

$1,317,000,000

Repayment of commercial paper

700,000,000

Early retirement of senior notes

1,900,000,000

Financing cost of early retirement of debt.

48,000,000

Proceeds from Unsecured Notes Payable

2,465,000,000

2,221,000,000

1,187,000,000

986,000,000

Senior Credit Facility [Member]

Debt Instrument [Line Items]

Credit Facility, borrowing capacity

3,000,000,000

Outstanding Credit Facility borrowings

0

Covenant description

This covenant requires Devon's ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments.

Debt-to-capitalization ratio

20.9

Credit facility, facility fee

3,800,000

Credit facility, frequency of facility fee payment

annual

Senior Credit Facility Two [Member]

Debt Instrument [Line Items]

Credit Facility, borrowing capacity

30,000,000

Line of credit facility expiration date

24-Oct-17

Senior Credit Facility Three [Member]

Debt Instrument [Line Items]

Credit Facility, borrowing capacity

164,000,000

Line of credit facility expiration date

24-Oct-18

Senior Credit Facility Four [Member]

Debt Instrument [Line Items]

Credit Facility, borrowing capacity

2,800,000,000

Line of credit facility expiration date

24-Oct-19

Commercial Paper [Member]

Debt Instrument [Line Items]

Average borrowing rate on commercial paper borrowings

0.44%

Credit Facility, borrowing capacity

3,000,000,000

2.40% due July 15, 2016 [Member]

Debt Instrument [Line Items]

Early retirement of senior notes

500,000,000

Debt instrument, face amount

500,000,000

[1]

Debt, maturity date

15-Jul-16

15-Jul-16

Debt interest rate, stated percentage

2.40%

2.40%

Long term debt, gross

500,000,000

1.20% Due December 15, 2016 [Member]

Debt Instrument [Line Items]

Early retirement of senior notes

650,000,000

Debt, maturity date

15-Dec-16

15-Dec-16

Debt interest rate, stated percentage

1.20%

1.20%

1.875% due May 15, 2017 [Member]

Debt Instrument [Line Items]

Early retirement of senior notes

750,000,000

Debt, maturity date

15-May-17

15-May-17

Debt interest rate, stated percentage

1.88%

1.88%

Long term debt, gross

750,000,000

Floating Rate due December 15, 2015 [Member]

Debt Instrument [Line Items]

Debt, maturity date

15-Dec-15

15-Dec-15

Floating Rate Due December 15, 2016 [Member]

Debt Instrument [Line Items]

Debt, maturity date

15-Dec-16

15-Dec-16

Long term debt, gross

350,000,000

Senior Notes [Member]

Debt Instrument [Line Items]

Unamortized discount

2,000,000

Unamortized debt issue cost

6,000,000

Make Whole Premium [Member]

Debt Instrument [Line Items]

Financing cost of early retirement of debt.

40,000,000

General Partner [Member] | Credit Facility [Member]

Debt Instrument [Line Items]

Credit Facility, borrowing capacity

250,000,000

Outstanding Credit Facility borrowings

0

Line of credit facility expiration date

7-Mar-19

Covenant description

The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i)B maintaining a maximum consolidated leverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other noncash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the credit facility) and (ii)B maintaining a minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other noncash charges to consolidated interest charges) of 2.50 to 1.00 at all times unless an investment grade event (as defined in the credit facility) occurs. EnLink and the General Partner are in compliance with all such covenants as of December 31, 2014.

Minimum [Member] | Commercial Paper [Member]

Debt Instrument [Line Items]

Commercial paper, maturity duration

1 day

Minimum [Member] | General Partner [Member] | Credit Facility [Member]

Debt Instrument [Line Items]

Ratio of consolidated earnings to consolidated interest charges

2.5

Maximum [Member] | Senior Credit Facility [Member]

Debt Instrument [Line Items]

Debt-to-capitalization ratio

65

Maximum [Member] | Commercial Paper [Member]

Debt Instrument [Line Items]

Commercial paper, maturity duration

365 days

Maximum [Member] | General Partner [Member] | Credit Facility [Member]

Debt Instrument [Line Items]

Consolidated leverage ratio

4

Maximum [Member] | General Partner [Member] | Credit Facility [Member] | Acquisition Period [Member]

Debt Instrument [Line Items]

Consolidated leverage ratio

4.5

GeoSouthern Intermediate Holdings, LLC [Member]

Debt Instrument [Line Items]

Aggregate purchase price of acquisitions

6,000,000,000

Proceeds from Unsecured Notes Payable

2,248,000,000

GeoSouthern Intermediate Holdings, LLC [Member] | Fixed and Floating Senior Notes [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

2,250,000,000

GeoSouthern Intermediate Holdings, LLC [Member] | Term Loan [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

2,000,000,000

GeoSouthern Intermediate Holdings, LLC [Member] | 1.20% Due December 15, 2016 [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

650,000,000

[2]

Debt, maturity date

15-Dec-16

Debt interest rate, stated percentage

1.20%

GeoSouthern Intermediate Holdings, LLC [Member] | Floating Rate due December 15, 2015 [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

500,000,000

Debt, maturity date

15-Dec-15

Basis spread on LIBOR rate

0.45%

GeoSouthern Intermediate Holdings, LLC [Member] | Floating Rate Due December 15, 2016 [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

350,000,000

Debt, maturity date

15-Dec-16

Basis spread on LIBOR rate

0.54%

E2 Energy Services LLC [Member]

Debt Instrument [Line Items]

Promissory note for vehicle fleet

400,000

EnLink [Member]

Debt Instrument [Line Items]

Fair value of debt assumed

1,454,000,000

Long term debt, gross

2,023,000,000

EnLink [Member] | Unsecured Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Credit Facility, borrowing capacity

1,000,000,000

Credit Facility, remaining borrowing capacity

749,000,000

Outstanding Credit Facility borrowings

237,000,000

Covenant description

Among other things, these covenants include maintaining a ratio of EnLink's consolidated indebtedness to consolidated EBITDA (as defined in the credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If EnLink consummates one or more acquisitions in which the aggregate purchase price is $50 million or more, the maximum allowed ratio of EnLink's consolidated indebtedness to consolidated EBITDA may increase to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Aggregate purchase price of acquisitions

50,000,000

EnLink [Member] | Unsecured Letter Of Credit Subfacility [Member]

Debt Instrument [Line Items]

Outstanding Credit Facility borrowings

14,000,000

EnLink [Member] | Unsecured Senior Notes [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

1,200,000,000

EnLink [Member] | 2.70% due April 1, 2019 [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

400,000,000

Debt, maturity date

1-Apr-19

Debt interest rate, stated percentage

2.70%

Long term debt, gross

400,000,000

EnLink [Member] | 4.40% due April 1, 2024 [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

450,000,000

100,000,000

Debt, maturity date

1-Apr-24

Debt interest rate, stated percentage

4.40%

Long term debt, gross

550,000,000

EnLink [Member] | 5.60% due April 1, 2044 [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

350,000,000

Debt, maturity date

1-Apr-44

Debt interest rate, stated percentage

5.60%

Long term debt, gross

350,000,000

EnLink [Member] | 5.05% due April 1, 2045 [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

300,000,000

Debt, maturity date

1-Apr-45

Debt interest rate, stated percentage

5.05%

Long term debt, gross

300,000,000

EnLink [Member] | Maximum [Member] | Unsecured Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Ratio of consolidated indebtness

5

EnLink [Member] | Maximum [Member] | Unsecured Revolving Credit Facility [Member] | Acquisition Period [Member]

Debt Instrument [Line Items]

Ratio of consolidated indebtness

5.5

Subsequent Event [Member] | EnLink [Member] | Unsecured Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Credit Facility, borrowing capacity

$1,500,000,000

Line of credit facility expiration date

7-Mar-20

[1]

The 1.875% $750 million note due May 15, 2017 and 2.4% $500 million note due July 15, 2016 were redeemed on November 13, 2014.

[2]

The 1.20% $650 million note due December 15, 2016 was redeemed on November 13, 2014.

Debt_And_Related_Expenses_Sche

Debt And Related Expenses (Schedule Of Debt Instruments) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Commercial paper	$932		$1,317
Net discount on debentures and notes	-18		-20
Total debt	11,262		12,022
Less amount classified as short-term debt	1,432	[1]	4,066	[1]
Long-term debt	9,830		7,956
5.625% due January 15, 2014 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	5.63%		5.63%
Debt, maturity date	15-Jan-14		15-Jan-14
Short-term debt			500
Floating Rate due December 15, 2015 [Member]
Debt Instrument [Line Items]
Debt, maturity date	15-Dec-15		15-Dec-15
Short-term debt	500		500
2.40% due July 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	2.40%		2.40%
Debt, maturity date	15-Jul-16		15-Jul-16
Long term debt, gross			500
Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt, maturity date	15-Dec-16		15-Dec-16
Short-term debt			350
Long term debt, gross	350
1.20% Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	1.20%		1.20%
Debt, maturity date	15-Dec-16		15-Dec-16
Short-term debt			650
1.875% due May 15, 2017 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	1.88%		1.88%
Debt, maturity date	15-May-17		15-May-17
Long term debt, gross			750
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	8.25%		8.25%
Debt, maturity date	1-Jul-18		1-Jul-18
Long term debt, gross	125		125
2.25% Due December 15, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	2.25%		2.25%
Debt, maturity date	15-Dec-18		15-Dec-18
Short-term debt			750
Long term debt, gross	750
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	6.30%		6.30%
Debt, maturity date	15-Jan-19		15-Jan-19
Long term debt, gross	700		700
4.00% Due July 15, 2021 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	4.00%		4.00%
Debt, maturity date	15-Jul-21		15-Jul-21
Long term debt, gross	500		500
3.25% due May 15, 2022 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	3.25%		3.25%
Debt, maturity date	15-May-22		15-May-22
Long term debt, gross	1,000		1,000
7.50% due September 15, 2027 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.50%		7.50%
Debt, maturity date	15-Sep-27		15-Sep-27
Long term debt, gross	150		150
7.875% due September 30, 2031 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.88%		7.88%
Debt, maturity date	30-Sep-31		30-Sep-31
Long term debt, gross	1,250		1,250
7.95% due April 15, 2032 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.95%		7.95%
Debt, maturity date	15-Apr-32		15-Apr-32
Long term debt, gross	1,000		1,000
5.60% due July 15, 2041 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	5.60%		5.60%
Debt, maturity date	15-Jul-41		15-Jul-41
Long term debt, gross	1,250		1,250
4.75% due May 15, 2042 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	4.75%		4.75%
Debt, maturity date	15-May-42		15-May-42
Long term debt, gross	750		750
Senior Notes For Acquisition of GeoSouthern [Member]
Debt Instrument [Line Items]
Short-term debt			2,250
Devon Energy Corporation [Member]
Debt Instrument [Line Items]
Total debt	9,239		12,022
GeoSouthern Intermediate Holdings, LLC [Member] | Floating Rate due December 15, 2015 [Member]
Debt Instrument [Line Items]
Debt, maturity date	15-Dec-15
GeoSouthern Intermediate Holdings, LLC [Member] | Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt, maturity date	15-Dec-16
GeoSouthern Intermediate Holdings, LLC [Member] | 1.20% Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	1.20%
Debt, maturity date	15-Dec-16
GeoSouthern Intermediate Holdings, LLC [Member] | 2.25% Due December 15, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	2.25%
Debt, maturity date	15-Dec-18
EnLink [Member]
Debt Instrument [Line Items]
Long term debt, gross	2,023
Net premium on debentures and notes	23
EnLink [Member] | Credit Facilities [Member]
Debt Instrument [Line Items]
Long term debt, gross	237
EnLink [Member] | 2.70% due April 1, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	2.70%
Debt, maturity date	1-Apr-19
Long term debt, gross	400
EnLink [Member] | 7.125% due June 1, 2022 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.13%
Debt, maturity date	1-Jun-22
Long term debt, gross	163
EnLink [Member] | 4.40% due April 1, 2024 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	4.40%
Debt, maturity date	1-Apr-24
Long term debt, gross	550
EnLink [Member] | 5.60% due April 1, 2044 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	5.60%
Debt, maturity date	1-Apr-44
Long term debt, gross	350
EnLink [Member] | 5.05% due April 1, 2045 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	5.05%
Debt, maturity date	1-Apr-45
Long term debt, gross	$300
[1]	2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015. 2013 short-term debt consists of $2.25 billion of senior notes issued in conjunction with the GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014.

Debt_And_Related_Expenses_Sche1

Debt And Related Expenses (Schedule Of Debt Maturities) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Debt And Related Expenses [Abstract]
2015	$1,432
2016	350
2018	875
2019	1,337
2020 and thereafter	7,263
Total debt	$11,257

Debt_And_Related_Expenses_Sche2

Debt And Related Expenses (Schedule Of Debt For GeoSouthern Acquisition) (Details) (USD $)	0 Months Ended	1 Months Ended				12 Months Ended
	Nov. 13, 2014	31-May-12	Jul. 31, 2011	Jan. 31, 2009	Mar. 31, 2002	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Discount and issuance costs		($35,000,000)	($29,000,000)	($13,000,000)	($14,000,000)
Net proceeds		2,465,000,000	2,221,000,000	1,187,000,000	986,000,000
Early retirement of senior notes	1,900,000,000
Floating Rate due December 15, 2015 [Member]
Debt Instrument [Line Items]
Debt, maturity date						15-Dec-15		15-Dec-15
Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt, maturity date						15-Dec-16		15-Dec-16
1.20% Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage						1.20%		1.20%
Debt, maturity date						15-Dec-16		15-Dec-16
Early retirement of senior notes						650,000,000
2.25% Due December 15, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage						2.25%		2.25%
Debt, maturity date						15-Dec-18		15-Dec-18
GeoSouthern Intermediate Holdings, LLC [Member]
Debt Instrument [Line Items]
Discount and issuance costs						-2,000,000
Net proceeds						2,248,000,000
GeoSouthern Intermediate Holdings, LLC [Member] | Floating Rate due December 15, 2015 [Member]
Debt Instrument [Line Items]
Debt, maturity date						15-Dec-15
Principal amount of senior notes issued						500,000,000
GeoSouthern Intermediate Holdings, LLC [Member] | Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt, maturity date						15-Dec-16
Principal amount of senior notes issued						350,000,000
GeoSouthern Intermediate Holdings, LLC [Member] | 1.20% Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage						1.20%
Debt, maturity date						15-Dec-16
Principal amount of senior notes issued						650,000,000	[1]
GeoSouthern Intermediate Holdings, LLC [Member] | 2.25% Due December 15, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage						2.25%
Debt, maturity date						15-Dec-18
Principal amount of senior notes issued						750,000,000
[1]	The 1.20% $650 million note due December 15, 2016 was redeemed on November 13, 2014.

Debt_And_Related_Expenses_Sche3

Debt And Related Expenses (Schedule Of Other Debt And Debentures) (Details) (USD $)	0 Months Ended	1 Months Ended							12 Months Ended
	Nov. 13, 2014	31-May-12		Jul. 31, 2011		Jan. 31, 2009		Mar. 31, 2002	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Discount and issuance costs		($35,000,000)		($29,000,000)		($13,000,000)		($14,000,000)
Net proceeds		2,465,000,000		2,221,000,000		1,187,000,000		986,000,000
Early retirement of senior notes	1,900,000,000
1.875% Due May 15, 2017 [Member]
Debt Instrument [Line Items]
Principal amount of senior notes issued		750,000,000	[1]
3.25% Due May 15, 2022 [Member]
Debt Instrument [Line Items]
Principal amount of senior notes issued		1,000,000,000
4.75% Due May 15, 2042 [Member]
Debt Instrument [Line Items]
Principal amount of senior notes issued		750,000,000
2.40% due July 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage									2.40%	2.40%
Debt, maturity date									15-Jul-16	15-Jul-16
Principal amount of senior notes issued				500,000,000	[1]
Early retirement of senior notes									500,000,000
4.00% Due July 15, 2021 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage									4.00%	4.00%
Debt, maturity date									15-Jul-21	15-Jul-21
Principal amount of senior notes issued				500,000,000
5.60% Due July 15, 2041 [Member]
Debt Instrument [Line Items]
Principal amount of senior notes issued				1,250,000,000
5.625% due January 15, 2014 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage									5.63%	5.63%
Debt, maturity date									15-Jan-14	15-Jan-14
Principal amount of senior notes issued						500,000,000	[2]
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage									6.30%	6.30%
Debt, maturity date									15-Jan-19	15-Jan-19
Principal amount of senior notes issued						700,000,000
7.95% Due April 15, 2032 [Member]
Debt Instrument [Line Items]
Principal amount of senior notes issued								$1,000,000,000
[1]	The 1.875% $750 million note due May 15, 2017 and 2.4% $500 million note due July 15, 2016 were redeemed on November 13, 2014.
[2]	The 5.625% $500 million note due January 15, 2014 was redeemed upon maturity.

Debt_And_Related_Expenses_Sche4

Debt And Related Expenses (Schedule Of Debt Assumed) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Apr. 25, 2003
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	8.25%	8.25%
Debt, maturity date	1-Jul-18	1-Jul-18
Principal amount of senior notes issued			$125,000,000
Fair Value of Debt Assumed	147,000,000
Effective rate of debt	5.50%
7.50% due September 15, 2027 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.50%	7.50%
Debt, maturity date	15-Sep-27	15-Sep-27
Principal amount of senior notes issued			150,000,000
Fair Value of Debt Assumed	$169,000,000
Effective rate of debt	6.50%

Debt_And_Related_Expenses_Sche5

Debt And Related Expenses (Schedule Of Fair Value of Enlink's Debt) (Details) (EnLink [Member], USD $)	0 Months Ended		12 Months Ended
	Mar. 07, 2014		Dec. 31, 2014	Mar. 07, 2014
Debt Instrument [Line Items]
Fair value of debt	$1,454,000,000
8.875% Due February 15, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage			8.88%
Debt, maturity date			15-Feb-18
Debt instrument, face amount	725,000,000			725,000,000
Fair value of debt	760,000,000	[1]
Effective rate of debt	7.70%	[1]		7.70%	[1]
7.125% due June 1, 2022 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage			7.13%
Debt, maturity date			1-Jun-22
Debt instrument, face amount	197,000,000			197,000,000
Fair value of debt	226,000,000
Effective rate of debt	5.30%			5.30%
Credit Facilities [Member]
Debt Instrument [Line Items]
Fair value of debt	$468,000,000
[1]	The 2018 senior notes were redeemed on April 18, 2014.

Debt_And_Related_Expenses_Sche6

Debt And Related Expenses (Schedule Of Net Financing Cost Components) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt And Related Expenses [Abstract]
Interest based on debt outstanding	$546	$466	$440
Early retirement of debt	48
Capitalized interest	-70	-56	-48
Other fees and expenses	12	27	14
Interest expense	536	437	406
Interest income	-10	-20	-36
Net financing costs	$526	$417	$370

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations [Abstract]
Asset retirement obligations as of beginning of period	$2,228	$2,095
Liabilities incurred	97	112
Liabilities settled	-56	-83
Revision of estimated obligation	70	104
Liabilities assumed by others	-953	-28
Accretion expense on discounted obligation	89	115
Foreign currency translation adjustment	-76	-87
Asset retirement obligations as of end of period	1,399	2,228
Less current portion	60	88
Asset retirement obligations, long-term	$1,339	$2,140

Retirement_Plans_Narrative_Det

Retirement Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Value of trusts established for certain supplemental plans	$25,000,000	$27,000,000
Increase in benefit obligations as a result of discount rate decrease	135,000,000
Increase in benefit obligations as a result of the mortality rate assumption update	61,000,000
Effect on accumulated postretirement benefit obligation of 1% change in assumed health care cost rates	1,000,000
Effect on service cost and interest costs of 1% change in assumed health care cost rates	1,000,000
Pension benefits to be funded from the trust	10,000,000
Postretirement benefits expected to be funded from cash and cash equivalents	3,000,000
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	1,200,000,000	1,100,000,000
Employer contributions transferred from trusts	$10,000,000	$11,000,000
Assumed compensation increase percentage	4.49%	4.48%	4.48%
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan health care cost trend rate assumed for next fiscal year	7.70%
Defined benefit plan ultimate health care cost trend rate	5.00%

Retirement_Plans_Schedule_Of_C

Retirement Plans (Schedule Of Changes In Defined Benefit Plan Obligations) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	$1,177	$1,360
Service cost	30	36	43
Interest cost	55	51	60
Actuarial loss (gain)	203	-158
Plan amendments		2
Plan settlements	-4
Foreign exchange rate changes	-3	-2
Benefits paid	-81	-112
Benefit obligation at end of year	1,377	1,177	1,360
Change in plan assets:
Fair value of plan assets at beginning of year	1,006	1,165
Actual return on plan assets	200	-57
Employer contributions	29	11
Plan settlements	-4
Benefits paid	-81	-112
Foreign exchange rate changes	-1	-1
Fair value of plan assets at end of year	1,149	1,006	1,165
Funded status at end of year	-228	-171
Amounts recognized in balance sheet:
Other long-term assets	22	47
Other current liabilities	-10	-12
Other long-term liabilities	-240	-206
Net amount	-228	-171
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	317	279
Post service cost (credit)	19	23
Total	336	302
Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	24	34
Service cost	1	1	1
Interest cost	1	1	1
Actuarial loss (gain)		-3
Plan amendments		-8
Plan settlements
Participant contributions	2	3
Benefits paid	-4	-4
Benefit obligation at end of year	24	24	34
Change in plan assets:
Employer contributions	2	1
Participant contributions	2	3
Plan settlements
Benefits paid	-4	-4
Funded status at end of year	-24	-24
Amounts recognized in balance sheet:
Other current liabilities	-3	-3
Other long-term liabilities	-21	-21
Net amount	-24	-24
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	-11	-13
Post service cost (credit)	-9	-11
Total	($20)	($24)

Retirement_Plans_Schedule_Of_P

Retirement Plans (Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Retirement Plans [Abstract]
Projected benefit obligation	$250	$218
Accumulated benefit obligation	191	179
Fair value of plan assets

Retirement_Plans_Schedule_Of_N

Retirement Plans (Schedule Of Net Periodic Benefit Cost And Other Comprehensive Income For Pension And Other Postretirement Benefit Plans) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Benefits [Member]
Net periodic benefit cost:
Service cost	$30		$36		$43
Interest cost	55		51		60
Expected return on plan assets	-54		-62		-64
Curtailment and settlement expense	1				26
Recognition of net actuarial loss (gain)	18	[1]	22	[1]	24	[1]
Recognition of prior service cost	4	[1]	4	[1]	3	[1]
Total net periodic benefit cost	54	[2]	51	[2]	92	[2]
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year	57		-39		37
Prior service cost (credit) arising in current year			2		14
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost	-19		-22		-45
Recognition of prior service cost, including curtailment, in net periodic benefit cost	-4		-4		-8
Total other comprehensive loss (earnings)	34		-63		-2
Total recognized	88		-12		90
Postretirement Benefits [Member]
Net periodic benefit cost:
Service cost	1		1		1
Interest cost	1		1		1
Curtailment and settlement expense					1
Recognition of net actuarial loss (gain)	-1	[1]	-1	[1]	-1	[1]
Recognition of prior service cost	-2	[1]	-1	[1]	-1	[1]
Total net periodic benefit cost	-1	[2]			1	[2]
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year			-3		-4
Prior service cost (credit) arising in current year			-8
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost	1		1		1
Recognition of prior service cost, including curtailment, in net periodic benefit cost	2		1		1
Total other comprehensive loss (earnings)	3		-9		-2
Total recognized	$2		($9)		($1)
[1]	These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
[2]	Net periodic benefit cost is a component of general and administrative expenses on the accompanying consolidated comprehensive statements of earnings.

Retirement_Plans_Schedule_Of_E

Retirement Plans (Schedule Of Estimated Net Actuarial Loss And Prior Service Cost For The Pension And Other Postretirement Plans That Will Be Amortized From Accumulated Other Comprehensive Income Into Net Periodic Benefit Cost During 2015) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$21
Prior service cost (credit)	4
Total	25
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	-1
Prior service cost (credit)	-2
Total	($3)

Retirement_Plans_Schedule_Of_W

Retirement Plans (Schedule Of Weighted Average Actuarial Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Costs) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	3.90%	4.80%	3.85%
Rate of compensation increase	4.49%	4.48%	4.48%
Assumptions to determine net periodic benefit cost:
Discount rate	4.80%	3.85%	4.65%
Rate of compensation increase	4.49%	4.48%	4.97%
Expected return on plan assets	5.42%	5.48%	5.48%
Postretirement Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	3.25%	3.65%	3.30%
Assumptions to determine net periodic benefit cost:
Discount rate	3.65%	3.30%	4.25%

Retirement_Plans_Schedule_Of_P1

Retirement Plans (Schedule Of Pension Plan Assets Target Allocation) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fixed Income [Member]
Target plan asset allocations	70.00%	70.00%
Equity Securities [Member]
Target plan asset allocations	20.00%	20.00%
Other Securities [Member]
Target plan asset allocations	10.00%	10.00%

Retirement_Plans_Schedule_of_F

Retirement Plans (Schedule of Fair Value of Pension Assets By Asset Class) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$112	$112	$103
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	100.00%	100.00%
Fair value of plan assets	1,149	1,006	1,165
Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	364	401
Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	673	493
Pension Benefits [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	112	112
Pension Benefits [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	69.50%	66.60%
Fair value of plan assets	799	670
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	349	386
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	450	284
Pension Benefits [Member] | United States Treasuries [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	35.20%	24.00%
Fair value of plan assets	405	241
Pension Benefits [Member] | United States Treasuries [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50	69
Pension Benefits [Member] | United States Treasuries [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	355	172
Pension Benefits [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	31.70%	39.50%
Fair value of plan assets	364	398
Pension Benefits [Member] | Corporate Bonds [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	269	286
Pension Benefits [Member] | Corporate Bonds [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	95	112
Pension Benefits [Member] | Other Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	2.60%	3.10%
Fair value of plan assets	30	31
Pension Benefits [Member] | Other Bonds [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30	31
Pension Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	17.20%	19.00%
Fair value of plan assets	197	190
Pension Benefits [Member] | Equity Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	197	190
Pension Benefits [Member] | Other Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	13.30%	14.40%
Fair value of plan assets	153	146
Pension Benefits [Member] | Other Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	15	15
Pension Benefits [Member] | Other Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	26	19
Pension Benefits [Member] | Other Securities [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	112	112
Pension Benefits [Member] | Hedge Fund And Alternative Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	9.70%	12.50%
Fair value of plan assets	112	127
Pension Benefits [Member] | Hedge Fund And Alternative Investments [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		15
Pension Benefits [Member] | Hedge Fund And Alternative Investments [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	112	112
Pension Benefits [Member] | Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	3.60%	1.90%
Fair value of plan assets	41	19
Pension Benefits [Member] | Short-Term Investments [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	15
Pension Benefits [Member] | Short-Term Investments [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$26	$19

Recovered_Sheet1

Retirement Plans (Schedule of Changes In Level 3 Plan Assets) (Details) (Level 3 Inputs [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$112	$103
Disbursements	-6
Investment returns	6	9
Fair value of plan assets at end of year	$112	$112

Retirement_Plans_Schedule_Of_E1

Retirement Plans (Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Devon's 2015 contributions	$10
Benefit payments:
2015	73
2016	75
2017	79
2018	82
2019	86
2020 to 2024	466
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Devon's 2015 contributions	3
Benefit payments:
2015	3
2016	3
2017	3
2018	3
2019	2
2020 to 2024	$8

Retirement_Plans_Schedule_Of_E2

Retirement Plans (Schedule Of Expense Related To These Defined Contribution Plans) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	$69	$67	$59
401(k) Plan And Enhanced Contribution Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	49	41	36
Canadian Pension And Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	$20	$26	$23

Stockholders_Equity_Details

Stockholders' Equity (Details) (USD $)	3 Months Ended			12 Months Ended
In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stockholders' Equity [Abstract]
Common stock, shares authorized (in shares)				1,000,000,000	1,000,000,000
Common stock, par value (in dollars per share)				$0.10	$0.10
Preferred stock, shares authorized				4,500,000
Preferred stock par value per share				$1
Payments of ordinary dividends				$386	$348	$324
Dividends paid per share	$0.24	$0.22	$0.20
Proceeds from stock option exercises				$93	$3	$27

Noncontrolling_Interests_Detai

Noncontrolling Interests (Details) (USD $)	12 Months Ended	1 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Mar. 31, 2014	Mar. 07, 2014
Noncontrolling Interest [Line Items]
Proceeds from issuance of subsidiary units	$410
General Partner [Member]
Noncontrolling Interest [Line Items]
Ownership percentage	70.00%
EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage	49.00%	52.00%
Common units sold	14.8	120.5
Proceeds from issuance of subsidiary units	410
General Partner And Enlink [Member]
Noncontrolling Interest [Line Items]
Distribution to unitholders other than Devon	135
Public Unitholders [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Ownership percentage	30.00%
Public Unitholders [Member] | EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage	43.00%	41.00%
Common units sold		92.7
General Partner [Member] | EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage	8.00%	7.00%
General Partner And Enlink [Member]
Noncontrolling Interest [Line Items]
Cash payment to acquire interest			$100

Commitments_And_Contingencies_1

Commitments And Contingencies (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies [Abstract]
Obligation related to the purchase of condensate, year of expiration	2021
Total rental expense, including certain office space and equipment under operating lease agreements, net of sub-lease income	$64	$26	$42

Commitments_And_Contingencies_2

Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Purchase Obligations [Member]
Long-term Purchase Commitment [Line Items]
2015	$663
2016	809
2017	885
2018	920
2019	895
Thereafter	1,134
Total	5,306
Drilling And Facility Obligations [Member]
Long-term Purchase Commitment [Line Items]
2015	234
2016	116
2017	77
2018	13
2019	1
Thereafter	5
Total	446
Operational Agreements [Member]
Long-term Purchase Commitment [Line Items]
2015	943
2016	919
2017	890
2018	856
2019	334
Thereafter	1,142
Total	5,084
Office And Equipment Leases [Member]
Long-term Purchase Commitment [Line Items]
2015	72
2016	50
2017	50
2018	45
2019	39
Thereafter	149
Total	$405

Fair_Value_Measurements_Schedu

Fair Value Measurements (Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities) (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		$2,004	$103
Derivatives, liabilities		-57	-121
Redemptions of auction rate securities	57	57
Auction rate securities redeemed lower than carrying value	5
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		950	5,305
Debt		-11,262	-12,022
Capital lease obligations		-20
Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		950	5,305
Debt		-12,472	-12,908
Capital lease obligations		-20
Level 1 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		340	4,191
Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		610	1,114
Debt		-12,472	-12,908
Capital lease obligations		-20
Long-Term Investments [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments			62
Long-Term Investments [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments			62
Long-Term Investments [Member] | Level 3 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments			62
Oil, Gas And NGL Commodity Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1,968	103
Derivatives, liabilities		-51	-120
Oil, Gas And NGL Commodity Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1,968	103
Derivatives, liabilities		-51	-120
Oil, Gas And NGL Commodity Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1,968	103
Derivatives, liabilities		-51	-120
Midstream Commodity Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		27
Derivatives, liabilities		-5
Midstream Commodity Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		27
Derivatives, liabilities		-5
Midstream Commodity Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		27
Derivatives, liabilities		-5
Interest Rate Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1
Derivatives, liabilities		-1
Interest Rate Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1
Derivatives, liabilities		-1
Interest Rate Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1
Derivatives, liabilities		-1
Foreign Currency Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		8
Derivatives, liabilities			-1
Foreign Currency Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		8
Derivatives, liabilities			-1
Foreign Currency Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		8
Derivatives, liabilities			($1)

Discontinued_Operations_Narrat

Discontinued Operations (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues related to discontinued operations	$0
Angola [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on discontinued operations before tax	-16
Loss on discontinued operations after tax	($21)

Segment_information_Condensed_

Segment information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenues from external customers	$5,995	$5,336	$4,510	$3,725	$2,624	$2,714	$3,088	$1,971	$19,566	$10,397	$9,501
Depreciation, depletion and amortization									3,319	2,780	2,811
Asset impairments	1,900								1,953	1,976	2,024
Gains and losses on asset sales									-1,072	9	-13
Interest expense									536	437	406
Earnings (loss) before income taxes	291	1,654	1,554	560	475	639	997	-1,962	4,059	149	-317
Income tax expense (benefit)									2,368	169	-132
Net earnings (loss)									1,691	-20	-185
Net earnings (loss) attributable to noncontrolling interests									84
Net earnings (loss) attributable to Devon	-408	1,016	675	324	207	429	683	-1,339	1,607	-20	-206
Property and equipment, net	36,296				28,447				36,296	28,447	27,316
Total assets	50,637				42,877				50,637	42,877	43,326
Capital expenditures									13,559	6,643	8,474
Eliminations [Member]
Segment Reporting Information [Line Items]
Interest expense									-44	-35	-19
Total assets	-124								-124
Eliminations [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Revenues from external customers									-859	-1,362	-1,105
United States [Member]
Segment Reporting Information [Line Items]
Number of reportable segments									1
Revenues from external customers									14,862	6,807	6,098
Depreciation, depletion and amortization									2,479	1,744	1,679
Asset impairments									12	1,133	1,845
Gains and losses on asset sales									5
Interest expense									441	392	343
Earnings (loss) before income taxes									4,388	495	-372
Income tax expense (benefit)									1,797	258	-143
Net earnings (loss)									2,591	237	-229
Net earnings (loss) attributable to noncontrolling interests									1
Net earnings (loss) attributable to Devon									2,590
Property and equipment, net	24,572				18,201				24,572	18,201	16,622
Total assets	32,147				27,080				32,147	27,080	22,050
Capital expenditures									11,245	4,589	6,159
Canada [Member]
Segment Reporting Information [Line Items]
Revenues from external customers									2,063	2,656	2,600
Depreciation, depletion and amortization									560	849	987
Asset impairments									1,941	843	163
Gains and losses on asset sales									-1,077
Interest expense									85	80	82
Earnings (loss) before income taxes									-657	-532	-73
Income tax expense (benefit)									495	-156	-35
Net earnings (loss)									-1,152	-376	-38
Net earnings (loss) attributable to Devon									-1,152
Property and equipment, net	6,790				8,478				6,790	8,478	8,955
Total assets	8,517				13,560				8,517	13,560	19,070
Capital expenditures									1,344	1,841	1,963
EnLink [Member]
Segment Reporting Information [Line Items]
Revenues from external customers									2,641	934	803
Depreciation, depletion and amortization									280	187	145
Asset impairments											16
Interest expense									54
Earnings (loss) before income taxes									328	186	128
Income tax expense (benefit)									76	67	46
Net earnings (loss)									252	119	82
Net earnings (loss) attributable to noncontrolling interests									83
Net earnings (loss) attributable to Devon									169
Property and equipment, net	4,934				1,768				4,934	1,768	1,739
Total assets	10,097				2,237				10,097	2,237	2,206
Capital expenditures									970	213	352
EnLink [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Revenues from external customers									$859	$1,362	$1,105

Supplemental_Information_On_Oi2

Supplemental Information On Oil And Gas Operations (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
	MMBoe		MMBoe		MMBoe		MMBoe
Reserve Quantities [Line Items]
Commitment to fund future costs for joint venture	$250,000,000
Capitalized general and administrative expenses	376,000,000		368,000,000		359,000,000
Capitalized interest costs	-70,000,000		-56,000,000		-48,000,000
Proved undeveloped reserve (MMBoe)	689	[1]	701	[1]	840	[1]	782	[1]
Increase (decrease) in proved undeveloped reserves	-2.00%
Percentage of total proved reserves	25.00%
Increase (decrease) in proved undeveloped reserves due to drilling and development activities (MMBoe)	161
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)	89
Proved undeveloped reserves, revisions other than price (MMboe)	-43
Proved undeveloped reserves to proved developed reserves, conversion, percentage	13.00%
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	-65	[1]	-88	[1]	-68	[1]
Cost incurred related to development and conversion	1,000,000,000
Year development schedule will be complete	2031
Proved developed and undeveloped reserves, revisions due to prices (MMboe)	9	[1]	94	[1]	-171	[1]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	211	[1]	261	[1]	449	[1]
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities (MMBoe)	5		175		229
Proved developed and undeveloped reserves, purchase of reserves (MMboe)	265	[1]	1	[1]
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	-383	[1]	-15	[1]	-2	[1]
Oil and gas properties not subject to amortization	2,752,000,000
Average price per barrel of oil used to estimate proved oil reserves	87.14
Average price per barrel of bitumen used to estimate proved oil reserves	57.25
Average price per Mcf of gas used to estimated proved gas	3.94
Average price per barrel of natural gas liquids used to estimate proved NGL reserves	25.05
Future development costs	10,787,000,000		10,756,000,000		12,767,000,000
Future dismantlement, abandonment and rehabilitation costs	1,500,000,000
Forecast [Member]
Reserve Quantities [Line Items]
Future development costs									1,000,000,000	1,900,000,000	2,200,000,000
Jackfish [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserve (MMBoe)	384		441
Daily barrel facility capacity	35,000
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	8		38		67
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities (MMBoe)			38
Barnett Shale [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves, revisions other than price (MMboe)	-69
Proved developed and undeveloped reserves, revisions due to prices (MMboe)			43		-100
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	36		54		95
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities (MMBoe)			54		82
Anadarko Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	14		42
Rocky Mountain [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices (MMboe)			19		-25
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)					16
Granite Wash Area [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)					18
Cana-Woodford Shale [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)					151
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities (MMBoe)			23		134
Permian Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	70		76		72
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities (MMBoe)	4		33
Eagle Ford [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	54
Proved developed and undeveloped reserves, purchase of reserves (MMboe)	246
Eagle Ford [Member] | Minimum [Member]
Reserve Quantities [Line Items]
Years until development and evaluation will be complete	4 years
Eagle Ford [Member] | Maximum [Member]
Reserve Quantities [Line Items]
Years until development and evaluation will be complete	5 years
Mississippian-Woodford Trend [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	14		32
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities (MMBoe)			20
Pike Thermal And Eagle Ford [Member] | Costs Deemed For Individual Assessment [Member]
Reserve Quantities [Line Items]
Oil and gas properties not subject to amortization	2,200,000,000
United States [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserve (MMBoe)	305	[1]	258	[1]	407	[1]	403	[1]
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)	40
Proved undeveloped reserves, revisions other than price (MMboe)	-61
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	-86	[1]	-117	[1]	-67	[1]
Proved developed and undeveloped reserves, revisions due to prices (MMboe)	38	[1]	76	[1]	-159	[1]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	197	[1]	212	[1]	367	[1]
Proved developed and undeveloped reserves, purchase of reserves (MMboe)	265	[1]	1	[1]
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	-207	[1]	-14	[1]
Future development costs	7,168,000,000		5,448,000,000		6,556,000,000
Oil and Gas Properties [Member]
Reserve Quantities [Line Items]
Capitalized interest costs	$45,000,000		$42,000,000		$36,000,000
[1]	Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

Supplemental_Information_On_Oi3

Supplemental Information On Oil And Gas Operations (Costs Incurred) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property acquisition costs:
Proved properties	$5,210	$22	$73
Unproved properties	1,177	216	1,167
Exploration costs	322	595	666
Development costs	5,463	5,089	6,099
Costs incurred	12,172	5,922	8,005
United States [Member]
Property acquisition costs:
Proved properties	5,210	19	2
Unproved properties	1,176	213	1,135
Exploration costs	270	443	351
Development costs	4,400	3,838	4,408
Costs incurred	11,056	4,513	5,896
Canada [Member]
Property acquisition costs:
Proved properties		3	71
Unproved properties	1	3	32
Exploration costs	52	152	315
Development costs	1,063	1,251	1,691
Costs incurred	$1,116	$1,409	$2,109

Supplemental_Information_On_Oi4

Supplemental Information On Oil And Gas Operations (Capitalized Costs) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	$75,738	$73,995
Unproved properties	2,752	2,791
Total oil and gas properties	78,490	76,786
Accumulated DD and A	-49,560	-52,461
Net capitalized costs	28,930	24,325
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	59,849	51,366
Unproved properties	1,460	1,277
Total oil and gas properties	61,309	52,643
Accumulated DD and A	-38,213	-35,848
Net capitalized costs	23,096	16,795
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	15,889	22,629
Unproved properties	1,292	1,514
Total oil and gas properties	17,181	24,143
Accumulated DD and A	-11,347	-16,613
Net capitalized costs	$5,834	$7,530

Supplemental_Information_On_Oi5

Supplemental Information On Oil And Gas Operations (Oil And Gas Properties Not Subject To Amortization) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$1,890
Exploration costs	362
Development costs	341
Capitalized interest	159
Total oil and gas properties not subject to amortization	2,752
2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	973
Exploration costs	111
Development costs	103
Capitalized interest	43
Total oil and gas properties not subject to amortization	1,230
2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	127
Exploration costs	76
Development costs	48
Capitalized interest	38
Total oil and gas properties not subject to amortization	289
2012 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	140
Exploration costs	68
Development costs	121
Capitalized interest	30
Total oil and gas properties not subject to amortization	359
Cost Incurred Prior to 2012 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	650
Exploration costs	107
Development costs	69
Capitalized interest	48
Total oil and gas properties not subject to amortization	$874

Supplemental_Information_On_Oi6

Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales		$9,910	$8,522	$7,153
Lease operating expenses		-2,332	-2,268	-2,074
General and administrative expenses		-210	-202	-296
Production and property taxes		-503	-439	-395
Depreciation, depletion and amortization		-2,896	-2,465	-2,526
Gain on sale of assets		1,077
Asset impairments			-1,953	-1,956
Accretion of asset retirement obligations		-88	-111	-109
Income tax benefit (expense)		-1,767	-422	96
Results of operations		3,191	662	-107
Depreciation, depletion and amortization per Boe		11.79	9.75	10.12
Goodwill impairments		1,941	0	0
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales		7,867	5,964	4,679
Lease operating expenses		-1,559	-1,257	-1,059
General and administrative expenses		-153	-125	-159
Production and property taxes		-466	-380	-340
Depreciation, depletion and amortization		-2,365	-1,640	-1,563
Asset impairments			-1,110	-1,793
Accretion of asset retirement obligations		-49	-47	-40
Income tax benefit (expense)		-1,199	-510	99
Results of operations		2,076	895	-176
Depreciation, depletion and amortization per Boe		11.41	8.69	8.55
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales		2,043	2,558	2,474
Lease operating expenses		-773	-1,011	-1,015
General and administrative expenses		-57	-77	-137
Production and property taxes		-37	-59	-55
Depreciation, depletion and amortization		-531	-825	-963
Gain on sale of assets		1,077
Asset impairments			-843	-163
Accretion of asset retirement obligations		-39	-64	-69
Income tax benefit (expense)		-568	88	-3
Results of operations		1,115	-233	69
Depreciation, depletion and amortization per Boe		13.8	12.87	14.41
Goodwill impairments	$1,900

Supplemental_Information_On_Oi7

Supplemental Information On Oil And Gas Operations (Proved Oil Reserves) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMBbls	MMBbls	MMBbls	MMBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	285	270	248
Proved developed and undeveloped reserves, revisions due to prices	-1		-6
Proved developed and undeveloped reserves, revisions other than price	-37	-18	-8
Proved developed and undeveloped reserves, extensions and discoveries	99	76	72
Proved developed and undeveloped reserves, purchase of reserves	132	1
Proved developed and undeveloped reserves, production	-58	-43	-36
Proved developed and undeveloped reserves, sale of reserves	-46	-1
Proved developed and undeveloped reserves, ending balance	374	285	270
Proved developed reserves	278	250	228	219
Proved developed producing reserves	243	229	211	204
Proved undeveloped reserve	96	35	42	29
Oil [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	229	205	168
Proved developed and undeveloped reserves, revisions due to prices	-1	1	-1
Proved developed and undeveloped reserves, revisions other than price	-38	-18	-6
Proved developed and undeveloped reserves, extensions and discoveries	94	69	65
Proved developed and undeveloped reserves, purchase of reserves	132	1
Proved developed and undeveloped reserves, production	-48	-28	-21
Proved developed and undeveloped reserves, sale of reserves	-17	-1
Proved developed and undeveloped reserves, ending balance	351	229	205
Proved developed reserves	255	194	166	146
Proved developed producing reserves	224	178	155	139
Proved undeveloped reserve	96	35	39	22
Oil [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	56	65	80
Proved developed and undeveloped reserves, revisions due to prices		-1	-5
Proved developed and undeveloped reserves, revisions other than price	1		-2
Proved developed and undeveloped reserves, extensions and discoveries	5	7	7
Proved developed and undeveloped reserves, production	-10	-15	-15
Proved developed and undeveloped reserves, sale of reserves	-29
Proved developed and undeveloped reserves, ending balance	23	56	65
Proved developed reserves	23	56	62	73
Proved developed producing reserves	19	51	56	65
Proved undeveloped reserve			3	7

Supplemental_Information_On_Oi8

Supplemental Information On Oil And Gas Operations (Proved Bitumen Reserves) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMBbls	MMBbls	MMBbls	MMBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Bitumen [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	552	528	457
Proved developed and undeveloped reserves, revisions due to prices	-37	-11	14
Proved developed and undeveloped reserves, revisions other than price	18	16	7
Proved developed and undeveloped reserves, extensions and discoveries	8	38	67
Proved developed and undeveloped reserves, production	-20	-19	-17
Proved developed and undeveloped reserves, ending balance	521	552	528
Proved developed reserves	137	111	99	90
Proved developed producing reserves	137	111	99	90
Proved undeveloped reserve	384	441	429	367
Bitumen [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	552	528	457
Proved developed and undeveloped reserves, revisions due to prices	-37	-11	14
Proved developed and undeveloped reserves, revisions other than price	18	16	7
Proved developed and undeveloped reserves, extensions and discoveries	8	38	67
Proved developed and undeveloped reserves, production	-20	-19	-17
Proved developed and undeveloped reserves, ending balance	521	552	528
Proved developed reserves	137	111	99	90
Proved developed producing reserves	137	111	99	90
Proved undeveloped reserve	384	441	429	367

Supplemental_Information_On_Oi9

Supplemental Information On Oil And Gas Operations (Proved Natural Gas Reserves) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcf	MMcf	MMcf	MMcf
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	9,308,000	9,446,000	10,486,000
Proved developed and undeveloped reserves, revisions due to prices	236,000	566,000	-930,000
Proved developed and undeveloped reserves, revisions other than price	-295,000	-232,000	-320,000
Proved developed and undeveloped reserves, extensions and discoveries	343,000	490,000	1,158,000
Proved developed and undeveloped reserves, purchase of reserves	457,000	1,000	2,000
Proved developed and undeveloped reserves, production	-701,000	-874,000	-938,000
Proved developed and undeveloped reserves, sale of reserves	-1,661,000	-89,000	-12,000
Proved developed and undeveloped reserves, ending balance	7,687,000	9,308,000	9,446,000
Proved developed reserves	6,984,000	8,459,000	8,070,000	8,908,000
Proved developed producing reserves	6,780,000	8,105,000	7,715,000	8,271,000
Proved undeveloped reserve	703,000	849,000	1,376,000	1,578,000
Natural Gas [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	8,550,000	8,762,000	9,507,000
Proved developed and undeveloped reserves, revisions due to prices	191,000	405,000	-831,000
Proved developed and undeveloped reserves, revisions other than price	-299,000	-299,000	-287,000
Proved developed and undeveloped reserves, extensions and discoveries	335,000	471,000	1,124,000
Proved developed and undeveloped reserves, purchase of reserves	457,000	1,000	2,000
Proved developed and undeveloped reserves, production	-660,000	-709,000	-752,000
Proved developed and undeveloped reserves, sale of reserves	-923,000	-81,000	-1,000
Proved developed and undeveloped reserves, ending balance	7,651,000	8,550,000	8,762,000
Proved developed reserves	6,948,000	7,707,000	7,391,000	7,957,000
Proved developed producing reserves	6,746,000	7,425,000	7,091,000	7,409,000
Proved undeveloped reserve	703,000	843,000	1,371,000	1,550,000
Natural Gas [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	758,000	684,000	979,000
Proved developed and undeveloped reserves, revisions due to prices	45,000	161,000	-99,000
Proved developed and undeveloped reserves, revisions other than price	4,000	67,000	-33,000
Proved developed and undeveloped reserves, extensions and discoveries	8,000	19,000	34,000
Proved developed and undeveloped reserves, production	-41,000	-165,000	-186,000
Proved developed and undeveloped reserves, sale of reserves	-738,000	-8,000	-11,000
Proved developed and undeveloped reserves, ending balance	36,000	758,000	684,000
Proved developed reserves	36,000	752,000	679,000	951,000
Proved developed producing reserves	34,000	680,000	624,000	862,000
Proved undeveloped reserve		6,000	5,000	28,000

Recovered_Sheet2

Supplemental Information On Oil And Gas Operations (Proved Natural Gas Liquids Reserves) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMBbls	MMBbls	MMBbls	MMBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	575	591	552
Proved developed and undeveloped reserves, revisions due to prices	8	11	-24
Proved developed and undeveloped reserves, revisions other than price	2	-47	-13
Proved developed and undeveloped reserves, extensions and discoveries	47	65	116
Proved developed and undeveloped reserves, purchase of reserves	57
Proved developed and undeveloped reserves, production	-51	-45	-40
Proved developed and undeveloped reserves, sale of reserves	-60
Proved developed and undeveloped reserves, ending balance	578	575	591
Proved developed reserves	486	491	451	428
Proved developed producing reserves	467	463	425	396
Proved undeveloped reserve	92	84	140	124
Natural Gas Liquids [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	552	571	525
Proved developed and undeveloped reserves, revisions due to prices	7	8	-19
Proved developed and undeveloped reserves, revisions other than price	2	-50	-13
Proved developed and undeveloped reserves, extensions and discoveries	47	64	114
Proved developed and undeveloped reserves, purchase of reserves	57
Proved developed and undeveloped reserves, production	-50	-41	-36
Proved developed and undeveloped reserves, sale of reserves	-37
Proved developed and undeveloped reserves, ending balance	578	552	571
Proved developed reserves	486	468	431	402
Proved developed producing reserves	467	442	406	372
Proved undeveloped reserve	92	84	140	123
Natural Gas Liquids [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	23	20	27
Proved developed and undeveloped reserves, revisions due to prices	1	3	-5
Proved developed and undeveloped reserves, revisions other than price		3
Proved developed and undeveloped reserves, extensions and discoveries		1	2
Proved developed and undeveloped reserves, production	-1	-4	-4
Proved developed and undeveloped reserves, sale of reserves	-23
Proved developed and undeveloped reserves, ending balance		23	20
Proved developed reserves		23	20	26
Proved developed producing reserves		21	19	24
Proved undeveloped reserve				1

Recovered_Sheet3

Supplemental Information On Oil And Gas Operations (Proved Total MMBoe Reserves) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	MMBoe		MMBoe		MMBoe		MMBoe
	Mcf
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	2,963	[1]	2,963	[1]	3,005	[1]
Proved developed and undeveloped reserves, revisions due to prices (MMboe)	9	[1]	94	[1]	-171	[1]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	-65	[1]	-88	[1]	-68	[1]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	211	[1]	261	[1]	449	[1]
Proved developed and undeveloped reserves, purchase of reserves (MMboe)	265	[1]	1	[1]
Proved developed and undeveloped reserves, production (MMBoe)	-246	[1]	-253	[1]	-250	[1]
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	-383	[1]	-15	[1]	-2	[1]
Proved developed and undeveloped reserves, ending balance (MMBoe)	2,754	[1]	2,963	[1]	2,963	[1]
Proved developed reserves (MMBoe)	2,065	[1]	2,262	[1]	2,123	[1]	2,223	[1]
Proved developed producing reserves (MMBoe)	1,977	[1]	2,154	[1]	2,021	[1]	2,069	[1]
Proved undeveloped reserve (MMBoe)	689	[1]	701	[1]	840	[1]	782	[1]
Conversion rate of gas reserves from barrels of oil to Boe	6
United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	2,205	[1]	2,236	[1]	2,278	[1]
Proved developed and undeveloped reserves, revisions due to prices (MMboe)	38	[1]	76	[1]	-159	[1]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	-86	[1]	-117	[1]	-67	[1]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	197	[1]	212	[1]	367	[1]
Proved developed and undeveloped reserves, purchase of reserves (MMboe)	265	[1]	1	[1]
Proved developed and undeveloped reserves, production (MMBoe)	-207	[1]	-189	[1]	-183	[1]
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	-207	[1]	-14	[1]
Proved developed and undeveloped reserves, ending balance (MMBoe)	2,205	[1]	2,205	[1]	2,236	[1]
Proved developed reserves (MMBoe)	1,900	[1]	1,947	[1]	1,829	[1]	1,875	[1]
Proved developed producing reserves (MMBoe)	1,815	[1]	1,857	[1]	1,743	[1]	1,746	[1]
Proved undeveloped reserve (MMBoe)	305	[1]	258	[1]	407	[1]	403	[1]
Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	758	[1]	727	[1]	727	[1]
Proved developed and undeveloped reserves, revisions due to prices (MMboe)	-29	[1]	18	[1]	-12	[1]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	21	[1]	29	[1]	-1	[1]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	14	[1]	49	[1]	82	[1]
Proved developed and undeveloped reserves, production (MMBoe)	-39	[1]	-64	[1]	-67	[1]
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	-176	[1]	-1	[1]	-2	[1]
Proved developed and undeveloped reserves, ending balance (MMBoe)	549	[1]	758	[1]	727	[1]
Proved developed reserves (MMBoe)	165	[1]	315	[1]	294	[1]	348	[1]
Proved developed producing reserves (MMBoe)	162	[1]	297	[1]	278	[1]	323	[1]
Proved undeveloped reserve (MMBoe)	384	[1]	443	[1]	433	[1]	379	[1]
[1]	Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

Recovered_Sheet4

Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2012		Dec. 31, 2011
	MMBoe		MMBoe		MMBoe
Reserve Quantities [Line Items]
Proved undeveloped reserve (MMBOE) beginning balance	701	[1]	840	[1]	782	[1]
Proved undeveloped reserves, extensions and discoveries	161
Proved undeveloped reserves, revisions due to prices	-35
Proved undeveloped reserves, revisions other than price	-43
Proved Undeveloped Reserves, Sale of reserves	-6
Proved undeveloped reserves, conversion to proved developed reserves	-89
Proved undeveloped reserve (MMBOE) ending balance	689	[1]	840	[1]	782	[1]
United States [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserve (MMBOE) beginning balance	258	[1]	407	[1]	403	[1]
Proved undeveloped reserves, extensions and discoveries	153
Proved undeveloped reserves, revisions due to prices	-1
Proved undeveloped reserves, revisions other than price	-61
Proved Undeveloped Reserves, Sale of reserves	-4
Proved undeveloped reserves, conversion to proved developed reserves	-40
Proved undeveloped reserve (MMBOE) ending balance	305	[1]	407	[1]	403	[1]
Canada [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserve (MMBOE) beginning balance	443	[1]	433	[1]	379	[1]
Proved undeveloped reserves, extensions and discoveries	8
Proved undeveloped reserves, revisions due to prices	-34
Proved undeveloped reserves, revisions other than price	18
Proved Undeveloped Reserves, Sale of reserves	-2
Proved undeveloped reserves, conversion to proved developed reserves	-49
Proved undeveloped reserve (MMBOE) ending balance	384	[1]	433	[1]	379	[1]
[1]	Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

Recovered_Sheet5

Supplemental Information On Oil And Gas Operations (Standardized Measure Of Discounted Future Net Cash Flows Related To Interest In Proved Reserves) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$107,218	$95,288	$88,867
Future costs:
Development	-10,787	-10,756	-12,767
Production	-43,972	-42,372	-40,876
Future income tax expense	-14,047	-11,373	-8,534
Future net cash flow	38,412	30,787	26,690
10% discount to reflect timing of cash flows	-17,938	-15,046	-13,469
Standardized measure of discounted future net cash flows	20,474	15,741	13,221	17,844
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	75,847	61,983	55,297
Future costs:
Development	-7,168	-5,448	-6,556
Production	-29,740	-26,663	-24,265
Future income tax expense	-11,021	-9,046	-6,542
Future net cash flow	27,918	20,826	17,934
10% discount to reflect timing of cash flows	-12,819	-10,346	-9,036
Standardized measure of discounted future net cash flows	15,099	10,480	8,898
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	31,371	33,305	33,570
Future costs:
Development	-3,619	-5,308	-6,211
Production	-14,232	-15,709	-16,611
Future income tax expense	-3,026	-2,327	-1,992
Future net cash flow	10,494	9,961	8,756
10% discount to reflect timing of cash flows	-5,119	-4,700	-4,433
Standardized measure of discounted future net cash flows	$5,375	$5,261	$4,323

Recovered_Sheet6

Supplemental Information On Oil And Gas Operations (Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Information On Oil And Gas Operations [Abstract]
Standardized measure of discounted future net cash flows, beginning balance	$15,741	$13,221	$17,844
Net changes in prices and production costs	2,561	3,018	-9,889
Oil, bitumen, gas and NGL sales, net of production costs	-6,865	-5,613	-4,388
Changes in estimated future development costs	-768	399	-1,094
Extensions and discoveries, net of future development costs	4,836	4,047	4,669
Purchase of reserves	6,422	14	18
Sale of reserves in place	-2,384	-44	-25
Revisions of quantity estimates	-746	-1,040	162
Previously estimated development costs incurred during the period	1,933	1,986	1,321
Accretion of discount	1,746	1,940	1,420
Other, primarily changes in timing and foreign exchange rates	-107	-583	113
Net change in income taxes	-1,895	-1,604	3,070
Standardized measure of discounted future net cash flows, ending balance	$20,474	$15,741	$13,221

Supplemental_Quarterly_Financi2

Supplemental Quarterly Financial Information (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended			3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2013
Gain on sale of assets		$1,072	($9)	$13
Asset impairments	1,900	1,953	1,976	2,024
Asset impairment charges, after taxes		1,948	1,353	1,308
Asset impairment per diluted share	$4.79
United States And Canada [Member]
Asset impairments					1,900
Asset impairment charges, after taxes					$1,300
Asset impairment per diluted share					$3.25

Supplemental_Quarterly_Financi3

Supplemental Quarterly Financial Information (Schedule Of Unaudited Interim Results Of Operations) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Operating revenues	$5,995	$5,336	$4,510	$3,725	$2,624	$2,714	$3,088	$1,971	$19,566	$10,397	$9,501
Earnings (loss) before income taxes	291	1,654	1,554	560	475	639	997	-1,962	4,059	149	-317
Net earnings (loss) attributable to Devon	($408)	$1,016	$675	$324	$207	$429	$683	($1,339)	$1,607	($20)	($206)
Basic net earnings (loss) per share attributable to Devon	($1.01)	$2.48	$1.65	$0.80	$0.51	$1.06	$1.69	($3.34)	$3.93	($0.06)	($0.52)
Diluted net earnings (loss) per share attributable to Devon	($1.01)	$2.47	$1.64	$0.79	$0.51	$1.05	$1.68	($3.34)	$3.91	($0.06)	($0.52)