Devon Energy (DVN) 10-K 17 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) shares in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 10, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Entity Registrant Name	DEVON ENERGY CORP/DE
Entity Central Index Key	1,090,012
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2,015
Entity Filer Category	Large Accelerated Filer
Document Fiscal Period Focus	FY
Entity Public Float			$ 24.3
Entity Common Stock, Shares Outstanding		441.3

Consolidated Comprehensive Stat

Consolidated Comprehensive Statements Of Earnings - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Comprehensive Statements Of Earnings [Abstract]
Oil, gas and NGL sales	$ 5,382	$ 9,910	$ 8,522
Oil, gas and NGL derivatives	503	1,989	(191)
Marketing and midstream revenues	7,260	7,667	2,066
Total operating revenues	13,145	19,566	10,397
Lease operating expenses	2,104	2,332	2,268
Marketing and midstream operating expenses	6,420	6,815	1,553
General and administrative expenses	855	847	617
Production and property taxes	388	535	461
Depreciation, depletion and amortization	3,129	3,319	2,780
Asset impairments	20,820	1,953	1,976
Restructuring costs	78	46	54
Gains and losses on asset sales		(1,072)	9
Other operating items	78	93	112
Total operating expenses	33,872	14,868	9,830
Operating income (loss)	(20,727)	4,698	567
Net financing costs	517	526	417
Other nonoperating items	24	113	1
Earnings (loss) before income taxes	(21,268)	4,059	149
Income tax expense (benefit)	(6,065)	2,368	169
Net earnings (loss)	(15,203)	1,691	(20)
Net earnings (loss) attributable to noncontrolling interests	(749)	84
Net earnings (loss) attributable to Devon	$ (14,454)	$ 1,607	$ (20)
Net earnings (loss) per share attributable to Devon:
Basic	$ (35.55)	$ 3.93	$ (0.06)
Diluted	$ (35.55)	$ 3.91	$ (0.06)
Comprehensive earnings (loss):
Net earnings (loss)	$ (15,203)	$ 1,691	$ (20)
Other comprehensive earnings (loss), net of tax:
Foreign currency translation	(559)	(465)	(548)
Pension and postretirement plans	10	(24)	45
Other comprehensive loss, net of tax	(549)	(489)	(503)
Comprehensive earnings (loss)	(15,752)	1,202	(523)
Comprehensive earnings (loss) attributable to noncontrolling interests	(749)	84
Comprehensive earnings (loss) attributable to Devon	$ (15,003)	$ 1,118	$ (523)

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net earnings (loss)	$ (15,203)	$ 1,691	$ (20)
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Depreciation, depletion and amortization	3,129	3,319	2,780
Asset impairments	20,820	1,953	1,976
Gains and losses on asset sales		(1,072)	9
Deferred income tax expense (benefit)	(5,828)	1,891	97
Derivatives and other financial instruments	(738)	(2,070)	135
Cash settlements on derivatives and financial instruments	2,688	104	277
Other noncash charges	537	457	309
Net change in working capital	(301)	50	(298)
Change in long-term other assets	285	(421)	10
Change in long-term other liabilities	(6)	79	161
Net cash from operating activities	5,383	5,981	5,436
Cash flows from investing activities:
Capital expenditures	(5,308)	(6,988)	(6,502)
Acquisitions of property, equipment and businesses	(1,107)	(6,462)	(256)
Divestitures of property and equipment	107	5,120	419
Purchases of short-term investments			(1,076)
Redemptions of short-term investments			3,419
Redemptions of long-term investments		57
Other	(16)	89	(3)
Net cash from investing activities	(6,324)	(8,184)	(3,999)
Cash flows from financing activities:
Borrowings of long-term debt, net of issuance costs	4,772	5,340	2,233
Repayments of long-term debt	(2,634)	(7,189)
Net short-term debt repayments	(307)	(385)	(1,872)
Stock option exercises	4	93	3
Sale of subsidiary units	654
Issuance of subsidiary units	25	410
Dividends paid on common stock	(396)	(386)	(348)
Distributions to noncontrolling interests	(254)	(235)
Other	(16)	(2)	4
Net cash from financing activities	1,848	(2,354)	20
Effect of exchange rate changes on cash	(77)	(29)	(28)
Net change in cash and cash equivalents	830	(4,586)	1,429
Cash and cash equivalents at beginning of period	1,480	6,066	4,637
Cash and cash equivalents at end of period	$ 2,310	$ 1,480	$ 6,066

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 2,310	$ 1,480
Accounts receivable		1,105	1,959
Derivatives, at fair value		43	1,993
Income taxes receivable		147	522
Other current assets		421	544
Total current assets		4,026	6,498
Oil and gas, based on full cost accounting:
Subject to amortization		78,190	75,738
Not subject to amortization		2,584	2,752
Total oil and gas		80,774	78,490
Midstream and other		10,380	9,695
Total property and equipment, at cost		91,154	88,185
Less accumulated depreciation, depletion and amortization		(72,086)	(51,889)
Property and equipment, net		19,068	36,296
Goodwill		5,032	6,303
Other long-term assets		1,406	1,540
Total assets		29,532	50,637
Current liabilities:
Accounts payable		906	1,400
Revenues and royalties payable		763	1,193
Short-term debt	[1]	976	1,432
Deferred income taxes			730
Other current liabilities		650	1,180
Total current liabilities		3,295	5,935
Long-term debt		12,137	9,830
Asset retirement obligations		1,370	1,339
Other long-term liabilities		853	948
Deferred income taxes		888	6,244
Stockholders' equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 418 million and 409 million shares in 2015 and 2014, respectively		42	41
Additional paid-in capital		4,996	4,088
Retained earnings		1,781	16,631
Accumulated other comprehensive earnings		230	779
Total stockholders' equity attributable to Devon		7,049	21,539
Noncontrolling interests		3,940	4,802
Total stockholders' equity		$ 10,989	$ 26,341
Commitments and contingencies (Note 18)
Total liabilities and stockholders' equity		$ 29,532	$ 50,637
[1]	2015 short-term debt consists of $626 million of commercial paper and the $350 million floating rate due on December 15, 2016. 2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
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)	418,000,000	409,000,000

Consolidated Statements Of Stoc

Consolidated Statements Of Stockholders' Equity - USD ($) shares in Millions, $ in Millions	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Earnings [Member]	Treasury Stock [Member]	Noncontrolling Interests [Member]	Total
Balance, at Dec. 31, 2012	$ 41	$ 3,688	$ 15,778	$ 1,771			$ 21,278
Balance, shares, at Dec. 31, 2012	406
Net earnings (loss)			(20)				(20)
Other comprehensive 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 (expense)		4					4
Balance, at Dec. 31, 2013	$ 41	3,780	15,410	1,268			20,499
Balance, shares, at Dec. 31, 2013	406
Net earnings (loss)			1,607			$ 84	1,691
Other comprehensive loss, net of tax				(489)			(489)
Stock option exercises		93					93
Stock option exercises, shares	1
Restricted stock grants, net of cancellations, shares	2
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 (expense)		(3)					(3)
Acquisition 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
Net earnings (loss)			(14,454)			(749)	(15,203)
Other comprehensive loss, net of tax				(549)			(549)
Stock option exercises		4					4
Restricted stock grants, net of cancellations, shares	2
Common stock repurchased					(35)		(35)
Common stock retired		(35)			$ 35
Common stock dividends			(396)				(396)
Common stock issued	$ 1	198					199
Common stock issued, shares	7
Share-based compensation		165					165
Share-based compensation tax benefits (expense)		(9)					(9)
Subsidiary equity transactions		585				141	726
Distributions to noncontrolling interests						(254)	(254)
Balance, at Dec. 31, 2015	$ 42	$ 4,996	$ 1,781	$ 230		$ 3,940	$ 10,989
Balance, shares, at Dec. 31, 2015	418

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	1. Summary of Significant Accounting Policies 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 and the General Partner . Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U .S. 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, D evon completed a business combination in 2014 whereby Devon controls both EnLink and 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, midstream assets and product and equipment inventories ; • 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; • legal and environmental risks and exposures; and • general credit risk associated with receivables and other assets. Reven ue Recognition 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 typically 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. 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 201 5 , 201 4 and 201 3 , no purchaser accounted for more than 10 % of Devon’s operating revenues. 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 and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from 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 and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar 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, 201 5 , 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. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements. 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. As of December 31, 201 5 and December 31, 2014 , Devon held $75 million and $524 million, respectively, 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 s . General and Administrative Expenses G &A is 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 the 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 G&A 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 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. 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 the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence , such as cumulative losses in recent years . See Note 7 for further discussion. 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 , as well as performance-based restricted stock awards that have met the requisite performance targets . 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. Accounts Receivable Devon ’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance. Investments Devon periodically invests excess cash in U .S. 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. 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 Mcf of gas to one Bbl 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. Sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs with no gain or loss 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. As dis cussed more fully in Note 2, t he 2014 divestitures of certain Canadian assets significantly altered such relationship , and Devon recognized a gain , which is included as a separate item in the accompanying consolidated comprehensive statements of earnings . 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% 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, 201 5 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 201 5 , 201 4 and 201 3 . No impairment of goodwill was required in 2013. However, write-downs were required in 2015 and 2014 based on the annual impairment test. EnLink’s Texas, Louisiana and Crude and Condensate reporting segment goodwill were deemed impaired in 2015, and Devon’s Canadian reporting unit goodwill was deemed impaired in 2014 . 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. During 2015, EnLink’s customer relationships were also evaluated for impairment, and a portion of these intangibles was considered impaired. See Note 12 for further discussion. 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. Foreign Currency Translation Adjustments The U .S. 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 U.S. 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 The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU 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 effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This ASU is effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures. The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. These ASUs will not have a material impact on Devon’s consolidated financial statements and related disclosures. The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes . This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. This ASU will be early-adopted by Devon, effective January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures.

Acquisitions And Divestitures

Acquisitions And Divestitures	12 Months Ended
	Dec. 31, 2015
Acquisitions And Divestitures [Abstract]
Acquisitions And Divestitures	2. Acquisitions and Divestitures Formation of EnLink and the General Partner On March 7, 2014 , Devon and Crosstex completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a midstream business that 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, E MH, and $100 million in cash. E MH owned 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. This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, E M H 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, E MH’s 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 (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 s 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 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. (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 (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 The following table presents a summary of EnLink’s acquisition activity for 2015. Purchase Price (Millions) Allocation (Millions) Date Acquiree Cash EnLink Units PP&E Goodwill Intangibles Other January 31 LPC $108 - $30 $30 $43 $5 March 16 Coronado $240 $360 $302 $18 $281 $(1) October 1 Matador $145 - $36 $9 $99 $1 On January 7, 2016 , EnLink also acquired Anadarko Basin gathering and processing midstream assets from Tall Oak for approximately $ 1.5 billion, subject to certain adjustments. EnLink paid approximately $800 million of cash at the time of closing, primarily funded with the issuance of EnLink preferred units, with another $500 million of cash to be paid within 24 months. The remainder of the purchase price consisted of approximately 15.6 million General Partner common units. EnLink Dropdowns In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million . I n April 2015, EnL ink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon c ontrol s EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common con trol. Devon Acquisition s On February 28, 2014 , Devon completed its acquisition of interests in cert ain affiliates of 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 (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 On December 17, 2015 , Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. A preliminary allocation of the purchase price at December 31, 2015 was $386 million to unproved properties and $113 million to proved properties and gathering systems. On January 7, 2016 , Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $850 million of cash and $659 million of equity. 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 (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 During 2014, Devon divest ed certain properties located throughout Canada and the U.S. as part of its asset portfolio transformation. Canada In the second quarter of 2014, Devon sold Canadian conventional assets for $2.8 billion ( $3.125 billion Canadian dollars) and recognized a gain totaling $1.1 billion ( $0.6 billion after-tax). This gain is included as a separate item in the accompanying consolidated compre hensive statements of earnings. Included in the gain calculation 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 c onjunction with the divestiture , Devon repatriated approximately $2.8 billion of proceeds to the U.S. in the second quarter of 2014 , which w as u tilized to repay commercial paper and term loan balances . 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. In the third quarter of 2014 , Devon sold certain U.S. assets for $2.2 billion. Additionally, approximately $200 million of asset retirement obligations were assumed by the purchaser . No gain or loss was recognized on the sale. These proceeds were used toward the early retirement of $1.9 billion in senior notes in November 2014 as discussed in Note 13.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Financial Instruments [Abstract]
Derivative Financial Instruments	3 . Derivative Financial Instruments Commodity Derivatives As of December 31, 201 5 , Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt mon th NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table. Call Options Sold Period Volume (Bbls/d) Weighted Average Price ($/Bbl) Q1-Q4 2016 18,500 $ 73.18 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2016 Western Canadian Select 5,249 $ (13.67) Q1-Q4 2016 West Texas Sour 5,000 $ (0.53) Q1-Q4 2016 Midland Sweet 13,000 $ 0.25 As of December 31, 201 5 , 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 respective indices noted within the table . Price Swaps Call Options Sold Period Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Q1-Q4 2016 54,650 $ 3.17 400,000 $ 4.30 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2016 Panhandle Eastern Pipe Line 175,000 $ (0.34) Q1-Q4 2016 El Paso Natural Gas 125,000 $ (0.12) Q1-Q4 2016 Houston Ship Channel 30,000 $ 0.11 Q1-Q4 2016 Transco Zone 4 70,000 $ 0.01 Q1-Q4 2017 Panhandle Eastern Pipe Line 150,000 $ (0.34) Q1-Q4 2017 El Paso Natural Gas 50,000 $ (0.14) Q1-Q4 2017 Houston Ship Channel 35,000 $ 0.06 Q1-Q4 2017 Transco Zone 4 185,000 $ 0.03 As of December 31, 201 5, EnLink had the following open derivative positions associated with gas proces sing and fractionation . 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. Period Product Volume (Total) Weighted Average Price Paid Weighted Average Price Received Q1 2016-Q4 2016 Ethane 571 MBbls $ 0.29 /gal Index Q1 2016-Q4 2016 Propane 812 MBbls Index $ 0.81 /gal Q1 2016-Q4 2016 Normal Butane 113 MBbls Index $ 0.61 /gal Q1 2016-Q4 2016 Natural Gasoline 61 MBbls Index $ 1.02 /gal Q1 2016-Q1 2017 Natural Gas 13,829 MMBtu/d $ 2.65 /MMBtu Index Interest Rate Derivatives As of December 31, 2015, Devon had the following open interest rate derivative positions: Notional Rate Received Rate Paid Expiration (Millions) $ 100 Three Month LIBOR 0.92% December 2016 $ 100 1.76% Three Month LIBOR January 2019 $ 750 Three Month LIBOR 2.98% December 2048 (1) ____________________________ (1) Mandatory settlement in December 2018 . Foreign Currency Derivatives As of December 31, 201 5 , Devon had the following open foreign currency derivative position: Forward Contract Currency Contract Type CAD Notional Weighted Average Fixed Rate Received Expiration (Millions) (CAD-USD) Canadian Dollar Sell $ 3,560 0.723 March 2016 Financial Statement Presentation The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption. Year Ended December 31, 2015 2014 2013 Commodity derivatives: (Millions) Oil, gas and NGL derivatives $ 503 $ 1,989 $ (191) Marketing and midstream revenues 9 22 — Interest rate derivatives: Other nonoperating items (20) (1) — Foreign currency derivatives: Other nonoperating items 246 60 56 Net gains (losses) recognized $ 738 $ 2,070 $ (135) The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2015 December 31, 2014 (Millions) Commodity derivative assets: Derivatives, at fair value $ 34 $ 1,984 Other long-term assets 1 11 Interest rate derivative assets: Derivatives, at fair value 1 1 Other long-term assets 1 — Foreign currency derivative assets: Derivatives, at fair value 8 8 Total derivative assets $ 45 $ 2,004 Commodity derivative liabilities: Other current liabilities $ 14 $ 28 Other long-term liabilities 4 28 Interest rate derivative liabilities: Other current liabilities — 1 Other long-term liabilities 22 — Foreign currency derivative liabilities: Other current liabilities 8 — Total derivative liabilities $ 48 $ 57

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
Share-Based Compensation	4. Share-Based Compensation In the second quarter of 2015, Devon’s stockholders approved the 2015 Long-Term Incentive Plan. The 2015 Plan replaces the 2009 Long-Term Incentive Plan, as amended. From the effective date of the 2015 Plan, no further awards may be made under the 2009 Plan, and awards previously granted will continue to be governed by the terms of the 2009 Plan. Subject to the terms of the 2015 Plan, awards may be made under the 2015 Plan for a total of 28 million shares of Devon common stock, plus the number of shares available for issuance under the 2009 Plan (including shares subject to outstanding awards under the 2009 Plan that are subsequently forfeited, canceled or expire). The 2015 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 or units, Canadian restricted stock units, performance awards or units and stock appreciation rights to eligible employees. The 2015 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2015 Plan, options and stock appreciation rights represent one share and other awards represent three 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. Gross G&A for the years ended December 31, 2015 and 2014 includes $31 million and $17 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans. The vesting for certain share-based awards was accelerated in 2014 in conjunction with the divestiture of Devon’s Canadian conventional assets . For the year ended December 31, 2014, approximately $15 million of associated expense for these accelerated awards is included in restructuring costs in the accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2015 2014 2013 (Millions) Gross general and administrative expense for share-based compensation $ 225 $ 199 $ 157 Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties $ 63 $ 53 $ 60 Related income tax benefit $ 45 $ 42 $ 29 The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plans. Restricted Stock Performance-Based Performance Awards and Units Restricted Stock Awards Share Units Awards and Units Weighted Average Grant-Date Fair Value Awards Weighted Average Grant-Date Fair Value Units Weighted Average Grant-Date Fair Value (Thousands, except fair value data) Unvested at 12/31/14 4,304 $ 60.85 380 $ 59.41 1,477 $ 70.90 Granted 2,771 $ 63.57 236 $ 62.02 786 $ 84.14 Vested (1,834) $ 60.33 (153) $ 59.49 (337) $ 66.00 Forfeited (503) $ 62.22 (29) $ 64.18 (67) $ 79.20 Unvested at 12/31/15 4,738 $ 62.49 434 $ 60.48 1,859 (1) $ 76.17 ____________________________ (1) A maximum of 3.7 million common shares could be awarded based upon Devon’s final TSR ranking. The following table presents the aggregate fair value of awards and units that vested during the indicated period. 2015 2014 2013 (Millions) Restricted stock awards and units $ 101 $ 112 $ 141 Performance-based restricted stock awards $ 8 $ 10 $ 5 Performance share units $ 22 $ - $ - The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2015. Performance-Based Restricted Stock Restricted Stock Performance Awards and Units Awards Share Units Unrecognized compensation cost (millions) $ 198 $ 6 $ 45 Weighted average period for recognition (years) 2.5 2.6 1.8 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. 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. In order for awards to vest, the performance target must be met in the first year, and if met, recipients are entitled to dividends on the awards over the remaining service vesting period. If the performance target and service period requirement s are not met, the award does not vest. 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. 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 Dev on’s 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 % 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 U .S. 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 the assumptions related to performance share units granted. 2015 2014 2013 Grant-date fair value $ 81.99 - $ 85.05 $ 70.18 - $ 81.05 $ 61.27 - $ 63.48 Risk-free interest rate 1.06% 0.54% 0.26% - 0.36% Volatility factor 26.2% 28.8% 30.3% Contractual term (years) 2.89 2.89 3.0 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 , including a volatility factor, dividend yield rate, risk-free interest rate and expected term . No stock options were granted in 2015, 2014 and 2013. The following table presents a summary of Devon's outstanding stock options. Weighted Average Options Exercise Price Remaining Term Intrinsic Value (Thousands) (Years) (Millions) Outstanding at December 31, 2014 4,218 $ 70.56 Granted - $ - Exercised (63) $ 64.25 Expired (680) $ 84.36 Forfeited (27) $ 66.71 Outstanding at December 31, 2015 3,448 $ 67.98 2.41 $ - Vested and expected to vest at December 31, 2015 3,448 $ 67.98 2.41 $ - Exercisable at December 31, 2015 3,448 $ 67.98 2.41 $ - The aggregate intrinsic value of stock options that were exercised during 201 5 , 201 4 and 201 3 was $0.2 million, $ 9 million and $ 0.3 million, respectively. As of December 31, 201 5, Devon had no unrecognized compensation cost related to unvested stock options. EnLink Share-Based Awards In March 2015, t he General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees for 2014. The combined grant fair value was $7 million, and the total cost was recognized in the first quarter of 2015 due to the awards vesting immediately. The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of December 31, 2015. General Partner EnLink Restricted Performance Restricted Performance Incentive Units Units Incentive Units Units Unrecognized compensation cost (millions) $ 17 $ 3 $ 16 $ 3 Weighted average period for recognition (years) 1.6 2.0 1.6 2.0

Asset Impairments

Asset Impairments	12 Months Ended
	Dec. 31, 2015
Asset Impairments [Abstract]
Asset Impairments	5. Asset Impairments The following table presents the asset impairments recognized in 201 5 , 201 4 and 201 3 . Year Ended December 31, 2015 2014 2013 (Millions) U.S. oil and gas assets $ 17,992 $ — $ 1,110 Canada oil and gas assets 1,257 — 843 Canada goodwill — 1,941 — EnLink goodwill 1,328 — — EnLink other intangible assets 223 — — Other assets 20 12 23 Total asset impairments $ 20,820 $ 1,953 $ 1,976 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 from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, natural gas and NGLs, which significantly reduced proved reserve s values and, to a lesser degree, proved reserves . For further information, see Note 21. Goodwill and Other Intangible Assets Impairment s In 2015, Devon recognized goodwill and other intangible asset impairments related to EnLink’s business. In 2014, Devon recognized a goodwill impairment related to its Canadian reporting unit. Additional information regarding the se impairment s is discussed in Note 12 .

Restructuring Costs

Restructuring Costs	12 Months Ended
	Dec. 31, 2015
Restructuring Costs [Abstract]
Restructuring Costs	6. Restructuring Costs Canadian Reduction in Work Force In 2015, Devon recognized $24 million of employee related and other costs associated with the reduction in work force made subsequent to the completion of the Jackfish development projects and a decrease in planned capital investment resulting from the drop in commodity prices. Devon incurred employee severance, lease obligation and other costs related to the vacated office space as part of the cost reduction plan. 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 Near the end of 2012, Devon consolidated 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 are associated with certain office space that is subject to non-cancellable operating lease agreements that Devon ceased using as part of the office consolidation. Due to a lack of demand for vacated office space in which Devon’s remaining leases are located, in 2015, Devon recognized an additional $54 million expense as a result of its inability to fully sublease remaining office space. Financial Statement Presentation The following table summarizes restructuring costs presented in the accompanying consolidated comprehensive s tatements of earnings. Year Ended December 31, 2015 2014 2013 (Millions) Office consolidation and offshore divestiture: Employee severance and retention $ - $ - $ 13 Lease obligations and other 54 - 41 Canada divestitures: Employee severance and retention 11 42 - Lease obligations and other 13 4 - Restructuring costs $ 78 $ 46 $ 54 The following table summarizes Devon’s restructuring liabilities. Other Other Current Long-term Liabilities Liabilities Total (Millions) Balance as of December 31, 2013 $ 27 $ 18 $ 45 Changes due to office consolidation and offshore divestiture (18) (11) (29) Changes due to Canadian divestitures 4 — 4 Balance as of December 31, 2014 13 7 20 Changes due to office consolidation and offshore divestiture 1 46 47 Changes due to Canadian divestitures (1) 10 9 Balance as of December 31, 2015 $ 13 $ 63 $ 76

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Income Taxes	7. Income Taxes Income Tax Expense (Benefit ) The following table presents Devon’s income tax components. Year Ended December 31, 2015 2014 2013 (Millions) Current income tax expense (benefit): U.S. federal $ (243) $ 152 $ 73 Various states (8) 18 (5) Canada and various provinces 14 307 4 Total current tax expense (benefit) (237) 477 72 Deferred income tax expense (benefit): U.S. federal (5,033) 1,610 198 Various states (336) 93 59 Canada and various provinces (459) 188 (160) Total deferred tax expense (benefit) (5,828) 1,891 97 Total income tax expense (benefit) $ (6,065) $ 2,368 $ 169 Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following: Year Ended December 31, 2015 2014 2013 Total income tax expense (benefit) (millions) $ (6,065) $ 2,368 $ 169 U.S. statutory income tax rate (35)% 35% 35% Non-deductible goodwill and intangible impairment 2% 23% 0% Taxation on Canadian operations 1% (4)% 9% State income taxes (1)% 2% 23% Repatriations 0% 2% 65% Deferred tax asset valuation allowance 4% 0% 0% Other 0% 0% (19)% Effective income tax rate (29)% 58% 113% Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur. Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance. Numerous judgements and assumptions are inherent in the determination of future taxable income, including factors such as future operation conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. 2015 In the third and fourth quarters of 2015, EnLink recorded goodwill and intangibles impairments of approximately $1.6 billion. These impairments are not deductible for purposes of calculating income tax and, therefore, have an impact on the effective tax rate. During 2015, Devon recorded approximately $18 billion of oil and gas impairments related to its U.S. operations. These impairments resulted in deferred tax assets against which we recognized a $967 million valuation allowance that impacted the effective tax rate and is discussed in the next section. 201 4 In the second and fourth quarters of 2014, goodwill was removed in conjunction with the Canadian conventional asset divestitures, and Devon recorded a goodwill impairment in the Canadian reporting unit, respectively. These transactions are not deductible for purposes of calculating income tax and therefore have an impact on the effective tax rate. 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. 201 3 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 following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities . December 31, 2015 2014 Deferred tax assets: (Millions) Property and equipment $ 490 $ - Asset retirement obligations 485 458 Accrued liabilities 160 150 Net operating loss carryforwards 175 200 Pension benefit obligations 106 113 Other 162 180 Total deferred tax assets before valuation allowance 1,578 1,101 Less: valuation allowance (967) - Net deferred tax assets 611 1,101 Deferred tax liabilities: Property and equipment (1,187) (6,940) Fair value of financial instruments - (699) Long-term debt (36) (115) Other (271) (160) Total deferred tax liabilities (1,494) (7,914) Net deferred tax liability $ (883) $ (6,813) At December 31, 2015, Devon has $175 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The net operating loss carryforwards consist of $495 million of Canadian carryforwards that expire between 2030 and 2035 , $275 million of U.S. state carryforwards that expire between 2018 and 2035 and $205 million of carryforwards related to EnLink’s operations that expire between 2028 and 2035 . In the current environment, Devon expects the tax benefits from the Canadian and EnLink net operating loss carryforwards to be utilize d in 2017 and beyond . Devon also has $6 million of deferred tax asset s related to alternative minimum tax credits , which have no expiration date and will be available for use against tax on future taxable income. At the end of 2015, Devon had deferred tax assets that largely resulted from the full cost impairments recognized during 2015. As a result of the recent cumulative financial losses, Devon recorded a $967 million, or 100% , valuation allowance against the U.S. deferred tax assets as of December 31, 2015 . In the event Devon were to determine that it would be able to realize the deferred income tax assets in the future, Devon would adjust the valuation allowance , reducing the provision for income taxes in the period of such adjustment . As of December 31, 201 5, Devon’s unremitted foreign earnings from its other international operations totaled approximately $1.2 billion. All but $37 million of the $1.2 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 U.S. income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. 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 $37 million of unremitted earnings deemed not to be indefinitely reinvested, Devon has recognized a $10 million deferred tax liability associated with such unremitted earnings as of December 31, 201 5 . Unrecognized Tax Benefits The following table presents changes in Devon's unrecognized tax benefits. December 31, 2015 2014 (Millions) Balance at beginning of year $ 241 $ 243 Tax positions taken in prior periods (19) - Tax positions taken in current year 31 - Accrual of interest related to tax positions taken (5) 2 Settlements (108) - Foreign currency translation (9) (4) Balance at end of year $ 131 $ 241 Devon’s unrecognized tax benefit balance at December 31, 201 5 and 201 4 included $29 million and $34 million, respectively, of interest and penalties. If recognized, $131 million of Devon's unrecognized tax benefits as of December 31, 201 5 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 - 2015 Various U.S. states 2008 - 2015 Canada Federal 2003 - 2015 Various Canadian provinces 2003 - 2015 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 A

Net Earnings (Loss) Per Share Attributable To Devon	12 Months Ended
	Dec. 31, 2015
Net earnings (loss) per share attributable to Devon:
Net 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 weighted-average common shares outstanding used in the calculations of basic and diluted net earnings per share. Year Ended December 31, 2015 2014 2013 (Millions, except per share amounts) Net earnings (loss): Net earnings (loss) attributable to Devon $ (14,454) $ 1,607 $ (20) Attributable to participating securities (5) (17) (2) Basic and diluted earnings (loss) $ (14,459) $ 1,590 $ (22) Common shares: Common shares outstanding - total 412 409 406 Attributable to participating securities (5) (4) (4) Common shares outstanding - basic 407 405 402 Dilutive effect of potential common shares issuable - 2 - Common shares outstanding - diluted 407 407 402 Net earnings (loss) per share attributable to Devon: Basic $ (35.55) $ 3.93 $ (0.06) Diluted $ (35.55) $ 3.91 $ (0.06) Antidilutive options (1) 4 3 7 ____________________________ (1 ) Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.

Other Comprehensive Earnings

Other Comprehensive Earnings	12 Months Ended
	Dec. 31, 2015
Other Comprehensive Earnings [Abstract]
Other Comprehensive Earnings	9 . Other Comprehensive Earnings Components of other comprehensive earnings consist of the following: Year Ended December 31, 2015 2014 2013 (Millions) Foreign currency translation: Beginning accumulated foreign currency translation $ 983 $ 1,448 $ 1,996 Change in cumulative translation adjustment (621) (499) (574) Income tax benefit 62 34 26 Ending accumulated foreign currency translation 424 983 1,448 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (204) (180) (225) Net actuarial gain (loss) and prior service cost arising in current year (5) (57) 48 Recognition of net actuarial loss and prior service cost in earnings (1) 21 20 24 Income tax benefit (expense) (6) 13 (27) Ending accumulated pension and postretirement benefits (194) (204) (180) Accumulated other comprehensive earnings, net of tax $ 230 $ 779 $ 1,268 ____________________________ (1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of earnings. See Note 15 for additional details.

Supplemental Information To Sta

Supplemental Information To Statements Of Cash Flows	12 Months Ended
	Dec. 31, 2015
Supplemental Information To Statements Of Cash Flows [Abstract]
Supplemental Information To Statements Of Cash Flows	1 0 . Supplemental Information to Statements of Cash Flows Year Ended December 31, 2015 2014 2013 (Millions) Net change in working capital accounts: Accounts receivable $ 942 $ 128 $ (288) Income taxes receivable 384 (467) 29 Other current assets (57) (222) 20 Accounts payable (190) (68) 26 Revenues and royalties payable (526) 133 35 Income taxes payable (275) 30 - Other current liabilities (579) 516 (120) Net change in working capital $ (301) $ 50 $ (298) Interest paid (net of capitalized interest) $ 494 $ 514 $ 406 Income taxes paid (received) $ (279) $ 899 $ 13 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. EnLink’s noncash acquisition activity during 2015 included a portion of the Coronado transaction. As discussed in Note 2, Devon’s acquisition of certain Powder River Basin assets included noncash common stock issuance totaling $199 million.

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2015
Accounts Receivable [Abstract]
Accounts Receivable	11. Accounts Receivable C omponents of accounts receivable include the following: December 31, 2015 December 31, 2014 (Millions) Oil, gas and NGL sales $ 362 $ 723 Joint interest billings 211 475 Marketing and midstream revenues 520 706 Other 30 71 Gross accounts receivable 1,123 1,975 Allowance for doubtful accounts (18) (16) Net accounts receivable $ 1,105 $ 1,959

Goodwill And Other Intangible A

Goodwill And Other Intangible Assets	12 Months Ended
	Dec. 31, 2015
Goodwill And Other Intangible Assets [Abstract]
Goodwill And Other Intangible Assets	12. Goodwill and Other Intangible Assets Goodwill The following table presents a summary of Devon's goodwill . U.S. Canada EnLink Total (Millions) 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 - - 57 57 Impairment - - (1,328) (1,328) Balance as of December 31, 2015 $ 2,618 $ - $ 2,414 $ 5,032 The following table presents the General Partner’s and EnLink’s goodwill activity by reporting unit. Texas Louisiana Oklahoma Crude and Condensate General Partner Total (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 Acquired during period 28 - - 29 - 57 Impairment (492) (787) - (49) - (1,328) Balance as of December 31, 2015 $ 704 $ - $ 190 $ 93 $ 1,427 $ 2,414 Acquired D uring P eriod Included in the assets Devon contributed to EMH was $402 million of goodwill. See Note 2 for discussion of acquired goodwill resulting from EnLink’s formation in 2014 and acquisitions in 2015. Asset D ivestitures In conjunction with the Canadian conventional asset divestitures in 2014, Devon removed $706 million of goodwill, which was allocated to these assets. Impairment As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units. Furthermore, due to the continued impact of declining commodity prices and EnLink unit price, an update was performed as of December 31, 2015. As a result of these tests, noncash goodwill impairments were recorded related to EnLink’s Texas, Louisiana and Crude and Condensate reporting units in 2015. In the fourth quarter of 2014, as a result of its annual impairment test of goodwill, Devon concluded the implied fair value of its Canadian goodwill was zero and wrote off the remaining goodwill. 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. 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. Other Intangible Assets During 2015, EnLink’s customer relationships were also evaluated for impairment due to the factors in the aforementioned goodwill impairment analysis. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment. This assessment resulted in a $223 million noncash impairment related to EnLink’s Crude and Condensate customer relationships in 2015. The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets. December 31, 2015 December 31, 2014 (Millions) Customer relationships $ 745 $ 569 Accumulated amortization (55) (36) Net intangibles $ 690 $ 533 The weighted - average amortization period for the customer relationships is 12.6 years. Amortization expense for intangibles was approximately $56 million and $36 million for the year s ended December 31, 201 5 and December 31, 2014, respectively . The remaining aggregate amortization expense is estimated to be approximately $46 million each of the next five years.

Debt And Related Expenses

Debt And Related Expenses	12 Months Ended
	Dec. 31, 2015
Debt And Related Expenses [Abstract]
Debt and Related Expenses	13. Debt and Related Expenses A summary of debt is as follows: December 31, 2015 December 31, 2014 (Millions) Devon debt Commercial paper $ 626 $ 932 Floating rate due December 15, 2015 - 500 Floating rate due December 15, 2016 350 350 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 5.85% due December 15, 2025 850 - 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 5.00% due June 15, 2045 750 - Net discount on debentures and notes (28) (18) Total Devon debt 10,023 9,239 EnLink debt Credit facilities 414 237 2.70% due April 1, 2019 400 400 7.1 25% due June 1, 2022 163 163 4.40% due April 1, 2024 550 550 4.15% due June 1, 2025 750 - 5.60% due April 1, 2044 350 350 5.05% due April 1, 2045 450 300 Net premium on debentures and notes 13 23 Total EnLink debt 3,090 2,023 Total debt 13,113 11,262 Less amount classified as short-term debt (1) 976 1,432 Total long-term debt $ 12,137 $ 9,830 __________________________ (1) 2015 short-term debt consists of $626 million of commercial paper and the $350 million floating rate due on December 15, 2016. 2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015. Debt maturities as of December 31, 201 5 , excluding premiums an d discounts, are as follows ( millions): 2016 $ 976 2017 - 2018 875 2019 1,100 2020 414 Thereafter 9,763 Total $ 13,128 Credit Lines Devon has a $ 3.0 billion 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, 201 5 , 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 %. 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, 201 5 , Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.7% . Commercial Paper Devon ’s Senior Credit Facility supports its $ 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, 201 5 , Devon’s outstanding commercial paper borrowings had a weighted-average borrowing rate of 0.63 % . Issuance of Senior Notes In June 2015, Devon issued $750 million of 5.0% senior notes due 2045 that are unsecured and unsubordinated obligations. Devon used the net proceeds to repay the floating rate senior notes that matured on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, in conjunction with the announcement of the Powder River Basin and STACK acquisitions, Devon issued $850 million of 5.85% senior notes due 2025 that are unsecured and unsubordinated obligations. Devon used the net proceeds to fund the cash portion of these acquisitions. Retirement of Senior Notes In November 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% 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, 2015 and 201 4 , 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 . Devon repaid the floating rate senior notes due 2015 upon maturity and redeemed the 1.2% senior notes due December 15, 2016 in November 2014. As of December 31, 2015, the floating rate senior notes due 2016 and the 2.25% senior notes due December 15, 2018 were outstanding. The floating rate senior notes due 2016 bear interest at a rate equal to three-month LIBOR plus 0.54 %, which will be reset quarterly. 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 , credit facility borrowings and other long-term debt . The schedule below summarizes the key terms of these notes ( millions). Date Issued May 2012 July 2011 January 2009 March 2002 3.25% due May 15, 2022 $ 1,000 $ - $ - $ - 4.75% due May 15, 2042 750 - - - 4.00% due July 15, 2021 - 500 - - 5.60% due July 15, 2041 - 1,250 - - 6.30% due January 15, 2019 - - 700 - 7.95% due April 15, 2032 - - - 1,000 Discount and issuance costs (28) (24) (8) (14) Net proceeds $ 1,722 $ 1,726 $ 692 $ 986 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, 201 5 , including the fair value of the debt at April 25, 2003 and the effective interest rate of the debt after determining the f air 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 (Millions) 8.25% due July 2018 (principal of $125 million) $ 147 5.5% 7.50% due September 2027 (principal of $150 million) $ 169 6.5% 7.875% Debentures due September 30, 2031 In October 2001, Devon, through 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 Anderson Exploration acquisition. 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 of Debt Effective Rate of Debt (Millions) 8.875% due February 2018 (principal of $725 million) (1) $ 760 7.7% 7.125% due June 2022 (principal of $197 million) 226 5.3% Credit facilities 468 Total long-term debt $ 1,454 __________________________ (1) The 2018 senior notes were redeemed on April 18, 2014. In February 2015, the commitments under EnLink’s $1.0 billion unsecured revolving credit facility were increased to $1.5 billion, and the maturity date was extended by a year to March 6, 2020 . As of December 31, 2015, there were $11 million in outstanding letters of credit and $414 million outstanding borrowings , with a weighted-average borrowing rate of 1.7% , under the $1.5 billion credit fa cility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019 . As of December 31, 2015, the General Partner had no outstanding borrowings under the $250 million credit facility. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2015. In March 2014, EnLink issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400 million of its 2.70% senior notes due 2019, $450 million of its 4.40% senior notes due 2024 and $350 million of its 5.60% senior notes due 2044, at discounts of their face value. EnLink used the net proceeds to redeem the 2018 senior notes, reduce outstanding credit facility borrowings, for capital expenditures and for general operations. In November 2014, EnLink issued $100 million of its 4.40% senior notes due 2024 and $300 million 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 March 2014. The 2024 notes issued in March 2014 and November 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. EnLink used the net proceeds for capital expenditures and for general operations. In May 2015, EnLink issued $900 million principal amount of unsecured senior notes, consisting of $750 million principal amount of its 4.15% senior notes due 2025 and an additional $150 million principal amount of its 5.05% senior notes due 2045. EnLink used the net proceeds to repay outstanding revolving credit facility borrowings, for capital expenditures and for general operations. Net F inancing C osts The following schedule includes the components of net financing costs. Year Ended December 31, 2015 2014 2013 (Millions) Interest based on debt outstanding $ 565 $ 532 $ 466 Early retirement of debt - 48 - Capitalized interest (62) (70) (56) Other fees and expenses 20 26 27 Interest expense 523 536 437 Interest income (6) (10) (20) Net financing costs $ 517 $ 526 $ 417

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	14. Asset Retirement Obligations The following table presents the changes in asset retirement obligations. Year Ended December 31, 2015 2014 (Millions) Asset retirement obligations as of beginning of period $ 1,399 $ 2,228 Liabilities incurred 63 97 Liabilities settled and divested (1) (89) (1,009) Revision of estimated obligation 62 70 Accretion expense on discounted obligation 75 89 Foreign currency translation adjustment (96) (76) Asset retirement obligations as of end of period 1,414 1,399 Less current portion 44 60 Asset retirement obligations, long-term $ 1,370 $ 1,339 __________________________ (1) 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, 2015
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 $ 22 million and $ 25 million at December 31, 201 5 and 201 4 , 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 qualifying U.S. retirees . 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 at December 31, 201 5 and 201 4 . Devon’s benefit obligations and plan assets are measured each year as of December 31. The projected benefit obligation s for Devon’s qualified plans were fully funded as of December 31, 201 5 and 201 4 . Pension Benefits Postretirement Benefits 2015 2014 2015 2014 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,377 $ 1,177 $ 24 $ 24 Service cost 33 30 1 1 Interest cost 52 55 1 1 Actuarial loss (gain) (68) 203 (2) - Plan amendments - - 1 - Plan settlements - (4) - - Foreign exchange rate changes (6) (3) - - Participant contributions - - 2 2 Benefits paid (80) (81) (4) (4) Benefit obligation at end of year 1,308 1,377 23 24 Change in plan assets: Fair value of plan assets at beginning of year 1,149 1,006 - - Actual return on plan assets (16) 200 - - Employer contributions 11 29 2 2 Participant contributions - - 2 2 Plan settlements - (4) - - Benefits paid (80) (81) (4) (4) Foreign exchange rate changes (5) (1) - - Fair value of plan assets at end of year 1,059 1,149 - - Funded status at end of year $ (249) $ (228) $ (23) $ (24) Amounts recognized in balance sheet: Other long-term assets $ 2 $ 22 $ - $ - Other current liabilities (12) (10) (3) (3) Other long-term liabilities (239) (240) (20) (21) Net amount $ (249) $ (228) $ (23) $ (24) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 302 $ 317 $ (11) $ (11) Prior service cost (credit) 14 19 (6) (9) Total $ 316 $ 336 $ (17) $ (20) 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 $ 11 million and $ 10 million for 201 5 and 201 4 , 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, 201 5 and 201 4, as presented in the following table . December 31, 2015 2014 (Millions) Projected benefit obligation $ 244 $ 250 Accumulated benefit obligation $ 199 $ 191 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 2015 2014 2013 2015 2014 2013 (Millions) Net periodic benefit cost: Service cost $ 33 $ 30 $ 36 $ 1 $ 1 $ 1 Interest cost 52 55 51 1 1 1 Expected return on plan assets (58) (54) (62) - - - Curtailment and settlement expense - 1 - - - - Recognition of net actuarial loss (gain) (1) 20 18 22 (1) (1) (1) Recognition of prior service cost (1) 4 4 4 (2) (2) (1) Total net periodic benefit cost (2) 51 54 51 (1) (1) - Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 5 57 (39) (1) - (3) Prior service cost (credit) arising in current year - - 2 1 - (8) Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost (20) (19) (22) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (4) (4) (4) 1 2 1 Total other comprehensive loss (earnings) (19) 34 (63) 2 3 (9) Total recognized $ 32 $ 88 $ (12) $ 1 $ 2 $ (9) __________________________ (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 G&A 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 201 6 . Pension Benefits Postretirement Benefits (Millions) Net actuarial loss (gain) $ 22 $ (2) Prior service cost (credit) 4 (1) Total $ 26 $ (3) Assumptions The following table presents the weighted - average actuarial assumptions used to determine obligations and periodic costs. Pension Benefits Postretirement Benefits 2015 2014 2013 2015 2014 2013 Assumptions to determine benefit obligations: Discount rate 4.25% 3.90% 4.80% 3.63% 3.25% 3.65% Rate of compensation increase 4.49% 4.49% 4.48% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate 3.90% 4.80% 3.85% 3.25% 3.65% 3.30% Rate of compensation increase 4.49% 4.49% 4.48% N/A N/A N/A Expected return on plan assets 5.22% 5.42% 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. At the end of 2015, Devon changed the approach used to measure service and interest costs for pension and other postretirement benefits. For 2015, Devon measured service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the pla n obligations. For 2016, Devon elected to measure service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. Devon believe s the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does n ot affect the measurement of the plan obligati ons nor the funded status of the plans. The change in the service and interest costs going forward is not expected to be significant. This change has been accounted for as a change in accounting estimate. Rate of compensation increase – For measurement of the 201 5 benefit obligation for the pension plans, a 4.49 % 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 U .S. While not required to strictly adhere to this data, Devon utilized actuary-produced mortality tables and an improvement s cale derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in Devon’s plan s . Other assumptions – For measurement of the 201 5 benefit obligation for the other postretirement medical plans, a 7.6 % annual rate of increase in the per capita cost of covered health care benefits was assumed for 201 6 . The rate was assumed to decrease annually to an ultimate rate of 5 % 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, 201 5 by less than $ 1 million and would change the 201 5 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, 2015 2014 Fixed income 70% 70% Equity 20% 20% Other 10% 10% The following tables present t he fair values of Devon's pension assets by asset class. December 31, 2015 Fair Value Measurements Using: Actual Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (Millions) Fixed-income securities: U.S. Treasury obligations 17% $ 179 $ 88 $ 91 $ - Corporate bonds 48% 507 371 136 - Other bonds 3% 35 35 - - Total fixed-income securities 68% 721 494 227 - Equity securities: Global (large, mid, small cap) 18% 186 - 186 - Other securities: Hedge fund and alternative investments 11% 120 - - 120 Short-term investments 3% 32 6 26 - Total other securities 14% 152 6 26 120 Total investments 100% $ 1,059 $ 500 $ 439 $ 120 December 31, 2014 Fair Value Measurements Using: Actual Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (Millions) Fixed-income securities: U.S. Treasury obligations 35% $ 405 $ 50 $ 355 $ - Corporate bonds 32% 364 269 95 - Other bonds 3% 30 30 - - Total fixed-income securities 70% 799 349 450 - Equity securities: Global (large, mid, small cap) 17% 197 - 197 - Other securities: Hedge fund and alternative investments 10% 112 - - 112 Short-term investments 3% 41 15 26 - Total other securities 13% 153 15 26 112 Total investments 100% $ 1,149 $ 364 $ 673 $ 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 U.S. 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 U.S. 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. The following table presents a summary of the changes in Devon's Level 3 plan assets ( millions). December 31, 2013 $ 112 Disbursements (6) Investment returns 6 December 31, 2014 112 Purchases 5 Investment returns 3 December 31, 2015 $ 120 Expected Cash Flows The following table presents expected cash flow information for Devon's pension and postretirement benefit plans. Pension Benefits Postretirement Benefits (Millions) Devon's 2016 contributions $ 12 $ 3 Benefit payments: 2016 $ 73 $ 3 2017 $ 75 $ 3 2018 $ 77 $ 3 2019 $ 78 $ 3 2020 $ 83 $ 2 2021 to 2025 $ 446 $ 7 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 201 6 , the $ 12 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 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, 2015 2014 2013 (Millions) 401(k) and enhanced contribution plans $ 63 $ 49 $ 41 Canadian pension and savings plans 16 20 26 Total $ 79 $ 69 $ 67

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2015
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. Common Stock Issued In December 2015, Devon issued approximately 7 million shares of common stock as part of the Powder River Basin asset acquisition discussed in Note 2. Additionally, in January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition. Dividends Devon paid common stock dividends of $396 million, $ 386 million and $ 348 million in 201 5 , 201 4 and 201 3, respectively. The quarterly cash dividend was $0.20 per share in the first quarter of 2013. 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 $4 million, $93 million and $3 million from stock option proceeds in 2015, 2014 and 2013, respectively.

Noncontrolling Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interests [Abstract]
Noncontrolling interests	17. Noncontrolling Interest s 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 G eneral P artner. Subsidiary E quity T ransactions Through its equity distribution agreements, EnLink has the ability to sell common units through an “at the market” equity offering program. During 2015 and 2014, EnLink issued and sold approximately 1.3 million and 14.8 million common units through its at the market program and general public offerings, generating net proceeds of $25 million and $410 million, respectively. Furthermore, in October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 million in proceeds. In 2015, Devon conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising net proceeds of $654 million. As a result of these transactions, the Coronado acquisition and dropdown transactions discussed in Note 2, the ownership of EnLink at December 31, 2015 is approximately: · 28% - Devon · 27% - General Partner (controlled by Devon) · 45% - Public unitholders The net gains and losses and related income taxes resulting from these transactions have been recorded as an adjustment to equity, and the change in ownership reflected as an adjustment to noncontrolling interests. As further discussed in Note 2, in January 2016, EnLink acquired midstream assets in exchange for cash and equity. Subsequent to this transaction, the ownership of the General Partner is approximately: · 64% - Devon · 36% - P ublic unitholders Subsequent to this transaction, the ownership of EnLink is approximately: · 25% - Devon · 23% - General Partner (controlled by Devon) · 52% - P ublic unitholders Distributions to N oncontrolling I nterests In conjunction with the formation of the General Partner in 2014, Devon made a payment of $100 million to noncontrolling interests . Further more , EnLink and the General Partner distributed $254 million and $135 million to non-Devon unitholders during 2015 and 2014 , respectively .

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
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 oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. 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 table presents Devon ’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 201 5 . Year Ending December 31, Purchase Obligations Drilling and Facility Obligations Operational Agreements Office and Equipment Leases (Millions) 2016 $ 557 $ 69 $ 994 $ 70 2017 703 51 972 58 2018 791 34 936 76 2019 803 5 402 68 2020 845 2 255 42 Thereafter 206 28 1,042 129 Total $ 3,905 $ 189 $ 4,601 $ 443 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 G&A under operating leases, net of sublease income, was $88 million, $64 million and $26 million in 201 5 , 201 4 and 201 3 , respectively.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements [Abstract]
Fair Value Measurements	19 . Fair Value Measurements The following table provide s 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, 201 5 and Decemb er 31, 201 4 . Therefore, such financial assets and liabilities are not p resented in the following table . Additionally, i nformation regarding the fair values of oil and gas assets, goodwill and other intangible assets and pension plan assets is provided in Note 5 , Note 12 and Note 15, respectiv ely . Fair Value Measurements Using: Carrying Total Fair Level 1 Level 2 Level 3 Amount Value Inputs Inputs Inputs (Millions) December 31, 2015 assets (liabilities): Cash equivalents $ 1,871 $ 1,871 $ 1,471 $ 400 $ - Commodity derivatives $ 35 $ 35 $ - $ 35 $ - Commodity derivatives $ (18) $ (18) $ - $ (18) $ - Interest rate derivatives $ 2 $ 2 $ - $ 2 $ - Interest rate derivatives $ (22) $ (22) $ - $ (22) $ - Foreign currency derivatives $ 8 $ 8 $ - $ 8 $ - Foreign currency derivatives $ (8) $ (8) $ - $ (8) $ - Debt $ (13,113) $ (11,927) $ - $ (11,927) $ - Capital lease obligations $ (17) $ (16) $ - $ (16) $ - December 31, 2014 assets (liabilities): Cash equivalents $ 950 $ 950 $ 340 $ 610 $ - Commodity derivatives $ 1,995 $ 1,995 $ - $ 1,995 $ - Commodity derivatives $ (56) $ (56) $ - $ (56) $ - 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) $ - 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 money market investments. The fair value approximates the carrying value. Level 2 Fair Value Measurements Cash equivalents — Amounts consist primarily of commercial paper and Canadian agency and provincial securities 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 s of commercial paper and credit facility balances are the carrying values . Capital lease obligations — The fair value was calculated using inputs from third-party banks.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Information [Abstract]
Segment Information	2 0 . 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 exploration and production 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 21. Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian 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 forma tion 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. (1) Canada EnLink (1) Eliminations Total (Millions) Year Ended December 31, 2015: Revenues from external customers $ 8,360 $ 1,012 $ 3,773 $ - $ 13,145 Intersegment revenues $ - $ - $ 679 $ (679) $ - Depreciation, depletion and amortization $ 2,220 $ 522 $ 387 $ - $ 3,129 Asset impairments $ 18,000 $ 1,257 $ 1,563 $ - $ 20,820 Interest expense $ 368 $ 94 $ 107 $ (46) $ 523 Loss before income taxes $ (18,214) $ (1,670) $ (1,384) $ - $ (21,268) Income tax expense (benefit) $ (5,650) $ (445) $ 30 $ - $ (6,065) Net loss $ (12,564) $ (1,225) $ (1,414) $ - $ (15,203) Net earnings (loss) attributable to noncontrolling interests $ 1 $ - $ (750) $ - $ (749) Net loss attributable to Devon $ (12,565) $ (1,225) $ (664) $ - $ (14,454) Property and equipment, net $ 8,811 $ 4,590 $ 5,667 $ - $ 19,068 Total assets $ 14,600 $ 5,464 $ 9,565 $ (97) $ 29,532 Capital expenditures $ 4,575 $ 680 $ 978 $ - $ 6,233 Year Ended December 31, 2014: Revenues from external customers $ 14,854 $ 2,063 $ 2,649 $ - $ 19,566 Intersegment revenues $ - $ - $ 859 $ (859) $ - Depreciation, depletion and amortization $ 2,475 $ 560 $ 284 $ - $ 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 $ 4,390 $ (657) $ 326 $ - $ 4,059 Income tax expense $ 1,797 $ 495 $ 76 $ - $ 2,368 Net earnings (loss) $ 2,593 $ (1,152) $ 250 $ - $ 1,691 Net earnings attributable to noncontrolling interests $ 1 $ - $ 83 $ - $ 84 Net earnings (loss) attributable to Devon $ 2,592 $ (1,152) $ 167 $ - $ 1,607 Property and equipment, net $ 24,463 $ 6,790 $ 5,043 $ - $ 36,296 Total assets $ 32,037 $ 8,517 $ 10,207 $ (124) $ 50,637 Capital expenditures $ 11,214 $ 1,344 $ 1,001 $ - $ 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 __________________________ (1) Due to Devon’s control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recasted periods .

Supplemental Information On Oil

Supplemental Information On Oil And Gas Operations	12 Months Ended
	Dec. 31, 2015
Supplemental Information On Oil And Gas Operations [Abstract]
Supplemental Information on Oil and Gas Operations	2 1 . 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. Costs Incurred The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities. Year Ended December 31, 2015 U.S. Canada Total (Millions) Property acquisition costs: Proved properties $ 193 $ 2 $ 195 Unproved properties 634 83 717 Exploration costs 478 109 587 Development costs 3,269 402 3,671 Costs incurred $ 4,574 $ 596 $ 5,170 Year Ended December 31, 2014 U.S. Canada Total (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 (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 Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations . Pursuant to the full cost method of accounting, Devon capitalizes certain of its G&A that is related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $372 million, $ 376 million and $ 368 million in 201 5 , 201 4 and 201 3 , 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 $54 million , $ 45 million and $ 42 million in 201 5 , 201 4 and 201 3 , respectively. Capitalized Costs The following tables reflect the aggregate capitalized costs related to oil and gas activities. December 31, 2015 U.S. Canada Total (Millions) Proved properties $ 64,443 $ 13,747 $ 78,190 Unproved properties 1,352 1,232 2,584 Total oil and gas properties 65,795 14,979 80,774 Accumulated DD&A (58,312) (11,185) (69,497) Net capitalized costs $ 7,483 $ 3,794 $ 11,277 December 31, 2014 U.S. Canada Total (Millions) Proved properties $ 59,849 $ 15,889 $ 75,738 Unproved properties 1,460 1,292 2,752 Total oil and 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 The following table presents a summary of Devon's oil and gas properties not subject to amortization as of December 31, 201 5 . Costs Incurred In 2015 2014 2013 Prior to 2013 Total (Millions) Acquisition costs $ 672 $ 412 $ 61 $ 510 $ 1,655 Exploration costs 191 132 69 170 562 Development costs 9 28 17 128 182 Capitalized interest 50 37 32 66 185 Total oil and gas properties not subject to amortization $ 922 $ 609 $ 179 $ 874 $ 2,584 Included in the $ 2.6 billion of oil and gas properties not subject to amortization are approximately $1.9 billion of costs that Devon deem s significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada and the newly acquired Powder River Basin assets . Devon anticipates determining its Pike development timeline in mid-2016, with its 50% partner. Based on the 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 begin s recognizing the associated proved reserves. Devon is evaluating and plans to develop the newly acquired Powder River Basin 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 DD&A and after giving effect to permanent differences. December 31, 2015 U.S. Canada Total (Millions) Oil, gas and NGL sales $ 4,356 $ 1,026 $ 5,382 Lease operating expenses (1,551) (553) (2,104) General and administrative expenses (196) (28) (224) Production and property taxes (309) (33) (342) Depreciation, depletion and amortization (2,107) (474) (2,581) Asset impairments (17,992) (1,257) (19,249) Accretion of asset retirement obligations (47) (27) (74) Income tax benefit 5,547 314 5,861 Results of operations $ (12,299) $ (1,032) $ (13,331) Depreciation, depletion and amortization per Boe $ 10.21 $ 11.30 $ 10.40 December 31, 2014 U.S. Canada Total (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 December 31, 2013 U.S. Canada Total (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 __________________________ (1) During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information. 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: December 31, 2012 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) December 31, 2013 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) December 31, 2014 351 23 374 Revisions due to prices (53) 4 (49) Revisions other than price (52) 2 (50) Extensions and discoveries 51 3 54 Purchase of reserves 5 - 5 Production (60) (10) (70) December 31, 2015 242 22 264 Proved developed reserves as of: December 31, 2012 166 62 228 December 31, 2013 194 56 250 December 31, 2014 255 23 278 December 31, 2015 203 22 225 Proved developed-producing reserves as of: December 31, 2012 155 56 211 December 31, 2013 178 51 229 December 31, 2014 224 19 243 December 31, 2015 192 19 211 Proved undeveloped reserves as of: December 31, 2012 39 3 42 December 31, 2013 35 - 35 December 31, 2014 96 - 96 December 31, 2015 39 - 39 Bitumen (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 - 528 528 Revisions due to prices - (11) (11) Revisions other than price - 16 16 Extensions and discoveries - 38 38 Production - (19) (19) December 31, 2013 - 552 552 Revisions due to prices - (37) (37) Revisions other than price - 18 18 Extensions and discoveries - 8 8 Production - (20) (20) December 31, 2014 - 521 521 Revisions due to prices - 103 103 Revisions other than price - (84) (84) Extensions and discoveries - 11 11 Production - (31) (31) December 31, 2015 - 520 520 Proved developed reserves as of: December 31, 2012 - 99 99 December 31, 2013 - 111 111 December 31, 2014 - 137 137 December 31, 2015 - 219 219 Proved developed-producing reserves as of: December 31, 2012 - 99 99 December 31, 2013 - 111 111 December 31, 2014 - 137 137 December 31, 2015 - 219 219 Proved undeveloped reserves as of: December 31, 2012 - 429 429 December 31, 2013 - 441 441 December 31, 2014 - 384 384 December 31, 2015 - 301 301 Gas (Bcf) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 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) December 31, 2013 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) December 31, 2014 7,651 36 7,687 Revisions due to prices (1,412) (9) (1,421) Revisions other than price (3) (6) (9) Extensions and discoveries 171 - 171 Purchase of reserves 17 - 17 Production (579) (8) (587) Sale of reserves (37) - (37) December 31, 2015 5,808 13 5,821 Proved developed reserves as of: December 31, 2012 7,391 679 8,070 December 31, 2013 7,707 752 8,459 December 31, 2014 6,948 36 6,984 December 31, 2015 5,694 13 5,707 Proved developed-producing reserves as of: December 31, 2012 7,091 624 7,715 December 31, 2013 7,425 680 8,105 December 31, 2014 6,746 34 6,780 December 31, 2015 5,546 13 5,559 Proved undeveloped reserves as of: December 31, 2012 1,371 5 1,376 December 31, 2013 843 6 849 December 31, 2014 703 - 703 December 31, 2015 114 - 114 Natural Gas Liquids (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 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) December 31, 2013 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) December 31, 2014 578 - 578 Revisions due to prices (119) - (119) Revisions other than price (6) - (6) Extensions and discoveries 24 - 24 Purchase of reserves 1 - 1 Production (50) - (50) December 31, 2015 428 - 428 Proved developed reserves as of: December 31, 2012 431 20 451 December 31, 2013 468 23 491 December 31, 2014 486 - 486 December 31, 2015 411 - 411 Proved developed-producing reserves as of: December 31, 2012 406 19 425 December 31, 2013 442 21 463 December 31, 2014 467 - 467 December 31, 2015 393 - 393 Proved undeveloped reserves as of: December 31, 2012 140 - 140 December 31, 2013 84 - 84 December 31, 2014 92 - 92 December 31, 2015 17 - 17 Total (MMBoe) (1) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 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) December 31, 2013 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) December 31, 2014 2,205 549 2,754 Revisions due to prices (408) 106 (302) Revisions other than price (59) (83) (142) Extensions and discoveries 104 14 118 Purchase of reserves 9 - 9 Production (206) (42) (248) Sale of reserves (7) - (7) December 31, 2015 1,638 544 2,182 Proved developed reserves as of: December 31, 2012 1,829 294 2,123 December 31, 2013 1,947 315 2,262 December 31, 2014 1,900 165 2,065 December 31, 2015 1,563 243 1,806 Proved developed-producing reserves as of: December 31, 2012 1,743 278 2,021 December 31, 2013 1,857 297 2,154 December 31, 2014 1,815 162 1,977 December 31, 2015 1,509 240 1,749 Proved undeveloped reserves as of: December 31, 2012 407 433 840 December 31, 2013 258 443 701 December 31, 2014 305 384 689 December 31, 2015 75 301 376 _______________________ (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 NGL 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 201 5 (MMBoe). U.S. Canada Total Proved undeveloped reserves as of December 31, 2014 305 384 689 Extensions and discoveries 13 11 24 Revisions due to prices (115) 80 (35) Revisions other than price (40) (80) (120) Conversion to proved developed reserves (88) (94) (182) Proved undeveloped reserves as of December 31, 2015 75 301 376 Proved undeveloped reserves decreas ed 45% from year-end 2014 to year-end 2015, and the year-end 2015 balance represents 17% of total proved reserves. Drilling and development activities increased Devon’s proved undeveloped reserves 24 MMBoe and resulted in the conversion of 182 MMBoe, or 26% , of the 201 4 proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $2.2 billion for 2015. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 120 MMBoe primarily due to evaluations of certain properties in the U.S. and Canada . The largest revisions, which reduced reserves by 80 MMBoe, relate to evaluations of Jackfish bitumen reserves. Of the 40 MMBoe revisions recorded for U.S. properties, a reduction of approximately 27 MMBoe represents reserves that Devon now does not expect to develop in the next five years, including 20 MMBoe attributable to the Eagle Ford. A significant amount of Devon’s proved undeveloped reserves at the end of 201 5 related to its Jackfish operations. At December 31, 201 5 and 201 4 , Devon’s Jackfish proved undeveloped reserves were 3 01 MMBoe and 384 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35 MBbl 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 through to 2030 . At the end of 2015, approximately 184 MMBoe of proved undeveloped reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of the reserves. Furthermore, approximately 180 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop. Price Revision s 201 5 - Reserves de creased 302 MMBoe primarily due to lower commodity prices across all products. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes . 201 4 - 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. 201 3 - Reserves in creased 94 MMBoe primarily due to higher gas prices. Of this in crease, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area. Revisions Other Than Price Total revisions other than price for 201 5 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish are primarily due to a refined reserves methodology that resulted in a reduced recovery factor. Revisions other than price in 201 4 and 201 3 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 201 5 – Of the 118 MMBoe of extensions and discoveries, 38 MMBoe related to the Delaware Basin , 30 MMBoe related to the Anadarko Basin , 21 MMBoe related to the Eagle Ford and 11 MMBoe related to Jackfish. The 201 5 extensions and discoveries included 13 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 11 MMBoe at Jackfish . 2014 – Of the 211 MMBoe of extensions and discoveries, 70 MMBoe related to the Permian Basin , 54 MMBoe related to the Eagle Ford, 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. 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 . Purchase of Reserves 2015 – Of the 9 MMBoe of reserves purchases, 6 MMBoe related to Devon’s acquisition in the Powder River Basin. 2014 – Of the 265 MMBoe of reserves purchases, 246 MMBoe related to Devon’s GeoSouthern acquisition in the Eagle Ford. Sale of Reserves 2015 – The 7 MMBoe of reserves sales related to Devon’s asset divestitures in the San Juan Basin. 2014 – The total 383 MMBoe of reserves sales related to Devon’s asset divestitures in the U.S. and Canada. Standardized Measure The following tables r eflect Devon’s standardized measure of discounted future net cash flows from its proved reserves. Year Ended December 31, 2015 U.S. Canada Total (Millions) Future cash inflows $ 27,398 $ 13,047 $ 40,445 Future costs: Development (3,306) (2,759) (6,065) Production (17,251) (6,891) (24,142) Future income tax expense - (475) (475) Future net cash flow 6,841 2,922 9,763 10% discount to reflect timing of cash flows (1,973) (1,102) (3,075) Standardized measure of discounted future net cash flows $ 4,868 $ 1,820 $ 6,688 Year Ended December 31, 2014 U.S. Canada Total (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 (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 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 201 5 estimates , Devon’s future realized prices were assumed to be $44.33 per Bbl of oil, $23.84 per Bbl of bitumen, $2.06 per Mcf of gas and $10.11 per Bbl of NGLs . O f the $ 6.1 billion of future development costs as of the end of 201 5 , $0.6 billion, $0.6 billion and $0.4 billion are estimated to be spent in 201 6 , 201 7 and 201 8 , respectively. Future development costs inc lude not only development costs but also future asset retirement costs. Included as part of the $ 6.1 billion of future development costs are $1.2 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 p rincipal changes in Devon’s standardized measure of discounted future net cash flows are as follows: Year Ended December 31, 2015 2014 2013 (Millions) Beginning balance $ 20,474 $ 15,741 $ 13,221 Net changes in prices and production costs (20,756) 2,561 3,018 Oil, bitumen, gas and NGL sales, net of production costs (2,704) (6,865) (5,613) Changes in estimated future development costs 1,313 (768) 399 Extensions and discoveries, net of future development costs 1,129 4,836 4,047 Purchase of reserves 95 6,422 14 Sales of reserves in place (79) (2,384) (44) Revisions of quantity estimates (1,451) (746) (1,040) Previously estimated development costs incurred during the period 2,158 1,933 1,986 Accretion of discount 567 1,746 1,940 Foreign exchange and other (1,254) (107) (583) Net change in income taxes 7,196 (1,895) (1,604) Ending balance $ 6,688 $ 20,474 $ 15,741

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Supplemental Quarterly Financial Information	2 2 . Supplemental Quarterly Financial Information (Unaudited) The following tables present a summary of Devon’s unaudited interim results of operations. 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Operating revenues $ 3,265 $ 3,393 $ 3,601 $ 2,886 $ 13,145 Loss before income taxes $ (5,624) $ (4,479) $ (5,623) $ (5,542) $ (21,268) Net loss attributable to Devon $ (3,599) $ (2,816) $ (3,507) $ (4,532) $ (14,454) Basic net loss per share attributable to Devon $ (8.88) $ (6.94) $ (8.64) $ (11.12) $ (35.55) Diluted net loss per share attributable to Devon $ (8.88) $ (6.94) $ (8.64) $ (11.12) $ (35.55) 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Operating revenues $ 3,725 $ 4,510 $ 5,336 $ 5,995 $ 19,566 Earnings 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 Net E arnings ( Loss) Attributable to Devon The 2015 quarterly results include asset impairment s of $5.5 billion (or $13.46 per diluted share) , $4.2 billion (or $10.27 per diluted share), $5.9 billion ( $14.41 per diluted share) and $5.3 billion (or $13.09 per diluted share) for the first quarter through the fourth quarter of 2015, respectively, as discussed in Note 5 . The fourth quarter of 2014 includes asset impairment s of $1.9 billion (or $4.79 per diluted share) as discussed in Note 5 .

Summary Of Significant Accoun29

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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, D evon completed a business combination in 2014 whereby Devon controls both EnLink and 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, midstream assets and product and equipment inventories ; • 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; • legal and environmental risks and exposures; and • general credit risk associated with receivables and other assets.
Revenue Recognition	Reven ue Recognition 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 typically 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. 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 201 5 , 201 4 and 201 3 , no purchaser accounted for more than 10 % of Devon’s operating revenues.
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 and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from 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 and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar 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, 201 5 , 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. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements. 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. As of December 31, 201 5 and December 31, 2014 , Devon held $75 million and $524 million, respectively, 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 s .
General And Administrative Expenses	General and Administrative Expenses G &A is 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 the 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 G&A 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 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. 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 the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence , such as cumulative losses in recent years . See Note 7 for further discussion. 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 , as well as performance-based restricted stock awards that have met the requisite performance targets . 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.
Accounts Receivable	Accounts Receivable Devon ’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance.
Investments	Investments Devon periodically invests excess cash in U .S. 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.
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 Mcf of gas to one Bbl 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. Sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs with no gain or loss 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. As dis cussed more fully in Note 2, t he 2014 divestitures of certain Canadian assets significantly altered such relationship , and Devon recognized a gain , which is included as a separate item in the accompanying consolidated comprehensive statements of earnings . 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% 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, 201 5 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 201 5 , 201 4 and 201 3 . No impairment of goodwill was required in 2013. However, write-downs were required in 2015 and 2014 based on the annual impairment test. EnLink’s Texas, Louisiana and Crude and Condensate reporting segment goodwill were deemed impaired in 2015, and Devon’s Canadian reporting unit goodwill was deemed impaired in 2014 . 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. During 2015, EnLink’s customer relationships were also evaluated for impairment, and a portion of these intangibles was considered impaired. See Note 12 for further discussion.
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. 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.
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.
Foreign Currency Translation Adjustments	Foreign Currency Translation Adjustments The U .S. 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 U.S. 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	Recently Issued Accounting Standards The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU 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 effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This ASU is effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures. The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. These ASUs will not have a material impact on Devon’s consolidated financial statements and related disclosures. The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes . This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. This ASU will be early-adopted by Devon, effective January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures.

Acquisitions And Divestitures (

Acquisitions And Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
EnLink [Member]
Business Acquisition [Line Items]
Schedule Of EnLink Business Combinations	Purchase Price (Millions) Allocation (Millions) Date Acquiree Cash EnLink Units PP&E Goodwill Intangibles Other January 31 LPC $108 - $30 $30 $43 $5 March 16 Coronado $240 $360 $302 $18 $281 $(1) October 1 Matador $145 - $36 $9 $99 $1
General Partner And EnLink [Member]
Business Acquisition [Line Items]
Schedule Of EnLink Business Combinations	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 s 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 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. (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.
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
General Partner and EnLink and GeoSouthern [Member]
Business Acquisition [Line Items]
Schedule Of Unaudited Proforma Information For General Partner and EnLink And GeoSouthern	Year Ended December 31, 2014 2013 (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)

Derivative Financial Instrume31

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Schedule Of Derivative Financial Instruments Included In Consolidated Statements Of Earnings And Consolidated Balance Sheets	The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption. Year Ended December 31, 2015 2014 2013 Commodity derivatives: (Millions) Oil, gas and NGL derivatives $ 503 $ 1,989 $ (191) Marketing and midstream revenues 9 22 — Interest rate derivatives: Other nonoperating items (20) (1) — Foreign currency derivatives: Other nonoperating items 246 60 56 Net gains (losses) recognized $ 738 $ 2,070 $ (135) The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2015 December 31, 2014 (Millions) Commodity derivative assets: Derivatives, at fair value $ 34 $ 1,984 Other long-term assets 1 11 Interest rate derivative assets: Derivatives, at fair value 1 1 Other long-term assets 1 — Foreign currency derivative assets: Derivatives, at fair value 8 8 Total derivative assets $ 45 $ 2,004 Commodity derivative liabilities: Other current liabilities $ 14 $ 28 Other long-term liabilities 4 28 Interest rate derivative liabilities: Other current liabilities — 1 Other long-term liabilities 22 — Foreign currency derivative liabilities: Other current liabilities 8 — Total derivative liabilities $ 48 $ 57
Open Oil Derivative Positions [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Call Options Sold Period Volume (Bbls/d) Weighted Average Price ($/Bbl) Q1-Q4 2016 18,500 $ 73.18 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2016 Western Canadian Select 5,249 $ (13.67) Q1-Q4 2016 West Texas Sour 5,000 $ (0.53) Q1-Q4 2016 Midland Sweet 13,000 $ 0.25
Open Natural Gas Derivative Positions [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Price Swaps Call Options Sold Period Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Q1-Q4 2016 54,650 $ 3.17 400,000 $ 4.30 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2016 Panhandle Eastern Pipe Line 175,000 $ (0.34) Q1-Q4 2016 El Paso Natural Gas 125,000 $ (0.12) Q1-Q4 2016 Houston Ship Channel 30,000 $ 0.11 Q1-Q4 2016 Transco Zone 4 70,000 $ 0.01 Q1-Q4 2017 Panhandle Eastern Pipe Line 150,000 $ (0.34) Q1-Q4 2017 El Paso Natural Gas 50,000 $ (0.14) Q1-Q4 2017 Houston Ship Channel 35,000 $ 0.06 Q1-Q4 2017 Transco Zone 4 185,000 $ 0.03
Gas Processing And Fractionation Open Positions [Member] | EnLink [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Period Product Volume (Total) Weighted Average Price Paid Weighted Average Price Received Q1 2016-Q4 2016 Ethane 571 MBbls $ 0.29 /gal Index Q1 2016-Q4 2016 Propane 812 MBbls Index $ 0.81 /gal Q1 2016-Q4 2016 Normal Butane 113 MBbls Index $ 0.61 /gal Q1 2016-Q4 2016 Natural Gasoline 61 MBbls Index $ 1.02 /gal Q1 2016-Q1 2017 Natural Gas 13,829 MMBtu/d $ 2.65 /MMBtu Index
Interest Rate Derivatives [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Notional Rate Received Rate Paid Expiration (Millions) $ 100 Three Month LIBOR 0.92% December 2016 $ 100 1.76% Three Month LIBOR January 2019 $ 750 Three Month LIBOR 2.98% December 2048 (1) ____________________________ (1) Mandatory settlement in December 2018 .
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 (Millions) (CAD-USD) Canadian Dollar Sell $ 3,560 0.723 March 2016

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule Of The Effects Of Share-Based Compensation Included In The Consolidated Comprehensive Statements Of Earnings	Year Ended December 31, 2015 2014 2013 (Millions) Gross general and administrative expense for share-based compensation $ 225 $ 199 $ 157 Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties $ 63 $ 53 $ 60 Related income tax benefit $ 45 $ 42 $ 29
Summary Of Unvested Restricted Stock Awards and Units, Performance-Based Restricted Stock Awards And Performance Share Units	Restricted Stock Performance-Based Performance Awards and Units Restricted Stock Awards Share Units Awards and Units Weighted Average Grant-Date Fair Value Awards Weighted Average Grant-Date Fair Value Units Weighted Average Grant-Date Fair Value (Thousands, except fair value data) Unvested at 12/31/14 4,304 $ 60.85 380 $ 59.41 1,477 $ 70.90 Granted 2,771 $ 63.57 236 $ 62.02 786 $ 84.14 Vested (1,834) $ 60.33 (153) $ 59.49 (337) $ 66.00 Forfeited (503) $ 62.22 (29) $ 64.18 (67) $ 79.20 Unvested at 12/31/15 4,738 $ 62.49 434 $ 60.48 1,859 (1) $ 76.17 ____________________________ (1) A maximum of 3.7 million common shares could be awarded based upon Devon’s final TSR ranking.
Schedule Of Aggregate Fair Value Of Awards And Units That Vested During The Period	2015 2014 2013 (Millions) Restricted stock awards and units $ 101 $ 112 $ 141 Performance-based restricted stock awards $ 8 $ 10 $ 5 Performance share units $ 22 $ - $ -
Summary Of Performance Share Units Grant-Date Fair Values And Their Related Assumptions	2015 2014 2013 Grant-date fair value $ 81.99 - $ 85.05 $ 70.18 - $ 81.05 $ 61.27 - $ 63.48 Risk-free interest rate 1.06% 0.54% 0.26% - 0.36% Volatility factor 26.2% 28.8% 30.3% Contractual term (years) 2.89 2.89 3.0
Summary Of Outstanding Stock Options, Including Changes During The Year	Weighted Average Options Exercise Price Remaining Term Intrinsic Value (Thousands) (Years) (Millions) Outstanding at December 31, 2014 4,218 $ 70.56 Granted - $ - Exercised (63) $ 64.25 Expired (680) $ 84.36 Forfeited (27) $ 66.71 Outstanding at December 31, 2015 3,448 $ 67.98 2.41 $ - Vested and expected to vest at December 31, 2015 3,448 $ 67.98 2.41 $ - Exercisable at December 31, 2015 3,448 $ 67.98 2.41 $ -
Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition	Performance-Based Restricted Stock Restricted Stock Performance Awards and Units Awards Share Units Unrecognized compensation cost (millions) $ 198 $ 6 $ 45 Weighted average period for recognition (years) 2.5 2.6 1.8
General Partner And EnLink [Member]
Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition	General Partner EnLink Restricted Performance Restricted Performance Incentive Units Units Incentive Units Units Unrecognized compensation cost (millions) $ 17 $ 3 $ 16 $ 3 Weighted average period for recognition (years) 1.6 2.0 1.6 2.0

Asset Impairments (Tables)

Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Impairments [Abstract]
Schedule Of Asset Impairments	Year Ended December 31, 2015 2014 2013 (Millions) U.S. oil and gas assets $ 17,992 $ — $ 1,110 Canada oil and gas assets 1,257 — 843 Canada goodwill — 1,941 — EnLink goodwill 1,328 — — EnLink other intangible assets 223 — — Other assets 20 12 23 Total asset impairments $ 20,820 $ 1,953 $ 1,976

Restructuring Costs (Tables)

Restructuring Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Restructuring Costs [Abstract]
Schedule Of The Components Of Restructuring Costs Included In The Consolidated Comprehensive Statements Of Earnings	Year Ended December 31, 2015 2014 2013 (Millions) Office consolidation and offshore divestiture: Employee severance and retention $ - $ - $ 13 Lease obligations and other 54 - 41 Canada divestitures: Employee severance and retention 11 42 - Lease obligations and other 13 4 - Restructuring costs $ 78 $ 46 $ 54
Schedule Of The Activity And Balances Associated With Restructuring Liabilities	Other Other Current Long-term Liabilities Liabilities Total (Millions) Balance as of December 31, 2013 $ 27 $ 18 $ 45 Changes due to office consolidation and offshore divestiture (18) (11) (29) Changes due to Canadian divestitures 4 — 4 Balance as of December 31, 2014 13 7 20 Changes due to office consolidation and offshore divestiture 1 46 47 Changes due to Canadian divestitures (1) 10 9 Balance as of December 31, 2015 $ 13 $ 63 $ 76

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Schedule Of Income Tax Expense (Benefit)	Year Ended December 31, 2015 2014 2013 (Millions) Current income tax expense (benefit): U.S. federal $ (243) $ 152 $ 73 Various states (8) 18 (5) Canada and various provinces 14 307 4 Total current tax expense (benefit) (237) 477 72 Deferred income tax expense (benefit): U.S. federal (5,033) 1,610 198 Various states (336) 93 59 Canada and various provinces (459) 188 (160) Total deferred tax expense (benefit) (5,828) 1,891 97 Total income tax expense (benefit) $ (6,065) $ 2,368 $ 169
Schedule Of Effective Income Tax Rate Reconciliation	Year Ended December 31, 2015 2014 2013 Total income tax expense (benefit) (millions) $ (6,065) $ 2,368 $ 169 U.S. statutory income tax rate (35)% 35% 35% Non-deductible goodwill and intangible impairment 2% 23% 0% Taxation on Canadian operations 1% (4)% 9% State income taxes (1)% 2% 23% Repatriations 0% 2% 65% Deferred tax asset valuation allowance 4% 0% 0% Other 0% 0% (19)% Effective income tax rate (29)% 58% 113%
Schedule Of Deferred Tax Assets And Liabilities	December 31, 2015 2014 Deferred tax assets: (Millions) Property and equipment $ 490 $ - Asset retirement obligations 485 458 Accrued liabilities 160 150 Net operating loss carryforwards 175 200 Pension benefit obligations 106 113 Other 162 180 Total deferred tax assets before valuation allowance 1,578 1,101 Less: valuation allowance (967) - Net deferred tax assets 611 1,101 Deferred tax liabilities: Property and equipment (1,187) (6,940) Fair value of financial instruments - (699) Long-term debt (36) (115) Other (271) (160) Total deferred tax liabilities (1,494) (7,914) Net deferred tax liability $ (883) $ (6,813)
Schedule Of Changes In Unrecognized Tax Benefits	December 31, 2015 2014 (Millions) Balance at beginning of year $ 241 $ 243 Tax positions taken in prior periods (19) - Tax positions taken in current year 31 - Accrual of interest related to tax positions taken (5) 2 Settlements (108) - Foreign currency translation (9) (4) Balance at end of year $ 131 $ 241
Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities	Jurisdiction Tax Years Open U.S. Federal 2008 - 2015 Various U.S. states 2008 - 2015 Canada Federal 2003 - 2015 Various Canadian provinces 2003 - 2015

Net Earnings (Loss) Per Share36

Net Earnings (Loss) Per Share Attributable To Devon (Tables)	12 Months Ended
	Dec. 31, 2015
Net earnings (loss) per share attributable to Devon:
Net Earnings (Loss) Per Share Computations	Year Ended December 31, 2015 2014 2013 (Millions, except per share amounts) Net earnings (loss): Net earnings (loss) attributable to Devon $ (14,454) $ 1,607 $ (20) Attributable to participating securities (5) (17) (2) Basic and diluted earnings (loss) $ (14,459) $ 1,590 $ (22) Common shares: Common shares outstanding - total 412 409 406 Attributable to participating securities (5) (4) (4) Common shares outstanding - basic 407 405 402 Dilutive effect of potential common shares issuable - 2 - Common shares outstanding - diluted 407 407 402 Net earnings (loss) per share attributable to Devon: Basic $ (35.55) $ 3.93 $ (0.06) Diluted $ (35.55) $ 3.91 $ (0.06) Antidilutive options (1) 4 3 7 ____________________________ (1 ) Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.

Other Comprehensive Earnings (T

Other Comprehensive Earnings (Tables)	12 Months Ended
	Dec. 31, 2015
Other Comprehensive Earnings [Abstract]
Components Of Other Comprehensive Earnings	Year Ended December 31, 2015 2014 2013 (Millions) Foreign currency translation: Beginning accumulated foreign currency translation $ 983 $ 1,448 $ 1,996 Change in cumulative translation adjustment (621) (499) (574) Income tax benefit 62 34 26 Ending accumulated foreign currency translation 424 983 1,448 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (204) (180) (225) Net actuarial gain (loss) and prior service cost arising in current year (5) (57) 48 Recognition of net actuarial loss and prior service cost in earnings (1) 21 20 24 Income tax benefit (expense) (6) 13 (27) Ending accumulated pension and postretirement benefits (194) (204) (180) Accumulated other comprehensive earnings, net of tax $ 230 $ 779 $ 1,268 ____________________________ (1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of earnings. See Note 15 for additional details.

Supplemental Information To S38

Supplemental Information To Statements Of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Information To Statements Of Cash Flows [Abstract]
Schedule Of Supplemental Information To Statements Of Cash Flows	Year Ended December 31, 2015 2014 2013 (Millions) Net change in working capital accounts: Accounts receivable $ 942 $ 128 $ (288) Income taxes receivable 384 (467) 29 Other current assets (57) (222) 20 Accounts payable (190) (68) 26 Revenues and royalties payable (526) 133 35 Income taxes payable (275) 30 - Other current liabilities (579) 516 (120) Net change in working capital $ (301) $ 50 $ (298) Interest paid (net of capitalized interest) $ 494 $ 514 $ 406 Income taxes paid (received) $ (279) $ 899 $ 13

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2015
Accounts Receivable [Abstract]
Schedule Of Components Of Accounts Receivable	December 31, 2015 December 31, 2014 (Millions) Oil, gas and NGL sales $ 362 $ 723 Joint interest billings 211 475 Marketing and midstream revenues 520 706 Other 30 71 Gross accounts receivable 1,123 1,975 Allowance for doubtful accounts (18) (16) Net accounts receivable $ 1,105 $ 1,959

Goodwill And Other Intangible40

Goodwill And Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Summary Of Goodwill	U.S. Canada EnLink Total (Millions) 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 - - 57 57 Impairment - - (1,328) (1,328) Balance as of December 31, 2015 $ 2,618 $ - $ 2,414 $ 5,032
Schedule Of Other Intangible Assets	December 31, 2015 December 31, 2014 (Millions) Customer relationships $ 745 $ 569 Accumulated amortization (55) (36) Net intangibles $ 690 $ 533
General Partner And EnLink [Member]
Summary Of Goodwill	Texas Louisiana Oklahoma Crude and Condensate General Partner Total (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 Acquired during period 28 - - 29 - 57 Impairment (492) (787) - (49) - (1,328) Balance as of December 31, 2015 $ 704 $ - $ 190 $ 93 $ 1,427 $ 2,414

Debt And Related Expenses (Tabl

Debt And Related Expenses (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instrument [Line Items]
Schedule Of Debt Instruments	December 31, 2015 December 31, 2014 (Millions) Devon debt Commercial paper $ 626 $ 932 Floating rate due December 15, 2015 - 500 Floating rate due December 15, 2016 350 350 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 5.85% due December 15, 2025 850 - 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 5.00% due June 15, 2045 750 - Net discount on debentures and notes (28) (18) Total Devon debt 10,023 9,239 EnLink debt Credit facilities 414 237 2.70% due April 1, 2019 400 400 7.1 25% due June 1, 2022 163 163 4.40% due April 1, 2024 550 550 4.15% due June 1, 2025 750 - 5.60% due April 1, 2044 350 350 5.05% due April 1, 2045 450 300 Net premium on debentures and notes 13 23 Total EnLink debt 3,090 2,023 Total debt 13,113 11,262 Less amount classified as short-term debt (1) 976 1,432 Total long-term debt $ 12,137 $ 9,830 __________________________ (1) 2015 short-term debt consists of $626 million of commercial paper and the $350 million floating rate due on December 15, 2016. 2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015.
Schedule of Debt Maturities	2016 $ 976 2017 - 2018 875 2019 1,100 2020 414 Thereafter 9,763 Total $ 13,128
Schedule Of Debt Assumed Upon Acquisition Of Business	Fair Value of Debt Assumed Effective Rate of Debt Assumed Debt Assumed (Millions) 8.25% due July 2018 (principal of $125 million) $ 147 5.5% 7.50% due September 2027 (principal of $150 million) $ 169 6.5%
Schedule Of Net Financing Cost Components	Year Ended December 31, 2015 2014 2013 (Millions) Interest based on debt outstanding $ 565 $ 532 $ 466 Early retirement of debt - 48 - Capitalized interest (62) (70) (56) Other fees and expenses 20 26 27 Interest expense 523 536 437 Interest income (6) (10) (20) Net financing costs $ 517 $ 526 $ 417
Other Debentures And Notes [Member]
Debt Instrument [Line Items]
Schedule Of Debt Instruments	Date Issued May 2012 July 2011 January 2009 March 2002 3.25% due May 15, 2022 $ 1,000 $ - $ - $ - 4.75% due May 15, 2042 750 - - - 4.00% due July 15, 2021 - 500 - - 5.60% due July 15, 2041 - 1,250 - - 6.30% due January 15, 2019 - - 700 - 7.95% due April 15, 2032 - - - 1,000 Discount and issuance costs (28) (24) (8) (14) Net proceeds $ 1,722 $ 1,726 $ 692 $ 986
EnLink [Member]
Debt Instrument [Line Items]
Schedule Of Fair Value Of Enlink's Debt	March 7, 2014 Fair Value of Debt Effective Rate of Debt (Millions) 8.875% due February 2018 (principal of $725 million) (1) $ 760 7.7% 7.125% due June 2022 (principal of $197 million) 226 5.3% Credit facilities 468 Total long-term debt $ 1,454 __________________________ (1) The 2018 senior notes were redeemed on April 18, 2014.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations [Abstract]
Summary Of Changes In Asset Retirement Obligations	Year Ended December 31, 2015 2014 (Millions) Asset retirement obligations as of beginning of period $ 1,399 $ 2,228 Liabilities incurred 63 97 Liabilities settled and divested (1) (89) (1,009) Revision of estimated obligation 62 70 Accretion expense on discounted obligation 75 89 Foreign currency translation adjustment (96) (76) Asset retirement obligations as of end of period 1,414 1,399 Less current portion 44 60 Asset retirement obligations, long-term $ 1,370 $ 1,339 __________________________ (1) 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 (Tables)

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule Of Changes In Defined Benefit Plan Obligations	Pension Benefits Postretirement Benefits 2015 2014 2015 2014 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,377 $ 1,177 $ 24 $ 24 Service cost 33 30 1 1 Interest cost 52 55 1 1 Actuarial loss (gain) (68) 203 (2) - Plan amendments - - 1 - Plan settlements - (4) - - Foreign exchange rate changes (6) (3) - - Participant contributions - - 2 2 Benefits paid (80) (81) (4) (4) Benefit obligation at end of year 1,308 1,377 23 24 Change in plan assets: Fair value of plan assets at beginning of year 1,149 1,006 - - Actual return on plan assets (16) 200 - - Employer contributions 11 29 2 2 Participant contributions - - 2 2 Plan settlements - (4) - - Benefits paid (80) (81) (4) (4) Foreign exchange rate changes (5) (1) - - Fair value of plan assets at end of year 1,059 1,149 - - Funded status at end of year $ (249) $ (228) $ (23) $ (24) Amounts recognized in balance sheet: Other long-term assets $ 2 $ 22 $ - $ - Other current liabilities (12) (10) (3) (3) Other long-term liabilities (239) (240) (20) (21) Net amount $ (249) $ (228) $ (23) $ (24) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 302 $ 317 $ (11) $ (11) Prior service cost (credit) 14 19 (6) (9) Total $ 316 $ 336 $ (17) $ (20)
Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets	December 31, 2015 2014 (Millions) Projected benefit obligation $ 244 $ 250 Accumulated benefit obligation $ 199 $ 191 Fair value of plan assets $ - $ -
Schedule Of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Postretirement Benefit Plans	Pension Benefits Postretirement Benefits 2015 2014 2013 2015 2014 2013 (Millions) Net periodic benefit cost: Service cost $ 33 $ 30 $ 36 $ 1 $ 1 $ 1 Interest cost 52 55 51 1 1 1 Expected return on plan assets (58) (54) (62) - - - Curtailment and settlement expense - 1 - - - - Recognition of net actuarial loss (gain) (1) 20 18 22 (1) (1) (1) Recognition of prior service cost (1) 4 4 4 (2) (2) (1) Total net periodic benefit cost (2) 51 54 51 (1) (1) - Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 5 57 (39) (1) - (3) Prior service cost (credit) arising in current year - - 2 1 - (8) Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost (20) (19) (22) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (4) (4) (4) 1 2 1 Total other comprehensive loss (earnings) (19) 34 (63) 2 3 (9) Total recognized $ 32 $ 88 $ (12) $ 1 $ 2 $ (9) __________________________ (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 G&A 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 2016	Pension Benefits Postretirement Benefits (Millions) Net actuarial loss (gain) $ 22 $ (2) Prior service cost (credit) 4 (1) Total $ 26 $ (3)
Schedule Of Weighted Average Actuarial Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Costs	Pension Benefits Postretirement Benefits 2015 2014 2013 2015 2014 2013 Assumptions to determine benefit obligations: Discount rate 4.25% 3.90% 4.80% 3.63% 3.25% 3.65% Rate of compensation increase 4.49% 4.49% 4.48% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate 3.90% 4.80% 3.85% 3.25% 3.65% 3.30% Rate of compensation increase 4.49% 4.49% 4.48% N/A N/A N/A Expected return on plan assets 5.22% 5.42% 5.48% N/A N/A N/A
Schedule Of Fair Value of Pension Assets By Asset Class	December 31, 2015 Fair Value Measurements Using: Actual Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (Millions) Fixed-income securities: U.S. Treasury obligations 17% $ 179 $ 88 $ 91 $ - Corporate bonds 48% 507 371 136 - Other bonds 3% 35 35 - - Total fixed-income securities 68% 721 494 227 - Equity securities: Global (large, mid, small cap) 18% 186 - 186 - Other securities: Hedge fund and alternative investments 11% 120 - - 120 Short-term investments 3% 32 6 26 - Total other securities 14% 152 6 26 120 Total investments 100% $ 1,059 $ 500 $ 439 $ 120 December 31, 2014 Fair Value Measurements Using: Actual Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (Millions) Fixed-income securities: U.S. Treasury obligations 35% $ 405 $ 50 $ 355 $ - Corporate bonds 32% 364 269 95 - Other bonds 3% 30 30 - - Total fixed-income securities 70% 799 349 450 - Equity securities: Global (large, mid, small cap) 17% 197 - 197 - Other securities: Hedge fund and alternative investments 10% 112 - - 112 Short-term investments 3% 41 15 26 - Total other securities 13% 153 15 26 112 Total investments 100% $ 1,149 $ 364 $ 673 $ 112
Schedule of Changes In Level 3 Plan Assets	December 31, 2013 $ 112 Disbursements (6) Investment returns 6 December 31, 2014 112 Purchases 5 Investment returns 3 December 31, 2015 $ 120
Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans	Pension Benefits Postretirement Benefits (Millions) Devon's 2016 contributions $ 12 $ 3 Benefit payments: 2016 $ 73 $ 3 2017 $ 75 $ 3 2018 $ 77 $ 3 2019 $ 78 $ 3 2020 $ 83 $ 2 2021 to 2025 $ 446 $ 7
Schedule Of Expense Related To These Defined Contribution Plans	Year Ended December 31, 2015 2014 2013 (Millions) 401(k) and enhanced contribution plans $ 63 $ 49 $ 41 Canadian pension and savings plans 16 20 26 Total $ 79 $ 69 $ 67
Target Allocation [Member]
Schedule Of Fair Value of Pension Assets By Asset Class	December 31, 2015 2014 Fixed income 70% 70% Equity 20% 20% Other 10% 10%

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
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 (Millions) 2016 $ 557 $ 69 $ 994 $ 70 2017 703 51 972 58 2018 791 34 936 76 2019 803 5 402 68 2020 845 2 255 42 Thereafter 206 28 1,042 129 Total $ 3,905 $ 189 $ 4,601 $ 443

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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 (Millions) December 31, 2015 assets (liabilities): Cash equivalents $ 1,871 $ 1,871 $ 1,471 $ 400 $ - Commodity derivatives $ 35 $ 35 $ - $ 35 $ - Commodity derivatives $ (18) $ (18) $ - $ (18) $ - Interest rate derivatives $ 2 $ 2 $ - $ 2 $ - Interest rate derivatives $ (22) $ (22) $ - $ (22) $ - Foreign currency derivatives $ 8 $ 8 $ - $ 8 $ - Foreign currency derivatives $ (8) $ (8) $ - $ (8) $ - Debt $ (13,113) $ (11,927) $ - $ (11,927) $ - Capital lease obligations $ (17) $ (16) $ - $ (16) $ - December 31, 2014 assets (liabilities): Cash equivalents $ 950 $ 950 $ 340 $ 610 $ - Commodity derivatives $ 1,995 $ 1,995 $ - $ 1,995 $ - Commodity derivatives $ (56) $ (56) $ - $ (56) $ - 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) $ -

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Information [Abstract]
Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments	U.S. (1) Canada EnLink (1) Eliminations Total (Millions) Year Ended December 31, 2015: Revenues from external customers $ 8,360 $ 1,012 $ 3,773 $ - $ 13,145 Intersegment revenues $ - $ - $ 679 $ (679) $ - Depreciation, depletion and amortization $ 2,220 $ 522 $ 387 $ - $ 3,129 Asset impairments $ 18,000 $ 1,257 $ 1,563 $ - $ 20,820 Interest expense $ 368 $ 94 $ 107 $ (46) $ 523 Loss before income taxes $ (18,214) $ (1,670) $ (1,384) $ - $ (21,268) Income tax expense (benefit) $ (5,650) $ (445) $ 30 $ - $ (6,065) Net loss $ (12,564) $ (1,225) $ (1,414) $ - $ (15,203) Net earnings (loss) attributable to noncontrolling interests $ 1 $ - $ (750) $ - $ (749) Net loss attributable to Devon $ (12,565) $ (1,225) $ (664) $ - $ (14,454) Property and equipment, net $ 8,811 $ 4,590 $ 5,667 $ - $ 19,068 Total assets $ 14,600 $ 5,464 $ 9,565 $ (97) $ 29,532 Capital expenditures $ 4,575 $ 680 $ 978 $ - $ 6,233 Year Ended December 31, 2014: Revenues from external customers $ 14,854 $ 2,063 $ 2,649 $ - $ 19,566 Intersegment revenues $ - $ - $ 859 $ (859) $ - Depreciation, depletion and amortization $ 2,475 $ 560 $ 284 $ - $ 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 $ 4,390 $ (657) $ 326 $ - $ 4,059 Income tax expense $ 1,797 $ 495 $ 76 $ - $ 2,368 Net earnings (loss) $ 2,593 $ (1,152) $ 250 $ - $ 1,691 Net earnings attributable to noncontrolling interests $ 1 $ - $ 83 $ - $ 84 Net earnings (loss) attributable to Devon $ 2,592 $ (1,152) $ 167 $ - $ 1,607 Property and equipment, net $ 24,463 $ 6,790 $ 5,043 $ - $ 36,296 Total assets $ 32,037 $ 8,517 $ 10,207 $ (124) $ 50,637 Capital expenditures $ 11,214 $ 1,344 $ 1,001 $ - $ 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 __________________________ (1) Due to Devon’s control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recasted periods .

Supplemental Information On O47

Supplemental Information On Oil And Gas Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Information On Oil And Gas Operations [Abstract]
Costs Incurred	Year Ended December 31, 2015 U.S. Canada Total (Millions) Property acquisition costs: Proved properties $ 193 $ 2 $ 195 Unproved properties 634 83 717 Exploration costs 478 109 587 Development costs 3,269 402 3,671 Costs incurred $ 4,574 $ 596 $ 5,170 Year Ended December 31, 2014 U.S. Canada Total (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 (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
Capitalized Costs	December 31, 2015 U.S. Canada Total (Millions) Proved properties $ 64,443 $ 13,747 $ 78,190 Unproved properties 1,352 1,232 2,584 Total oil and gas properties 65,795 14,979 80,774 Accumulated DD&A (58,312) (11,185) (69,497) Net capitalized costs $ 7,483 $ 3,794 $ 11,277 December 31, 2014 U.S. Canada Total (Millions) Proved properties $ 59,849 $ 15,889 $ 75,738 Unproved properties 1,460 1,292 2,752 Total oil and 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
Oil And Gas Properties Not Subject To Amortization	Costs Incurred In 2015 2014 2013 Prior to 2013 Total (Millions) Acquisition costs $ 672 $ 412 $ 61 $ 510 $ 1,655 Exploration costs 191 132 69 170 562 Development costs 9 28 17 128 182 Capitalized interest 50 37 32 66 185 Total oil and gas properties not subject to amortization $ 922 $ 609 $ 179 $ 874 $ 2,584
Results Of Operations	December 31, 2015 U.S. Canada Total (Millions) Oil, gas and NGL sales $ 4,356 $ 1,026 $ 5,382 Lease operating expenses (1,551) (553) (2,104) General and administrative expenses (196) (28) (224) Production and property taxes (309) (33) (342) Depreciation, depletion and amortization (2,107) (474) (2,581) Asset impairments (17,992) (1,257) (19,249) Accretion of asset retirement obligations (47) (27) (74) Income tax benefit 5,547 314 5,861 Results of operations $ (12,299) $ (1,032) $ (13,331) Depreciation, depletion and amortization per Boe $ 10.21 $ 11.30 $ 10.40 December 31, 2014 U.S. Canada Total (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 December 31, 2013 U.S. Canada Total (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 __________________________ (1) During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information.
Proved Reserves	Oil (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 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) December 31, 2013 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) December 31, 2014 351 23 374 Revisions due to prices (53) 4 (49) Revisions other than price (52) 2 (50) Extensions and discoveries 51 3 54 Purchase of reserves 5 - 5 Production (60) (10) (70) December 31, 2015 242 22 264 Proved developed reserves as of: December 31, 2012 166 62 228 December 31, 2013 194 56 250 December 31, 2014 255 23 278 December 31, 2015 203 22 225 Proved developed-producing reserves as of: December 31, 2012 155 56 211 December 31, 2013 178 51 229 December 31, 2014 224 19 243 December 31, 2015 192 19 211 Proved undeveloped reserves as of: December 31, 2012 39 3 42 December 31, 2013 35 - 35 December 31, 2014 96 - 96 December 31, 2015 39 - 39 Bitumen (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 - 528 528 Revisions due to prices - (11) (11) Revisions other than price - 16 16 Extensions and discoveries - 38 38 Production - (19) (19) December 31, 2013 - 552 552 Revisions due to prices - (37) (37) Revisions other than price - 18 18 Extensions and discoveries - 8 8 Production - (20) (20) December 31, 2014 - 521 521 Revisions due to prices - 103 103 Revisions other than price - (84) (84) Extensions and discoveries - 11 11 Production - (31) (31) December 31, 2015 - 520 520 Proved developed reserves as of: December 31, 2012 - 99 99 December 31, 2013 - 111 111 December 31, 2014 - 137 137 December 31, 2015 - 219 219 Proved developed-producing reserves as of: December 31, 2012 - 99 99 December 31, 2013 - 111 111 December 31, 2014 - 137 137 December 31, 2015 - 219 219 Proved undeveloped reserves as of: December 31, 2012 - 429 429 December 31, 2013 - 441 441 December 31, 2014 - 384 384 December 31, 2015 - 301 301 Gas (Bcf) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 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) December 31, 2013 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) December 31, 2014 7,651 36 7,687 Revisions due to prices (1,412) (9) (1,421) Revisions other than price (3) (6) (9) Extensions and discoveries 171 - 171 Purchase of reserves 17 - 17 Production (579) (8) (587) Sale of reserves (37) - (37) December 31, 2015 5,808 13 5,821 Proved developed reserves as of: December 31, 2012 7,391 679 8,070 December 31, 2013 7,707 752 8,459 December 31, 2014 6,948 36 6,984 December 31, 2015 5,694 13 5,707 Proved developed-producing reserves as of: December 31, 2012 7,091 624 7,715 December 31, 2013 7,425 680 8,105 December 31, 2014 6,746 34 6,780 December 31, 2015 5,546 13 5,559 Proved undeveloped reserves as of: December 31, 2012 1,371 5 1,376 December 31, 2013 843 6 849 December 31, 2014 703 - 703 December 31, 2015 114 - 114 Natural Gas Liquids (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 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) December 31, 2013 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) December 31, 2014 578 - 578 Revisions due to prices (119) - (119) Revisions other than price (6) - (6) Extensions and discoveries 24 - 24 Purchase of reserves 1 - 1 Production (50) - (50) December 31, 2015 428 - 428 Proved developed reserves as of: December 31, 2012 431 20 451 December 31, 2013 468 23 491 December 31, 2014 486 - 486 December 31, 2015 411 - 411 Proved developed-producing reserves as of: December 31, 2012 406 19 425 December 31, 2013 442 21 463 December 31, 2014 467 - 467 December 31, 2015 393 - 393 Proved undeveloped reserves as of: December 31, 2012 140 - 140 December 31, 2013 84 - 84 December 31, 2014 92 - 92 December 31, 2015 17 - 17 Total (MMBoe) (1) U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2012 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) December 31, 2013 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) December 31, 2014 2,205 549 2,754 Revisions due to prices (408) 106 (302) Revisions other than price (59) (83) (142) Extensions and discoveries 104 14 118 Purchase of reserves 9 - 9 Production (206) (42) (248) Sale of reserves (7) - (7) December 31, 2015 1,638 544 2,182 Proved developed reserves as of: December 31, 2012 1,829 294 2,123 December 31, 2013 1,947 315 2,262 December 31, 2014 1,900 165 2,065 December 31, 2015 1,563 243 1,806 Proved developed-producing reserves as of: December 31, 2012 1,743 278 2,021 December 31, 2013 1,857 297 2,154 December 31, 2014 1,815 162 1,977 December 31, 2015 1,509 240 1,749 Proved undeveloped reserves as of: December 31, 2012 407 433 840 December 31, 2013 258 443 701 December 31, 2014 305 384 689 December 31, 2015 75 301 376 _______________________ (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 NGL 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, 2014 305 384 689 Extensions and discoveries 13 11 24 Revisions due to prices (115) 80 (35) Revisions other than price (40) (80) (120) Conversion to proved developed reserves (88) (94) (182) Proved undeveloped reserves as of December 31, 2015 75 301 376
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended December 31, 2015 U.S. Canada Total (Millions) Future cash inflows $ 27,398 $ 13,047 $ 40,445 Future costs: Development (3,306) (2,759) (6,065) Production (17,251) (6,891) (24,142) Future income tax expense - (475) (475) Future net cash flow 6,841 2,922 9,763 10% discount to reflect timing of cash flows (1,973) (1,102) (3,075) Standardized measure of discounted future net cash flows $ 4,868 $ 1,820 $ 6,688 Year Ended December 31, 2014 U.S. Canada Total (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 (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
Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves	Year Ended December 31, 2015 2014 2013 (Millions) Beginning balance $ 20,474 $ 15,741 $ 13,221 Net changes in prices and production costs (20,756) 2,561 3,018 Oil, bitumen, gas and NGL sales, net of production costs (2,704) (6,865) (5,613) Changes in estimated future development costs 1,313 (768) 399 Extensions and discoveries, net of future development costs 1,129 4,836 4,047 Purchase of reserves 95 6,422 14 Sales of reserves in place (79) (2,384) (44) Revisions of quantity estimates (1,451) (746) (1,040) Previously estimated development costs incurred during the period 2,158 1,933 1,986 Accretion of discount 567 1,746 1,940 Foreign exchange and other (1,254) (107) (583) Net change in income taxes 7,196 (1,895) (1,604) Ending balance $ 6,688 $ 20,474 $ 15,741

Supplemental Quarterly Financ48

Supplemental Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Schedule Of Unaudited Interim Results Of Operations	2015 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Operating revenues $ 3,265 $ 3,393 $ 3,601 $ 2,886 $ 13,145 Loss before income taxes $ (5,624) $ (4,479) $ (5,623) $ (5,542) $ (21,268) Net loss attributable to Devon $ (3,599) $ (2,816) $ (3,507) $ (4,532) $ (14,454) Basic net loss per share attributable to Devon $ (8.88) $ (6.94) $ (8.64) $ (11.12) $ (35.55) Diluted net loss per share attributable to Devon $ (8.88) $ (6.94) $ (8.64) $ (11.12) $ (35.55) 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Operating revenues $ 3,725 $ 4,510 $ 5,336 $ 5,995 $ 19,566 Earnings 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

Summary Of Significant Accoun49

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Accrued derivative receivable	$ 236
Derivative collateral held	$ 75	$ 524
Major Customer Accounting For More Than 10 Percent Of Operating Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Concentration risk percentage	0.00%	0.00%	0.00%
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 Divestitures50

Acquisitions And Divestitures (Narrative) (Details) shares in Millions, CAD in Millions, $ in Millions

Jan. 07, 2016USD ($)ashares

Dec. 17, 2015USD ($)a

Mar. 07, 2014USD ($)

Feb. 28, 2014USD ($)a

Dec. 31, 2015USD ($)shares

May. 31, 2015USD ($)

Apr. 30, 2015USD ($)

Feb. 28, 2015USD ($)

Nov. 30, 2014USD ($)

Sep. 30, 2014USD ($)

Jun. 30, 2014CAD

Jun. 30, 2014USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Business Acquisition [Line Items]

Gains and losses on assets sales

$ 1,072

$ (9)

Asset retirement obligation settled and divested

[1]

$ 89

1,009

Foreign currency exchange loss

$ (84)

Foreign earnings repatriated

2,800

2,800

4,300

Early retirement of senior notes

$ 1,900

Proceeds from property and equipment divestitures

$ 107

$ 5,120

$ 419

Foreign Currency Derivatives [Member]

Business Acquisition [Line Items]

Loss on derivative

29

Canadian Conventional Assets [Member]

Business Acquisition [Line Items]

Gains and losses on assets sales

1,100

Gains and losses on assets sales after tax

600

Asset retirement obligation settled and divested

700

Derecognition in goodwill allocated to sold assets

(700)

Proceeds from property and equipment divestitures

CAD 3,125

$ 2,800

U.S. Assets [Member]

Business Acquisition [Line Items]

Gains and losses on assets sales

$ 0

Asset retirement obligation settled and divested

200

Proceeds from property and equipment divestitures

$ 2,200

General Partner And EnLink [Member]

Business Acquisition [Line Items]

Close date of acquisition

Mar. 7, 2014

Cash payment to acquire interest

$ 100

GeoSouthern Intermediate Holdings, LLC [Member]

Business Acquisition [Line Items]

Close date of acquisition

Feb. 28, 2014

Aggregate purchase price

$ 6,000

Unproved properties

1,007

Proved properties

$ 5,026

Number of net acres acquired | a

82,000

Powder River Basin

Business Acquisition [Line Items]

Close date of acquisition

Dec. 17, 2015

Aggregate purchase price

$ 499

Unproved properties

$ 386

$ 386

Proved properties

$ 113

$ 113

Cash payment to acquire interest

$ 300

Number of net acres acquired | a

253,000

Powder River Basin | Common Stock [Member] | Equity Issued in Business Combination [Member]

Business Acquisition [Line Items]

Equity units value

$ 199

Units issued for acquisition | shares

7

Anadarko Basin STACK [Member] | Subsequent Event [Member]

Business Acquisition [Line Items]

Close date of acquisition

Jan. 7, 2016

Aggregate purchase price

$ 1,500

Cash payment to acquire interest

$ 850

Number of net acres acquired | a

80,000

Anadarko Basin STACK [Member] | Subsequent Event [Member] | Common Stock [Member] | Equity Issued in Business Combination [Member]

Business Acquisition [Line Items]

Equity units value

$ 659

EnLink [Member] | Victoria Express Pipeline [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 176

Estimated construction costs assumed

$ 35

EnLink [Member] | EnLink Midstream Holdings [Member]

Business Acquisition [Line Items]

Ownership interest percentage acquired

25.00%

25.00%

Equity units value

$ 900

$ 925

EnLink [Member] | Anadarko Basin [Member] | Subsequent Event [Member]

Business Acquisition [Line Items]

Close date of acquisition

Jan. 7, 2016

Aggregate purchase price

1,500

Cash payment to acquire interest

800

Amount committed to pay

$ 500

Commitment to pay cash due date

24 months

General Partner [Member] | Anadarko Basin [Member] | Subsequent Event [Member] | Common Stock [Member] | Equity Issued in Business Combination [Member]

Business Acquisition [Line Items]

Units issued for acquisition | shares

15.6

[1]

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.

Acquisitions And Divestitures51

Acquisitions And Divestitures (Components Of Business Formation For General Partner And EnLink) (Details) - General Partner And EnLink [Member] $ / shares in Units, shares in Millions, $ in Millions	Mar. 07, 2014USD ($)$ / sharesshares
Business Acquisition [Line Items]
Total consideration and fair value of noncontrolling interests | $	$ 4,670
Crosstex Energy, Inc. [Member]
Business Acquisition [Line Items]
Held by public shareholders	48
Total	48.4
Exchange ratio	1
Converted shares	48.4
Common share or unit price | $ / shares	$ 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, Inc. [Member] | Restricted Stock [Member]
Business Acquisition [Line Items]
Restricted shares/units	0.4
Crosstex Energy, LP [Member]
Business Acquisition [Line Items]
Total	92.6
Common share or unit price | $ / shares	$ 30.51	[3]
Common units held by public unitholders	75.1
Preferred units held by third party	17.1	[4]
Common units value | $	$ 2,825
Outstanding unit options value | $	4
Fair value of noncontrolling interests | $	$ 2,829	[3]
Crosstex Energy, LP [Member] | Restricted Stock [Member]
Business Acquisition [Line Items]
Restricted shares/units	0.4
[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.
[3]	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.
[4]	Crosstex Energy, LP converted the preferred units to common units in February 2014.

Acquisitions And Divestitures52

Acquisitions And Divestitures (Schedule of Purchase Price Allocation for EnLink and General Partner) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014	Mar. 07, 2014	Dec. 31, 2013
Assets acquired:
Goodwill		$ 5,032	$ 6,303		$ 5,858
General Partner And EnLink [Member]
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.

Acquisitions And Divestitures53

Acquisitions And Divestitures (Schedule of EnLink's Acquisition Activity) (Details) - USD ($) $ in Millions	Oct. 01, 2015	Mar. 16, 2015	Jan. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Goodwill				$ 5,032	$ 6,303	$ 5,858
EnLink [Member] | LPC [Member]
Business Acquisition [Line Items]
Cash payment to acquire interest			$ 108
PP&E			30
Goodwill			30
Intangibles			43
Current assets			$ 5
EnLink [Member] | Coronado [Member]
Business Acquisition [Line Items]
Cash payment to acquire interest		$ 240
Common units value		360
PP&E		302
Goodwill		18
Intangibles		281
Current liabilities		$ (1)
EnLink [Member] | Matador [Member]
Business Acquisition [Line Items]
Cash payment to acquire interest	$ 145
PP&E	36
Goodwill	9
Intangibles	99
Current assets	$ 1

Acquisitions And Divestitures54

Acquisitions And Divestitures (Schedule Of Purchase Price Allocation For GeoSouthern Intermediate Holdings) (Details) - GeoSouthern Intermediate Holdings, LLC [Member] $ in Millions	Feb. 28, 2014USD ($)
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 Divestitures55

Acquisitions And Divestitures (Schedule Of Unaudited Proforma Information For General Partner and EnLink And GeoSouthern) (Details) - General Partner and EnLink and GeoSouthern [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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 Instrume56

Derivative Financial Instruments (Schedule Of Open Oil Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2015$ / bblbbl
NYMEX West Texas Intermediate Call Options Sold Oil Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d) | bbl	18,500
Weighted Average Call Option Sold Price | $ / bbl	73.18
Western Canadian Select Basis Swaps Oil Q1 - Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d) | bbl	5,249
Weighted Average Differential To WTI | $ / bbl	(13.67)
West Texas Sour Basis Swaps Oil Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d) | bbl	5,000
Weighted Average Differential To WTI | $ / bbl	(0.53)
Midland Sweet Basis Swaps Oil Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (Bbls/d) | bbl	13,000
Weighted Average Differential To WTI | $ / bbl	0.25

Derivative Financial Instrume57

Derivative Financial Instruments (Schedule Of Open Natural Gas Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2015MMBTU$ / MMBTU
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	54,650
Weighted Average Price Swap | $ / MMBTU	3.17
FERC Henry Hub Call Options Sold Natural Gas Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	400,000
Weighted Average Call Option Sold Price | $ / MMBTU	4.30
PEPL Basis Swaps Natural Gas Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	175,000
Weighted Average Differential To Henry Hub | $ / MMBTU	(0.34)
El Paso Natural Gas Basis Swaps Q1-Q4 2016 [Member
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	125,000
Weighted Average Differential To Henry Hub | $ / MMBTU	(0.12)
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	30,000
Weighted Average Differential To Henry Hub | $ / MMBTU	0.11
Transco Zone 4 Natural Gas Basis Swaps Q1-Q4 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	70,000
Weighted Average Differential To Henry Hub | $ / MMBTU	0.01
PEPL Basis Swaps Natural Gas Q1-Q4 2017 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	150,000
Weighted Average Differential To Henry Hub | $ / MMBTU	(0.34)
El Paso Natural Gas Basis Swaps Q1-Q4 2017 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	50,000
Weighted Average Differential To Henry Hub | $ / MMBTU	(0.14)
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2017 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	35,000
Weighted Average Differential To Henry Hub | $ / MMBTU	0.06
Transco Zone 4 Natural Gas Basis Swaps Q1-Q4 2017 [Member]
Derivatives, Fair Value [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	185,000
Weighted Average Differential To Henry Hub | $ / MMBTU	0.03

Derivative Financial Instrume58

Derivative Financial Instruments (Schedule Of Gas Processing and Fractionation Open Positions) (Details) - EnLink [Member]	12 Months Ended
	Dec. 31, 2015MMBTU$ / gal$ / MMBTUMBbls
OPIS Mont Belvieu Texas Ethane Basis Swap Q1 2016-Q4 2016 [Member]
Derivative [Line Items]
Volume (MBbls) | MBbls	571
Weighted average price paid, $/gal | $ / gal	0.29
Weighted average price received	Index
OPIS Mont Belvieu Texas Propane Basis Swap Q1 2016-Q4 2016 [Member]
Derivative [Line Items]
Volume (MBbls) | MBbls	812
Weighted average price paid	Index
Weighted average price received, $/gal | $ / gal	0.81
OPIS Mont Belvieu Texas Normal Butane Basis Swap Q1 2016-Q4 2016 [Member]
Derivative [Line Items]
Volume (MBbls) | MBbls	113
Weighted average price paid	Index
Weighted average price received, $/gal | $ / gal	0.61
OPIS Mont Belvieu Texas Natural Gasoline Basis Swap Q1 2016-Q4 2016 [Member]
Derivative [Line Items]
Volume (MBbls) | MBbls	61
Weighted average price paid	Index
Weighted average price received, $/gal | $ / gal	1.02
Henry Hub Natural Gas Basis Swap Q1 2016-Q1 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	13,829
Weighted average price paid, $/MMBtu | $ / MMBTU	2.65
Weighted average price received	Index

Derivative Financial Instrume59

Derivative Financial Instruments (Schedule Of Open Interest Rate Swap Derivative Positions) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Interest Rate Contract 0.92% Expiration December 2016 [Member]
Derivative [Line Items]
Notional	$ 100
Rate Received	Three Month LIBOR
Rate Paid, percent	0.92%
Expiration	Dec. 31, 2016
Interest Rate Contract 1.76% Expiration January 2019 [Member]
Derivative [Line Items]
Notional	$ 100
Rate Received, percent	1.76%
Rate Paid	Three Month LIBOR
Expiration	Jan. 31, 2019
Interest Rate Contract 2.98% Expiration December 2048 [Member]
Derivative [Line Items]
Notional	$ 750
Rate Received	Three Month LIBOR
Rate Paid, percent	2.98%
Expiration	Dec. 31, 2018
Reference period end date	Dec. 31, 2048	[1]
[1]	Mandatory settlement in December 2018.

Derivative Financial Instrume60

Derivative Financial Instruments (Schedule Of Open Foreign Exchange Rate Derivative Positions) (Details) - Forward Contract Expiration March 2016 [Member] CAD in Millions	12 Months Ended
	Dec. 31, 2015CAD
Derivative [Line Items]
Currency	Canadian Dollar
CAD Notional	CAD 3,560
Weighted Average Fixed Rate Received	0.723
Expiration	Mar. 31, 2016

Derivative Financial Instrume61

Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Comprehensive Statements Of Earnings) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	$ 738	$ 2,070	$ (135)
Commodity Derivatives [Member] | Oil, Gas And NGL Derivatives [Member]
Derivatives, Fair Value [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	503	1,989	(191)
Commodity Derivatives [Member] | Marketing And Midstream Revenues [Member]
Derivatives, Fair Value [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	9	22
Interest Rate Derivatives [Member] | Other Nonoperating Items [Member]
Derivatives, Fair Value [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	(20)	(1)
Foreign Currency Derivatives [Member] | Other Nonoperating Items [Member]
Derivatives, Fair Value [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	$ 246	$ 60	$ 56

Derivative Financial Instrume62

Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	$ 45	$ 2,004
Fair value of derivative liabilities	48	57
Commodity Derivatives [Member] | Derivatives, At Fair Value [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	34	1,984
Commodity Derivatives [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	1	11
Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	14	28
Commodity Derivatives [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	4	28
Interest Rate Derivatives [Member] | Derivatives, At Fair Value [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	1	1
Interest Rate Derivatives [Member] | Other Long-Term 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
Interest Rate Derivatives [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	22
Foreign Currency Derivatives [Member] | Derivatives, At Fair Value [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative assets	8	$ 8
Foreign Currency Derivatives [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative liabilities	$ 8

Share-Based Compensation (Narra

Share-Based Compensation (Narrative) (Details) $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2015shares	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)itemshares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation			$ 225	$ 199	$ 157
Restructuring charges			$ 78	$ 46	$ 54
Options, Granted | shares			0	0	0
2015 Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance | shares	28,000,000
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, options and stock appreciation rights | shares	1
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, other awards | shares	3
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost			$ 0
Expiration duration of options			8 years
Aggregate intrinsic value			$ 0.2	$ 9	$ 0.3
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of predetermined peer companies to compare against Devon's total shareholder's return for Performance awards | item			14
EnLink [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation			$ 31	17
General Partner And EnLink [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation		$ 7
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%
Accelerated Vesting Of Share-Based Grants For Employees [Member] | Canadian Divestitures [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restructuring charges				$ 15

Share-Based Compensation (Sched

Share-Based Compensation (Schedule Of The Effects Of Share Based Compensation Included In The Consolidated Comprehensive Statement Of Earnings) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation [Abstract]
Gross general and administrative expense for share-based compensation	$ 225	$ 199	$ 157
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	63	53	60
Related income tax benefit	$ 45	$ 42	$ 29

Share-Based Compensation (Summa

Share-Based Compensation (Summary Of Unvested Restricted Stock Awards and Units, Performance-Based Restricted Stock Awards And Performance Share Units) (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2014	4,304
Granted, awards and units	2,771
Vested, awards and units	(1,834)
Forfeited, awards and units	(503)
Unvested at December 31, 2015	4,738		4,304
Unvested weighted average grant-date fair value at December 31, 2014	$ 60.85
Granted, weighted average grant-date fair value	63.57
Vested, weighted average grant-date fair value	60.33
Forfeited, weighted average grant-date fair value	62.22
Unvested weighted average grant-date fair value at December 31, 2015	$ 62.49		$ 60.85
Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2014	380
Granted, awards and units	236
Vested, awards and units	(153)
Forfeited, awards and units	(29)
Unvested at December 31, 2015	434		380
Unvested weighted average grant-date fair value at December 31, 2014	$ 59.41
Granted, weighted average grant-date fair value	62.02
Vested, weighted average grant-date fair value	59.49
Forfeited, weighted average grant-date fair value	64.18
Unvested weighted average grant-date fair value at December 31, 2015	$ 60.48		$ 59.41
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2014	1,477
Granted, awards and units	786
Vested, awards and units	(337)
Forfeited, awards and units	(67)
Unvested at December 31, 2015	1,859	[1]	1,477
Unvested weighted average grant-date fair value at December 31, 2014	$ 70.90
Granted, weighted average grant-date fair value	84.14
Vested, weighted average grant-date fair value	66
Forfeited, weighted average grant-date fair value	79.20
Unvested weighted average grant-date fair value at December 31, 2015	76.17		$ 70.90
Maximum [Member] | Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, weighted average grant-date fair value	$ 85.05		$ 81.05	$ 63.48
Maximum common shares that could be awarded based upon total shareholder return	3,700
[1]	A maximum of 3.7 million common shares could be awarded based upon Devon's final TSR ranking.

Share-Based Compensation (Sch66

Share-Based Compensation (Schedule Of Aggregate Fair Value Restricted Stock, Performance-Based Restricted Stock And Performance Shares, Awards And Units) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate fair value of awards and units, vested	$ 101	$ 112	$ 141
Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate fair value of awards and units, vested	8	$ 10	$ 5
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate fair value of awards and units, vested	$ 22

Share-Based Compensation (Sum67

Share-Based Compensation (Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 198
Weighted average period for recognition (years)	2 years 6 months
Performance-Based Restricted Stock Awards [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 6
Weighted average period for recognition (years)	2 years 7 months 6 days
Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 45
Weighted average period for recognition (years)	1 year 9 months 18 days

Share-Based Compensation (Sum68

Share-Based Compensation (Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition General Partner And EnLink ) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 198
Weighted average period for recognition (years)	2 years 6 months
Performance-Based Restricted Stock Awards [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 6
Weighted average period for recognition (years)	2 years 7 months 6 days
Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 45
Weighted average period for recognition (years)	1 year 9 months 18 days
EnLink [Member] | Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 16
Weighted average period for recognition (years)	1 year 7 months 6 days
EnLink [Member] | Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 3
Weighted average period for recognition (years)	2 years
General Partner [Member] | Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 17
Weighted average period for recognition (years)	1 year 7 months 6 days
General Partner [Member] | Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 3
Weighted average period for recognition (years)	2 years

Share-Based Compensation (Sum69

Share-Based Compensation (Summary Of Performance Share Units Grant-Date Fair Values And Their Related Assumptions) (Details) - Performance Share Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 84.14
Risk-free interest rate	1.06%	0.54%
Volatility factor	26.20%	28.80%	30.30%
Contractual term (in years)	2 years 10 months 21 days	2 years 10 months 21 days	3 years
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 81.99	$ 70.18	$ 61.27
Risk-free interest rate			0.26%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 85.05	$ 81.05	$ 63.48
Risk-free interest rate			0.36%

Share-Based Compensation (Sum70

Share-Based Compensation (Summary Of Outstanding Stock Options, Including Changes During The Year) (Details) - Stock Options [Member] shares in Thousands	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Outstanding at December 31, 2014 | shares	4,218
Options, Exercised | shares	(63)
Options, Expired | shares	(680)
Options, Forfeited | shares	(27)
Outstanding at December 31, 2015 | shares	3,448
Vested and expected to vest, options | shares	3,448
Exercisable, options | shares	3,448
Weighted average exercise price, Outstanding, December 31, 2014 | $ / shares	$ 70.56
Exercised, weighted average exercise price | $ / shares	64.25
Expired, weighted average exercise price | $ / shares	84.36
Forfeited, weighted average exercise price | $ / shares	66.71
Weighted average exercise price, Outstanding, December 31, 2015 | $ / shares	67.98
Vested and expected to vest, weighted average exercise price | $ / shares	67.98
Exercisable, weighted average exercise price | $ / shares	$ 67.98
Outstanding, weighted average remaining term	2 years 4 months 28 days
Vested and expected to vest, weighted average remaining term	2 years 4 months 28 days
Exercisable, weighted average remaining term	2 years 4 months 28 days

Asset Impairments (Schedule of

Asset Impairments (Schedule of Asset Impairments) (Details) - USD ($) $ in Millions	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges	$ 5,300	$ 5,900	$ 4,200	$ 5,500	$ 1,900	$ 20,820	$ 1,953	$ 1,976
Goodwill, impairment loss						1,328	1,941
U.S. Oil And Gas Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges						17,992		1,110
Canada Oil And Gas Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges						1,257		843
Other Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges						20	12	$ 23
EnLink [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill, impairment loss						1,328
Impairment of intangible assets						$ 223
Canada [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill, impairment loss							$ 1,941

Restructuring Costs (Narrative)

Restructuring Costs (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ 78	$ 46	$ 54
Office Consolidation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred to date			$ 134
Employee Related And Other Costs [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges	24
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
Lease Obligations [Member] | Office Consolidation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ 54

Restructuring Costs (Schedule O

Restructuring Costs (Schedule Of The Components Of Restructuring Costs Included In The Comprehensive Consolidated Statements Of Earnings) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Restructuring costs	$ 78	$ 46	$ 54
Employee Severance And Retention [Member] | Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	11	42
Employee Severance And Retention [Member] | Office Consolidation And Offshore Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs			13
Lease Obligations And Other [Member] | Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	13	$ 4
Lease Obligations And Other [Member] | Office Consolidation And Offshore Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	$ 54		$ 41

Restructuring Costs (Schedule74

Restructuring Costs (Schedule Of The Activity And Balances Associated With Restructuring Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Restructuring Cost and Reserve [Line Items]
Beginning balance	$ 20	$ 45
Ending balance	76	20
Other Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Beginning balance	13	27
Ending balance	13	13
Other Long-Term Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Beginning balance	7	18
Ending balance	63	7
Canadian Divestitures [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	9	4
Canadian Divestitures [Member] | Other Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	(1)	4
Canadian Divestitures [Member] | Other Long-Term Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	10
Office Consolidation And Offshore Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	47	(29)
Office Consolidation And Offshore Divestiture [Member] | Other Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	1	(18)
Office Consolidation And Offshore Divestiture [Member] | Other Long-Term Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring reserve activity	$ 46	$ (11)

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended						6 Months Ended	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax [Line Items]
Asset impairments	$ 5,300	$ 5,900	$ 4,200	$ 5,500	$ 1,900			$ 20,820	$ 1,953	$ 1,976
Current income tax expense (benefit)								(237)	477	72
Income tax expense (benefit)								(6,065)	2,368	169
Deferred income tax expense (benefit)								(5,828)	1,891	97
Current income tax expense (benefit) on repatriation after foreign tax credits									67
Foreign earnings repatriated						$ 2,800			2,800	$ 4,300
Deferred tax liabilities, taxes on unremitted foreign earnings	10						$ 10	10
Deferred tax liability, other	271				160		271	271	160
Unremitted foreign earnings	1,200						1,200	1,200
Unremitted earnings from subsidiaries not to be permanently reinvested	37						37	37
Net operating loss carryforwards	175				200		175	175	200
Deferred tax assets, alternative minimum tax credits	6						6	6
Deferred tax assets, before valuation allowance	1,578				1,101		1,578	1,578	$ 1,101
Deferred tax assets, valuation allowance	967						967	$ 967
Valuation allowance against U.S. deferred tax assets, percent								4.00%	0.00%	0.00%
Unrecognized tax benefits, interest and penalties	29				34		29	$ 29	$ 34
Unrecognized tax benefit that would impact effective tax rate	131						131	$ 131
$83 Million Deferred Tax Benefit Component [Member]
Income Tax [Line Items]
Deferred income tax expense (benefit)										$ (180)
$83 Million Deferred Tax Benefit Component Offsetting Expense Component[Member]
Income Tax [Line Items]
Deferred income tax expense (benefit)										97
Full Cost Impairments Recognized [Member]
Income Tax [Line Items]
Valuation allowance against U.S. deferred tax assets, percent								100.00%
Assumed Repatriations Of Foreign Earnings [Member]
Income Tax [Line Items]
Deferred tax liabilities, taxes on unremitted foreign earnings					143				143
Repatriated Foreign Earnings [Member]
Income Tax [Line Items]
Current income tax expense (benefit)									105	180
Income tax expense (benefit)										97
Deferred income tax expense (benefit)										(83)
Canada Federal [Member]
Income Tax [Line Items]
Deferred tax assets, Canadian net operating loss carryforward	495						495	$ 495
Various U.S. States [Member]
Income Tax [Line Items]
Net operating loss carryforwards	275						275	275
EnLink [Member]
Income Tax [Line Items]
Goodwill and intangibles impairments							1,600
Deferred tax liability, other					$ 46				46
Net operating loss carryforwards	$ 205						$ 205	$ 205
Minimum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date								Dec. 31, 2030
Minimum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date								Dec. 31, 2018
Minimum [Member] | EnLink [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date								Dec. 31, 2028
Minimum [Member] | EnLink [Member] | Canada Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, utilization period								Dec. 31, 2017
Maximum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date								Dec. 31, 2035
Maximum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date								Dec. 31, 2035
Maximum [Member] | EnLink [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date								Dec. 31, 2035
U.S. Asset Divestiture [Member]
Income Tax [Line Items]
Current income tax expense (benefit)									$ 294
U.S. Oil And Gas Assets [Member]
Income Tax [Line Items]
Asset impairments								$ 17,992		$ 1,110
U.S. Oil And Gas Operations [Member]
Income Tax [Line Items]
Asset impairments								$ 18,000

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current income tax expense (benefit):
United States federal, current income tax expense (benefit)	$ (243)	$ 152	$ 73
Various states, current income tax expense (benefit)	(8)	18	(5)
Canada and various provinces, current income tax expense (benefit)	14	307	4
Total current tax expense (benefit)	(237)	477	72
Deferred income tax expense (benefit):
United States federal, deferred income tax expense (benefit)	(5,033)	1,610	198
Various states, deferred income tax expense (benefit)	(336)	93	59
Canada and various provinces, deferred income tax expense (benefit)	(459)	188	(160)
Total deferred tax expense (benefit)	(5,828)	1,891	97
Total income tax expense (benefit)	$ (6,065)	$ 2,368	$ 169

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Abstract]
Total income tax expense (benefit)	$ (6,065)	$ 2,368	$ 169
U.S. statutory income tax rate	(35.00%)	35.00%	35.00%
Non-deductible goodwill and intangibles impairment	2.00%	23.00%	0.00%
Taxation on Canadian operations	1.00%	(4.00%)	9.00%
State income taxes	(1.00%)	2.00%	23.00%
Repatriations	0.00%	2.00%	65.00%
Deferred tax asset valuation allowance	4.00%	0.00%	0.00%
Other	0.00%	0.00%	(19.00%)
Effective income tax rate	(29.00%)	58.00%	113.00%

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Abstract]
Deferred tax assets, property and equipment	$ 490
Deferred tax assets, asset retirement obligations	485	$ 458
Deferred tax assets, accrued liabilities	160	150
Deferred tax assets, net operating loss carryforwards	175	200
Deferred tax assets, pension benefit obligations	106	113
Deferred tax assets, other	162	180
Total deferred tax assets before valuation allowance	1,578	1,101
Less: valuation allowance	(967)
Net deferred tax assets	611	1,101
Deferred tax liabilities, property and equipment	(1,187)	(6,940)
Deferred tax liabilities, fair value of financial instruments		(699)
Deferred tax liabilities, long-term debt	(36)	(115)
Deferred tax liabilities, other	(271)	(160)
Total deferred tax liabilities	(1,494)	(7,914)
Net deferred tax liabilities	$ (883)	$ (6,813)

Income Taxes (Schedule Of Chang

Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Abstract]
Unrecognized tax benefits, Balance at beginning of year	$ 241	$ 243
Unrecognized tax benefits, Tax positions taken in prior periods	(19)
Unrecognized tax benefits, Tax positions taken in current year	31
Unrecognized tax benefits, Accrual of interest related to tax positions taken	(5)	2
Unrecognized tax benefits, Settlements	(108)
Unrecognized tax benefits, Foreign currency translation	(9)	(4)
Unrecognized tax benefits, Balance at end of year	$ 131	$ 241

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, 2015
United States Federal [Member] | Minimum [Member]
Tax years open	2,008
United States Federal [Member] | Maximum [Member]
Tax years open	2,015
Various U.S. States [Member] | Minimum [Member]
Tax years open	2,008
Various U.S. States [Member] | Maximum [Member]
Tax years open	2,015
Canada Federal [Member] | Minimum [Member]
Tax years open	2,003
Canada Federal [Member] | Maximum [Member]
Tax years open	2,015
Various Canadian Provinces [Member] | Minimum [Member]
Tax years open	2,003
Various Canadian Provinces [Member] | Maximum [Member]
Tax years open	2,015

Net Earnings (Loss) Per Share81

Net Earnings (Loss) Per Share Attributable To Devon (Earnings Per Share Computations) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net earnings (loss):
Net earnings (loss) attributable to Devon		$ (4,532)	$ (3,507)	$ (2,816)	$ (3,599)	$ (408)	$ 1,016	$ 675	$ 324	$ (14,454)	$ 1,607	$ (20)
Attributable to participating securities										(5)	(17)	(2)
Basic and diluted earnings (loss)										$ (14,459)	$ 1,590	$ (22)
Common shares:
Common shares outstanding - total										412	409	406
Attributable to participating securities										(5)	(4)	(4)
Common shares outstanding - basic										407	405	402
Dilutive effect of potential common shares issuable											2
Common shares outstanding - diluted										407	407	402
Net earnings (loss) per share attributable to Devon:
Basic		$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (1.01)	$ 2.48	$ 1.65	$ 0.80	$ (35.55)	$ 3.93	$ (0.06)
Diluted		$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (1.01)	$ 2.47	$ 1.64	$ 0.79	$ (35.55)	$ 3.91	$ (0.06)
Antidilutive options	[1]									4	3	7
[1]	Amounts represent options to purchase shares of Devon's common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.

Other Comprehensive Earnings (C

Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Foreign currency translation:
Beginning accumulated foreign currency translation		$ 983	$ 1,448	$ 1,996
Change in cumulative translation adjustment		(621)	(499)	(574)
Income tax benefit		62	34	26
Ending accumulated foreign currency translation		424	983	1,448
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(204)	(180)	(225)
Net actuarial gain (loss) and prior service cost arising in current year		(5)	(57)	48
Recognition of net actuarial loss and prior service cost in earnings	[1]	21	20	24
Income tax benefit (expense)		(6)	13	(27)
Ending accumulated pension and postretirement benefits		(194)	(204)	(180)
Accumulated other comprehensive earnings, net of tax		$ 230	$ 779	$ 1,268
[1]	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of earnings. See Note 15 for additional details.

Supplemental Information To S83

Supplemental Information To Statements Of Cash Flows (Schedule Of Supplemental Information To Statements Of Cash Flows) (Narrative) (Details) - USD ($) $ in Millions	Dec. 17, 2015	Mar. 07, 2014
General Partner And EnLink [Member]
Supplemental Cash Flow [Line Items]
Cash payment to acquire interest		$ 100
Powder River Basin
Supplemental Cash Flow [Line Items]
Cash payment to acquire interest	$ 300
Equity Issued in Business Combination [Member] | Powder River Basin | Common Stock [Member]
Supplemental Cash Flow [Line Items]
Noncash common stock issuance in acquisition, value	$ 199

Supplemental Information To S84

Supplemental Information To Statements Of Cash Flows (Schedule Of Supplemental Information To Statements Of Cash Flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net change in working capital accounts:
Accounts receivable	$ 942	$ 128	$ (288)
Income taxes receivable	384	(467)	29
Other current assets	(57)	(222)	20
Accounts payable	(190)	(68)	26
Revenues and royalties payable	(526)	133	35
Income taxes payable	(275)	30
Other current liabilities	(579)	516	(120)
Net change in working capital	(301)	50	(298)
Interest paid (net of capitalized interest)	494	514	406
Income taxes paid (received)	$ (279)	$ 899	$ 13

Accounts Receivable (Schedule O

Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Joint interest billings	$ 211	$ 475
Other	30	71
Gross accounts receivable	1,123	1,975
Allowance for doubtful accounts	(18)	(16)
Net accounts receivable	1,105	1,959
Oil, Gas And NGL Sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	362	723
Marketing And Midstream Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	$ 520	$ 706

Goodwill And Other Intangible86

Goodwill And Other Intangible Assets (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Goodwill	$ 5,032	$ 6,303	$ 5,858
Removal of goodwill for asset divestitures		706
Goodwill impairments	1,328	1,941
Amortization expense, next five years	46
EnLink Midstream Holdings [Member]
Goodwill [Line Items]
Goodwill			402
EnLink [Member]
Goodwill [Line Items]
Goodwill impairments	1,328
Impairment of noncash other intangible assets	$ 223
Customer Relationships [Member]
Goodwill [Line Items]
Weighted average amortization period	12 years 7 months 6 days
Amortization expense of intangible assets	$ 56	36
Canada [Member]
Goodwill [Line Items]
Goodwill		0	$ 2,838
Removal of goodwill for asset divestitures		706
Goodwill impairments		$ 1,941

Goodwill And Other Intangible87

Goodwill And Other Intangible Assets (Summary Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Goodwill	$ 5,032	$ 6,303	$ 5,858
Acquired during period	57	3,283
Asset divestitures		(706)
Impairment loss	(1,328)	(1,941)
Translation adjustments		(191)
United States [Member]
Goodwill [Line Items]
Goodwill	2,618	2,618	2,618
Canada [Member]
Goodwill [Line Items]
Goodwill		0	2,838
Asset divestitures		(706)
Impairment loss		(1,941)
Translation adjustments		(191)
EnLink [Member]
Goodwill [Line Items]
Goodwill	2,414	3,685	$ 402
Acquired during period	57	$ 3,283
Impairment loss	$ (1,328)

Goodwill And Other Intangible88

Goodwill And Other Intangible Assets (Schedule Of General Partner And EnLink Goodwill By Reporting Units) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Goodwill, Beginning Balance	$ 6,303	$ 5,858
Acquired during period	57	3,283
Impairment loss	(1,328)	(1,941)
Goodwill, Ending Balance	5,032	6,303
General Partner And EnLink [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	3,685	402
Acquired during period	57	3,283
Impairment loss	(1,328)
Goodwill, Ending Balance	2,414	3,685
General Partner And EnLink [Member] | Texas [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	1,168	326
Acquired during period	28	842
Impairment loss	(492)
Goodwill, Ending Balance	704	1,168
General Partner And EnLink [Member] | Louisiana [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	787
Acquired during period		787
Impairment loss	(787)
Goodwill, Ending Balance		787
General Partner And EnLink [Member] | Oklahoma [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	190	76
Acquired during period		114
Goodwill, Ending Balance	190	190
General Partner And EnLink [Member] | Crude And Condensate [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	113
Acquired during period	29	113
Impairment loss	(49)
Goodwill, Ending Balance	93	113
General Partner And EnLink [Member] | General Partner [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	1,427
Acquired during period		1,427
Goodwill, Ending Balance	$ 1,427	$ 1,427

Goodwill And Other Intangible89

Goodwill And Other Intangible Assets (Schedule Of Other Intangible Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Goodwill And Other Intangible Assets [Abstract]
Customer relationships	$ 745	$ 569
Accumulated amortization	(55)	(36)
Net intangibles	$ 690	$ 533

Debt And Related Expenses (Narr

Debt And Related Expenses (Narrative) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Nov. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2015	May. 31, 2015	Feb. 28, 2015	Mar. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Early retirement of senior notes	$ 1,900,000,000
Early retirement of debt			$ 48,000,000
Commercial Paper		$ 626,000,000	$ 932,000,000
Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 3,000,000,000
Frequency of payment		annual
Commitment fee amount		$ 3,800,000
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%. 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		23.7
$30 Million Of Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 30,000,000
Line of credit facility expiration date		Oct. 24, 2017
$164 Million Of Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 164,000,000
Line of credit facility expiration date		Oct. 24, 2018
$2.8 Billion Of Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 2,800,000,000
Line of credit facility expiration date		Oct. 24, 2019
2.40% due July 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		2.40%
Early retirement of senior notes	500,000,000
1.20% Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		1.20%
Early retirement of senior notes	650,000,000
1.875% Due May 15, 2017 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		1.875%
Early retirement of senior notes	750,000,000
Make Whole Premium [Member]
Debt Instrument [Line Items]
Early retirement of debt	40,000,000
5.00% due June 15, 2045 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 750,000,000
Debt interest rate, stated percentage		5.00%	5.00%
Debt, maturity date		Jun. 15, 2045
5.85% due December 15, 2025 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount		$ 850,000,000
Debt interest rate, stated percentage		5.85%	5.85%
Debt, maturity date		Dec. 15, 2025
Floating Rate due December 15, 2015 [Member]
Debt Instrument [Line Items]
Debt, maturity date		Dec. 15, 2015
Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt, maturity date		Dec. 15, 2016
Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized discount	2,000,000
Unamortized debt issuance costs	6,000,000
EnLink [Member]
Debt Instrument [Line Items]
Outstanding credit facility borrowings		$ 414,000,000	$ 237,000,000
EnLink [Member] | Unsecured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 1,500,000,000				$ 1,000,000,000
Line of credit facility expiration date		Mar. 6, 2020
Outstanding credit facility borrowings		$ 414,000,000
Line of credit average interest rate during period		1.70%
EnLink [Member] | Unsecured Letter Of Credit Subfacility [Member]
Debt Instrument [Line Items]
Outstanding credit facility borrowings		$ 11,000,000
EnLink [Member] | 2.70% due April 1, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		2.70%	2.70%
Debt, maturity date		Apr. 1, 2019
EnLink [Member] | 4.40% due April 1, 2024 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		4.40%	4.40%
Debt, maturity date		Apr. 1, 2024
EnLink [Member] | 4.15% due June 1, 2025 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		4.15%	4.15%
Debt, maturity date		Jun. 1, 2025
EnLink [Member] | 5.05% due April 1, 2045 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		5.05%	5.05%
Debt, maturity date		Apr. 1, 2045
EnLink [Member] | 5.60% due April 1, 2044 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		5.60%	5.60%
Debt, maturity date		Apr. 1, 2044
EnLink [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, face amount					$ 900,000,000		$ 1,200,000,000
EnLink [Member] | Senior Notes [Member] | 2.70% due April 1, 2019 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount							400,000,000
Debt interest rate, stated percentage		2.70%
EnLink [Member] | Senior Notes [Member] | 4.40% due April 1, 2024 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount	100,000,000						450,000,000
Debt interest rate, stated percentage		4.40%
EnLink [Member] | Senior Notes [Member] | 4.15% due June 1, 2025 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount					750,000,000
Debt interest rate, stated percentage		4.15%
EnLink [Member] | Senior Notes [Member] | 5.05% due April 1, 2045 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount	$ 300,000,000				$ 150,000,000
Debt interest rate, stated percentage		5.05%
EnLink [Member] | Senior Notes [Member] | 5.60% due April 1, 2044 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount							$ 350,000,000
Debt interest rate, stated percentage		5.60%
General Partner [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 250,000,000
Line of credit facility expiration date		Mar. 7, 2019
Outstanding credit facility borrowings		$ 0
GeoSouthern Intermediate Holdings, LLC [Member] | Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Basis spread		0.54%
GeoSouthern Intermediate Holdings, LLC [Member] | Fixed And Floating Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, face amount								$ 2,250,000,000
Maximum [Member] | Senior Credit Facility [Member]
Debt Instrument [Line Items]
Debt-to-capitalization ratio		65
Commercial Paper [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 3,000,000,000
Average borrowing rate on commercial paper borrowings		0.63%

Debt And Related Expenses (Sche

Debt And Related Expenses (Schedule Of Debt Instruments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Commercial Paper		$ 626	$ 932
Net (discount) premium on debentures and notes		(28)	(18)
Total debt		13,113	11,262
Less amount classified as short-term debt	[1]	976	1,432
Total long-term debt		$ 12,137	9,830
Floating Rate due December 15, 2015 [Member]
Debt Instrument [Line Items]
Debt, maturity date		Dec. 15, 2015
Short-term debt			500
Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt, maturity date		Dec. 15, 2016
Short-term debt		$ 350
Long-term debt, gross			$ 350
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		8.25%	8.25%
Debt, maturity date		Jul. 1, 2018
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		Dec. 15, 2018
Long-term debt, gross		$ 750	$ 750
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		6.30%	6.30%
Debt, maturity date		Jan. 15, 2019
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		Jul. 15, 2021
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		May 15, 2022
Long-term debt, gross		$ 1,000	$ 1,000
5.85% due December 15, 2025 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		5.85%	5.85%
Debt, maturity date		Dec. 15, 2025
Long-term debt, gross		$ 850
7.50% due September 15, 2027 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		7.50%	7.50%
Debt, maturity date		Sep. 15, 2027
Long-term debt, gross		$ 150	$ 150
7.875% due September 30, 2031 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		7.875%	7.875%
Debt, maturity date		Sep. 30, 2031
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		Apr. 15, 2032
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		Jul. 15, 2041
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		May 15, 2042
Long-term debt, gross		$ 750	$ 750
5.00% due June 15, 2045 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		5.00%	5.00%
Debt, maturity date		Jun. 15, 2045
Long-term debt, gross		$ 750
Devon [Member]
Debt Instrument [Line Items]
Total debt		10,023	$ 9,239
EnLink [Member]
Debt Instrument [Line Items]
Credit facilities		414	237
Net (discount) premium on debentures and notes		13	23
Total debt		$ 3,090	$ 2,023
EnLink [Member] | 2.70% due April 1, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		2.70%	2.70%
Debt, maturity date		Apr. 1, 2019
Long-term debt, gross		$ 400	$ 400
EnLink [Member] | 7.125% due June 1, 2022 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		7.125%	7.125%
Debt, maturity date		Jun. 1, 2022
Long-term debt, gross		$ 163	$ 163
EnLink [Member] | 4.40% due April 1, 2024 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		4.40%	4.40%
Debt, maturity date		Apr. 1, 2024
Long-term debt, gross		$ 550	$ 550
EnLink [Member] | 4.15% due June 1, 2025 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		4.15%	4.15%
Debt, maturity date		Jun. 1, 2025
Long-term debt, gross		$ 750
EnLink [Member] | 5.60% due April 1, 2044 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		5.60%	5.60%
Debt, maturity date		Apr. 1, 2044
Long-term debt, gross		$ 350	$ 350
EnLink [Member] | 5.05% due April 1, 2045 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		5.05%	5.05%
Debt, maturity date		Apr. 1, 2045
Long-term debt, gross		$ 450	$ 300
[1]	2015 short-term debt consists of $626 million of commercial paper and the $350 million floating rate due on December 15, 2016. 2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015.

Debt And Related Expenses (Sc92

Debt And Related Expenses (Schedule Of Debt Maturities) (Details) $ in Millions	Dec. 31, 2015USD ($)
Debt And Related Expenses [Abstract]
2,016	$ 976
2,018	875
2,019	1,100
2,020	414
Thereafter	9,763
Total	$ 13,128

Debt And Related Expenses (Sc93

Debt And Related Expenses (Schedule Of Other Debt And Debentures) (Details) - USD ($)	1 Months Ended				12 Months Ended
	May. 31, 2012	Jul. 31, 2011	Jan. 31, 2009	Mar. 31, 2002	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Discount and issuance costs	$ (28,000,000)	$ (24,000,000)	$ (8,000,000)	$ (14,000,000)
Net proceeds	1,722,000,000	1,726,000,000	692,000,000	986,000,000
3.25% Due May 15, 2022 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage					3.25%	3.25%
Debt, maturity date					May 15, 2022
Principal amount of senior notes issued	1,000,000,000
4.75% Due May 15, 2042 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage					4.75%	4.75%
Debt, maturity date					May 15, 2042
Principal amount of senior notes issued	$ 750,000,000
4.00% Due July 15, 2021 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage					4.00%	4.00%
Debt, maturity date					Jul. 15, 2021
Principal amount of senior notes issued		500,000,000
5.60% Due July 15, 2041 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage					5.60%	5.60%
Debt, maturity date					Jul. 15, 2041
Principal amount of senior notes issued		$ 1,250,000,000
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage					6.30%	6.30%
Debt, maturity date					Jan. 15, 2019
Principal amount of senior notes issued			$ 700,000,000
7.95% Due April 15, 2032 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage					7.95%	7.95%
Debt, maturity date					Apr. 15, 2032
Principal amount of senior notes issued				$ 1,000,000,000

Debt And Related Expenses (Sc94

Debt And Related Expenses (Schedule Of Debt Assumed) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	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	Jul. 1, 2018
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	Sep. 15, 2027
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 (Sc95

Debt And Related Expenses (Schedule Of EnLink's Debt) (Details) - EnLink [Member] - USD ($)		12 Months Ended
		Dec. 31, 2015	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		8.875%
Debt, maturity date		Feb. 15, 2018
Debt instrument, face amount				725,000,000
Fair value of debt	[1]			$ 760,000,000
Effective rate of debt	[1]			7.70%
7.125% due June 1, 2022 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		7.125%	7.125%
Debt, maturity date		Jun. 1, 2022
Debt instrument, face amount				$ 197,000,000
Fair value of debt				$ 226,000,000
Effective rate of debt				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 (Sc96

Debt And Related Expenses (Schedule Of Net Financing Cost Components) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt And Related Expenses [Abstract]
Interest based on debt outstanding	$ 565	$ 532	$ 466
Early retirement of debt		48
Capitalized interest	(62)	(70)	(56)
Other fees and expenses	20	26	27
Interest expense	523	536	437
Interest income	(6)	(10)	(20)
Net financing costs	$ 517	$ 526	$ 417

Asset Retirement Obligations (S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Line Items]
Asset retirement obligations as of beginning of period		$ 1,399	$ 2,228
Liabilities incurred		63	97
Liabilities settled and divested	[1]	(89)	(1,009)
Revision of estimated obligation		62	70
Accretion expense on discounted obligation		75	89
Foreign currency translation adjustment		(96)	(76)
Asset retirement obligations as of end of period		$ 1,399	2,228	$ 1,414	$ 1,399
Less current portion				44	60
Asset retirement obligations, long-term				$ 1,370	$ 1,339
Canadian And U.S. Oil And Gas Properties [Member]
Asset Retirement Obligations [Line Items]
Liabilities settled and divested			$ (953)
[1]	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 (Narrative) (D

Retirement Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Value of trusts established for certain supplemental plans	$ 22	$ 25
Effect on accumulated postretirement benefit obligation of 1% change in assumed health care cost rates	1
Effect on service cost and interest costs of 1% change in assumed health care cost rates	1
Pension benefits to be funded from the trust	12
Postretirement benefits expected to be funded from cash and cash equivalents	3
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	1,200	1,200
Employer contributions transferred from trusts	$ 11	$ 10
Assumed compensation increase percentage	4.49%	4.49%	4.48%
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan health care cost trend rate assumed for next fiscal year	7.60%
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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	$ 1,377	$ 1,177
Service cost	33	30	$ 36
Interest cost	52	55	51
Actuarial loss (gain)	$ (68)	203
Plan settlements		(4)
Foreign exchange rate changes	$ (6)	(3)
Benefits paid	(80)	(81)
Benefit obligation at end of year	1,308	1,377	1,177
Change in plan assets:
Fair value of plan assets at beginning of year	1,149	1,006
Actual return on plan assets	(16)	200
Employer contributions	$ 11	29
Plan settlements		(4)
Benefits paid	$ (80)	(81)
Foreign exchange rate changes	(5)	(1)
Fair value of plan assets at end of year	1,059	1,149	1,006
Funded status at end of year	(249)	(228)
Amounts recognized in balance sheet:
Other long-term assets	2	22
Other current liabilities	(12)	(10)
Other long-term liabilities	(239)	(240)
Net amount	(249)	(228)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	302	317
Post service cost (credit)	14	19
Total	316	336
Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	24	24
Service cost	1	1	1
Interest cost	1	$ 1	1
Actuarial loss (gain)	(2)
Plan amendments	$ 1
Plan settlements
Participant contributions	$ 2	$ 2
Benefits paid	(4)	(4)
Benefit obligation at end of year	23	24	$ 24
Change in plan assets:
Employer contributions	2	2
Participant contributions	$ 2	$ 2
Plan settlements
Benefits paid	$ (4)	$ (4)
Funded status at end of year	(23)	(24)
Amounts recognized in balance sheet:
Other current liabilities	(3)	(3)
Other long-term liabilities	(20)	(21)
Net amount	(23)	(24)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	(11)	(11)
Post service cost (credit)	(6)	(9)
Total	$ (17)	$ (20)

Retirement Plans (Schedule Of P

Retirement Plans (Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Retirement Plans [Abstract]
Projected benefit obligation	$ 244	$ 250
Accumulated benefit obligation	$ 199	$ 191
Fair value of plan assets

Retirement Plans (Schedule Of N

Retirement Plans (Schedule Of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Other Postretirement Benefit Plans) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Net periodic benefit cost:
Service cost		$ 33	$ 30	$ 36
Interest cost		52	55	51
Expected return on plan assets		(58)	(54)	(62)
Curtailment and settlement expense			1
Recognition of net actuarial loss (gain)	[1]	20	18	22
Recognition of prior service cost	[1]	4	4	4
Total net periodic benefit cost	[2]	51	54	51
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year		5	57	(39)
Prior service cost (credit) arising in current year				2
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost		(20)	(19)	(22)
Recognition of prior service cost, including curtailment, in net periodic benefit cost		(4)	(4)	(4)
Total other comprehensive loss (earnings)		(19)	34	(63)
Total recognized		32	88	(12)
Postretirement Benefits [Member]
Net periodic benefit cost:
Service cost		1	1	1
Interest cost		1	1	1
Recognition of net actuarial loss (gain)	[1]	(1)	(1)	(1)
Recognition of prior service cost	[1]	(2)	(2)	(1)
Total net periodic benefit cost	[2]	(1)	(1)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year		(1)		(3)
Prior service cost (credit) arising in current year		1		(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		1	2	1
Total other comprehensive loss (earnings)		2	3	(9)
Total recognized		$ 1	$ 2	$ (9)
[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 G&A 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 2016) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 22
Prior service cost (credit)	4
Total	26
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	(2)
Prior service cost (credit)	(1)
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	4.25%	3.90%	4.80%
Rate of compensation increase	4.49%	4.49%	4.48%
Assumptions to determine net periodic benefit cost:
Discount rate	3.90%	4.80%	3.85%
Rate of compensation increase	4.49%	4.49%	4.48%
Expected return on plan assets	5.22%	5.42%	5.48%
Postretirement Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	3.63%	3.25%	3.65%
Assumptions to determine net periodic benefit cost:
Discount rate	3.25%	3.65%	3.30%

Retirement Plans (Schedule O104

Retirement Plans (Schedule Of Pension Plan Assets Target Allocation) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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 ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 120	$ 112	$ 112
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	100.00%	100.00%
Fair value of plan assets	$ 1,059	$ 1,149	$ 1,006
Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	500	364
Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	439	673
Pension Benefits [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 120	$ 112
Pension Benefits [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	68.00%	70.00%
Fair value of plan assets	$ 721	$ 799
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	494	349
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 227	$ 450
Pension Benefits [Member] | United States Treasuries [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	17.00%	35.00%
Fair value of plan assets	$ 179	$ 405
Pension Benefits [Member] | United States Treasuries [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	88	50
Pension Benefits [Member] | United States Treasuries [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 91	$ 355
Pension Benefits [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	48.00%	32.00%
Fair value of plan assets	$ 507	$ 364
Pension Benefits [Member] | Corporate Bonds [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	371	269
Pension Benefits [Member] | Corporate Bonds [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 136	$ 95
Pension Benefits [Member] | Other Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	3.00%	3.00%
Fair value of plan assets	$ 35	$ 30
Pension Benefits [Member] | Other Bonds [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 35	$ 30
Pension Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	18.00%	17.00%
Fair value of plan assets	$ 186	$ 197
Pension Benefits [Member] | Equity Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 186	$ 197
Pension Benefits [Member] | Other Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	14.00%	13.00%
Fair value of plan assets	$ 152	$ 153
Pension Benefits [Member] | Other Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6	15
Pension Benefits [Member] | Other Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	26	26
Pension Benefits [Member] | Other Securities [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 120	$ 112
Pension Benefits [Member] | Hedge Fund And Alternative Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	11.00%	10.00%
Fair value of plan assets	$ 120	$ 112
Pension Benefits [Member] | Hedge Fund And Alternative Investments [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 120	$ 112
Pension Benefits [Member] | Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	3.00%	3.00%
Fair value of plan assets	$ 32	$ 41
Pension Benefits [Member] | Short-Term Investments [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6	15
Pension Benefits [Member] | Short-Term Investments [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 26	$ 26

Retirement Plans (Schedule o106

Retirement Plans (Schedule of Changes In Level 3 Plan Assets) (Details) - Level 3 Inputs [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$ 112	$ 112
Purchases (Disbursements)	5	(6)
Investment returns	3	6
Fair value of plan assets at end of year	$ 120	$ 112

Retirement Plans (Schedule O107

Retirement Plans (Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Devon's 2016 contributions	$ 12
Benefit payments:
2,016	73
2,017	75
2,018	77
2,019	78
2,020	83
2021 to 2025	446
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Devon's 2016 contributions	3
Benefit payments:
2,016	3
2,017	3
2,018	3
2,019	3
2,020	2
2021 to 2025	$ 7

Retirement Plans (Schedule O108

Retirement Plans (Schedule Of Expense Related To These Defined Contribution Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	$ 79	$ 69	$ 67
401(k) Plan And Enhanced Contribution Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	63	49	41
Canadian Pension And Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	$ 16	$ 20	$ 26

Stockholders' Equity (Narrative

Stockholders' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended			12 Months Ended
	Jan. 31, 2016	Dec. 31, 2015	Jun. 30, 2014	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stockholders Equity [Line Items]
Common stock, shares authorized (in shares)		1,000,000,000				1,000,000,000	1,000,000,000
Common stock, par value (in dollars per share)		$ 0.10				$ 0.10	$ 0.10
Preferred Stock, Par or Stated Value Per Share		$ 1				$ 1
Preferred Stock, Shares Authorized		4,500,000				4,500,000
Payments of ordinary dividends						$ 396	$ 386	$ 348
Dividends paid per share			$ 0.24	$ 0.22	$ 0.20
Proceeds from stock option exercises						$ 4	$ 93	$ 3
Equity Issued in Business Combination [Member] | Common Stock [Member] | Powder River Basin
Stockholders Equity [Line Items]
Units issued for acquisition		7,000,000
Equity Issued in Business Combination [Member] | Common Stock [Member] | Anadarko Basin STACK [Member] | Subsequent Event [Member]
Stockholders Equity [Line Items]
Units issued for acquisition	23,000,000

Noncontrolling Interests (Narra

Noncontrolling Interests (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	Mar. 07, 2014	Jan. 31, 2016	Oct. 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Number of units sold to public for interests in EnLink					26.2
Sale of investment in EnLink					$ 654
Net proceeds of common units sold					25	$ 410
Distributions to unitholders other than Devon					$ 254	$ 235
EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership interest by Devon					28.00%
Proceeds of private placement transaction			$ 50
EnLink [Member] | Equity Distribution Agreements [Member]
Noncontrolling Interest [Line Items]
Number of units sold to public for interests in EnLink					1.3	14.8
Net proceeds of common units sold					$ 25	$ 410
Public Unitholders Interest In EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners					45.00%
General Partner And EnLink [Member]
Noncontrolling Interest [Line Items]
Distributions to unitholders other than Devon					$ 254	$ 135
General Partner Interest In EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners					27.00%
EnLink [Member]
Noncontrolling Interest [Line Items]
Number of units sold to public for interests in EnLink				120.5
Ownership interest by Devon				52.00%
EnLink [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Common units issued in private placement			2.8
EnLink [Member] | Public Unitholders [Member]
Noncontrolling Interest [Line Items]
Number of units sold to public for interests in EnLink				92.7
EnLink [Member] | Public Unitholders Interest In EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners				41.00%
EnLink [Member] | General Partner Interest In EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners				7.00%
General Partner And EnLink [Member]
Noncontrolling Interest [Line Items]
Cash payment to acquire interest	$ 100
Subsequent Event [Member] | EnLink [Member]
Noncontrolling Interest [Line Items]
Percentage of ownership after stock transactions		25.00%
Subsequent Event [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Percentage of ownership after stock transactions		64.00%
Subsequent Event [Member] | Public Unitholders Interest In General Partner [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners		36.00%
Subsequent Event [Member] | Public Unitholders Interest In EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners		52.00%
Subsequent Event [Member] | General Partner Interest In EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners		23.00%

Commitments And Contingencie111

Commitments And Contingencies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies [Abstract]
Obligation related to the purchase of condensate, year of expiration	2,021
Total rental expense, including certain office space and equipment under operating lease agreements, net of sub-lease income	$ 88	$ 64	$ 26

Commitments And Contingencie112

Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details) $ in Millions	Dec. 31, 2015USD ($)
Purchase Obligations [Member]
Long-term Purchase Commitment [Line Items]
2,016	$ 557
2,017	703
2,018	791
2,019	803
2,020	845
Thereafter	206
Total	3,905
Drilling And Facility Obligations [Member]
Long-term Purchase Commitment [Line Items]
2,016	69
2,017	51
2,018	34
2,019	5
2,020	2
Thereafter	28
Total	189
Operational Agreements [Member]
Long-term Purchase Commitment [Line Items]
2,016	994
2,017	972
2,018	936
2,019	402
2,020	255
Thereafter	1,042
Total	4,601
Office And Equipment Leases [Member]
Long-term Purchase Commitment [Line Items]
2,016	70
2,017	58
2,018	76
2,019	68
2,020	42
Thereafter	129
Total	$ 443

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	$ 45	$ 2,004
Derivatives, liabilities	(48)	(57)
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,871	950
Debt	(13,113)	(11,262)
Capital lease obligations	(17)	(20)
Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,871	950
Debt	(11,927)	(12,472)
Capital lease obligations	(16)	(20)
Level 1 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,471	340
Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	400	610
Debt	(11,927)	(12,472)
Capital lease obligations	(16)	(20)
Commodity Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	35	1,995
Derivatives, liabilities	(18)	(56)
Commodity Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	35	1,995
Derivatives, liabilities	(18)	(56)
Commodity Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	35	1,995
Derivatives, liabilities	(18)	(56)
Interest Rate Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	2	1
Derivatives, liabilities	(22)	(1)
Interest Rate Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	2	1
Derivatives, liabilities	(22)	(1)
Interest Rate Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	2	1
Derivatives, liabilities	(22)	(1)
Foreign Currency Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	8	8
Derivatives, liabilities	(8)
Foreign Currency Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	8	8
Derivatives, liabilities	(8)
Foreign Currency Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	8	$ 8
Derivatives, liabilities	$ (8)

Segment information (Condensed

Segment information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Details) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)segment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Segment Reporting Information [Line Items]
Revenues from external customers		$ 2,886	$ 3,601	$ 3,393	$ 3,265	$ 5,995	$ 5,336	$ 4,510	$ 3,725	$ 13,145	$ 19,566	$ 10,397
Depreciation, depletion and amortization										3,129	3,319	2,780
Asset impairments		5,300	5,900	4,200	5,500	1,900				20,820	1,953	1,976
Gains and losses on asset sales											(1,072)	9
Interest expense										523	536	437
Earnings (loss) before income taxes		(5,542)	(5,623)	(4,479)	(5,624)	291	1,654	1,554	560	(21,268)	4,059	149
Income tax expense (benefit)										(6,065)	2,368	169
Net earnings (loss)										(15,203)	1,691	(20)
Net earnings (loss) attributable to noncontrolling interests										(749)	84
Net earnings (loss) attributable to Devon		(4,532)	$ (3,507)	$ (2,816)	$ (3,599)	(408)	$ 1,016	$ 675	$ 324	(14,454)	1,607	(20)
Property and equipment, net		19,068				36,296				19,068	36,296	28,447
Total assets		29,532				50,637				29,532	50,637	42,877
Capital expenditures										6,233	13,559	6,643
Eliminations [Member]
Segment Reporting Information [Line Items]
Interest expense										(46)	(44)	(35)
Total assets		(97)				(124)				(97)	(124)
Eliminations [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										$ (679)	(859)	(1,362)
United States [Member]
Segment Reporting Information [Line Items]
Number of reportable segments | segment										1
United States [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues from external customers	[1]									$ 8,360	14,854	6,807
Depreciation, depletion and amortization	[1]									2,220	2,475	1,744
Asset impairments	[1]									18,000	12	1,133
Gains and losses on asset sales	[1]										5
Interest expense	[1]									368	441	392
Earnings (loss) before income taxes	[1]									(18,214)	4,390	495
Income tax expense (benefit)	[1]									(5,650)	1,797	258
Net earnings (loss)	[1]									(12,564)	2,593	237
Net earnings (loss) attributable to noncontrolling interests	[1]									1	1
Net earnings (loss) attributable to Devon	[1]									(12,565)	2,592
Property and equipment, net	[1]	8,811				24,463				8,811	24,463	18,201
Total assets	[1]	14,600				32,037				14,600	32,037	27,080
Capital expenditures	[1]									4,575	11,214	4,589
Canada [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										1,012	2,063	2,656
Depreciation, depletion and amortization										522	560	849
Asset impairments										1,257	1,941	843
Gains and losses on asset sales											(1,077)
Interest expense										94	85	80
Earnings (loss) before income taxes										(1,670)	(657)	(532)
Income tax expense (benefit)										(445)	495	(156)
Net earnings (loss)										(1,225)	(1,152)	(376)
Net earnings (loss) attributable to Devon										(1,225)	(1,152)
Property and equipment, net		4,590				6,790				4,590	6,790	8,478
Total assets		5,464				8,517				5,464	8,517	13,560
Capital expenditures										680	1,344	1,841
General Partner And EnLink [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues from external customers	[1]									3,773	2,649	934
Depreciation, depletion and amortization	[1]									387	284	187
Asset impairments	[1]									1,563
Interest expense	[1]									107	54
Earnings (loss) before income taxes	[1]									(1,384)	326	186
Income tax expense (benefit)	[1]									30	76	67
Net earnings (loss)	[1]									(1,414)	250	119
Net earnings (loss) attributable to noncontrolling interests	[1]									(750)	83
Net earnings (loss) attributable to Devon	[1]									(664)	167
Property and equipment, net	[1]	5,667				5,043				5,667	5,043	1,768
Total assets	[1]	$ 9,565				$ 10,207				9,565	10,207	2,237
Capital expenditures	[1]									978	1,001	213
General Partner And EnLink [Member] | Operating Segments [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Revenues from external customers	[1]									$ 679	$ 859	$ 1,362
[1]	Due to Devon's control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recasted periods.

Supplemental Information On 115

Supplemental Information On Oil And Gas Operations (Narrative) (Details) $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)bbl / DMMBoe$ / Mcf$ / bbl	Dec. 31, 2014USD ($)MMBoe	Dec. 31, 2013USD ($)MMBoe	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2012MMBoe
Reserve Quantities [Line Items]
Capitalized general and administrative expenses | $		$ 372	$ 376	$ 368
Capitalized interest costs | $		62	$ 70	$ 56
Oil and gas properties not subject to amortization | $		$ 2,584
Proved undeveloped reserves (MMBoe)	[1]	376	689	701				840
Increase (decrease) in proved undeveloped reserves		(45.00%)
Proved undeveloped reserves as a percentage of total proved reserves		17.00%
Increase (decrease) in proved undeveloped reserves due to drilling and development activities (MMBoe)		24
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)		182
Proved undeveloped reserves, revisions other than price (MMBoe)		(120)
Proved undeveloped reserves to proved developed reserves, conversion, percentage		26.00%
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	(142)	(65)	(88)
Cost incurred related to development and conversion | $		$ 2,200
Proved undeveloped reserves not expected to be developed within next 5 years (energy)		27
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	(302)	9	94
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	118	211	261
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)		13	5	175
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)	[1]	9	265	1
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]	(7)	(383)	(15)
Average estimated future realized price per barrel of oil used to estimate future cash inflows for proved oil reserves | $ / bbl		44.33
Average estimated future realized price per barrel of bitumen used to estimate future cash inflows for proved bitumen reserves | $ / bbl		23.84
Average estimated future realized price per Mcf of gas used to estimate future cash inflows for proved gas reserves | $ / Mcf		2.06
Average estimated future realized price per barrel of natural gas liquids used to estimate future cash inflows for proved NGL reserves | $ / bbl		10.11
Future development costs | $		$ 6,065	$ 10,787	$ 10,756
Future dismantlement, abandonment and rehabilitation costs | $		$ 1,200
Forecast [Member]
Reserve Quantities [Line Items]
Future development costs | $					$ 400	$ 600	$ 600
Delaware Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)		38
Jackfish [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe)		301	384
Proved undeveloped reserves, revisions other than price (MMBoe)		(80)
Daily barrel facility capacity (MBbls/d) | bbl / D		35
Year development schedule will be complete		Dec. 31, 2030
Proved undeveloped reserves, remaining undeveloped 5 years or more after initial booking (energy)		184
Proved undeveloped reseve, requiring excess of five years to develop		180
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)		11	8	38
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)		11		38
Barnett Shale [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)				43
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)			36	54
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)				54
Anadarko Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)		30	14	42
Rocky Mountain [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)				19
Cana-Woodford Shale [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)				23
Permian Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)			70	76
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)			4	33
Eagle Ford [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves not expected to be developed within next 5 years (energy)		20
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)		21	54
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)			246
Powder River Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)		6
Powder River Basin | Minimum [Member]
Reserve Quantities [Line Items]
Years until development and evaluation will be complete		4 years
Powder River Basin | Maximum [Member]
Reserve Quantities [Line Items]
Years until development and evaluation will be complete		5 years
San Juan Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, sale of reserves (MMBoe)		(7)
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 infill drilling activities (MMBoe)				20
Pike And Powder River Basin [Member] | Costs Deemed For Individual Assessment [Member]
Reserve Quantities [Line Items]
Oil and gas properties not subject to amortization | $		$ 1,900
United States [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe)	[1]	75	305	258				407
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)		88
Proved undeveloped reserves, revisions other than price (MMBoe)		(40)
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	(59)	(86)	(117)
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	(408)	38	76
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	104	197	212
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)	[1]	9	265	1
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]	(7)	(207)	(14)
Future development costs | $		$ 3,306	$ 7,168	$ 5,448
Oil and Gas Properties [Member]
Reserve Quantities [Line Items]
Capitalized interest costs | $		$ 54	$ 45	$ 42
[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 NGL reserves are converted to Boe on a one-to-one basis with oil.

Supplemental Information On 116

Supplemental Information On Oil And Gas Operations (Costs Incurred) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property acquisition costs:
Proved properties	$ 195	$ 5,210	$ 22
Unproved properties	717	1,177	216
Exploration costs	587	322	595
Development costs	3,671	5,463	5,089
Costs incurred	5,170	12,172	5,922
United States [Member]
Property acquisition costs:
Proved properties	193	5,210	19
Unproved properties	634	1,176	213
Exploration costs	478	270	443
Development costs	3,269	4,400	3,838
Costs incurred	4,574	11,056	4,513
Canada [Member]
Property acquisition costs:
Proved properties	2		3
Unproved properties	83	1	3
Exploration costs	109	52	152
Development costs	402	1,063	1,251
Costs incurred	$ 596	$ 1,116	$ 1,409

Supplemental Information On 117

Supplemental Information On Oil And Gas Operations (Capitalized Costs) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	$ 78,190	$ 75,738
Unproved properties	2,584	2,752
Total oil and gas properties	80,774	78,490
Accumulated DD&A	(69,497)	(49,560)
Net capitalized costs	11,277	28,930
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	64,443	59,849
Unproved properties	1,352	1,460
Total oil and gas properties	65,795	61,309
Accumulated DD&A	(58,312)	(38,213)
Net capitalized costs	7,483	23,096
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	13,747	15,889
Unproved properties	1,232	1,292
Total oil and gas properties	14,979	17,181
Accumulated DD&A	(11,185)	(11,347)
Net capitalized costs	$ 3,794	$ 5,834

Supplemental Information On 118

Supplemental Information On Oil And Gas Operations (Oil And Gas Properties Not Subject To Amortization) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$ 1,655
Exploration costs	562
Development costs	182
Capitalized interest	185
Total oil and gas properties not subject to amortization	2,584
2015 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	672
Exploration costs	191
Development costs	9
Capitalized interest	50
Total oil and gas properties not subject to amortization	922
2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	412
Exploration costs	132
Development costs	28
Capitalized interest	37
Total oil and gas properties not subject to amortization	609
2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	61
Exploration costs	69
Development costs	17
Capitalized interest	32
Total oil and gas properties not subject to amortization	179
Prior to 2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	510
Exploration costs	170
Development costs	128
Capitalized interest	66
Total oil and gas properties not subject to amortization	$ 874

Supplemental Information On 119

Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / Boe	Dec. 31, 2014USD ($)$ / Boe		Dec. 31, 2013USD ($)$ / Boe
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 5,382	$ 9,910		$ 8,522
Lease operating expenses	(2,104)	(2,332)		(2,268)
General and administrative expenses	(224)	(210)		(202)
Production and property taxes	(342)	(503)		(439)
Depreciation, depletion and amortization	(2,581)	(2,896)		(2,465)
Asset impairments	(19,249)			(1,953)
Gain on sale of assets		1,077
Accretion of asset retirement obligations	(74)	(88)		(111)
Income tax benefit (expense)	5,861	(1,767)		(422)
Results of operations	$ (13,331)	$ 3,191	[1]	$ 662
Depreciation, depletion and amortization per Boe | $ / Boe	10.40	11.79		9.75
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 4,356	$ 7,867		$ 5,964
Lease operating expenses	(1,551)	(1,559)		(1,257)
General and administrative expenses	(196)	(153)		(125)
Production and property taxes	(309)	(466)		(380)
Depreciation, depletion and amortization	(2,107)	(2,365)		(1,640)
Asset impairments	(17,992)			(1,110)
Accretion of asset retirement obligations	(47)	(49)		(47)
Income tax benefit (expense)	5,547	(1,199)		(510)
Results of operations	$ (12,299)	$ 2,076	[1]	$ 895
Depreciation, depletion and amortization per Boe | $ / Boe	10.21	11.41		8.69
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 1,026	$ 2,043		$ 2,558
Lease operating expenses	(553)	(773)		(1,011)
General and administrative expenses	(28)	(57)		(77)
Production and property taxes	(33)	(37)		(59)
Depreciation, depletion and amortization	(474)	(531)		(825)
Asset impairments	(1,257)			(843)
Gain on sale of assets		1,077
Accretion of asset retirement obligations	(27)	(39)		(64)
Income tax benefit (expense)	314	(568)		88
Results of operations	$ (1,032)	$ 1,115	[1]	$ (233)
Depreciation, depletion and amortization per Boe | $ / Boe	11.30	13.80		12.87
[1]	During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information.

Supplemental Information On 120

Supplemental Information On Oil And Gas Operations (Proved Oil Reserves) (Details)	12 Months Ended
	Dec. 31, 2015MMBblsMcf	Dec. 31, 2014MMBbls	Dec. 31, 2013MMBbls	Dec. 31, 2012MMBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe | Mcf	6
Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	374	285	270
Proved developed and undeveloped reserves, revisions due to prices	(49)	(1)
Proved developed and undeveloped reserves, revisions other than price	(50)	(37)	(18)
Proved developed and undeveloped reserves, extensions and discoveries	54	99	76
Proved developed and undeveloped reserves, purchase of reserves	5	132	1
Proved developed and undeveloped reserves, production	(70)	(58)	(43)
Proved developed and undeveloped reserves, sale of reserves		(46)	(1)
Proved developed and undeveloped reserves, ending balance	264	374	285
Proved developed reserves	225	278	250	228
Proved developed producing reserves	211	243	229	211
Proved undeveloped reserves	39	96	35	42
Oil [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	351	229	205
Proved developed and undeveloped reserves, revisions due to prices	(53)	(1)	1
Proved developed and undeveloped reserves, revisions other than price	(52)	(38)	(18)
Proved developed and undeveloped reserves, extensions and discoveries	51	94	69
Proved developed and undeveloped reserves, purchase of reserves	5	132	1
Proved developed and undeveloped reserves, production	(60)	(48)	(28)
Proved developed and undeveloped reserves, sale of reserves		(17)	(1)
Proved developed and undeveloped reserves, ending balance	242	351	229
Proved developed reserves	203	255	194	166
Proved developed producing reserves	192	224	178	155
Proved undeveloped reserves	39	96	35	39
Oil [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	23	56	65
Proved developed and undeveloped reserves, revisions due to prices	4		(1)
Proved developed and undeveloped reserves, revisions other than price	2	1
Proved developed and undeveloped reserves, extensions and discoveries	3	5	7
Proved developed and undeveloped reserves, production	(10)	(10)	(15)
Proved developed and undeveloped reserves, sale of reserves		(29)
Proved developed and undeveloped reserves, ending balance	22	23	56
Proved developed reserves	22	23	56	62
Proved developed producing reserves	19	19	51	56
Proved undeveloped reserves				3

Supplemental Information On 121

Supplemental Information On Oil And Gas Operations (Proved Bitumen Reserves) (Details)	12 Months Ended
	Dec. 31, 2015MMBblsMcf	Dec. 31, 2014MMBbls	Dec. 31, 2013MMBbls	Dec. 31, 2012MMBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe | Mcf	6
Bitumen [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	521	552	528
Proved developed and undeveloped reserves, revisions due to prices	103	(37)	(11)
Proved developed and undeveloped reserves, revisions other than price	(84)	18	16
Proved developed and undeveloped reserves, extensions and discoveries	11	8	38
Proved developed and undeveloped reserves, production	(31)	(20)	(19)
Proved developed and undeveloped reserves, ending balance	520	521	552
Proved developed reserves	219	137	111	99
Proved developed producing reserves	219	137	111	99
Proved undeveloped reserves	301	384	441	429
Bitumen [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	521	552	528
Proved developed and undeveloped reserves, revisions due to prices	103	(37)	(11)
Proved developed and undeveloped reserves, revisions other than price	(84)	18	16
Proved developed and undeveloped reserves, extensions and discoveries	11	8	38
Proved developed and undeveloped reserves, production	(31)	(20)	(19)
Proved developed and undeveloped reserves, ending balance	520	521	552
Proved developed reserves	219	137	111	99
Proved developed producing reserves	219	137	111	99
Proved undeveloped reserves	301	384	441	429

Supplemental Information On 122

Supplemental Information On Oil And Gas Operations (Proved Natural Gas Reserves) (Details) MMcf in Thousands	12 Months Ended
	Dec. 31, 2015MMcfMcf	Dec. 31, 2014MMcf	Dec. 31, 2013MMcf	Dec. 31, 2012MMcf
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe | Mcf	6
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	7,687	9,308	9,446
Proved developed and undeveloped reserves, revisions due to prices	(1,421)	236	566
Proved developed and undeveloped reserves, revisions other than price	(9)	(295)	(232)
Proved developed and undeveloped reserves, extensions and discoveries	171	343	490
Proved developed and undeveloped reserves, purchase of reserves	17	457	1
Proved developed and undeveloped reserves, production	(587)	(701)	(874)
Proved developed and undeveloped reserves, sale of reserves	(37)	(1,661)	(89)
Proved developed and undeveloped reserves, ending balance	5,821	7,687	9,308
Proved developed reserves	5,707	6,984	8,459	8,070
Proved developed producing reserves	5,559	6,780	8,105	7,715
Proved undeveloped reserves	114	703	849	1,376
Natural Gas [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	7,651	8,550	8,762
Proved developed and undeveloped reserves, revisions due to prices	(1,412)	191	405
Proved developed and undeveloped reserves, revisions other than price	(3)	(299)	(299)
Proved developed and undeveloped reserves, extensions and discoveries	171	335	471
Proved developed and undeveloped reserves, purchase of reserves	17	457	1
Proved developed and undeveloped reserves, production	(579)	(660)	(709)
Proved developed and undeveloped reserves, sale of reserves	(37)	(923)	(81)
Proved developed and undeveloped reserves, ending balance	5,808	7,651	8,550
Proved developed reserves	5,694	6,948	7,707	7,391
Proved developed producing reserves	5,546	6,746	7,425	7,091
Proved undeveloped reserves	114	703	843	1,371
Natural Gas [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	36	758	684
Proved developed and undeveloped reserves, revisions due to prices	(9)	45	161
Proved developed and undeveloped reserves, revisions other than price	(6)	4	67
Proved developed and undeveloped reserves, extensions and discoveries		8	19
Proved developed and undeveloped reserves, production	(8)	(41)	(165)
Proved developed and undeveloped reserves, sale of reserves		(738)	(8)
Proved developed and undeveloped reserves, ending balance	13	36	758
Proved developed reserves	13	36	752	679
Proved developed producing reserves	13	34	680	624
Proved undeveloped reserves			6	5

Supplemental Information On 123

Supplemental Information On Oil And Gas Operations (Proved Natural Gas Liquids Reserves) (Details)	12 Months Ended
	Dec. 31, 2015MMBblsMcf	Dec. 31, 2014MMBbls	Dec. 31, 2013MMBbls	Dec. 31, 2012MMBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe | Mcf	6
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	578	575	591
Proved developed and undeveloped reserves, revisions due to prices	(119)	8	11
Proved developed and undeveloped reserves, revisions other than price	(6)	2	(47)
Proved developed and undeveloped reserves, extensions and discoveries	24	47	65
Proved developed and undeveloped reserves, purchase of reserves	1	57
Proved developed and undeveloped reserves, production	(50)	(51)	(45)
Proved developed and undeveloped reserves, sale of reserves		(60)
Proved developed and undeveloped reserves, ending balance	428	578	575
Proved developed reserves	411	486	491	451
Proved developed producing reserves	393	467	463	425
Proved undeveloped reserves	17	92	84	140
Natural Gas Liquids [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	578	552	571
Proved developed and undeveloped reserves, revisions due to prices	(119)	7	8
Proved developed and undeveloped reserves, revisions other than price	(6)	2	(50)
Proved developed and undeveloped reserves, extensions and discoveries	24	47	64
Proved developed and undeveloped reserves, purchase of reserves	1	57
Proved developed and undeveloped reserves, production	(50)	(50)	(41)
Proved developed and undeveloped reserves, sale of reserves		(37)
Proved developed and undeveloped reserves, ending balance	428	578	552
Proved developed reserves	411	486	468	431
Proved developed producing reserves	393	467	442	406
Proved undeveloped reserves	17	92	84	140
Natural Gas Liquids [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance		23	20
Proved developed and undeveloped reserves, revisions due to prices		1	3
Proved developed and undeveloped reserves, revisions other than price			3
Proved developed and undeveloped reserves, extensions and discoveries			1
Proved developed and undeveloped reserves, production		(1)	(4)
Proved developed and undeveloped reserves, sale of reserves		(23)
Proved developed and undeveloped reserves, ending balance			23
Proved developed reserves			23	20
Proved developed producing reserves			21	19

Supplemental Information On 124

Supplemental Information On Oil And Gas Operations (Proved Total MMBoe Reserves) (Details)		12 Months Ended
		Dec. 31, 2015MMBoeMcf	Dec. 31, 2014MMBoe	Dec. 31, 2013MMBoe	Dec. 31, 2012MMBoe
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	[1]	2,754	2,963	2,963
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	(302)	9	94
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	(142)	(65)	(88)
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	118	211	261
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)	[1]	9	265	1
Proved developed and undeveloped reserves, production (MMBoe)	[1]	(248)	(246)	(253)
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]	(7)	(383)	(15)
Proved developed and undeveloped reserves, ending balance (MMBoe)	[1]	2,182	2,754	2,963
Proved developed reserves (MMBoe)	[1]	1,806	2,065	2,262	2,123
Proved developed producing reserves (MMBoe)	[1]	1,749	1,977	2,154	2,021
Proved undeveloped reserves (MMBoe)	[1]	376	689	701	840
Conversion rate of gas reserves from barrels of oil to Boe | Mcf		6
United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	[1]	2,205	2,205	2,236
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	(408)	38	76
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	(59)	(86)	(117)
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	104	197	212
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)	[1]	9	265	1
Proved developed and undeveloped reserves, production (MMBoe)	[1]	(206)	(207)	(189)
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]	(7)	(207)	(14)
Proved developed and undeveloped reserves, ending balance (MMBoe)	[1]	1,638	2,205	2,205
Proved developed reserves (MMBoe)	[1]	1,563	1,900	1,947	1,829
Proved developed producing reserves (MMBoe)	[1]	1,509	1,815	1,857	1,743
Proved undeveloped reserves (MMBoe)	[1]	75	305	258	407
Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	[1]	549	758	727
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	106	(29)	18
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	(83)	21	29
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	14	14	49
Proved developed and undeveloped reserves, production (MMBoe)	[1]	(42)	(39)	(64)
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]		(176)	(1)
Proved developed and undeveloped reserves, ending balance (MMBoe)	[1]	544	549	758
Proved developed reserves (MMBoe)	[1]	243	165	315	294
Proved developed producing reserves (MMBoe)	[1]	240	162	297	278
Proved undeveloped reserves (MMBoe)	[1]	301	384	443	433
[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 NGL reserves are converted to Boe on a one-to-one basis with oil.

Supplemental Information On 125

Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2015MMBoe
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	689	[1]
Proved undeveloped reserves, extensions and discoveries	24
Proved undeveloped reserves, revisions due to prices	(35)
Proved undeveloped reserves, revisions other than price	(120)
Proved undeveloped reserves, conversion to proved developed reserves	(182)
Proved undeveloped reserves (MMBoe) ending balance	376	[1]
United States [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	305	[1]
Proved undeveloped reserves, extensions and discoveries	13
Proved undeveloped reserves, revisions due to prices	(115)
Proved undeveloped reserves, revisions other than price	(40)
Proved undeveloped reserves, conversion to proved developed reserves	(88)
Proved undeveloped reserves (MMBoe) ending balance	75	[1]
Canada [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	384	[1]
Proved undeveloped reserves, extensions and discoveries	11
Proved undeveloped reserves, revisions due to prices	80
Proved undeveloped reserves, revisions other than price	(80)
Proved undeveloped reserves, conversion to proved developed reserves	(94)
Proved undeveloped reserves (MMBoe) ending balance	301	[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 NGL reserves are converted to Boe on a one-to-one basis with oil.

Supplemental Information On 126

Supplemental Information On Oil And Gas Operations (Standardized Measure Of Discounted Future Net Cash Flows Related To Interest In Proved Reserves) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 40,445	$ 107,218	$ 95,288
Future costs:
Development	(6,065)	(10,787)	(10,756)
Production	(24,142)	(43,972)	(42,372)
Future income tax expense	(475)	(14,047)	(11,373)
Future net cash flow	9,763	38,412	30,787
10% discount to reflect timing of cash flows	(3,075)	(17,938)	(15,046)
Standardized measure of discounted future net cash flows	6,688	20,474	15,741	$ 13,221
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	27,398	75,847	61,983
Future costs:
Development	(3,306)	(7,168)	(5,448)
Production	(17,251)	(29,740)	(26,663)
Future income tax expense		(11,021)	(9,046)
Future net cash flow	6,841	27,918	20,826
10% discount to reflect timing of cash flows	(1,973)	(12,819)	(10,346)
Standardized measure of discounted future net cash flows	4,868	15,099	10,480
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	13,047	31,371	33,305
Future costs:
Development	(2,759)	(3,619)	(5,308)
Production	(6,891)	(14,232)	(15,709)
Future income tax expense	(475)	(3,026)	(2,327)
Future net cash flow	2,922	10,494	9,961
10% discount to reflect timing of cash flows	(1,102)	(5,119)	(4,700)
Standardized measure of discounted future net cash flows	$ 1,820	$ 5,375	$ 5,261

Supplemental Information On 127

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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Information On Oil And Gas Operations [Abstract]
Standardized measure of discounted future net cash flows, beginning balance	$ 20,474	$ 15,741	$ 13,221
Net changes in prices and production costs	(20,756)	2,561	3,018
Oil, bitumen, gas and NGL sales, net of production costs	(2,704)	(6,865)	(5,613)
Changes in estimated future development costs	1,313	(768)	399
Extensions and discoveries, net of future development costs	1,129	4,836	4,047
Purchase of reserves	95	6,422	14
Sales of reserves in place	(79)	(2,384)	(44)
Revisions of quantity estimates	(1,451)	(746)	(1,040)
Previously estimated development costs incurred during the period	2,158	1,933	1,986
Accretion of discount	567	1,746	1,940
Foreign exchange and other	(1,254)	(107)	(583)
Net change in income taxes	7,196	(1,895)	(1,604)
Standardized measure of discounted future net cash flows, ending balance	$ 6,688	$ 20,474	$ 15,741

Supplemental Quarterly Finan128

Supplemental Quarterly Financial Information (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Abstract]
Asset impairments	$ 5,300	$ 5,900	$ 4,200	$ 5,500	$ 1,900	$ 20,820	$ 1,953	$ 1,976
Asset impairment per diluted share	$ 13.09	$ 14.41	$ 10.27	$ 13.46	$ 4.79

Supplemental Quarterly Finan129

Supplemental Quarterly Financial Information (Schedule Of Unaudited Interim Results Of Operations) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Abstract]
Operating revenues	$ 2,886	$ 3,601	$ 3,393	$ 3,265	$ 5,995	$ 5,336	$ 4,510	$ 3,725	$ 13,145	$ 19,566	$ 10,397
Earnings (loss) before income taxes	(5,542)	(5,623)	(4,479)	(5,624)	291	1,654	1,554	560	(21,268)	4,059	149
Net earnings (loss) attributable to Devon	$ (4,532)	$ (3,507)	$ (2,816)	$ (3,599)	$ (408)	$ 1,016	$ 675	$ 324	$ (14,454)	$ 1,607	$ (20)
Basic net earnings (loss) per share attributable to Devon	$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (1.01)	$ 2.48	$ 1.65	$ 0.80	$ (35.55)	$ 3.93	$ (0.06)
Diluted net earnings (loss) per share attributable to Devon	$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (1.01)	$ 2.47	$ 1.64	$ 0.79	$ (35.55)	$ 3.91	$ (0.06)