Devon Energy (DVN) 10-K 15 Feb 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) shares in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2016	Feb. 08, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Trading Symbol	DVN
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	2,016
Entity Filer Category	Large Accelerated Filer
Document Fiscal Period Focus	FY
Entity Public Float			$ 18.9
Entity Common Stock, Shares Outstanding		524.6

Consolidated Comprehensive Stat

Consolidated Comprehensive Statements Of Earnings - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Oil, gas and NGL sales	$ 4,182	$ 5,382	$ 9,910
Oil, gas and NGL derivatives	(201)	503	1,989
Marketing and midstream revenues	6,323	7,260	7,667
Asset dispositions and other	1,893		1,072
Total revenues and other	12,197	13,145	20,638
Lease operating expenses	1,582	2,104	2,332
Marketing and midstream operating expenses	5,492	6,420	6,815
General and administrative expenses	645	855	847
Production and property taxes	275	388	535
Depreciation, depletion and amortization	1,792	3,129	3,319
Asset impairments	4,975	20,820	1,953
Restructuring and transaction costs	267	78	46
Other operating items	64	78	93
Total operating expenses	15,092	33,872	15,940
Operating income (loss)	(2,895)	(20,727)	4,698
Net financing costs	904	517	526
Other nonoperating items	78	24	113
Earnings (loss) before income taxes	(3,877)	(21,268)	4,059
Income tax expense (benefit)	(173)	(6,065)	2,368
Net earnings (loss)	(3,704)	(15,203)	1,691
Net earnings (loss) attributable to noncontrolling interests	(402)	(749)	84
Net earnings (loss) attributable to Devon	$ (3,302)	$ (14,454)	$ 1,607
Net earnings (loss) per share attributable to Devon:
Basic	$ (6.52)	$ (35.55)	$ 3.93
Diluted	$ (6.52)	$ (35.55)	$ 3.91
Comprehensive earnings (loss):
Net earnings (loss)	$ (3,704)	$ (15,203)	$ 1,691
Other comprehensive earnings (loss), net of tax:
Foreign currency translation	32	(559)	(465)
Pension and postretirement plans	22	10	(24)
Other comprehensive earnings (loss), net of tax	54	(549)	(489)
Comprehensive earnings (loss)	(3,650)	(15,752)	1,202
Comprehensive earnings (loss) attributable to noncontrolling interests	(402)	(749)	84
Comprehensive earnings (loss) attributable to Devon	$ (3,248)	$ (15,003)	$ 1,118

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net earnings (loss)	$ (3,704)	$ (15,203)	$ 1,691
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Depreciation, depletion and amortization	1,792	3,129	3,319
Asset impairments	4,975	20,820	1,953
Gains and losses on asset sales	(1,887)		(1,072)
Deferred income tax expense (benefit)	(273)	(5,828)	1,891
Derivatives and other financial instruments	386	(738)	(2,070)
Cash settlements on derivatives and financial instruments	(142)	2,688	104
Asset retirement obligation accretion	75	75	89
Amortization of stock-based compensation	194	181	163
Other	303	281	245
Net change in working capital	(8)	(311)	50
Change in long-term other assets	36	285	(421)
Change in long-term other liabilities	(1)	(6)	79
Net cash from operating activities	1,746	5,373	6,021
Cash flows from investing activities:
Capital expenditures	(2,330)	(5,308)	(6,988)
Acquisitions of property, equipment and businesses	(1,641)	(1,107)	(6,462)
Divestitures of property and equipment	3,118	107	5,120
Redemptions of long-term investments			57
Other	(19)	(16)	89
Net cash from investing activities	(872)	(6,324)	(8,184)
Cash flows from financing activities:
Borrowings of long-term debt, net of issuance costs	2,145	4,772	5,340
Repayments of long-term debt	(4,409)	(2,634)	(7,178)
Net short-term debt repayments	(626)	(307)	(385)
Early retirement of debt	(265)		(51)
Issuance of common stock	1,469
Sale of subsidiary units		654
Issuance of subsidiary units	892	25	410
Dividends paid on common stock	(221)	(396)	(386)
Contributions from noncontrolling interests	168	16	6
Distributions to noncontrolling interests	(304)	(254)	(235)
Other	(13)	(18)	85
Net cash from financing activities	(1,164)	1,858	(2,394)
Effect of exchange rate changes on cash	(61)	(77)	(29)
Net change in cash and cash equivalents	(351)	830	(4,586)
Cash and cash equivalents at beginning of period	2,310	1,480	6,066
Cash and cash equivalents at end of period	$ 1,959	$ 2,310	$ 1,480

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 1,959	$ 2,310
Accounts receivable		1,356	1,105
Assets held for sale		193
Other current assets		264	606
Total current assets		3,772	4,021
Oil and gas, based on full cost accounting:
Subject to amortization		75,648	78,190
Not subject to amortization		3,437	2,584
Total oil and gas		79,085	80,774
Midstream and other		10,455	10,380
Total property and equipment, at cost		89,540	91,154
Less accumulated depreciation, depletion and amortization		(73,350)	(72,086)
Property and equipment, net		16,190	19,068
Goodwill		3,964	5,032
Other long-term assets		1,987	1,330
Total assets		25,913	29,451
Current liabilities:
Accounts payable		642	906
Revenues and royalties payable		908	763
Short-term debt	[1]		976
Other current liabilities		1,066	650
Total current liabilities		2,616	3,295
Long-term debt		10,154	12,056
Asset retirement obligations		1,226	1,370
Other long-term liabilities		894	853
Deferred income taxes		648	888
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 523 million and 418 million shares in 2016 and 2015, respectively		52	42
Additional paid-in capital		7,237	4,996
Retained earnings (accumulated deficit)		(1,646)	1,781
Accumulated other comprehensive earnings		284	230
Total stockholders’ equity attributable to Devon		5,927	7,049
Noncontrolling interests		4,448	3,940
Total stockholders’ equity		10,375	10,989
Total liabilities and stockholders’ equity		$ 25,913	$ 29,451
[1]	2015 short-term debt consists of commercial paper balances and floating rate debt that was retired upon maturity in December 2016.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [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)	523,000,000	418,000,000

Consolidated Statements Of Stoc

Consolidated Statements Of Stockholders' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Earnings [Member]	Treasury Stock [Member]	Noncontrolling Interests [Member]
Balance at Dec. 31, 2013	$ 20,499	$ 41	$ 3,780	$ 15,410	$ 1,268
Balance, shares at Dec. 31, 2013		406
Net earnings (loss)	1,691			1,607			$ 84
Other comprehensive earnings (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 expense	(3)		(3)
Acquisition of noncontrolling interests	4,670						4,670
Subsidiary equity transactions	370		93				277
Distributions to noncontrolling interests	(235)						(235)
Other	7		1				6
Balance at Dec. 31, 2014	26,341	$ 41	4,088	16,631	779		4,802
Balance, shares at Dec. 31, 2014		409
Net earnings (loss)	(15,203)			(14,454)			(749)
Other comprehensive earnings (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	199	$ 1	198
Common stock issued, shares		7
Share-based compensation	165		165
Share-based compensation tax expense	(9)		(9)
Subsidiary equity transactions	726		585				141
Distributions to noncontrolling interests	(254)						(254)
Balance at Dec. 31, 2015	10,989	$ 42	4,996	1,781	230		3,940
Balance, shares at Dec. 31, 2015		418
Net earnings (loss)	(3,704)			(3,302)			(402)
Other comprehensive earnings (loss), net of tax	54				54
Restricted stock grants, net of cancellations, shares		2
Common stock repurchased	(28)					(28)
Common stock retired			(28)			$ 28
Common stock dividends	(221)		(96)	(125)
Common stock issued	2,127	$ 10	2,117
Common stock issued, shares		103
Share-based compensation	168		168
Subsidiary equity transactions	1,294		80				1,214
Distributions to noncontrolling interests	(304)						(304)
Balance at Dec. 31, 2016	$ 10,375	$ 52	$ 7,237	$ (1,646)	$ 284		$ 4,448
Balance, shares at Dec. 31, 2016		523

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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, Devon 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. Revenue 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 2016, 2015 and 2014, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue. 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 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. As of December 31, 2016, Devon did not have any open foreign exchange contracts. 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, 2016, 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, 2016, Devon held no collateral from counterparties. As of December 31, 2015, Devon held $75 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying consolidated balance sheets. As a result of ratings downgrades for Devon during 2016, we were required to post $17 million of cash collateral under certain of our derivative contracts. The collateral is reported in other current assets in the accompanying December 31, 2016 consolidated balance sheet. In January 2017, this collateral was deemed to be no longer required and was returned to Devon. As of the date of this report, Devon has no cash collateral held by its counterparties. 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 members of its Board of Directors and select employees. EnLink and the General Partner also grant share-based awards to members of its Board of Directors and select 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. 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. 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. 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 their respective holding periods generally 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. However, if a disposition or series of dispositions occurring in a quarterly reporting period significantly alters the relationship between capitalized costs and proved reserves in a particular country, a gain or loss is recognized. As discussed more fully in Note 2, the 2014 and 2016 divestitures of certain Canadian and U.S. non-core upstream assets significantly altered such relationship, and Devon recognized gains on these transactions. These gains are classified as asset dispositions and other in the accompanying consolidated statements of earnings. Furthermore, upon recognizing the gain on the 2016 divestitures and to be more consistent with industry practice, Devon began presenting gains on asset sales in the total revenues and other section of the accompanying consolidated statements of earnings, and has reclassified the 2014 gain on asset sales of $1.1 billion from operating expenses to total revenues and other to reflect consistent financial statement presentation. 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, 2016 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 and EnLink performed annual impairment tests of goodwill in the fourth quarters of 2016, 2015 and 2014. No impairment write-down was required as a result of the annual tests in 2016; however, sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units and in 2014 for Devon’s Canadian reporting unit based on interim and annual impairment tests. 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 2016 and 2015, EnLink’s customer relationships were also evaluated for impairment, and in 2015, a portion of these intangible assets 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 Adopted Accounting Standards In January 2016, Devon adopted ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2014-15 , Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern Recently Issued Accounting Standards The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Extractive Activities – Oil and Gas – Revenue Recognition. Revenue from Contracts with Customers – Deferral of the Effective Date, The FASB issued ASU 2016-02, Leases (Topic 842) Leases The FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting The FASB issued ASU No. 2016-13, Credit Losses, Measurement of Credit Losses on Financial Instruments

Acquisitions And Divestitures

Acquisitions And Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions And Divestitures	2. Acquisitions and Divestitures Devon Acquisitions 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 $849 million of cash and $659 million of equity. The allocation of the purchase price at December 31, 2016 was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties. 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. The allocation of the purchase price was $393 million to unproved properties and $106 million to proved properties and gathering systems. On February 28, 2014, Devon acquired approximately 82,000 net acres (unaudited) and assets located in DeWitt and Lavaca counties in south Texas from GeoSouthern for approximately $6.0 billion. Devon funded the acquisition with cash on hand and debt financing. The allocation of the purchase price was approximately $5.0 billion to proved properties and approximately $1.0 billion to unproved properties. Devon Asset Divestitures During 2016, Devon divested certain non-core upstream assets in the U.S. and its 50% interest in the Access Pipeline in Canada. Proceeds from the transactions have been utilized primarily for debt repayment and to support future capital investment in Devon’s core resource plays. Upstream Assets In the second quarter of 2016, Devon divested its non-core Mississippian assets for approximately $200 million. Estimated proved reserves associated with these assets were approximately 11 MMBoe, or less than 1% of total U.S. proved reserves. During the third quarter of 2016, in several separate transactions with different purchasers, Devon divested non-core upstream assets located in east Texas, the Anadarko Basin and the Midland Basin for approximately $1.7 billion. Estimated proved reserves associated with these assets were approximately 146 MMBoe, or approximately 9% of total U.S. proved reserves. Absent gain recognition, the divestiture transactions that closed in the third quarter of 2016 would have significantly altered the costs and reserves relationship of Devon’s U.S cost center. Therefore, Devon recognized a $1.4 billion gain in the third quarter of 2016 associated with these divestitures. A summary of the gain computation follows. Three Months Ended September 30, 2016 (Millions) Proceeds received, net of purchase price adjustments and selling costs $ 1,653 Asset retirement obligation assumed by purchasers 250 Total consideration received 1,903 Allocated oil and gas property basis sold 355 Allocated goodwill 197 Total assets sold 552 Gains on asset sales $ 1,351 Access Pipeline In October 2016, Devon divested Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes. Prior Year Divestitures During 2014, Devon divested certain upstream properties located throughout Canada and the U.S. as part of its asset portfolio transformation for approximately $5 billion. A gain of $1.1 billion was recognized with the sale of the Canadian conventional assets. This gain is included as a separate item in the accompanying consolidated comprehensive statements of earnings. Devon repatriated the Canadian asset proceeds to the U.S. Between collecting the divestiture proceeds and repatriating the 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. The proceeds were used to repay debt. EnLink Acquisitions On January 7, 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.5 billion, subject to certain adjustments. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily funded with the issuance of EnLink preferred units. The remaining $500 million of the purchase price is to be paid within one year with the option to defer $250 million of the final payment 24 months from the close date. The first $250 million of undiscounted future installment payment is reported in other current liabilities in the accompanying consolidated balance sheets with the remaining $250 million payment reported in other long-term liabilities. The accretion of the discount is reported within net financing costs in the accompanying consolidated comprehensive statement of earnings. The first installment payment of $250 million was paid in January 2017 and was funded using divestiture proceeds, proceeds from equity issuances and borrowings under EnLink’s credit facility. The allocation of the purchase price at December 31, 2016 was $1.0 billion to intangible assets and approximately $400 million to property and equipment. On August 1, 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $251 million of existing non-monetary assets and cash to the joint venture and had committed an additional $285 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including cash contributions of approximately $144 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest On November 9, 2016, EnLink entered into a gathering and compression joint venture with a commitment of approximately $40 million to expand its midstream assets in the STACK. The joint venture is initially owned 30% by EnLink and 70% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $29 million in cash for new infrastructure build. After the initial capital commitment, EnLink and the joint venture partner will be responsible for their proportionate share of capital expenses. 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 2015 LPC $ 108 — $ 30 $ 30 $ 43 $ 5 March 2015 Coronado $ 240 $ 360 $ 302 $ 18 $ 281 $ (1 ) October 2015 Matador $ 141 — $ 36 $ 11 $ 99 $ (5) EnLink Asset Divestitures and Dropdowns In December 2016, EnLink entered into definitive agreements to divest approximately $278 million of certain non-core midstream assets. Certain of these transactions are expected to close during the first quarter of 2017. As of December 31, 2016, these assets were classified as held for sale. 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. In April 2015, EnLink 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 controls 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 control. 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, EMH, and $100 million in cash. EMH 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, EMH 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, EMH’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 in E2 (2) 18 Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests $ 1,841 Crosstex Energy, LP outstanding units: Common units held by public unitholders 75.1 Preferred units held by third party (3) 17.1 Restricted units 0.4 Total 92.6 Crosstex Energy, LP common unit price (4) $ 30.51 Crosstex Energy, LP common units value $ 2,825 Crosstex Energy, LP outstanding unit options value 4 Total fair value of noncontrolling interests in the Crosstex Energy, LP (4) 2,829 Total consideration and fair value of noncontrolling interests $ 4,670 (1) The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014. (2) Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2. (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 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 purchase price $ 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. 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, 2014. 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 (Millions) Total operating revenues $ 20,213 Net earnings $ 1,716 Noncontrolling interests $ 97 Net earnings attributable to Devon $ 1,619 Net earnings per common share attributable to Devon $ 3.94

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	3. Derivative Financial Instruments Commodity Derivatives As of December 31, 2016, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table. Price Swaps Price Collars Period Volume (Bbls/d) Weighted Average Price ($/Bbl) Volume (Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2017 72,527 $ 54.32 53,245 $ 45.16 $ 57.97 Q1-Q4 2018 2,600 $ 53.38 6,189 $ 46.97 $ 56.97 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2017 Midland Sweet 10,000 $ (0.43 ) As of December 31, 2016, 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 Price Collars Period Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Volume (MMBtu/d) Weighted Average Floor Price ($/MMBtu) Weighted Average Ceiling Price ($/MMBtu) Q1-Q4 2017 189,753 $ 3.13 335,274 $ 2.97 $ 3.38 Q1-Q4 2018 29,705 $ 3.17 19,110 $ 3.20 $ 3.50 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2017 Panhandle Eastern Pipe Line 150,000 $ (0.34 ) Q1-Q4 2017 El Paso Natural Gas 80,000 $ (0.13 ) Q1-Q4 2017 Houston Ship Channel 35,000 $ 0.06 Q1-Q4 2017 Transco Zone 4 205,000 $ 0.03 Q1 2018 Panhandle Eastern Pipe Line 50,000 $ (0.29 ) As of December 31, 2016, EnLink had the following open derivative positions associated with gas processing 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 2017-Q4 2017 Propane 434 MBbls Index $0.55/gal Q1 2017-Q4 2017 Normal Butane 161 MBbls Index $0.70/gal Q1 2017-Q4 2017 Natural Gas 21,685 MMBtu/d Index $3.14/MMbtu Interest Rate Derivatives As of December 31, 2016, Devon had the following open interest rate derivative positions: Notional Rate Received Rate Paid Expiration (Millions) $ 750 Three Month LIBOR 2.98% December 2048 (1) $ 100 1.76% Three Month LIBOR January 2019 (1) Mandatory settlement in December 2018. 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, 2016 2015 2014 Commodity derivatives: (Millions) Oil, gas and NGL derivatives $ (201 ) $ 503 $ 1,989 Marketing and midstream revenues (13 ) 9 22 Interest rate derivatives: Other nonoperating items (19 ) (20 ) (1 ) Foreign currency derivatives: Other nonoperating items (153 ) 246 60 Net gains (losses) recognized $ (386 ) $ 738 $ 2,070 The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2016 December 31, 2015 (Millions) Commodity derivative assets: Other current assets $ 9 $ 34 Other long-term assets 1 1 Interest rate derivative assets: Other current assets 1 1 Other long-term assets — 1 Foreign currency derivative assets: Other current assets — 8 Total derivative assets $ 11 $ 45 Commodity derivative liabilities: Other current liabilities $ 187 $ 14 Other long-term liabilities 16 4 Interest rate derivative liabilities: Other long-term liabilities 41 22 Foreign currency derivative liabilities: Other current liabilities — 8 Total derivative liabilities $ 244 $ 48

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [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. The table below presents the effects of share-based compensation included in Devon’s accompanying consolidated comprehensive statements of earnings. Gross G&A in 2016, 2015 and 2014 includes $24 million, $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 2016 in conjunction with the reduction of workforce described in Note 6. Approximately $60 million of associated expense for these accelerated awards is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings. In 2014, vesting of certain share-based awards was accelerated in conjunction with the divestiture of Devon’s Canadian conventional assets. Approximately $15 million of associated expense for these accelerated awards is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2016 2015 2014 (Millions) Gross G&A for share-based compensation $ 154 $ 225 $ 199 Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties $ 39 $ 63 $ 53 Related income tax benefit $ 4 $ 45 $ 42 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 12/31/15 4,738 $ 62.49 434 $ 60.48 1,859 $ 76.17 Granted 4,390 $ 19.91 330 $ 19.22 1,388 $ 10.41 Vested (2,473 ) $ 61.44 (179 ) $ 59.10 (602 ) $ 63.37 Forfeited (248 ) $ 44.38 — $ — (41 ) $ 43.88 Unvested at 12/31/16 6,407 $ 34.40 585 $ 37.60 2,604 (1 ) $ 46.66 (1) A maximum of 5.2 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. 2016 2015 2014 (Millions) Restricted Stock Awards and Units $ 73 $ 101 $ 112 Performance-Based Restricted Stock Awards $ 5 $ 8 $ 10 Performance Share Units $ 13 $ 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, 2016. Performance-Based Restricted Stock Restricted Stock Performance Awards and Units Awards Share Units Unrecognized compensation cost (millions) $ 131 $ 5 $ 21 Weighted average period for recognition (years) 2.3 2.2 1.6 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 one 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 one 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 requirements 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 management and senior employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified 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. 2016 2015 2014 Grant-date fair value $ 9.24 — $ 10.61 $ 81.99 — $ 85.05 $ 70.18 — $ 81.05 Risk-free interest rate 0.94% 1.06% 0.54% Volatility factor 37.7% 26.2% 28.8% Contractual term (years) 2.83 2.89 2.89 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 one 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 2016, 2015 and 2014. 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, 2015 3,448 $ 67.98 Expired (916 ) $ 67.75 Outstanding at December 31, 2016 2,532 $ 68.06 1.87 $ — Vested and expected to vest at December 31, 2016 2,532 $ 68.06 1.87 $ — Exercisable at December 31, 2016 2,532 $ 68.06 1.87 $ — The aggregate intrinsic value of stock options that were exercised during 2015 and 2014 was $0.2 million and $9 million, respectively. As of December 31, 2016, Devon had no unrecognized compensation cost related to unvested stock options. EnLink Share-Based Awards 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, 2016. General Partner EnLink Restricted Performance Restricted Performance Incentive Units Units Incentive Units Units Unrecognized compensation cost (millions) $ 14 $ 4 $ 14 $ 4 Weighted average period for recognition (years) 1.6 1.8 1.7 1.8

Asset Impairments

Asset Impairments	12 Months Ended
	Dec. 31, 2016
Asset Impairment Charges [Abstract]
Asset Impairments	5. Asset Impairments The following table presents the asset impairments recognized in 2016, 2015 and 2014. Year Ended December 31, 2016 2015 2014 (Millions) U.S. oil and gas assets $ 2,809 $ 17,992 $ — Canada oil and gas assets 1,291 1,257 — Canada goodwill — — 1,941 EnLink goodwill 873 1,328 — EnLink other intangible assets — 223 — Other assets 2 20 12 Total asset impairments $ 4,975 $ 20,820 $ 1,953 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 reserves values and, to a lesser degree, proved reserves. For further information, see Note 22. Goodwill and Other Intangible Assets Impairments In 2016 and 2015, Devon recognized goodwill and other intangible assets impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 12. In 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.

Restructuring And Transaction C

Restructuring And Transaction Costs	12 Months Ended
	Dec. 31, 2016
Restructuring And Related Activities [Abstract]
Restructuring And Transaction Costs	6. Restructuring and Transaction Costs The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets. Other Other Current Long-term Liabilities Liabilities Total (Millions) Balance as of December 31, 2014 $ 13 $ 7 $ 20 Changes related to prior years' restructurings — 56 56 Balance as of December 31, 2015 $ 13 $ 63 $ 76 Changes due to 2016 workforce reductions 29 6 35 Changes related to prior years' restructurings 6 (7 ) (1 ) Balance as of December 31, 2016 $ 48 $ 62 $ 110 Reduction in Workforce In 2016, Devon recognized employee-related and other costs associated with a reduction in workforce that was made in response to the depressed commodity price environment. The following table summarizes restructuring and transaction costs presented in the accompanying consolidated comprehensive statement of earnings. Year Ended December 31, 2016 (Millions) 2016 reduction in workforce: Employee related costs $ 227 Lease obligations 20 Asset impairments 3 Transaction costs 17 Restructuring and transaction costs $ 267 Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $24 million resulted from estimated defined benefit settlements. These cash and noncash charges included estimates for employees released from service during 2016, as well as amounts based on the number of employees impacted by certain of its non-core asset divestitures. Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, Devon recognized restructuring costs that represent the present value of its future obligations under the leases. Additionally, Devon recognized asset impairment charges for leasehold improvements and furniture associated with the office space it ceased using. Transaction Costs In 2016, Devon and EnLink recognized transaction costs primarily associated with the closing of the acquisitions discussed in Note 2. Prior Years’ Restructurings In 2015, Devon recognized $24 million of employee-related and other costs associated with the reduction in workforce made subsequent to the completion of the Jackfish development projects and a decrease in planned Canadian 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. As part of the U.S. corporate headquarters office consolidation, Devon recognized an additional $54 million expense in 2015, due to a lack of demand for vacated office space and the inability to fully sublease remaining office space. In 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.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	7. Income Taxes Income Tax Expense (Benefit) The following table presents Devon’s income tax components. Year Ended December 31, 2016 2015 2014 (Millions) Current income tax expense (benefit): U.S. federal $ 5 $ (243 ) $ 152 Various states (11 ) (8 ) 18 Canada and various provinces 106 14 307 Total current tax expense (benefit) 100 (237 ) 477 Deferred income tax expense (benefit): U.S. federal (3 ) (5,033 ) 1,610 Various states — (336 ) 93 Canada and various provinces (270 ) (459 ) 188 Total deferred tax expense (benefit) (273 ) (5,828 ) 1,891 Total income tax expense (benefit) $ (173 ) $ (6,065 ) $ 2,368 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, 2016 2015 2014 (Millions) Total income tax expense (benefit) $ (173 ) $ (6,065 ) $ 2,368 U.S. statutory income tax rate 35 % 35 % 35 % Deferred tax asset valuation allowance (22 %) (4 %) 0 % Non-deductible goodwill and intangible impairment (8 %) (2 %) 23 % Change in unrecognized tax benefits (2 %) 0 % 1 % Taxation on Canadian operations (3 %) (1 %) (4 %) State income taxes 1 % 1 % 2 % Other 3 % 0 % 1 % Effective income tax rate 4 % 29 % 58 % 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 examinations 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 operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. 2016 During 2016, Devon’s U.S. segment recorded an additional $774 million valuation allowance against its deferred tax assets. The allowance results from continued financial losses resulting from additional full cost impairments in 2016. As of December 31, 2016, the allowance continues to represent a 100% valuation against the U.S. net deferred tax assets. Additionally, the Canadian segment recognized a $71 million partial valuation allowance resulting from continued financial losses. The valuation allowances impacted the effective tax rate and are discussed in the next section. In the first quarter of 2016, EnLink recorded a goodwill impairment of approximately $873 million. Additionally, during the third quarter of 2016, Devon derecognized $197 million of goodwill related to its U.S. operations in conjunction with the divestiture of certain non-core U.S upstream oil and gas assets. 2015 In the third and fourth quarters of 2015, EnLink recorded goodwill and intangibles impairments of approximately $1.6 billion, which impacted 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 Devon recognized a $967 million valuation allowance. 2014 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. These non-deductible goodwill reductions impacted 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 divestitures, 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. 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, 2016 2015 (Millions) Deferred tax assets: Property and equipment $ 685 $ 490 Asset retirement obligations 488 485 Accrued liabilities 130 160 Net operating loss carryforwards 777 175 Pension benefit obligations 98 106 Other 203 162 Total deferred tax assets before valuation allowance 2,381 1,578 Less: valuation allowance (1,666 ) (967 ) Net deferred tax assets 715 611 Deferred tax liabilities: Property and equipment (884 ) (1,187 ) Long-term debt (53 ) (36 ) Other (426 ) (271 ) Total deferred tax liabilities (1,363 ) (1,494 ) Net deferred tax liability $ (648 ) $ (883 ) At December 31, 2016, Devon has recognized $777 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 $536 million of Canadian carryforwards that expire between 2029 and 2037, $1.5 billion of U.S. federal carryforward that expires in 2036, and EnLink carryforwards to be utilized in 2018 and beyond. Devon currently does not anticipate utilizing the U.S. federal or state net operating loss carryforwards, as indicated by the full valuation allowance position in the U.S. segment. As a result of Devon’s continued financial losses incurred largely by the additional full cost impairments, Devon recorded an additional $630 million of valuation allowance against the U.S. deferred tax assets in 2016 and remains in a full valuation allowance position. Also during 2016, Devon’s Canadian segment recorded a $69 million partial valuation allowance due to its continued financial losses. 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, 2016, Devon’s unremitted foreign earnings from its international operations totaled approximately $1.0 billion. All but $47 million of the $1.0 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 $47 million of unremitted earnings deemed not to be indefinitely reinvested, Devon has recognized a $13 million deferred tax liability associated with such unremitted earnings as of December 31, 2016. Unrecognized Tax Benefits The following table presents changes in Devon’s unrecognized tax benefits. December 31, 2016 2015 (Millions) Balance at beginning of year $ 131 $ 241 Tax positions taken in prior periods 36 (19 ) Tax positions taken in current year — 31 Accrual of interest related to tax positions taken 39 (5 ) Settlements — (108 ) Lapse of statute of limitations (5 ) — Foreign currency translation 1 (9 ) Balance at end of year $ 202 $ 131 Devon’s unrecognized tax benefit balance at December 31, 2016 and 2015 included $68 million and $29 million, respectively, of interest and penalties. If recognized, $202 million of Devon’s unrecognized tax benefits as of December 31, 2016 would affect Devon’s effective income tax rate. Jurisdiction Tax Years Open U.S. Federal 2012-2016 Various U.S. states 2010-2016 Canada Federal 2003-2016 Various Canadian provinces 2003-2016 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.

Net Earnings (Loss) Per Share A

Net Earnings (Loss) Per Share Attributable To Devon	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
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, 2016 2015 2014 (Millions, except per share amounts) Net earnings (loss): Net earnings (loss) attributable to Devon $ (3,302 ) $ (14,454 ) $ 1,607 Attributable to participating securities (2 ) (5 ) (17 ) Basic and diluted earnings (loss) $ (3,304 ) $ (14,459 ) $ 1,590 Common shares: Common shares outstanding - total 513 412 409 Attributable to participating securities (6 ) (5 ) (4 ) Common shares outstanding - basic 507 407 405 Dilutive effect of potential common shares issuable — — 2 Common shares outstanding - diluted 507 407 407 Net earnings (loss) per share attributable to Devon: Basic $ (6.52 ) $ (35.55 ) $ 3.93 Diluted $ (6.52 ) $ (35.55 ) $ 3.91 Antidilutive options (1) 3 4 3 (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, 2016
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease [Abstract]
Other Comprehensive Earnings	9. Other Comprehensive Earnings Components of other comprehensive earnings consist of the following: Year Ended December 31, 2016 2015 2014 (Millions) Foreign currency translation: Beginning accumulated foreign currency translation $ 424 $ 983 $ 1,448 Change in cumulative translation adjustment 45 (621 ) (499 ) Income tax benefit (expense) (13 ) 62 34 Ending accumulated foreign currency translation 456 424 983 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (194 ) (204 ) (180 ) Net actuarial loss and prior service cost arising in current year (28 ) (5 ) (57 ) Recognition of net actuarial loss and prior service cost in earnings (1) 26 21 20 Curtailment and settlement of pension benefits 24 — — Income tax benefit (expense) — (6 ) 13 Ending accumulated pension and postretirement benefits (172 ) (194 ) (204 ) Accumulated other comprehensive earnings, net of tax $ 284 $ 230 $ 779 (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 16 for additional details.

Supplemental Information To Sta

Supplemental Information To Statements Of Cash Flows	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Supplemental Information To Statements Of Cash Flows	10. Supplemental Information to Statements of Cash Flows Year Ended December 31, 2016 2015 2014 (Millions) Net change in working capital accounts, net of assets and liabilities assumed: Accounts receivable $ (176 ) $ 942 $ 128 Income taxes receivable 130 384 (467 ) Other current assets 215 (57 ) (222 ) Accounts payable (167 ) (190 ) (68 ) Revenues and royalties payable 96 (526 ) 133 Other current liabilities (106 ) (864 ) 546 Net change in working capital $ (8 ) $ (311 ) $ 50 Interest paid (net of capitalized interest) $ 566 $ 494 $ 514 Income taxes paid (received) $ (159 ) $ (279 ) $ 899 In 2016, Devon’s acquisition of certain STACK assets included the noncash issuance of Devon common stock. Further, in 2016, EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets included noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions. See Note 2 for additional details. In 2015, Devon’s acquisition of certain Powder River Basin assets included noncash common stock issuance totaling $199 million. EnLink’s acquisitions in 2015 also included $360 million of noncash equity. 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.

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2016
Accounts Receivable Net [Abstract]
Accounts Receivable	11. Accounts Receivable Components of accounts receivable include the following: December 31, 2016 December 31, 2015 (Millions) Oil, gas and NGL sales $ 487 $ 362 Joint interest billings 110 211 Marketing and midstream revenues 708 520 Other 69 30 Gross accounts receivable 1,374 1,123 Allowance for doubtful accounts (18 ) (18 ) Net accounts receivable $ 1,356 $ 1,105

Goodwill And Other Intangible A

Goodwill And Other Intangible Assets	12 Months Ended
	Dec. 31, 2016
Goodwill And Intangible Assets Disclosure [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. EnLink Total (Millions) 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 Acquired during period — 2 2 Asset divestitures (197 ) — (197 ) Impairment — (873 ) (873 ) Balance as of December 31, 2016 $ 2,421 $ 1,543 $ 3,964 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, 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 during period 2 — — — — 2 Impairment (473 ) — — (93 ) (307 ) (873 ) Balance as of December 31, 2016 $ 233 $ — $ 190 $ — $ 1,120 $ 1,543 Asset Divestitures In conjunction with the U.S. non-core upstream asset divestitures in 2016 discussed in Note 2, Devon removed $197 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 in the first quarter of 2016. Based on that test, EnLink recorded a noncash goodwill impairment. During 2015, as a result of interim and annual impairment tests of goodwill, noncash goodwill impairments were recorded related to EnLink’s Texas, Louisiana and Crude and Condensate reporting units. Other Intangible Assets In the third quarter of 2015, Devon recorded a $223 million noncash impairment of intangible assets related to EnLink’s Crude and Condensate reporting unit resulting from an assessment of EnLink’s customer relationships. 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. The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets. December 31, 2016 December 31, 2015 (Millions) Customer relationships $ 1,796 $ 745 Accumulated amortization (172 ) (55 ) Net intangibles $ 1,624 $ 690 The weighted-average amortization period for the customer relationships is 14 years. Amortization expense for intangibles was approximately $117 million, $56 million and $36 million for the years ended 2016, 2015 and 2014, respectively. The remaining aggregate amortization expense is estimated to be approximately $118 million in each of the next five years.

Other Current Liabilities

Other Current Liabilities	12 Months Ended
	Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	13. Other Current Liabilities Components of other current liabilities include the following: December 31, 2016 December 31, 2015 (Millions) Installment payment - see Note 2 $ 249 $ — Derivative liabilities 187 22 Accrued interest payable 130 149 Restructuring liabilities 48 13 Other 452 466 Other current liabilities $ 1,066 $ 650

Debt And Related Expenses

Debt And Related Expenses	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt and Related Expenses	14. Debt and Related Expenses See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon. December 31, 2016 December 31, 2015 (Millions) Devon debt: Commercial paper $ — $ 626 Floating rate due December 15, 2016 — 350 8.25% due July 1, 2018 (1)(2) 20 125 2.25% due December 15, 2018 (1) 95 750 6.30% due January 15, 2019 (1) 162 700 4.00% due July 15, 2021 500 500 3.25% due May 15, 2022 1,000 1,000 5.85% due December 15, 2025 (1) 485 850 7.50% due September 15, 2027 (1)(2) 73 150 7.875% due September 30, 2031 (1)(3) 1,059 1,250 7.95% due April 15, 2032 (1) 789 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 750 750 Net discount on debentures and notes (30 ) (28 ) Debt issuance costs (44 ) (57 ) Total Devon debt 6,859 9,966 EnLink and General Partner debt: Credit facilities 148 414 2.70% due April 1, 2019 400 400 7.125% due June 1, 2022 163 163 4.40% due April 1, 2024 550 550 4.15% due June 1, 2025 750 750 4.85% due July 15, 2026 500 — 5.60% due April 1, 2044 350 350 5.05% due April 1, 2045 450 450 Net premium on debentures and notes 9 13 Debt issuance costs (25 ) (24 ) Total EnLink and General Partner debt 3,295 3,066 Total debt 10,154 13,032 Less amount classified as short-term debt (4) — 976 Total long-term debt $ 10,154 $ 12,056 (1) These senior notes were included in 2016 tender offer redemptions discussed below. (2) These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively. (3) Issued in October 2001, these are unsecured and unsubordinated obligations of Devon Financing, a wholly owned finance subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. (4) 2015 short-term debt consists of commercial paper balances and floating rate debt that was retired upon maturity in December 2016. Debt maturities as of December 31, 2016, excluding debt issuance costs, premiums and discounts, are as follows (millions): 2017 $ — 2018 115 2019 590 2020 120 2021 500 Thereafter 8,919 Total $ 10,244 Credit Lines Devon has a $3.0 billion Senior Credit Facility. The facility matures as follows: $30 million on October 24, 2017, $164 million on October 24, 2018 and the remaining $2.8 billion on 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 $7.6 million. As of December 31, 2016, Devon had $140 million in outstanding letters of credit, including $57 million in outstanding letters of credit under the Senior Credit Facility. There were no borrowings under the Senior Credit Facility as of December 31, 2016. 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 asset impairments. As of December 31, 2016, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 18.7%. 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. During 2016, Devon reduced commercial paper borrowings by $626 million. As of December 31, 2016, Devon had no outstanding commercial paper borrowings. Retirement of Senior Notes During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 2. Devon recognized a loss on early retirement of debt, primarily consisting of $265 million in cash retirement costs and other fees. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings. In November 2014, Devon redeemed $1.9 billion of senior notes prior to their scheduled maturity, primarily with proceeds received from asset divestitures. Devon recognized a loss on the early retirement of debt, primarily consisting of $40 million in cash retirement costs and other noncash charges. These costs are included in net financing costs in the consolidated comprehensive statement of earnings. Issuance of Senior Notes 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 partially fund the cash portion of these acquisitions. 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. EnLink Debt All of EnLink’s and the General Partner’s debt is non-recourse to Devon. EnLink has a $1.5 billion unsecured revolving credit facility that will mature on March 6, 2020. As of December 31, 2016, there were $12 million in outstanding letters of credit and $120 million outstanding borrowings, with a weighted-average borrowing rate of 2.3%, under the $1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019. As of December 31, 2016, the General Partner had $28 million outstanding borrowings under the $250 million credit facility at a weighted average borrowing rate of 3.4%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2016. In July 2016, EnLink issued $500 million of 4.85% unsecured senior notes due 2026. EnLink used the net proceeds to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. 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 Financing Costs The following schedule includes the components of net financing costs. Year Ended December 31, 2016 2015 2014 (Millions) Devon net financing costs: Interest based on debt outstanding $ 488 $ 450 $ 468 Early retirement of debt 269 — 48 Capitalized interest (64 ) (54 ) (58 ) Other 21 14 15 Total Devon net financing costs 714 410 473 EnLink net financing costs: Interest based on debt outstanding 144 115 64 Interest accretion on deferred installment payment 52 — — Other (6 ) (8 ) (11 ) Total EnLink net financing costs 190 107 53 Total net financing costs $ 904 $ 517 $ 526

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	15. Asset Retirement Obligations The following table presents the changes in asset retirement obligations. Year Ended December 31, 2016 2015 (Millions) Asset retirement obligations as of beginning of period $ 1,414 $ 1,399 Liabilities incurred and assumed through acquisitions 27 63 Liabilities settled and divested (324 ) (89 ) Revision of estimated obligation 66 62 Accretion expense on discounted obligation 75 75 Foreign currency translation adjustment 14 (96 ) Asset retirement obligations as of end of period 1,272 1,414 Less current portion 46 44 Asset retirement obligations, long-term $ 1,226 $ 1,370 During 2016, Devon reduced its asset retirement obligation by $287 million for those obligations that were assumed by purchasers of certain upstream U.S. assets.

Retirement Plans

Retirement Plans	12 Months Ended
	Dec. 31, 2016
Compensation And Retirement Disclosure [Abstract]
Retirement Plans	16. 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 $16 million and $22 million at December 31, 2016 and 2015, 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, 2016 and 2015. Devon’s benefit obligations and plan assets are measured each year as of December 31. Pension Benefits Postretirement Benefits 2016 2015 2016 2015 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,308 $ 1,377 $ 23 $ 24 Service cost 15 33 — 1 Interest cost 42 52 1 1 Actuarial loss (gain) 63 (68 ) (1 ) (2 ) Plan amendments 2 — — 1 Plan curtailments (31 ) — — — Plan settlements (94 ) — — — Foreign exchange rate changes 1 (6 ) — — Participant contributions — — — 2 Benefits paid (57 ) (80 ) (2 ) (4 ) Benefit obligation at end of year 1,249 1,308 21 23 Change in plan assets: Fair value of plan assets at beginning of year 1,059 1,149 — — Actual return on plan assets 61 (16 ) — — Employer contributions 16 11 2 2 Participant contributions — — — 2 Plan settlements (94 ) — — — Benefits paid (57 ) (80 ) (2 ) (4 ) Foreign exchange rate changes — (5 ) — — Fair value of plan assets at end of year 985 1,059 — — Funded status at end of year $ (264 ) $ (249 ) $ (21 ) $ (23 ) Amounts recognized in balance sheet: Other long-term assets $ 3 $ 2 $ — $ — Other current liabilities (13 ) (12 ) (3 ) (3 ) Other long-term liabilities (254 ) (239 ) (18 ) (20 ) Net amount $ (264 ) $ (249 ) $ (21 ) $ (23 ) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 285 $ 302 $ (11 ) $ (11 ) Prior service cost (credit) 8 14 (5 ) (6 ) Total $ 293 $ 316 $ (16 ) $ (17 ) 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 $13 million and $11 million for 2016 and 2015, respectively, which were funded from the trusts established for the nonqualified plans. Certain of Devon’s pension plans are unfunded and have a combined projected benefit obligation and accumulated benefit obligation of $234 million and $211 million, respectively, at December 31, 2016 and $244 million and $199 million, respectively, at December 31, 2015. 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 2016 2015 2014 2016 2015 2014 (Millions) Net periodic benefit cost: Service cost $ 15 $ 33 $ 30 $ — $ 1 $ 1 Interest cost 42 52 55 1 1 1 Expected return on plan assets (55 ) (58 ) (54 ) — — — Curtailment and settlement expense — — 1 — — — Recognition of net actuarial loss (gain) (1) 25 20 18 (1 ) (1 ) (1 ) Recognition of prior service cost (1) 3 4 4 (1 ) (2 ) (2 ) Total net periodic benefit cost (2) 30 51 54 (1 ) (1 ) (1 ) Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 26 5 57 — (1 ) — Prior service cost (credit) arising in current year 2 — — — 1 — Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost (3) (43 ) (20 ) (19 ) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) (9 ) (4 ) (4 ) 1 1 2 Total other comprehensive loss (earnings) (24 ) (19 ) 34 2 2 3 Total recognized $ 6 $ 32 $ 88 $ 1 $ 1 $ 2 (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. (3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in the current period. See Note 6 for further discussion. The estimated net actuarial loss and prior service cost for our pension and postretirement benefits that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2017 are $18 million and $1 million, respectively. Assumptions The following table presents the weighted-average actuarial assumptions used to determine obligations and periodic costs. Pension Benefits Postretirement Benefits 2016 2015 2014 2016 2015 2014 Assumptions to determine benefit obligations: Discount rate 4.07% 4.25% 3.90% 3.46% 3.63% 3.25% Rate of compensation increase 4.49% 4.49% 4.49% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate 4.39% 3.90% 4.80% 3.63% 3.25% 3.65% Rate of compensation increase 4.49% 4.49% 4.49% N/A N/A N/A Expected return on plan assets 5.20% 5.22% 5.42% 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 plan 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 believes 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 not affect the measurement of the plan obligations 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 2016 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 scale derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in Devon’s plans. Other assumptions – For measurement of the 2016 benefit obligation for the other postretirement medical plans, a 7.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. A one percentage point change in assumed health care cost trend rates would not have a material impact on periodic benefit cost or benefit obligations. 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. Devon’s target allocations for its pension plan assets are 70% fixed income, 20% equity and 10% other. The following tables present the fair values of Devon’s pension assets by asset class. As of December 31, 2016 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 % $ 343 $ 68 $ 275 $ — Corporate bonds 30 % 297 205 92 — Other bonds 4 % 38 38 — — Total fixed-income securities 69 % 678 311 367 — Equity securities: Global (large, mid, small cap) 17 % 171 — 171 — Other securities: Hedge fund and alternative investments 11 % 112 — — 112 Short-term investments 3 % 24 8 16 — Total other securities 14 % 136 8 16 112 Total investments 100 % $ 985 $ 319 $ 554 $ 112 As of 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 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, 2014 $ 112 Purchases 5 Investment returns 3 December 31, 2015 120 Investments sold (12 ) Investment returns 4 December 31, 2016 $ 112 Expected Cash Flows The table below presents contributions expected to be made to Devon’s qualified plans, nonqualified plans and postretirement plans. Of the benefits expected to be paid in 2017, $13 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. Pension Benefits Postretirement Benefits (Millions) 2017 $ 60 $ 3 2018 $ 61 $ 3 2019 $ 62 $ 3 2020 $ 64 $ 2 2021 $ 67 $ 2 2022 to 2026 $ 374 $ 7 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, 2016 2015 2014 (Millions) 401(k) and enhanced contribution plans $ 53 $ 63 $ 49 Canadian pension and savings plans 11 16 20 Total $ 64 $ 79 $ 69

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2016
Stockholders Equity Note [Abstract]
Stockholders' Equity	17. 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 January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition discussed in Note 2. Additionally, in February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion. 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. Dividends The table below summarizes the dividends Devon paid on its common stock. Amounts Rate (Millions) (Per Share) Year Ended 2016: First quarter 2016 $ 125 $ 0.24 Second quarter 2016 33 $ 0.06 Third quarter 2016 32 $ 0.06 Fourth quarter 2016 31 $ 0.06 Total year-to-date $ 221 Year Ended 2015: First quarter 2015 $ 99 $ 0.24 Second quarter 2015 98 $ 0.24 Third quarter 2015 99 $ 0.24 Fourth quarter 2015 100 $ 0.24 Total year-to-date $ 396 Year Ended 2014: First quarter 2014 $ 90 $ 0.22 Second quarter 2014 99 $ 0.24 Third quarter 2014 98 $ 0.24 Fourth quarter 2014 99 $ 0.24 Total year-to-date $ 386

Noncontrolling Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2016
Noncontrolling Interest [Abstract]
Noncontrolling interests	18. Noncontrolling Interests Subsidiary Equity Transactions During the first quarter of 2016, EnLink issued common units in conjunction with the Tall Oak acquisition discussed in Note 2. Through its equity distribution agreements, EnLink has the ability to sell common units through an “at the market” equity offering program. During 2016, 2015 and 2014, EnLink issued and sold approximately 10.0 million, 1.3 million and 14.8 million common units through its at the market program and general public offerings, generating net proceeds of $167 million, $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 and EnLink’s acquisition and dropdown activity discussed further in Note 2, the table below shows the ownership interest activity in the General Partner and EnLink since inception. EnLink General Partner Ownership interest as of Devon Non-Devon Unitholders General Partner Devon Non-Devon Unitholders March 7, 2014 52% 41% 7% 70% 30% December 31, 2014 49% 43% 8% 70% 30% December 31, 2015 28% 45% 27% 70% 30% December 31, 2016 24% 53% 23% 64% 36% Distributions to Noncontrolling Interests In conjunction with the formation of the General Partner in 2014, Devon made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $304 million, $254 million and $135 million to non-Devon unitholders during 2016, 2015 and 2014, respectively.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments And Contingencies	19. 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 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, 2016. Year Ending December 31, Purchase Obligations Drilling and Facility Obligations Operational Agreements Office and Equipment Leases EnLink Obligations (Millions) 2017 $ 609 $ 76 $ 1,145 $ 50 $ 50 2018 649 66 1,134 85 51 2019 762 67 627 83 33 2020 748 57 457 59 18 2021 181 37 285 39 17 Thereafter — 85 2,667 55 102 Total $ 2,949 $ 388 $ 6,315 $ 371 $ 271 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 $78 million, $88 million and $64 million in 2016, 2015 and 2014, respectively.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	20. Fair Value Measurements The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. 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, 2016 and December 31, 2015. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items and the pension plan assets is provided in Note 5, Note 12 and Note 16, respectively. Fair Value Measurements Using: Carrying Total Fair Level 1 Level 2 Amount Value Inputs Inputs (Millions) December 31, 2016 assets (liabilities): Cash equivalents $ 1,542 $ 1,542 $ 1,298 $ 244 Commodity derivatives $ 10 $ 10 $ — $ 10 Commodity derivatives $ (203 ) $ (203 ) $ — $ (203 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (41 ) $ (41 ) $ — $ (41 ) Debt $ (10,154 ) $ (10,760 ) $ — $ (10,760 ) Installment payment $ (473 ) $ (477 ) $ — $ (477 ) Capital lease obligations $ (7 ) $ (6 ) $ — $ (6 ) 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 $ (13,032 ) $ (11,927 ) $ — $ (11,927 ) Capital lease obligations $ (17 ) $ (16 ) $ — $ (16 ) The following methods and assumptions were used to estimate the fair values in the tables above. Level 1 Fair Value Measurements Cash equivalents – Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value. Level 2 Fair Value Measurements Cash equivalents – Amounts consist primarily of 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 values of commercial paper and credit facility balances are the carrying values. Installment payment – The fair value of the EnLink installment payment as of December 31, 2016 was based on Level 2 inputs from third-party market quotations. Capital lease obligations – The fair value was calculated using inputs from third-party banks.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Information	21. Segment Information Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian 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 22. 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. U.S. (1) Canada EnLink (1) Eliminations Total (Millions) Year Ended December 31, 2016: Revenues from external customers $ 5,722 $ 1,031 $ 3,551 $ — $ 10,304 Asset dispositions and other $ 1,367 $ 542 $ (16) $ — $ 1,893 Intersegment revenues $ — $ — $ 701 $ (701 ) $ — Depreciation, depletion and amortization $ 928 $ 360 $ 504 $ — $ 1,792 Asset impairments $ 2,809 $ 1,293 $ 873 $ — $ 4,975 Restructuring and transaction costs $ 242 $ 19 $ 6 $ — $ 267 Interest expense $ 624 $ 181 $ 190 $ (84 ) $ 911 Loss before income taxes $ (2,051 ) $ (942 ) $ (884 ) $ — $ (3,877 ) Income tax benefit $ (8 ) $ (165 ) $ — $ — $ (173 ) Net loss $ (2,043 ) $ (777 ) $ (884 ) $ — $ (3,704 ) Net earnings (loss) attributable to noncontrolling interests $ 1 $ — $ (403 ) $ — $ (402 ) Net loss attributable to Devon $ (2,044 ) $ (777 ) $ (481 ) $ — $ (3,302 ) Property and equipment, net $ 7,358 $ 2,575 $ 6,257 $ — $ 16,190 Total assets $ 12,163 $ 3,536 $ 10,276 $ (62 ) $ 25,913 Capital expenditures, including acquisitions $ 2,880 $ 229 $ 1,082 $ — $ 4,191 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 Restructuring and transaction costs $ 54 $ 24 $ — $ — $ 78 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 $ 14,550 $ 5,457 $ 9,541 $ (97 ) $ 29,451 Capital expenditures, including acquisitions $ 4,575 $ 680 $ 978 $ — $ 6,233 Year Ended December 31, 2014: Revenues from external customers $ 14,854 $ 2,063 $ 2,649 $ — $ 19,566 Asset dispositions and other $ (5 ) $ 1,077 $ — $ — $ 1,072 Intersegment revenues $ — $ — $ 859 $ (859 ) $ — Depreciation, depletion and amortization $ 2,475 $ 560 $ 284 $ — $ 3,319 Asset impairments $ 12 $ 1,941 $ — $ — $ 1,953 Restructuring and transaction costs $ — $ 46 $ — $ — $ 46 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 $ 31,994 $ 8,509 $ 10,189 $ (124 ) $ 50,568 Capital expenditures, including acquisitions $ 11,214 $ 1,344 $ 1,001 $ — $ 13,559 (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, 2016
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Supplemental Information on Oil and Gas Operations	22. Supplemental Information on Oil and Gas Operations (Unaudited) Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country. Costs Incurred The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities. Year Ended December 31, 2016 U.S. Canada Total (Millions) Property acquisition costs: Proved properties $ 237 $ — $ 237 Unproved properties 1,356 2 1,358 Exploration costs 345 49 394 Development costs 1,034 109 1,143 Costs incurred $ 2,972 $ 160 $ 3,132 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 Development costs 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 $244 million, $372 million and $376 million in 2016, 2015 and 2014, 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 $64 million, $54 million and $45 million in 2016, 2015 and 2014, respectively. Capitalized Costs The following tables reflect the aggregate capitalized costs related to oil and gas activities. December 31, 2016 U.S. Canada Total (Millions) Proved properties $ 61,401 $ 14,247 $ 75,648 Unproved properties 2,092 1,345 3,437 Total oil and gas properties 63,493 15,592 79,085 Accumulated DD&A (57,323 ) (13,107 ) (70,430 ) Net capitalized costs $ 6,170 $ 2,485 $ 8,655 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 The following table presents a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2016. Costs Incurred In 2016 2015 2014 Prior to 2014 Total (Millions) Acquisition costs $ 1,176 $ 579 $ 246 $ 464 $ 2,465 Exploration costs 107 134 89 206 536 Development costs 12 — 23 150 185 Capitalized interest 63 52 37 99 251 Total oil and gas properties not subject to amortization $ 1,358 $ 765 $ 395 $ 919 $ 3,437 Included in the $3.4 billion of oil and gas properties not subject to amortization are approximately $2.9 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada, the assets acquired in the STACK play during 2016 and the Powder River Basin assets acquired in 2015. Devon continues to assess its Pike development timeline 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 begins recognizing the associated proved reserves. Devon is evaluating and plans to develop the newly acquired STACK and 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, 2016 U.S. Canada Total (Millions) Oil, gas and NGL sales $ 3,198 $ 984 $ 4,182 Lease operating expenses (1,123 ) (459 ) (1,582 ) General and administrative expenses (148 ) (20 ) (168 ) Production and property taxes (200 ) (31 ) (231 ) Depreciation, depletion and amortization (817 ) (326 ) (1,143 ) Gains on asset sales 1,351 — 1,351 Asset impairments (2,809 ) (1,291 ) (4,100 ) Accretion of asset retirement obligations (49 ) (25 ) (74 ) Income tax benefit — 245 245 Results of operations $ (597 ) $ (923 ) $ (1,520 ) Depreciation, depletion and amortization per Boe $ 4.68 $ 6.65 $ 5.11 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 ) Gains on asset sales — 1,077 1,077 Accretion of asset retirement obligations (49 ) (39 ) (88 ) Income tax expense (1,199 ) (568 ) (1,767 ) Results of operations (1) $ 2,076 $ 1,115 $ 3,191 Depreciation, depletion and amortization per Boe $ 11.41 $ 13.80 $ 11.79 (1) 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, 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 Revisions due to prices (18 ) (2 ) (20 ) Revisions other than price (2 ) 3 1 Extensions and discoveries 36 2 38 Purchase of reserves 8 — 8 Production (47 ) (8 ) (55 ) Sale of reserves (25 ) — (25 ) December 31, 2016 194 17 211 Proved developed reserves as of: December 31, 2013 194 56 250 December 31, 2014 255 23 278 December 31, 2015 203 22 225 December 31, 2016 160 17 177 Proved developed-producing reserves as of: December 31, 2013 178 51 229 December 31, 2014 224 19 243 December 31, 2015 192 19 211 December 31, 2016 143 13 156 Proved undeveloped reserves as of: December 31, 2013 35 — 35 December 31, 2014 96 — 96 December 31, 2015 39 — 39 December 31, 2016 34 — 34 Bitumen (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices — 23 23 Revisions other than price — (19 ) (19 ) Production — (40 ) (40 ) December 31, 2016 — 484 484 Proved developed reserves as of: December 31, 2013 — 111 111 December 31, 2014 — 137 137 December 31, 2015 — 219 219 December 31, 2016 — 190 190 Proved developed-producing reserves as of: December 31, 2013 — 111 111 December 31, 2014 — 137 137 December 31, 2015 — 219 219 December 31, 2016 — 190 190 Proved undeveloped reserves as of: December 31, 2013 — 441 441 December 31, 2014 — 384 384 December 31, 2015 — 301 301 December 31, 2016 — 294 294 Gas (Bcf) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices (103 ) — (103 ) Revisions other than price 628 10 638 Extensions and discoveries 280 — 280 Purchase of reserves 33 — 33 Production (510 ) (7 ) (517 ) Sale of reserves (521 ) — (521 ) December 31, 2016 5,615 16 5,631 Proved developed reserves as of: December 31, 2013 7,707 752 8,459 December 31, 2014 6,948 36 6,984 December 31, 2015 5,694 13 5,707 December 31, 2016 5,361 16 5,377 Proved developed-producing reserves as of: December 31, 2013 7,425 680 8,105 December 31, 2014 6,746 34 6,780 December 31, 2015 5,546 13 5,559 December 31, 2016 5,243 16 5,259 Proved undeveloped reserves as of: December 31, 2013 843 6 849 December 31, 2014 703 — 703 December 31, 2015 114 — 114 December 31, 2016 254 — 254 Natural Gas Liquids (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices (13 ) — (13 ) Revisions other than price 48 — 48 Extensions and discoveries 42 — 42 Purchase of reserves 7 — 7 Production (42 ) — (42 ) Sale of reserves (45 ) — (45 ) December 31, 2016 425 — 425 Proved developed reserves as of: December 31, 2013 468 23 491 December 31, 2014 486 — 486 December 31, 2015 411 — 411 December 31, 2016 387 — 387 Proved developed-producing reserves as of: December 31, 2013 442 21 463 December 31, 2014 467 — 467 December 31, 2015 393 — 393 December 31, 2016 370 — 370 Proved undeveloped reserves as of: December 31, 2013 84 — 84 December 31, 2014 92 — 92 December 31, 2015 17 — 17 December 31, 2016 38 — 38 Total (MMBoe) (1) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices (48 ) 21 (27 ) Revisions other than price 151 (14 ) 137 Extensions and discoveries 124 2 126 Purchase of reserves 20 — 20 Production (174 ) (49 ) (223 ) Sale of reserves (157 ) — (157 ) December 31, 2016 1,554 504 2,058 Proved developed reserves as of: December 31, 2013 1,947 315 2,262 December 31, 2014 1,900 165 2,065 December 31, 2015 1,563 243 1,806 December 31, 2016 1,439 210 1,649 Proved developed-producing reserves as of: December 31, 2013 1,857 297 2,154 December 31, 2014 1,815 162 1,977 December 31, 2015 1,509 240 1,749 December 31, 2016 1,386 207 1,593 Proved undeveloped reserves as of: December 31, 2013 258 443 701 December 31, 2014 305 384 689 December 31, 2015 75 301 376 December 31, 2016 115 294 409 (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 2016 (MMBoe). U.S. Canada Total Proved undeveloped reserves as of December 31, 2015 75 301 376 Extensions and discoveries 78 — 78 Revisions due to prices (8 ) 10 2 Revisions other than price (1 ) (4 ) (5 ) Sale of reserves (1 ) — (1 ) Conversion to proved developed reserves (28 ) (13 ) (41 ) Proved undeveloped reserves as of December 31, 2016 115 294 409 Proved undeveloped reserves increased 9% from 2015 to 2016, and the year-end 2016 balance represents 20% of total proved reserves. Drilling and development activities in the STACK and Delaware Basin increased Devon’s proved undeveloped reserves by 78 MMBoe. Continued development of Devon’s Eagle Ford and Jackfish properties led to the conversion of 41 MMBoe, or 11%, of the 2015 proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $586 million for 2016. A significant amount of Devon’s proved undeveloped reserves at the end of 2016 related to its Jackfish operations. At December 31, 2016 and 2015, Devon’s Jackfish proved undeveloped reserves were 294 MMBoe and 301 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 2029. At the end of 2016, approximately 199 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 119 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop. Price Revisions Reserves decreased 27 MMBoe and 302 MMBoe during 2016 and 2015, respectively, primarily due to lower commodity prices for oil, bitumen and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes. In 2014, price revisions increased Devon’s total proved reserves less than 1% due to higher commodity prices. Revisions Other Than Price Total revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and NGLs, with the largest revisions being made in the Barnett Shale and STACK (Cana-Woodford Shale). Revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish were primarily due to a refined reserves methodology that resulted in a reduced recovery factor. Revisions other than price in 2014 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 2016 – Of the 126 MMBoe of extensions and discoveries, 97 MMBoe related to STACK, 18 MMBoe related to the Delaware Basin and 7 MMBoe related to the Eagle Ford. The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 73 MMBoe related to STACK. 2015 – 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 2015 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. Purchase of Reserves 2016 – Primarily related to Devon’s acquisition in the STACK play. 2015 – Primarily 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 2016 – The 157 MMBoe of reserves sales related to Devon’s non-core upstream asset divestitures discussed further in Note 2. 2015 – The 7 MMBoe of reserves sales related to Devon’s asset divestitures in the San Juan Basin. 2014 – The 383 MMBoe of reserves sales related to Devon’s asset divestitures in the U.S. and Canada. Standardized Measure The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves. Year Ended December 31, 2016 U.S. Canada Total (Millions) Future cash inflows $ 22,847 $ 9,672 $ 32,519 Future costs: Development (2,784 ) (2,201 ) (4,985 ) Production (14,484 ) (6,287 ) (20,771 ) Future income tax expense — (57 ) (57 ) Future net cash flow 5,579 1,127 6,706 10% discount to reflect timing of cash flows (2,128 ) (380 ) (2,508 ) Standardized measure of discounted future net cash flows $ 3,451 $ 747 $ 4,198 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 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 2016 estimates, Devon’s future realized prices were assumed to be $37.37 per Bbl of oil, $15.74 per Bbl of bitumen, $1.98 per Mcf of gas and $9.91 per Bbl of NGLs. Of the $5.0 billion of future development costs as of the end of 2016, $0.4 billion, $0.8 billion and $0.5 billion are estimated to be spent in 2017, 2018 and 2019, respectively. Future development costs include not only development costs but also future asset retirement costs. Included as part of the $5.0 billion of future development costs are $1.3 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws. The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows: Year Ended December 31, 2016 2015 2014 (Millions) Beginning balance $ 6,688 $ 20,474 $ 15,741 Net changes in prices and production costs (2,128 ) (20,756 ) 2,561 Oil, bitumen, gas and NGL sales, net of production costs (2,163 ) (2,704 ) (6,865 ) Changes in estimated future development costs 112 1,313 (768 ) Extensions and discoveries, net of future development costs 660 1,129 4,836 Purchase of reserves 222 95 6,422 Sales of reserves in place (560 ) (79 ) (2,384 ) Revisions of quantity estimates (32 ) (1,451 ) (746 ) Previously estimated development costs incurred during the period 663 2,158 1,933 Accretion of discount 403 567 1,746 Foreign exchange and other 105 (1,254 ) (107 ) Net change in income taxes 228 7,196 (1,895 ) Ending balance $ 4,198 $ 6,688 $ 20,474

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Supplemental Quarterly Financial Information	23. Supplemental Quarterly Financial Information (Unaudited) The following tables present a summary of Devon’s unaudited interim results of operations. 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Total revenues and other $ 2,126 $ 2,488 $ 4,233 $ 3,350 $ 12,197 Earnings (loss) before income taxes $ (3,685 ) $ (1,745 ) $ 1,178 $ 375 $ (3,877 ) Net earnings (loss) attributable to Devon $ (3,056 ) $ (1,570 ) $ 993 $ 331 $ (3,302 ) Basic net earnings (loss) per share attributable to Devon $ (6.44 ) $ (3.04 ) $ 1.90 $ 0.63 $ (6.52 ) Diluted net earnings (loss) per share attributable to Devon $ (6.44 ) $ (3.04 ) $ 1.89 $ 0.63 $ (6.52 ) 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Total revenues and other $ 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 ) Net Earnings (Loss) Attributable to Devon The 2016 quarterly results include asset impairments of $3.0 billion (or $6.40 per diluted share), $1.5 billion (or $2.89 per diluted share), $0.3 billion (or $0.61 per diluted share) and $0.1 billion (or $0.24 per diluted share) for the first quarter through the fourth quarter of 2016, respectively, as discussed in Note 5. Additionally, the 2016 quarterly results include gains from asset dispositions of approximately $1.4 billion (or $2.59 per diluted share) and $540 million (or $1.04 per diluted share) during the third and fourth quarter of 2016, respectively, as discussed in Note 2. The 2015 quarterly results include asset impairments of $5.5 billion (or $13.46 per diluted share), $4.2 billion (or $10.27 per diluted share), $5.9 billion (or $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.

Summary Of Significant Accoun30

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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, Devon 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	Revenue 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 2016, 2015 and 2014, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue.
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 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. As of December 31, 2016, Devon did not have any open foreign exchange contracts. 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, 2016, 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, 2016, Devon held no collateral from counterparties. As of December 31, 2015, Devon held $75 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying consolidated balance sheets. As a result of ratings downgrades for Devon during 2016, we were required to post $17 million of cash collateral under certain of our derivative contracts. The collateral is reported in other current assets in the accompanying December 31, 2016 consolidated balance sheet. In January 2017, this collateral was deemed to be no longer required and was returned to Devon. As of the date of this report, Devon has no cash collateral held by its counterparties.
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 members of its Board of Directors and select employees. EnLink and the General Partner also grant share-based awards to members of its Board of Directors and select 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. 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.
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.
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 their respective holding periods generally 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. However, if a disposition or series of dispositions occurring in a quarterly reporting period significantly alters the relationship between capitalized costs and proved reserves in a particular country, a gain or loss is recognized. As discussed more fully in Note 2, the 2014 and 2016 divestitures of certain Canadian and U.S. non-core upstream assets significantly altered such relationship, and Devon recognized gains on these transactions. These gains are classified as asset dispositions and other in the accompanying consolidated statements of earnings. Furthermore, upon recognizing the gain on the 2016 divestitures and to be more consistent with industry practice, Devon began presenting gains on asset sales in the total revenues and other section of the accompanying consolidated statements of earnings, and has reclassified the 2014 gain on asset sales of $1.1 billion from operating expenses to total revenues and other to reflect consistent financial statement presentation. 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, 2016 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 and EnLink performed annual impairment tests of goodwill in the fourth quarters of 2016, 2015 and 2014. No impairment write-down was required as a result of the annual tests in 2016; however, sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units and in 2014 for Devon’s Canadian reporting unit based on interim and annual impairment tests. 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 2016 and 2015, EnLink’s customer relationships were also evaluated for impairment, and in 2015, a portion of these intangible assets 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.
Recent Accounting Standards	Recently Adopted Accounting Standards In January 2016, Devon adopted ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2014-15 , Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern Recently Issued Accounting Standards The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Extractive Activities – Oil and Gas – Revenue Recognition. Revenue from Contracts with Customers – Deferral of the Effective Date, The FASB issued ASU 2016-02, Leases (Topic 842) Leases The FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting The FASB issued ASU No. 2016-13, Credit Losses, Measurement of Credit Losses on Financial Instruments

Acquisitions And Divestitures (

Acquisitions And Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
Business Acquisition [Line Items]
Summary of the Gain Computation	A summary of the gain computation follows. Three Months Ended September 30, 2016 (Millions) Proceeds received, net of purchase price adjustments and selling costs $ 1,653 Asset retirement obligation assumed by purchasers 250 Total consideration received 1,903 Allocated oil and gas property basis sold 355 Allocated goodwill 197 Total assets sold 552 Gains on asset sales $ 1,351
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 in E2 (2) 18 Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests $ 1,841 Crosstex Energy, LP outstanding units: Common units held by public unitholders 75.1 Preferred units held by third party (3) 17.1 Restricted units 0.4 Total 92.6 Crosstex Energy, LP common unit price (4) $ 30.51 Crosstex Energy, LP common units value $ 2,825 Crosstex Energy, LP outstanding unit options value 4 Total fair value of noncontrolling interests in the Crosstex Energy, LP (4) 2,829 Total consideration and fair value of noncontrolling interests $ 4,670 (1) The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014. (2) Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2. (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 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 purchase price $ 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.
General Partner and EnLink and GeoSouthern [Member]
Business Acquisition [Line Items]
Schedule Of Unaudited Pro Forma Information For General Partner and EnLink And GeoSouthern	The following unaudited pro forma financial information has been prepared assuming both the EnLink formation and the GeoSouthern acquisition occurred on January 1, 2014. 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 (Millions) Total operating revenues $ 20,213 Net earnings $ 1,716 Noncontrolling interests $ 97 Net earnings attributable to Devon $ 1,619 Net earnings per common share attributable to Devon $ 3.94
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 2015 LPC $ 108 — $ 30 $ 30 $ 43 $ 5 March 2015 Coronado $ 240 $ 360 $ 302 $ 18 $ 281 $ (1 ) October 2015 Matador $ 141 — $ 36 $ 11 $ 99 $ (5)

Derivative Financial Instrume32

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative [Line Items]
Schedule Of Derivative Financial Instruments Included In Consolidated Comprehensive 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, 2016 2015 2014 Commodity derivatives: (Millions) Oil, gas and NGL derivatives $ (201 ) $ 503 $ 1,989 Marketing and midstream revenues (13 ) 9 22 Interest rate derivatives: Other nonoperating items (19 ) (20 ) (1 ) Foreign currency derivatives: Other nonoperating items (153 ) 246 60 Net gains (losses) recognized $ (386 ) $ 738 $ 2,070 The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2016 December 31, 2015 (Millions) Commodity derivative assets: Other current assets $ 9 $ 34 Other long-term assets 1 1 Interest rate derivative assets: Other current assets 1 1 Other long-term assets — 1 Foreign currency derivative assets: Other current assets — 8 Total derivative assets $ 11 $ 45 Commodity derivative liabilities: Other current liabilities $ 187 $ 14 Other long-term liabilities 16 4 Interest rate derivative liabilities: Other long-term liabilities 41 22 Foreign currency derivative liabilities: Other current liabilities — 8 Total derivative liabilities $ 244 $ 48
Interest Rate Derivatives [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Notional Rate Received Rate Paid Expiration (Millions) $ 750 Three Month LIBOR 2.98% December 2048 (1) $ 100 1.76% Three Month LIBOR January 2019 (1) Mandatory settlement in December 2018.
Open Oil Derivative Positions [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Price Swaps Price Collars Period Volume (Bbls/d) Weighted Average Price ($/Bbl) Volume (Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2017 72,527 $ 54.32 53,245 $ 45.16 $ 57.97 Q1-Q4 2018 2,600 $ 53.38 6,189 $ 46.97 $ 56.97 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2017 Midland Sweet 10,000 $ (0.43 )
Open Natural Gas Derivative Positions [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Price Swaps Price Collars Period Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Volume (MMBtu/d) Weighted Average Floor Price ($/MMBtu) Weighted Average Ceiling Price ($/MMBtu) Q1-Q4 2017 189,753 $ 3.13 335,274 $ 2.97 $ 3.38 Q1-Q4 2018 29,705 $ 3.17 19,110 $ 3.20 $ 3.50 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2017 Panhandle Eastern Pipe Line 150,000 $ (0.34 ) Q1-Q4 2017 El Paso Natural Gas 80,000 $ (0.13 ) Q1-Q4 2017 Houston Ship Channel 35,000 $ 0.06 Q1-Q4 2017 Transco Zone 4 205,000 $ 0.03 Q1 2018 Panhandle Eastern Pipe Line 50,000 $ (0.29 )
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 2017-Q4 2017 Propane 434 MBbls Index $0.55/gal Q1 2017-Q4 2017 Normal Butane 161 MBbls Index $0.70/gal Q1 2017-Q4 2017 Natural Gas 21,685 MMBtu/d Index $3.14/MMbtu

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule Of The Effects Of Share-Based Compensation Included In The Consolidated Comprehensive Statements Of Earnings	Year Ended December 31, 2016 2015 2014 (Millions) Gross G&A for share-based compensation $ 154 $ 225 $ 199 Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties $ 39 $ 63 $ 53 Related income tax benefit $ 4 $ 45 $ 42
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 12/31/15 4,738 $ 62.49 434 $ 60.48 1,859 $ 76.17 Granted 4,390 $ 19.91 330 $ 19.22 1,388 $ 10.41 Vested (2,473 ) $ 61.44 (179 ) $ 59.10 (602 ) $ 63.37 Forfeited (248 ) $ 44.38 — $ — (41 ) $ 43.88 Unvested at 12/31/16 6,407 $ 34.40 585 $ 37.60 2,604 (1 ) $ 46.66 (1) A maximum of 5.2 million common shares could be awarded based upon Devon’s final TSR ranking.
Schedule Of Aggregate Fair Value Of Restricted Stock, Performance-Based Restricted Stock And Performance Shares, Awards And Units, That Vested During The Period	2016 2015 2014 (Millions) Restricted Stock Awards and Units $ 73 $ 101 $ 112 Performance-Based Restricted Stock Awards $ 5 $ 8 $ 10 Performance Share Units $ 13 $ 22 $ —
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) $ 131 $ 5 $ 21 Weighted average period for recognition (years) 2.3 2.2 1.6
Summary Of Performance Share Units Grant-Date Fair Values And Their Related Assumptions	2016 2015 2014 Grant-date fair value $ 9.24 — $ 10.61 $ 81.99 — $ 85.05 $ 70.18 — $ 81.05 Risk-free interest rate 0.94% 1.06% 0.54% Volatility factor 37.7% 26.2% 28.8% Contractual term (years) 2.83 2.89 2.89
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, 2015 3,448 $ 67.98 Expired (916 ) $ 67.75 Outstanding at December 31, 2016 2,532 $ 68.06 1.87 $ — Vested and expected to vest at December 31, 2016 2,532 $ 68.06 1.87 $ — Exercisable at December 31, 2016 2,532 $ 68.06 1.87 $ —
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) $ 14 $ 4 $ 14 $ 4 Weighted average period for recognition (years) 1.6 1.8 1.7 1.8

Asset Impairments (Tables)

Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Impairment Charges [Abstract]
Components of Asset Impairments	The following table presents the asset impairments recognized in 2016, 2015 and 2014. Year Ended December 31, 2016 2015 2014 (Millions) U.S. oil and gas assets $ 2,809 $ 17,992 $ — Canada oil and gas assets 1,291 1,257 — Canada goodwill — — 1,941 EnLink goodwill 873 1,328 — EnLink other intangible assets — 223 — Other assets 2 20 12 Total asset impairments $ 4,975 $ 20,820 $ 1,953

Restructuring And Transaction35

Restructuring And Transaction Costs (Tables)	12 Months Ended
	Dec. 31, 2016
Restructuring And Related Activities [Abstract]
Schedule Of The Activity And Balances Associated With Restructuring Liabilities	Other Other Current Long-term Liabilities Liabilities Total (Millions) Balance as of December 31, 2014 $ 13 $ 7 $ 20 Changes related to prior years' restructurings — 56 56 Balance as of December 31, 2015 $ 13 $ 63 $ 76 Changes due to 2016 workforce reductions 29 6 35 Changes related to prior years' restructurings 6 (7 ) (1 ) Balance as of December 31, 2016 $ 48 $ 62 $ 110
Schedule Of The Components Of Restructuring And Transaction Costs Included In The Consolidated Comprehensive Statements Of Earnings	Year Ended December 31, 2016 (Millions) 2016 reduction in workforce: Employee related costs $ 227 Lease obligations 20 Asset impairments 3 Transaction costs 17 Restructuring and transaction costs $ 267

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule Of Income Tax Expense (Benefit)	Year Ended December 31, 2016 2015 2014 (Millions) Current income tax expense (benefit): U.S. federal $ 5 $ (243 ) $ 152 Various states (11 ) (8 ) 18 Canada and various provinces 106 14 307 Total current tax expense (benefit) 100 (237 ) 477 Deferred income tax expense (benefit): U.S. federal (3 ) (5,033 ) 1,610 Various states — (336 ) 93 Canada and various provinces (270 ) (459 ) 188 Total deferred tax expense (benefit) (273 ) (5,828 ) 1,891 Total income tax expense (benefit) $ (173 ) $ (6,065 ) $ 2,368
Schedule Of Effective Income Tax Rate Reconciliation	Year Ended December 31, 2016 2015 2014 (Millions) Total income tax expense (benefit) $ (173 ) $ (6,065 ) $ 2,368 U.S. statutory income tax rate 35 % 35 % 35 % Deferred tax asset valuation allowance (22 %) (4 %) 0 % Non-deductible goodwill and intangible impairment (8 %) (2 %) 23 % Change in unrecognized tax benefits (2 %) 0 % 1 % Taxation on Canadian operations (3 %) (1 %) (4 %) State income taxes 1 % 1 % 2 % Other 3 % 0 % 1 % Effective income tax rate 4 % 29 % 58 %
Schedule Of Deferred Tax Assets And Liabilities	December 31, 2016 2015 (Millions) Deferred tax assets: Property and equipment $ 685 $ 490 Asset retirement obligations 488 485 Accrued liabilities 130 160 Net operating loss carryforwards 777 175 Pension benefit obligations 98 106 Other 203 162 Total deferred tax assets before valuation allowance 2,381 1,578 Less: valuation allowance (1,666 ) (967 ) Net deferred tax assets 715 611 Deferred tax liabilities: Property and equipment (884 ) (1,187 ) Long-term debt (53 ) (36 ) Other (426 ) (271 ) Total deferred tax liabilities (1,363 ) (1,494 ) Net deferred tax liability $ (648 ) $ (883 )
Schedule Of Changes In Unrecognized Tax Benefits	December 31, 2016 2015 (Millions) Balance at beginning of year $ 131 $ 241 Tax positions taken in prior periods 36 (19 ) Tax positions taken in current year — 31 Accrual of interest related to tax positions taken 39 (5 ) Settlements — (108 ) Lapse of statute of limitations (5 ) — Foreign currency translation 1 (9 ) Balance at end of year $ 202 $ 131
Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities	Jurisdiction Tax Years Open U.S. Federal 2012-2016 Various U.S. states 2010-2016 Canada Federal 2003-2016 Various Canadian provinces 2003-2016

Net Earnings (Loss) Per Share37

Net Earnings (Loss) Per Share Attributable To Devon (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Earnings (Loss) Per Share Computations	Year Ended December 31, 2016 2015 2014 (Millions, except per share amounts) Net earnings (loss): Net earnings (loss) attributable to Devon $ (3,302 ) $ (14,454 ) $ 1,607 Attributable to participating securities (2 ) (5 ) (17 ) Basic and diluted earnings (loss) $ (3,304 ) $ (14,459 ) $ 1,590 Common shares: Common shares outstanding - total 513 412 409 Attributable to participating securities (6 ) (5 ) (4 ) Common shares outstanding - basic 507 407 405 Dilutive effect of potential common shares issuable — — 2 Common shares outstanding - diluted 507 407 407 Net earnings (loss) per share attributable to Devon: Basic $ (6.52 ) $ (35.55 ) $ 3.93 Diluted $ (6.52 ) $ (35.55 ) $ 3.91 Antidilutive options (1) 3 4 3 (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, 2016
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease [Abstract]
Components Of Other Comprehensive Earnings	Year Ended December 31, 2016 2015 2014 (Millions) Foreign currency translation: Beginning accumulated foreign currency translation $ 424 $ 983 $ 1,448 Change in cumulative translation adjustment 45 (621 ) (499 ) Income tax benefit (expense) (13 ) 62 34 Ending accumulated foreign currency translation 456 424 983 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (194 ) (204 ) (180 ) Net actuarial loss and prior service cost arising in current year (28 ) (5 ) (57 ) Recognition of net actuarial loss and prior service cost in earnings (1) 26 21 20 Curtailment and settlement of pension benefits 24 — — Income tax benefit (expense) — (6 ) 13 Ending accumulated pension and postretirement benefits (172 ) (194 ) (204 ) Accumulated other comprehensive earnings, net of tax $ 284 $ 230 $ 779 (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 16 for additional details.

Supplemental Information To S39

Supplemental Information To Statements Of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Schedule Of Supplemental Information To Statements Of Cash Flows	Year Ended December 31, 2016 2015 2014 (Millions) Net change in working capital accounts, net of assets and liabilities assumed: Accounts receivable $ (176 ) $ 942 $ 128 Income taxes receivable 130 384 (467 ) Other current assets 215 (57 ) (222 ) Accounts payable (167 ) (190 ) (68 ) Revenues and royalties payable 96 (526 ) 133 Other current liabilities (106 ) (864 ) 546 Net change in working capital $ (8 ) $ (311 ) $ 50 Interest paid (net of capitalized interest) $ 566 $ 494 $ 514 Income taxes paid (received) $ (159 ) $ (279 ) $ 899

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2016
Accounts Receivable Net [Abstract]
Schedule Of Components Of Accounts Receivable	Components of accounts receivable include the following: December 31, 2016 December 31, 2015 (Millions) Oil, gas and NGL sales $ 487 $ 362 Joint interest billings 110 211 Marketing and midstream revenues 708 520 Other 69 30 Gross accounts receivable 1,374 1,123 Allowance for doubtful accounts (18 ) (18 ) Net accounts receivable $ 1,356 $ 1,105

Goodwill And Other Intangible41

Goodwill And Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2016
Summary Of Goodwill	U.S. EnLink Total (Millions) 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 Acquired during period — 2 2 Asset divestitures (197 ) — (197 ) Impairment — (873 ) (873 ) Balance as of December 31, 2016 $ 2,421 $ 1,543 $ 3,964
Schedule Of Other Intangible Assets	December 31, 2016 December 31, 2015 (Millions) Customer relationships $ 1,796 $ 745 Accumulated amortization (172 ) (55 ) Net intangibles $ 1,624 $ 690
General Partner And EnLink [Member]
Summary Of Goodwill	Texas Louisiana Oklahoma Crude and Condensate General Partner Total (Millions) 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 during period 2 — — — — 2 Impairment (473 ) — — (93 ) (307 ) (873 ) Balance as of December 31, 2016 $ 233 $ — $ 190 $ — $ 1,120 $ 1,543

Other Current Liabilities (Tabl

Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
Schedule Of Other Current Liabilities	December 31, 2016 December 31, 2015 (Millions) Installment payment - see Note 2 $ 249 $ — Derivative liabilities 187 22 Accrued interest payable 130 149 Restructuring liabilities 48 13 Other 452 466 Other current liabilities $ 1,066 $ 650

Debt And Related Expenses (Tabl

Debt And Related Expenses (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule Of Debt Instruments and Balances	December 31, 2016 December 31, 2015 (Millions) Devon debt: Commercial paper $ — $ 626 Floating rate due December 15, 2016 — 350 8.25% due July 1, 2018 (1)(2) 20 125 2.25% due December 15, 2018 (1) 95 750 6.30% due January 15, 2019 (1) 162 700 4.00% due July 15, 2021 500 500 3.25% due May 15, 2022 1,000 1,000 5.85% due December 15, 2025 (1) 485 850 7.50% due September 15, 2027 (1)(2) 73 150 7.875% due September 30, 2031 (1)(3) 1,059 1,250 7.95% due April 15, 2032 (1) 789 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 750 750 Net discount on debentures and notes (30 ) (28 ) Debt issuance costs (44 ) (57 ) Total Devon debt 6,859 9,966 EnLink and General Partner debt: Credit facilities 148 414 2.70% due April 1, 2019 400 400 7.125% due June 1, 2022 163 163 4.40% due April 1, 2024 550 550 4.15% due June 1, 2025 750 750 4.85% due July 15, 2026 500 — 5.60% due April 1, 2044 350 350 5.05% due April 1, 2045 450 450 Net premium on debentures and notes 9 13 Debt issuance costs (25 ) (24 ) Total EnLink and General Partner debt 3,295 3,066 Total debt 10,154 13,032 Less amount classified as short-term debt (4) — 976 Total long-term debt $ 10,154 $ 12,056 (1) These senior notes were included in 2016 tender offer redemptions discussed below. (2) These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively. (3) Issued in October 2001, these are unsecured and unsubordinated obligations of Devon Financing, a wholly owned finance subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. (4) 2015 short-term debt consists of commercial paper balances and floating rate debt that was retired upon maturity in December 2016.
Schedule of Debt Maturities	2017 $ — 2018 115 2019 590 2020 120 2021 500 Thereafter 8,919 Total $ 10,244
Schedule Of Net Financing Cost Components	Year Ended December 31, 2016 2015 2014 (Millions) Devon net financing costs: Interest based on debt outstanding $ 488 $ 450 $ 468 Early retirement of debt 269 — 48 Capitalized interest (64 ) (54 ) (58 ) Other 21 14 15 Total Devon net financing costs 714 410 473 EnLink net financing costs: Interest based on debt outstanding 144 115 64 Interest accretion on deferred installment payment 52 — — Other (6 ) (8 ) (11 ) Total EnLink net financing costs 190 107 53 Total net financing costs $ 904 $ 517 $ 526

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Summary Of Changes In Asset Retirement Obligations	Year Ended December 31, 2016 2015 (Millions) Asset retirement obligations as of beginning of period $ 1,414 $ 1,399 Liabilities incurred and assumed through acquisitions 27 63 Liabilities settled and divested (324 ) (89 ) Revision of estimated obligation 66 62 Accretion expense on discounted obligation 75 75 Foreign currency translation adjustment 14 (96 ) Asset retirement obligations as of end of period 1,272 1,414 Less current portion 46 44 Asset retirement obligations, long-term $ 1,226 $ 1,370

Retirement Plans (Tables)

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Compensation And Retirement Disclosure [Abstract]
Schedule Of Changes In Defined Benefit Plan Obligations	Pension Benefits Postretirement Benefits 2016 2015 2016 2015 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,308 $ 1,377 $ 23 $ 24 Service cost 15 33 — 1 Interest cost 42 52 1 1 Actuarial loss (gain) 63 (68 ) (1 ) (2 ) Plan amendments 2 — — 1 Plan curtailments (31 ) — — — Plan settlements (94 ) — — — Foreign exchange rate changes 1 (6 ) — — Participant contributions — — — 2 Benefits paid (57 ) (80 ) (2 ) (4 ) Benefit obligation at end of year 1,249 1,308 21 23 Change in plan assets: Fair value of plan assets at beginning of year 1,059 1,149 — — Actual return on plan assets 61 (16 ) — — Employer contributions 16 11 2 2 Participant contributions — — — 2 Plan settlements (94 ) — — — Benefits paid (57 ) (80 ) (2 ) (4 ) Foreign exchange rate changes — (5 ) — — Fair value of plan assets at end of year 985 1,059 — — Funded status at end of year $ (264 ) $ (249 ) $ (21 ) $ (23 ) Amounts recognized in balance sheet: Other long-term assets $ 3 $ 2 $ — $ — Other current liabilities (13 ) (12 ) (3 ) (3 ) Other long-term liabilities (254 ) (239 ) (18 ) (20 ) Net amount $ (264 ) $ (249 ) $ (21 ) $ (23 ) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 285 $ 302 $ (11 ) $ (11 ) Prior service cost (credit) 8 14 (5 ) (6 ) Total $ 293 $ 316 $ (16 ) $ (17 )
Schedule Of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Postretirement Benefit Plans	Pension Benefits Postretirement Benefits 2016 2015 2014 2016 2015 2014 (Millions) Net periodic benefit cost: Service cost $ 15 $ 33 $ 30 $ — $ 1 $ 1 Interest cost 42 52 55 1 1 1 Expected return on plan assets (55 ) (58 ) (54 ) — — — Curtailment and settlement expense — — 1 — — — Recognition of net actuarial loss (gain) (1) 25 20 18 (1 ) (1 ) (1 ) Recognition of prior service cost (1) 3 4 4 (1 ) (2 ) (2 ) Total net periodic benefit cost (2) 30 51 54 (1 ) (1 ) (1 ) Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 26 5 57 — (1 ) — Prior service cost (credit) arising in current year 2 — — — 1 — Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost (3) (43 ) (20 ) (19 ) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) (9 ) (4 ) (4 ) 1 1 2 Total other comprehensive loss (earnings) (24 ) (19 ) 34 2 2 3 Total recognized $ 6 $ 32 $ 88 $ 1 $ 1 $ 2 (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. (3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in the current period. See Note 6 for further discussion.
Schedule Of Weighted Average Actuarial Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Costs	Pension Benefits Postretirement Benefits 2016 2015 2014 2016 2015 2014 Assumptions to determine benefit obligations: Discount rate 4.07% 4.25% 3.90% 3.46% 3.63% 3.25% Rate of compensation increase 4.49% 4.49% 4.49% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate 4.39% 3.90% 4.80% 3.63% 3.25% 3.65% Rate of compensation increase 4.49% 4.49% 4.49% N/A N/A N/A Expected return on plan assets 5.20% 5.22% 5.42% N/A N/A N/A
Schedule Of Fair Value of Pension Assets By Asset Class	As of December 31, 2016 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 % $ 343 $ 68 $ 275 $ — Corporate bonds 30 % 297 205 92 — Other bonds 4 % 38 38 — — Total fixed-income securities 69 % 678 311 367 — Equity securities: Global (large, mid, small cap) 17 % 171 — 171 — Other securities: Hedge fund and alternative investments 11 % 112 — — 112 Short-term investments 3 % 24 8 16 — Total other securities 14 % 136 8 16 112 Total investments 100 % $ 985 $ 319 $ 554 $ 112 As of 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
Schedule of Changes In Level 3 Plan Assets	December 31, 2014 $ 112 Purchases 5 Investment returns 3 December 31, 2015 120 Investments sold (12 ) Investment returns 4 December 31, 2016 $ 112
Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans	Pension Benefits Postretirement Benefits (Millions) 2017 $ 60 $ 3 2018 $ 61 $ 3 2019 $ 62 $ 3 2020 $ 64 $ 2 2021 $ 67 $ 2 2022 to 2026 $ 374 $ 7
Schedule Of Expense Related To These Defined Contribution Plans	Year Ended December 31, 2016 2015 2014 (Millions) 401(k) and enhanced contribution plans $ 53 $ 63 $ 49 Canadian pension and savings plans 11 16 20 Total $ 64 $ 79 $ 69

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Stockholders Equity Note [Abstract]
Summary Of Dividends Paid On Common Stock	Amounts Rate (Millions) (Per Share) Year Ended 2016: First quarter 2016 $ 125 $ 0.24 Second quarter 2016 33 $ 0.06 Third quarter 2016 32 $ 0.06 Fourth quarter 2016 31 $ 0.06 Total year-to-date $ 221 Year Ended 2015: First quarter 2015 $ 99 $ 0.24 Second quarter 2015 98 $ 0.24 Third quarter 2015 99 $ 0.24 Fourth quarter 2015 100 $ 0.24 Total year-to-date $ 396 Year Ended 2014: First quarter 2014 $ 90 $ 0.22 Second quarter 2014 99 $ 0.24 Third quarter 2014 98 $ 0.24 Fourth quarter 2014 99 $ 0.24 Total year-to-date $ 386

Noncontrolling Interests (Table

Noncontrolling Interests (Tables)	12 Months Ended
	Dec. 31, 2016
Noncontrolling Interest [Abstract]
Summary of Ownership Interest Activity	EnLink General Partner Ownership interest as of Devon Non-Devon Unitholders General Partner Devon Non-Devon Unitholders March 7, 2014 52% 41% 7% 70% 30% December 31, 2014 49% 43% 8% 70% 30% December 31, 2015 28% 45% 27% 70% 30% December 31, 2016 24% 53% 23% 64% 36%

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Schedule Of Commitments And Contingencies	Year Ending December 31, Purchase Obligations Drilling and Facility Obligations Operational Agreements Office and Equipment Leases EnLink Obligations (Millions) 2017 $ 609 $ 76 $ 1,145 $ 50 $ 50 2018 649 66 1,134 85 51 2019 762 67 627 83 33 2020 748 57 457 59 18 2021 181 37 285 39 17 Thereafter — 85 2,667 55 102 Total $ 2,949 $ 388 $ 6,315 $ 371 $ 271

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [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 Amount Value Inputs Inputs (Millions) December 31, 2016 assets (liabilities): Cash equivalents $ 1,542 $ 1,542 $ 1,298 $ 244 Commodity derivatives $ 10 $ 10 $ — $ 10 Commodity derivatives $ (203 ) $ (203 ) $ — $ (203 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (41 ) $ (41 ) $ — $ (41 ) Debt $ (10,154 ) $ (10,760 ) $ — $ (10,760 ) Installment payment $ (473 ) $ (477 ) $ — $ (477 ) Capital lease obligations $ (7 ) $ (6 ) $ — $ (6 ) 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 $ (13,032 ) $ (11,927 ) $ — $ (11,927 ) Capital lease obligations $ (17 ) $ (16 ) $ — $ (16 )

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [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, 2016: Revenues from external customers $ 5,722 $ 1,031 $ 3,551 $ — $ 10,304 Asset dispositions and other $ 1,367 $ 542 $ (16) $ — $ 1,893 Intersegment revenues $ — $ — $ 701 $ (701 ) $ — Depreciation, depletion and amortization $ 928 $ 360 $ 504 $ — $ 1,792 Asset impairments $ 2,809 $ 1,293 $ 873 $ — $ 4,975 Restructuring and transaction costs $ 242 $ 19 $ 6 $ — $ 267 Interest expense $ 624 $ 181 $ 190 $ (84 ) $ 911 Loss before income taxes $ (2,051 ) $ (942 ) $ (884 ) $ — $ (3,877 ) Income tax benefit $ (8 ) $ (165 ) $ — $ — $ (173 ) Net loss $ (2,043 ) $ (777 ) $ (884 ) $ — $ (3,704 ) Net earnings (loss) attributable to noncontrolling interests $ 1 $ — $ (403 ) $ — $ (402 ) Net loss attributable to Devon $ (2,044 ) $ (777 ) $ (481 ) $ — $ (3,302 ) Property and equipment, net $ 7,358 $ 2,575 $ 6,257 $ — $ 16,190 Total assets $ 12,163 $ 3,536 $ 10,276 $ (62 ) $ 25,913 Capital expenditures, including acquisitions $ 2,880 $ 229 $ 1,082 $ — $ 4,191 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 Restructuring and transaction costs $ 54 $ 24 $ — $ — $ 78 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 $ 14,550 $ 5,457 $ 9,541 $ (97 ) $ 29,451 Capital expenditures, including acquisitions $ 4,575 $ 680 $ 978 $ — $ 6,233 Year Ended December 31, 2014: Revenues from external customers $ 14,854 $ 2,063 $ 2,649 $ — $ 19,566 Asset dispositions and other $ (5 ) $ 1,077 $ — $ — $ 1,072 Intersegment revenues $ — $ — $ 859 $ (859 ) $ — Depreciation, depletion and amortization $ 2,475 $ 560 $ 284 $ — $ 3,319 Asset impairments $ 12 $ 1,941 $ — $ — $ 1,953 Restructuring and transaction costs $ — $ 46 $ — $ — $ 46 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 $ 31,994 $ 8,509 $ 10,189 $ (124 ) $ 50,568 Capital expenditures, including acquisitions $ 11,214 $ 1,344 $ 1,001 $ — $ 13,559 (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 O51

Supplemental Information On Oil And Gas Operations (Tables)	12 Months Ended
	Dec. 31, 2016
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Costs Incurred	Year Ended December 31, 2016 U.S. Canada Total (Millions) Property acquisition costs: Proved properties $ 237 $ — $ 237 Unproved properties 1,356 2 1,358 Exploration costs 345 49 394 Development costs 1,034 109 1,143 Costs incurred $ 2,972 $ 160 $ 3,132 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
Capitalized Costs	December 31, 2016 U.S. Canada Total (Millions) Proved properties $ 61,401 $ 14,247 $ 75,648 Unproved properties 2,092 1,345 3,437 Total oil and gas properties 63,493 15,592 79,085 Accumulated DD&A (57,323 ) (13,107 ) (70,430 ) Net capitalized costs $ 6,170 $ 2,485 $ 8,655 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
Oil And Gas Properties Not Subject To Amortization	Costs Incurred In 2016 2015 2014 Prior to 2014 Total (Millions) Acquisition costs $ 1,176 $ 579 $ 246 $ 464 $ 2,465 Exploration costs 107 134 89 206 536 Development costs 12 — 23 150 185 Capitalized interest 63 52 37 99 251 Total oil and gas properties not subject to amortization $ 1,358 $ 765 $ 395 $ 919 $ 3,437
Results Of Operations	December 31, 2016 U.S. Canada Total (Millions) Oil, gas and NGL sales $ 3,198 $ 984 $ 4,182 Lease operating expenses (1,123 ) (459 ) (1,582 ) General and administrative expenses (148 ) (20 ) (168 ) Production and property taxes (200 ) (31 ) (231 ) Depreciation, depletion and amortization (817 ) (326 ) (1,143 ) Gains on asset sales 1,351 — 1,351 Asset impairments (2,809 ) (1,291 ) (4,100 ) Accretion of asset retirement obligations (49 ) (25 ) (74 ) Income tax benefit — 245 245 Results of operations $ (597 ) $ (923 ) $ (1,520 ) Depreciation, depletion and amortization per Boe $ 4.68 $ 6.65 $ 5.11 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 ) Gains on asset sales — 1,077 1,077 Accretion of asset retirement obligations (49 ) (39 ) (88 ) Income tax expense (1,199 ) (568 ) (1,767 ) Results of operations (1) $ 2,076 $ 1,115 $ 3,191 Depreciation, depletion and amortization per Boe $ 11.41 $ 13.80 $ 11.79 (1) 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, 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 Revisions due to prices (18 ) (2 ) (20 ) Revisions other than price (2 ) 3 1 Extensions and discoveries 36 2 38 Purchase of reserves 8 — 8 Production (47 ) (8 ) (55 ) Sale of reserves (25 ) — (25 ) December 31, 2016 194 17 211 Proved developed reserves as of: December 31, 2013 194 56 250 December 31, 2014 255 23 278 December 31, 2015 203 22 225 December 31, 2016 160 17 177 Proved developed-producing reserves as of: December 31, 2013 178 51 229 December 31, 2014 224 19 243 December 31, 2015 192 19 211 December 31, 2016 143 13 156 Proved undeveloped reserves as of: December 31, 2013 35 — 35 December 31, 2014 96 — 96 December 31, 2015 39 — 39 December 31, 2016 34 — 34 Bitumen (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices — 23 23 Revisions other than price — (19 ) (19 ) Production — (40 ) (40 ) December 31, 2016 — 484 484 Proved developed reserves as of: December 31, 2013 — 111 111 December 31, 2014 — 137 137 December 31, 2015 — 219 219 December 31, 2016 — 190 190 Proved developed-producing reserves as of: December 31, 2013 — 111 111 December 31, 2014 — 137 137 December 31, 2015 — 219 219 December 31, 2016 — 190 190 Proved undeveloped reserves as of: December 31, 2013 — 441 441 December 31, 2014 — 384 384 December 31, 2015 — 301 301 December 31, 2016 — 294 294 Gas (Bcf) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices (103 ) — (103 ) Revisions other than price 628 10 638 Extensions and discoveries 280 — 280 Purchase of reserves 33 — 33 Production (510 ) (7 ) (517 ) Sale of reserves (521 ) — (521 ) December 31, 2016 5,615 16 5,631 Proved developed reserves as of: December 31, 2013 7,707 752 8,459 December 31, 2014 6,948 36 6,984 December 31, 2015 5,694 13 5,707 December 31, 2016 5,361 16 5,377 Proved developed-producing reserves as of: December 31, 2013 7,425 680 8,105 December 31, 2014 6,746 34 6,780 December 31, 2015 5,546 13 5,559 December 31, 2016 5,243 16 5,259 Proved undeveloped reserves as of: December 31, 2013 843 6 849 December 31, 2014 703 — 703 December 31, 2015 114 — 114 December 31, 2016 254 — 254 Natural Gas Liquids (MMBbls) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices (13 ) — (13 ) Revisions other than price 48 — 48 Extensions and discoveries 42 — 42 Purchase of reserves 7 — 7 Production (42 ) — (42 ) Sale of reserves (45 ) — (45 ) December 31, 2016 425 — 425 Proved developed reserves as of: December 31, 2013 468 23 491 December 31, 2014 486 — 486 December 31, 2015 411 — 411 December 31, 2016 387 — 387 Proved developed-producing reserves as of: December 31, 2013 442 21 463 December 31, 2014 467 — 467 December 31, 2015 393 — 393 December 31, 2016 370 — 370 Proved undeveloped reserves as of: December 31, 2013 84 — 84 December 31, 2014 92 — 92 December 31, 2015 17 — 17 December 31, 2016 38 — 38 Total (MMBoe) (1) U.S. Canada Total Proved developed and undeveloped reserves: 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 Revisions due to prices (48 ) 21 (27 ) Revisions other than price 151 (14 ) 137 Extensions and discoveries 124 2 126 Purchase of reserves 20 — 20 Production (174 ) (49 ) (223 ) Sale of reserves (157 ) — (157 ) December 31, 2016 1,554 504 2,058 Proved developed reserves as of: December 31, 2013 1,947 315 2,262 December 31, 2014 1,900 165 2,065 December 31, 2015 1,563 243 1,806 December 31, 2016 1,439 210 1,649 Proved developed-producing reserves as of: December 31, 2013 1,857 297 2,154 December 31, 2014 1,815 162 1,977 December 31, 2015 1,509 240 1,749 December 31, 2016 1,386 207 1,593 Proved undeveloped reserves as of: December 31, 2013 258 443 701 December 31, 2014 305 384 689 December 31, 2015 75 301 376 December 31, 2016 115 294 409 (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, 2015 75 301 376 Extensions and discoveries 78 — 78 Revisions due to prices (8 ) 10 2 Revisions other than price (1 ) (4 ) (5 ) Sale of reserves (1 ) — (1 ) Conversion to proved developed reserves (28 ) (13 ) (41 ) Proved undeveloped reserves as of December 31, 2016 115 294 409
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended December 31, 2016 U.S. Canada Total (Millions) Future cash inflows $ 22,847 $ 9,672 $ 32,519 Future costs: Development (2,784 ) (2,201 ) (4,985 ) Production (14,484 ) (6,287 ) (20,771 ) Future income tax expense — (57 ) (57 ) Future net cash flow 5,579 1,127 6,706 10% discount to reflect timing of cash flows (2,128 ) (380 ) (2,508 ) Standardized measure of discounted future net cash flows $ 3,451 $ 747 $ 4,198 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
Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves	Year Ended December 31, 2016 2015 2014 (Millions) Beginning balance $ 6,688 $ 20,474 $ 15,741 Net changes in prices and production costs (2,128 ) (20,756 ) 2,561 Oil, bitumen, gas and NGL sales, net of production costs (2,163 ) (2,704 ) (6,865 ) Changes in estimated future development costs 112 1,313 (768 ) Extensions and discoveries, net of future development costs 660 1,129 4,836 Purchase of reserves 222 95 6,422 Sales of reserves in place (560 ) (79 ) (2,384 ) Revisions of quantity estimates (32 ) (1,451 ) (746 ) Previously estimated development costs incurred during the period 663 2,158 1,933 Accretion of discount 403 567 1,746 Foreign exchange and other 105 (1,254 ) (107 ) Net change in income taxes 228 7,196 (1,895 ) Ending balance $ 4,198 $ 6,688 $ 20,474

Supplemental Quarterly Financ52

Supplemental Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Schedule Of Unaudited Interim Results Of Operations	The following tables present a summary of Devon’s unaudited interim results of operations. 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Total revenues and other $ 2,126 $ 2,488 $ 4,233 $ 3,350 $ 12,197 Earnings (loss) before income taxes $ (3,685 ) $ (1,745 ) $ 1,178 $ 375 $ (3,877 ) Net earnings (loss) attributable to Devon $ (3,056 ) $ (1,570 ) $ 993 $ 331 $ (3,302 ) Basic net earnings (loss) per share attributable to Devon $ (6.44 ) $ (3.04 ) $ 1.90 $ 0.63 $ (6.52 ) Diluted net earnings (loss) per share attributable to Devon $ (6.44 ) $ (3.04 ) $ 1.89 $ 0.63 $ (6.52 ) 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (Millions, except per share amounts) Total revenues and other $ 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 )

Summary Of Significant Accoun53

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 31, 2017
Summary Of Significant Accounting Policies [Line Items]
Other receivables	$ 69,000,000		$ 69,000,000	$ 30,000,000
Derivative collateral held	0		0	75,000,000
Cash collateral posted	17,000,000		17,000,000
Gains on asset sales	540,000,000	$ 1,400,000,000	1,893,000,000		$ 1,072,000,000
Debt issuance costs	$ 44,000,000		44,000,000	57,000,000
Debt retirement payments			265,000,000		51,000,000
Accounting Standards Update 2015-03 [Member]
Summary Of Significant Accounting Policies [Line Items]
Debt issuance costs				81,000,000
Accounting Standards Update 2016-15 [Member]
Summary Of Significant Accounting Policies [Line Items]
Debt retirement payments			$ 265,000,000		$ 40,000,000
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Depletion calculation holding period			3 years
Other property and equipment, useful life			3 years
Finite lived intangible asset useful life			10 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Depletion calculation holding period			4 years
Other property and equipment, useful life			60 years
Finite lived intangible asset useful life			20 years
Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Cash collateral posted						$ 0
Accrued Derivative Settlements [Member]
Summary Of Significant Accounting Policies [Line Items]
Other receivables				$ 236,000,000
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%

Acquisitions And Divestitures54

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

Jan. 07, 2016USD ($)a

Dec. 17, 2015USD ($)a

Mar. 07, 2014USD ($)

Feb. 28, 2014USD ($)a

Jan. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Oct. 31, 2016USD ($)

Oct. 31, 2016CAD

May 31, 2015USD ($)

Apr. 30, 2015USD ($)

Feb. 28, 2015USD ($)

Dec. 31, 2016USD ($)

Sep. 30, 2016USD ($)MMBoe

Jun. 30, 2016USD ($)MMBoe

Dec. 31, 2016USD ($)MMBoe

Dec. 31, 2015USD ($)MMBoe

Dec. 31, 2014USD ($)MMBoe

Nov. 09, 2016

Aug. 01, 2016

Business Acquisition [Line Items]

Divestitures of property and equipment

$ 3,118

$ 107

$ 5,120

Estimated proved reserves associated with divestitures | MMBoe

[1]

157

7

383

Gains on asset sales

$ 540

$ 1,400

$ 1,893

$ 1,072

Foreign currency exchange loss

(84)

Installment Payable, Current [Member]

Business Acquisition [Line Items]

Installment payment

$ 249

249

$ 249

Foreign Currency Derivatives [Member]

Business Acquisition [Line Items]

Loss on derivative

$ 29

US [Member]

Business Acquisition [Line Items]

Estimated proved reserves associated with divestitures | MMBoe

[1]

157

7

207

Access Pipeline [Member]

Business Acquisition [Line Items]

Ownership interest

50.00%

Divestitures of property and equipment

$ 1,100

CAD 1,400

Gains on asset sales

$ 540

Divestiture agreement dedication initial term

25 years

25 years

Access Pipeline [Member] | Scenario Plan [Member]

Business Acquisition [Line Items]

Divestitures of property and equipment | CAD

CAD 150

Access Pipeline [Member] | Maximum [Member]

Business Acquisition [Line Items]

Potential pipeline capacity committed, percentage

90.00%

90.00%

Mississippian [Member]

Business Acquisition [Line Items]

Divestitures of property and equipment

$ 200

Estimated proved reserves associated with divestitures | MMBoe

11

Mississippian [Member] | US [Member] | Maximum [Member]

Business Acquisition [Line Items]

Percentage of Estimated proved reserves associated with divestiture assets

1.00%

East Texas, Anadarko Basin and Midland Basin [Member]

Business Acquisition [Line Items]

Divestitures of property and equipment

$ 1,700

Estimated proved reserves associated with divestitures | MMBoe

146

East Texas, Anadarko Basin and Midland Basin [Member] | US [Member]

Business Acquisition [Line Items]

Percentage of Estimated proved reserves associated with divestiture assets

9.00%

Oil and Gas Properties [Member]

Business Acquisition [Line Items]

Divestitures of property and equipment

$ 1,653

Gains on asset sales

$ 1,351

Canadian Conventional and U.S Assets [Member]

Business Acquisition [Line Items]

Divestitures of property and equipment

$ 5,000

Canadian Conventional Assets [Member]

Business Acquisition [Line Items]

Gains on asset sales

$ 1,100

Delaware Basin Joint Venture [Member] | EnLink [Member]

Business Acquisition [Line Items]

Joint venture formation date

Aug. 1, 2016

Ownership interest percentage acquired

50.10%

Contribution of non monetary assets and cash to joint venture

$ 251

Future capital commitments

$ 285

Call rights to acquire increasing portions of joint venture partner's interest, start year

2,021

Delaware Basin Joint Venture [Member] | EnLink [Member] | Joint Venture Partner [Member]

Business Acquisition [Line Items]

Ownership interest percentage acquired

49.90%

Future capital commitments

$ 400

Cash contribution

$ 144

STACK [Member] | EnLink [Member]

Business Acquisition [Line Items]

Joint venture formation date

Nov. 9, 2016

Ownership interest percentage acquired

30.00%

Future capital commitments

$ 40

Cash contribution

$ 29

STACK [Member] | EnLink [Member] | Joint Venture Partner [Member]

Business Acquisition [Line Items]

Ownership interest percentage acquired

70.00%

Non-Core Midstream Assets [Member] | Scenario Plan [Member] | EnLink [Member]

Business Acquisition [Line Items]

Divestitures of property and equipment

278

Victoria Express Pipeline [Member] | EnLink [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 176

Estimated construction costs assumed

$ 35

Equity Issued in Business Combination [Member] | EnLink [Member]

Business Acquisition [Line Items]

Equity units value

$ 360

STACK [Member]

Business Acquisition [Line Items]

Close date of acquisition

Jan. 7, 2016

Number of net acres acquired | a

80,000

Aggregate purchase price

$ 1,500

Cash payment to acquire interest

849

Unproved properties

1,300

1,300

$ 1,300

Proved properties

200

200

$ 200

STACK [Member] | Common Stock [Member] | Equity Issued in Business Combination [Member]

Business Acquisition [Line Items]

Equity units value

659

Powder River Basin [Member]

Business Acquisition [Line Items]

Close date of acquisition

Dec. 17, 2015

Number of net acres acquired | a

253,000

Aggregate purchase price

$ 499

Cash payment to acquire interest

300

Unproved properties

393

393

$ 393

Proved properties

106

106

$ 106

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

Business Acquisition [Line Items]

Equity units value

$ 199

$ 199

GeoSouthern Intermediate Holdings, LLC [Member]

Business Acquisition [Line Items]

Close date of acquisition

Feb. 28, 2014

Number of net acres acquired | a

82,000

Aggregate purchase price

$ 6,000

Unproved properties

1,000

1,000

$ 1,000

Proved properties

5,000

5,000

$ 5,000

Anadarko Basin [Member] | EnLink [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

1 year

Installment payable, noncurrent

250

250

$ 250

Intangible assets

1,000

1,000

1,000

Property, plant and equipment

400

400

400

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

Business Acquisition [Line Items]

Installment payment, paid

$ 250

Anadarko Basin [Member] | Installment Payable, Noncurrent [Member] | EnLink [Member]

Business Acquisition [Line Items]

Commitment to pay cash due date

24 months

Installment payable, noncurrent

$ 250

Anadarko Basin [Member] | Installment Payable, Current [Member] | Undiscounted [Member] | EnLink [Member]

Business Acquisition [Line Items]

Installment payment

$ 250

$ 250

$ 250

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

Business Acquisition [Line Items]

Equity units value

$ 215

EnLink Midstream Holdings [Member] | EnLink [Member]

Business Acquisition [Line Items]

Equity units value

$ 900

$ 925

Ownership interest percentage acquired

25.00%

25.00%

General Partner And EnLink [Member]

Business Acquisition [Line Items]

Close date of acquisition

Mar. 7, 2014

Cash payment to acquire interest

$ 100

Intangible assets

569

Property, plant and equipment

$ 2,438

[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.

Acquisitions And Divestitures55

Acquisitions And Divestitures (Summary of Gain Computation) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Divestitures of property and equipment			$ 3,118	$ 107	$ 5,120
Asset retirement obligation assumed by purchasers			324	$ 89
Allocated goodwill			197
Gains on asset sales	$ 540	$ 1,400	$ 1,893		$ 1,072
Oil and Gas Properties [Member]
Business Acquisition [Line Items]
Divestitures of property and equipment		1,653
Asset retirement obligation assumed by purchasers		250
Total consideration received		1,903
Allocated oil and gas property basis sold		355
Allocated goodwill		197
Total assets sold		552
Gains on asset sales		$ 1,351

Acquisitions And Divestitures56

Acquisitions And Divestitures (Schedule of EnLink's Acquisition Activity) (Details) - USD ($) $ in Millions	Oct. 31, 2015	Mar. 31, 2015	Jan. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Goodwill				$ 3,964	$ 5,032	$ 6,303
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	$ 141
PP&E	36
Goodwill	11
Intangibles	99
Current liabilities	$ (5)

Acquisitions And Divestitures57

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]
Fair value of noncontrolling interests | $	$ 2,829	[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
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 Divestitures58

Acquisitions And Divestitures (Schedule of Purchase Price Allocation for EnLink and General Partner) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 07, 2014
Assets acquired:
Goodwill		$ 3,964	$ 5,032	$ 6,303
General Partner And EnLink [Member]
Assets acquired:
Current assets					$ 437
Property, plant and equipment					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 purchase price					$ 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 Divestitures59

Acquisitions And Divestitures (Schedule Of Unaudited Pro Forma Information For General Partner and EnLink And GeoSouthern) (Details) - General Partner and EnLink and GeoSouthern [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2014USD ($)$ / shares
Business Acquisition [Line Items]
Total operating revenues	$ 20,213
Net earnings	1,716
Noncontrolling interests	97
Net earnings attributable to Devon	$ 1,619
Net earnings per common share attributable to Devon | $ / shares	$ 3.94

Derivative Financial Instrume60

Derivative Financial Instruments (Schedule Of Open Oil Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2016$ / bblbbl
NYMEX West Texas Intermediate Price Swaps Oil Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	72,527
Weighted Average Price Swap	54.32
NYMEX West Texas Intermediate Price Swaps Oil Q1-Q4 2018 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	2,600
Weighted Average Price Swap	53.38
NYMEX West Texas Intermediate Price Collars Oil Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	53,245
Weighted Average Floor Price	45.16
Weighted Average Ceiling Price	57.97
NYMEX West Texas Intermediate Price Collars Oil Q1-Q4 2018 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	6,189
Weighted Average Floor Price	46.97
Weighted Average Ceiling Price	56.97
Midland Sweet Basis Swaps Oil Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	10,000
Weighted Average Differential To WTI	(0.43)

Derivative Financial Instrume61

Derivative Financial Instruments (Schedule Of Open Natural Gas Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2016MMBTU$ / MMBTU
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	189,753
Weighted Average Price Swap	3.13
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2018 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	29,705
Weighted Average Price Swap	3.17
FERC Henry Hub Price Collars Natural Gas Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	335,274
Weighted Average Floor Price	2.97
Weighted Average Ceiling Price	3.38
FERC Henry Hub Price Collars Natural Gas Q1-Q4 2018 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	19,110
Weighted Average Floor Price	3.20
Weighted Average Ceiling Price	3.50
PEPL Basis Swaps Natural Gas Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	150,000
Weighted Average Differential To Henry Hub	(0.34)
El Paso Natural Gas Basis Swaps Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	80,000
Weighted Average Differential To Henry Hub	(0.13)
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	35,000
Weighted Average Differential To Henry Hub	0.06
Transco Zone 4 Natural Gas Basis Swaps Q1-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	205,000
Weighted Average Differential To Henry Hub	0.03
PEPL Basis Swaps Natural Gas Q1 2018 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	50,000
Weighted Average Differential To Henry Hub	(0.29)

Derivative Financial Instrume62

Derivative Financial Instruments (Schedule Of Gas Processing and Fractionation Open Positions) (Details) - EnLink [Member]	12 Months Ended
	Dec. 31, 2016MMBTU$ / MMBTU$ / galMBbls
OPIS Mont Belvieu Texas Propane Basis Swap Q1 2017-Q4 2017 [Member]
Derivative [Line Items]
Volume (MBbls) | MBbls	434
Weighted average price paid	Index
Weighted average price received | $ / gal	0.55
OPIS Mont Belvieu Texas Normal Butane Basis Swap Q1 2017-Q4 2017 [Member]
Derivative [Line Items]
Volume (MBbls) | MBbls	161
Weighted average price paid	Index
Weighted average price received | $ / gal	0.70
Henry Hub Natural Gas Basis Swap Q1 2017-Q4 2017 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	21,685
Weighted average price paid	Index
Weighted average price received, $/MMBtu | $ / MMBTU	3.14

Derivative Financial Instrume63

Derivative Financial Instruments (Schedule Of Open Interest Rate Swap Derivative Positions) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
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]
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
[1]	Mandatory settlement in December 2018.

Derivative Financial Instrume64

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	$ (386)	$ 738	$ 2,070
Commodity Derivatives [Member] | Oil, Gas And NGL Derivatives [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	(201)	503	1,989
Commodity Derivatives [Member] | Marketing And Midstream Revenues [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	(13)	9	22
Interest Rate Derivatives [Member] | Other Nonoperating Items [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	(19)	(20)	(1)
Foreign Currency Derivatives [Member] | Other Nonoperating Items [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	$ (153)	$ 246	$ 60

Derivative Financial Instrume65

Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Fair value of derivative assets	$ 11	$ 45
Fair value of derivative liabilities	244	48
Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities	187	22
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative assets	9	34
Commodity Derivatives [Member] | Other Long-Term Assets [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative assets	1	1
Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities	187	14
Commodity Derivatives [Member] | Other Long-Term Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities	16	4
Interest Rate Derivatives [Member] | Other Current Assets [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 Long-Term Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities	$ 41	22
Foreign Currency Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative assets		8
Foreign Currency Derivatives [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities		$ 8

Share-Based Compensation (Narra

Share-Based Compensation (Narrative) (Details)	3 Months Ended	12 Months Ended
	Jun. 30, 2015shares	Dec. 31, 2016USD ($)Companyshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation		$ 154,000,000	$ 225,000,000	$ 199,000,000
Stock options granted | shares		0	0	0
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 | Company		14
Comparison period of peer companies for performance awards		3 years
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration duration of options		8 years
Aggregate intrinsic value			$ 200,000	$ 9,000,000
Unrecognized compensation cost		$ 0
Minimum [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		1 year
Minimum [Member] | Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		1 year
Minimum [Member] | Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of vesting units to units granted		0.00%
Minimum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		1 year
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]
Percentage of vesting units to units granted		200.00%
Maximum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		4 years
Reduction of workforce [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense associated with accelerated awards		$ 60,000,000
Canadian Divestitures [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense associated with accelerated awards				15,000,000
EnLink [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation		$ 24,000,000	$ 31,000,000	$ 17,000,000
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

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation [Abstract]
Gross G&A for share-based compensation	$ 154	$ 225	$ 199
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	39	63	53
Related income tax benefit	$ 4	$ 45	$ 42

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 in Thousands	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2015 | shares	4,738
Granted, awards and units | shares	4,390
Vested, awards and units | shares	(2,473)
Forfeited, awards and units | shares	(248)
Unvested at December 31, 2016 | shares	6,407
Unvested weighted average grant-date fair value at December 31, 2015 | $ / shares	$ 62.49
Granted, weighted average grant-date fair value | $ / shares	19.91
Vested, weighted average grant-date fair value | $ / shares	61.44
Forfeited, weighted average grant-date fair value | $ / shares	44.38
Unvested weighted average grant-date fair value at December 31, 2016 | $ / shares	$ 34.40
Performance-Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2015 | shares	434
Granted, awards and units | shares	330
Vested, awards and units | shares	(179)
Unvested at December 31, 2016 | shares	585
Unvested weighted average grant-date fair value at December 31, 2015 | $ / shares	$ 60.48
Granted, weighted average grant-date fair value | $ / shares	19.22
Vested, weighted average grant-date fair value | $ / shares	59.10
Unvested weighted average grant-date fair value at December 31, 2016 | $ / shares	$ 37.60
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2015 | shares	1,859
Granted, awards and units | shares	1,388
Vested, awards and units | shares	(602)
Forfeited, awards and units | shares	(41)
Unvested at December 31, 2016 | shares	2,604	[1]
Unvested weighted average grant-date fair value at December 31, 2015 | $ / shares	$ 76.17
Granted, weighted average grant-date fair value | $ / shares	10.41
Vested, weighted average grant-date fair value | $ / shares	63.37
Forfeited, weighted average grant-date fair value | $ / shares	43.88
Unvested weighted average grant-date fair value at December 31, 2016 | $ / shares	$ 46.66
[1]	A maximum of 5.2 million common shares could be awarded based upon Devon’s final TSR ranking.

Share-Based Compensation (Sum69

Share-Based Compensation (Summary Of Unvested Restricted Stock Awards and Units, Performance-Based Restricted Stock Awards And Performance Share Units) (Parenthetical) (Details) shares in Millions	12 Months Ended
	Dec. 31, 2016shares
Performance Share Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum common shares that could be awarded based upon total shareholder return	5.2

Share-Based Compensation (Sch70

Share-Based Compensation (Schedule Of Aggregate Fair Value Of Restricted Stock, Performance-Based Restricted Stock And Performance Shares, Awards And Units, That Vested During The Period) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 73	$ 101	$ 112
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	5	8	$ 10
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate fair value of awards and units, vested	$ 13	$ 22

Share-Based Compensation (Sum71

Share-Based Compensation (Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 131
Weighted average period for recognition (years)	2 years 3 months 18 days
Performance-Based Restricted Stock Awards [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 5
Weighted average period for recognition (years)	2 years 2 months 12 days
Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 21
Weighted average period for recognition (years)	1 year 7 months 6 days

Share-Based Compensation (Sum72

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 10.41
Risk-free interest rate	0.94%	1.06%	0.54%
Volatility factor	37.70%	26.20%	28.80%
Contractual term (years)	2 years 9 months 29 days	2 years 10 months 21 days	2 years 10 months 21 days
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 9.24	$ 81.99	$ 70.18
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 10.61	$ 85.05	$ 81.05

Share-Based Compensation (Sum73

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, 2016$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2015 | shares	3,448
Options, Expired | shares	(916)
Outstanding at December 31, 2016 | shares	2,532
Vested and expected to vest, options | shares	2,532
Exercisable, options | shares	2,532
Weighted average exercise price, Outstanding, December 31, 2015 | $ / shares	$ 67.98
Expired, weighted average exercise price | $ / shares	67.75
Weighted average exercise price, Outstanding, December 31, 2016 | $ / shares	68.06
Vested and expected to vest, weighted average exercise price | $ / shares	68.06
Exercisable, weighted average exercise price | $ / shares	$ 68.06
Outstanding, weighted average remaining term	1 year 10 months 13 days
Vested and expected to vest, weighted average remaining term	1 year 10 months 13 days
Exercisable, weighted average remaining term	1 year 10 months 13 days

Share-Based Compensation (Sum74

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, 2016USD ($)
Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 131
Weighted average period for recognition (years)	2 years 3 months 18 days
Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 21
Weighted average period for recognition (years)	1 year 7 months 6 days
General Partner [Member] | Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 14
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)	$ 4
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)	$ 14
Weighted average period for recognition (years)	1 year 8 months 12 days
EnLink [Member] | Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost (millions)	$ 4
Weighted average period for recognition (years)	1 year 9 months 18 days

Asset Impairments (Components o

Asset Impairments (Components of Asset Impairments) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges	$ 100	$ 300	$ 1,500	$ 3,000	$ 5,300	$ 5,900	$ 4,200	$ 5,500	$ 4,975	$ 20,820	$ 1,953
Goodwill, impairment loss									873	1,328
U.S. Oil And Gas Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges									2,809	17,992
Canada Oil And Gas Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges									1,291	1,257
Other Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment charges									2	20	12
General Partner And EnLink [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill, impairment loss				$ 873					$ 873	1,328
Impairment of intangible assets										$ 223
Canada [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill, impairment loss											$ 1,941

Asset Impairments (Narrative) (

Asset Impairments (Narrative) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill	$ 3,964,000,000	$ 5,032,000,000	$ 6,303,000,000
Canada [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill			$ 0

Restructuring And Transaction77

Restructuring And Transaction Costs (Schedule Of The Activity And Balances Associated With Restructuring Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Restructuring Cost And Reserve [Line Items]
Beginning balance	$ 76	$ 20
Ending balance	110	76
Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	(1)	56
Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	35
Other Current Liabilities [Member]
Restructuring Cost And Reserve [Line Items]
Beginning balance	13	13
Ending balance	48	13
Other Current Liabilities [Member] | Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	6
Other Current Liabilities [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	29
Other Long-Term Liabilities [Member]
Restructuring Cost And Reserve [Line Items]
Beginning balance	63	7
Ending balance	62	63
Other Long-Term Liabilities [Member] | Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	(7)	$ 56
Other Long-Term Liabilities [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	$ 6

Restructuring And Transaction78

Restructuring And Transaction Costs (Schedule Of The Components Of Restructuring And Transaction Costs Included In The Consolidated Comprehensive Statements Of Earnings) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	$ 267	$ 78	$ 46
Employee Related Costs [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	227	$ 24
Lease Obligations [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	20
Asset Impairments [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	3
Transaction Costs [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	$ 17

Restructuring And Transaction79

Restructuring And Transaction Costs (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	$ 267	$ 78	$ 46
Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Expense associated with accelerated awards	60
Canadian Divestitures [Member]
Restructuring Cost And Reserve [Line Items]
Expense associated with accelerated awards			15
Estimated Defined Benefit Settlements [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	24
Employee Related Costs [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	227	24
Employee Related Costs [Member] | Canadian Divestitures [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs			$ 46
Lease Obligations [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	$ 20
Lease Obligations [Member] | Office Consolidation [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs		$ 54

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current income tax expense (benefit):
United States federal, current income tax expense (benefit)	$ 5	$ (243)	$ 152
Various states, current income tax expense (benefit)	(11)	(8)	18
Canada and various provinces, current income tax expense (benefit)	106	14	307
Total current tax expense (benefit)	100	(237)	477
Deferred income tax expense (benefit):
United States federal, deferred income tax expense (benefit)	(3)	(5,033)	1,610
Various states, deferred income tax expense (benefit)		(336)	93
Canada and various provinces, deferred income tax expense (benefit)	(270)	(459)	188
Total deferred tax expense (benefit)	(273)	(5,828)	1,891
Total income tax expense (benefit)	$ (173)	$ (6,065)	$ 2,368

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Total income tax expense (benefit)	$ (173)	$ (6,065)	$ 2,368
U.S. statutory income tax rate	35.00%	35.00%	35.00%
Deferred tax asset valuation allowance	(22.00%)	(4.00%)	0.00%
Non-deductible goodwill and intangible impairment	(8.00%)	(2.00%)	23.00%
Change in unrecognized tax benefits	(2.00%)	0.00%	1.00%
Taxation on Canadian operations	(3.00%)	(1.00%)	(4.00%)
State income taxes	1.00%	1.00%	2.00%
Other	3.00%	0.00%	1.00%
Effective income tax rate	4.00%	29.00%	58.00%

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	12 Months Ended
	Sep. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax [Line Items]
Valuation allowance against U.S. deferred tax assets, percent				100.00%
Goodwill, impairment loss				$ 873	$ 1,328
Allocated goodwill				197
Deferred tax assets, valuation allowance			$ 967	1,666	967
Foreign earnings repatriated						$ 2,800
Current income tax expense (benefit)				100	(237)	477
Deferred tax liabilities, taxes on unremitted foreign earnings				13
Current income tax expense (benefit) on repatriation after foreign tax credits						67
Deferred tax liability, other			271	426	271
Net operating loss carryforwards, deferred tax assets			175	777	175
Unremitted foreign earnings				1,000
Unremitted earnings from subsidiaries not to be permanently reinvested				47
Unrecognized tax benefits, interest and penalties			29	68	29
Unrecognized tax benefit that would impact effective tax rate				202
Interest associated with tax examinations				36
United States Federal [Member]
Income Tax [Line Items]
Net operating loss carryforwards				$ 1,500
Operating loss carryforward, expiration date				Dec. 31, 2036
Canada Federal [Member]
Income Tax [Line Items]
Net operating loss carryforwards				$ 536
Various U.S. States [Member]
Income Tax [Line Items]
Net operating loss carryforwards				$ 689
Maximum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date				Dec. 31, 2037
Maximum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date				Dec. 31, 2036
Minimum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date				Dec. 31, 2029
Operating loss carryforward, utilization period				Dec. 31, 2017
Minimum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date				Dec. 31, 2018
U.S. Asset Divestitures [Member]
Income Tax [Line Items]
Current income tax expense (benefit)						294
Repatriated Foreign Earnings [Member]
Income Tax [Line Items]
Current income tax expense (benefit)						105
Assumed Repatriations Of Foreign Earnings [Member]
Income Tax [Line Items]
Deferred tax liabilities, taxes on unremitted foreign earnings						143
Scenario Plan [Member]
Income Tax [Line Items]
Unrecognized tax benefits recognized				$ 88
U.S. Oil And Gas Operations [Member]
Income Tax [Line Items]
Oil and Gas asset impairment charges					18,000
General Partner And EnLink [Member]
Income Tax [Line Items]
Goodwill, impairment loss		$ 873		873	$ 1,328
Goodwill and intangibles impairments			$ 1,600
Deferred tax liability, other						46
Net operating loss carryforwards				293
Deferred tax assets, alternative minimum tax credits				$ 1
General Partner And EnLink [Member] | Maximum [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date				Dec. 31, 2036
General Partner And EnLink [Member] | Minimum [Member]
Income Tax [Line Items]
Operating loss carryforward, expiration date				Dec. 31, 2028
Operating loss carryforward, utilization period				Dec. 31, 2018
United States [Member]
Income Tax [Line Items]
Change in deferred tax valuation allowance				$ 774
Allocated goodwill	$ 197
Deferred tax assets, valuation allowance				630
Canada [Member]
Income Tax [Line Items]
Change in deferred tax valuation allowance				71
Goodwill, impairment loss						$ 1,941
Deferred tax assets, valuation allowance				$ 69

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred tax assets, property and equipment	$ 685	$ 490
Deferred tax assets, asset retirement obligations	488	485
Deferred tax assets, accrued liabilities	130	160
Deferred tax assets, net operating loss carryforwards	777	175
Deferred tax assets, pension benefit obligations	98	106
Deferred tax assets, other	203	162
Total deferred tax assets before valuation allowance	2,381	1,578
Less: valuation allowance	(1,666)	(967)
Net deferred tax assets	715	611
Deferred tax liabilities, property and equipment	(884)	(1,187)
Deferred tax liabilities, long-term debt	(53)	(36)
Deferred tax liabilities, other	(426)	(271)
Total deferred tax liabilities	(1,363)	(1,494)
Net deferred tax liability	$ (648)	$ (883)

Income Taxes (Schedule Of Chang

Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Unrecognized tax benefits, Balance at beginning of year	$ 131	$ 241
Unrecognized tax benefits, Tax positions taken in prior periods	36	(19)
Unrecognized tax benefits, Tax positions taken in current year		31
Unrecognized tax benefits, Accrual of interest related to tax positions taken	39	(5)
Unrecognized tax benefits, Settlements		(108)
Unrecognized tax benefits, Lapse of statute of limitations	(5)
Unrecognized tax benefits, Foreign currency translation	1	(9)
Unrecognized tax benefits, Balance at end of year	$ 202	$ 131

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, 2016
Minimum [Member] | United States Federal [Member]
Tax years open	2,012
Minimum [Member] | Canada Federal [Member]
Tax years open	2,003
Maximum [Member] | United States Federal [Member]
Tax years open	2,016
Maximum [Member] | Canada Federal [Member]
Tax years open	2,016
Various U.S. States [Member] | Minimum [Member]
Tax years open	2,010
Various U.S. States [Member] | Maximum [Member]
Tax years open	2,016
Various Canadian Provinces [Member] | Minimum [Member]
Tax years open	2,003
Various Canadian Provinces [Member] | Maximum [Member]
Tax years open	2,016

Net Earnings (Loss) Per Share86

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net earnings (loss):
Net earnings (loss) attributable to Devon		$ 331	$ 993	$ (1,570)	$ (3,056)	$ (4,532)	$ (3,507)	$ (2,816)	$ (3,599)	$ (3,302)	$ (14,454)	$ 1,607
Attributable to participating securities										(2)	(5)	(17)
Basic and diluted earnings (loss)										$ (3,304)	$ (14,459)	$ 1,590
Common shares:
Common shares outstanding - total										513	412	409
Attributable to participating securities										(6)	(5)	(4)
Common shares outstanding - basic										507	407	405
Dilutive effect of potential common shares issuable												2
Common shares outstanding - diluted										507	407	407
Net earnings (loss) per share attributable to Devon:
Basic		$ 0.63	$ 1.90	$ (3.04)	$ (6.44)	$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (6.52)	$ (35.55)	$ 3.93
Diluted		$ 0.63	$ 1.89	$ (3.04)	$ (6.44)	$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (6.52)	$ (35.55)	$ 3.91
Antidilutive options	[1]									3	4	3
[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Foreign currency translation:
Beginning accumulated foreign currency translation		$ 424	$ 983	$ 1,448
Change in cumulative translation adjustment		45	(621)	(499)
Income tax benefit (expense)		(13)	62	34
Ending accumulated foreign currency translation		456	424	983
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(194)	(204)	(180)
Net actuarial loss and prior service cost arising in current year		(28)	(5)	(57)
Recognition of net actuarial loss and prior service cost in earnings	[1]	26	21	20
Curtailment and settlement of pension benefits		24
Income tax benefit (expense)			(6)	13
Ending accumulated pension and postretirement benefits		(172)	(194)	(204)
Accumulated other comprehensive earnings, net of tax		$ 284	$ 230	$ 779
[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 16 for additional details.

Supplemental Information To S88

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Net change in working capital accounts, net of assets and liabilities assumed:
Accounts receivable	$ (176)	$ 942	$ 128
Income taxes receivable	130	384	(467)
Other current assets	215	(57)	(222)
Accounts payable	(167)	(190)	(68)
Revenues and royalties payable	96	(526)	133
Other current liabilities	(106)	(864)	546
Net change in working capital	(8)	(311)	50
Interest paid (net of capitalized interest)	566	494	514
Income taxes paid (received)	$ (159)	$ (279)	$ 899

Supplemental Information To S89

Supplemental Information To Statements Of Cash Flows (Narrative) (Details) - USD ($) $ in Millions	Dec. 17, 2015	Mar. 07, 2014	Dec. 31, 2015
Powder River Basin [Member]
Supplemental Cash Flow [Line Items]
Cash payment to acquire interest	$ 300
General Partner And EnLink [Member]
Supplemental Cash Flow [Line Items]
Cash payment to acquire interest		$ 100
Equity Issued in Business Combination [Member] | EnLink [Member]
Supplemental Cash Flow [Line Items]
Noncash equity issuance in acquisition, value			$ 360
Equity Issued in Business Combination [Member] | Powder River Basin [Member] | Common Stock [Member]
Supplemental Cash Flow [Line Items]
Noncash equity issuance in acquisition, value	$ 199		$ 199

Accounts Receivable (Schedule O

Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Joint interest billings	$ 110	$ 211
Other	69	30
Gross accounts receivable	1,374	1,123
Allowance for doubtful accounts	(18)	(18)
Net accounts receivable	1,356	1,105
Oil, Gas And NGL Sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	487	362
Marketing And Midstream Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	$ 708	$ 520

Goodwill And Other Intangible91

Goodwill And Other Intangible Assets (Summary Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill, Beginning Balance	$ 5,032	$ 6,303
Acquired during period	2	57
Asset divestitures	(197)
Impairment	(873)	(1,328)
Goodwill, Ending Balance	3,964	5,032
United States [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	2,618	2,618
Asset divestitures	(197)
Goodwill, Ending Balance	2,421	2,618
General Partner And EnLink [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	2,414	3,685
Acquired during period	2	57
Impairment	(873)	(1,328)
Goodwill, Ending Balance	$ 1,543	$ 2,414

Goodwill And Other Intangible92

Goodwill And Other Intangible Assets (Schedule Of General Partner And EnLink Goodwill By Reporting Units) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill, Beginning Balance	$ 5,032	$ 5,032	$ 6,303
Acquired during period		2	57
Impairment		(873)	(1,328)
Goodwill, Ending Balance		3,964	5,032
General Partner And EnLink [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	2,414	2,414	3,685
Acquired during period		2	57
Impairment	(873)	(873)	(1,328)
Goodwill, Ending Balance		1,543	2,414
General Partner And EnLink [Member] | Texas [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	704	704	1,168
Acquired during period		2	28
Impairment		(473)	(492)
Goodwill, Ending Balance		233	704
General Partner And EnLink [Member] | Louisiana [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance			787
Impairment			(787)
Goodwill, Ending Balance
General Partner And EnLink [Member] | Oklahoma [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	190	190	190
Goodwill, Ending Balance		190	190
General Partner And EnLink [Member] | Crude And Condensate [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	93	93	113
Acquired during period			29
Impairment		(93)	(49)
Goodwill, Ending Balance			93
General Partner And EnLink [Member] | General Partner [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance	$ 1,427	1,427	1,427
Impairment		(307)
Goodwill, Ending Balance		$ 1,120	$ 1,427

Goodwill And Other Intangible93

Goodwill And Other Intangible Assets (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Removal of goodwill for asset divestitures		$ 197
Customer Relationships [Member]
Goodwill [Line Items]
Weighted average amortization period, other intangible assets		14 years
Amortization expense of intangible assets		$ 117	$ 56	$ 36
Amortization Expense, Next Five Years		118
General Partner And EnLink [Member]
Goodwill [Line Items]
Impairment of intangible assets			$ 223
General Partner And EnLink [Member] | Crude And Condensate [Member]
Goodwill [Line Items]
Impairment of intangible assets	$ 223
Upstream Oil And Gas Assets [Member]
Goodwill [Line Items]
Removal of goodwill for asset divestitures		$ 197

Goodwill And Other Intangible94

Goodwill And Other Intangible Assets (Schedule Of Other Intangible Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Customer relationships	$ 1,796	$ 745
Accumulated amortization	(172)	(55)
Net intangibles	$ 1,624	$ 690

Other Current Liabilities (Sche

Other Current Liabilities (Schedule Of Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Liabilities, Current [Abstract]
Derivative liabilities	$ 244	$ 48
Accrued interest payable	130	149
Restructuring liabilities	48	13
Other	452	466
Other current liabilities	1,066	650
Installment Payable, Current [Member]
Other Liabilities, Current [Abstract]
Installment payment - see Note 2	249
Other Current Liabilities [Member]
Other Liabilities, Current [Abstract]
Derivative liabilities	$ 187	$ 22

Debt And Related Expenses (Sche

Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Commercial paper		$ 0	$ 626
Net (discount) premium on debentures and notes		(30)	(28)
Debt issuance costs		(44)	(57)
Total debt		10,154	13,032
Less amount classified as short-term debt	[1]		976
Total long-term debt		$ 10,154	12,056
Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Short-term debt			350
Debt, maturity date		Dec. 15, 2016
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	[2],[3]	$ 20	$ 125
Debt, maturity date		Jul. 1, 2018
Debt interest rate, stated percentage		8.25%	8.25%
2.25% Due December 15, 2018 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	[3]	$ 95	$ 750
Debt, maturity date		Dec. 15, 2018
Debt interest rate, stated percentage		2.25%	2.25%
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	[3]	$ 162	$ 700
Debt, maturity date		Jan. 15, 2019
Debt interest rate, stated percentage		6.30%	6.30%
4.00% Due July 15, 2021 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 500	$ 500
Debt, maturity date		Jul. 15, 2021
Debt interest rate, stated percentage		4.00%	4.00%
3.25% due May 15, 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,000	$ 1,000
Debt, maturity date		May 15, 2022
Debt interest rate, stated percentage		3.25%	3.25%
5.85% due December 15, 2025 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	[3]	$ 485	$ 850
Debt, maturity date		Dec. 15, 2025
Debt interest rate, stated percentage		5.85%	5.85%
7.50% due September 15, 2027 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	[2],[3]	$ 73	$ 150
Debt, maturity date		Sep. 15, 2027
Debt interest rate, stated percentage		7.50%	7.50%
7.875% due September 30, 2031 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	[3],[4]	$ 1,059	$ 1,250
Debt, maturity date		Sep. 30, 2031
Debt interest rate, stated percentage		7.875%	7.875%
7.95% due April 15, 2032 [Member]
Debt Instrument [Line Items]
Long-term debt, gross	[3]	$ 789	$ 1,000
Debt, maturity date		Apr. 15, 2032
Debt interest rate, stated percentage		7.95%	7.95%
5.60% due July 15, 2041 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,250	$ 1,250
Debt, maturity date		Jul. 15, 2041
Debt interest rate, stated percentage		5.60%	5.60%
4.75% due May 15, 2042 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 750	$ 750
Debt, maturity date		May 15, 2042
Debt interest rate, stated percentage		4.75%	4.75%
5.00% due June 15, 2045 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 750	$ 750
Debt, maturity date		Jun. 15, 2045
Debt interest rate, stated percentage		5.00%	5.00%
Devon [Member]
Debt Instrument [Line Items]
Total debt		$ 6,859	$ 9,966
EnLink [Member]
Debt Instrument [Line Items]
Credit facilities		148	414
Net (discount) premium on debentures and notes		9	13
Debt issuance costs		(25)	(24)
Total debt		3,295	3,066
EnLink [Member] | 2.70% due April 1, 2019 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 400	$ 400
Debt, maturity date		Apr. 1, 2019
Debt interest rate, stated percentage		2.70%	2.70%
EnLink [Member] | 7.125% due June 1, 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 163	$ 163
Debt, maturity date		Jun. 1, 2022
Debt interest rate, stated percentage		7.125%	7.125%
EnLink [Member] | 4.40% due April 1, 2024 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 550	$ 550
Debt, maturity date		Apr. 1, 2024
Debt interest rate, stated percentage		4.40%	4.40%
EnLink [Member] | 4.15% due June 1, 2025 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 750	$ 750
Debt, maturity date		Jun. 1, 2025
Debt interest rate, stated percentage		4.15%	4.15%
EnLink [Member] | 4.85% due July 15, 2026 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 500
Debt, maturity date		Jul. 15, 2026
Debt interest rate, stated percentage		4.85%
EnLink [Member] | 5.60% due April 1, 2044 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 350	$ 350
Debt, maturity date		Apr. 1, 2044
Debt interest rate, stated percentage		5.60%	5.60%
EnLink [Member] | 5.05% due April 1, 2045 [Member]
Debt Instrument [Line Items]
Long-term debt, gross		$ 450	$ 450
Debt, maturity date		Apr. 1, 2045
Debt interest rate, stated percentage		5.05%	5.05%
[1]	2015 short-term debt consists of commercial paper balances and floating rate debt that was retired upon maturity in December 2016.
[2]	These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively.
[3]	These senior notes were included in 2016 tender offer redemptions discussed below.
[4]	Issued in October 2001, these are unsecured and unsubordinated obligations of Devon Financing, a wholly owned finance subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon.

Debt And Related Expenses (Sc97

Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Parenthetical) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2003	Dec. 31, 2016	Dec. 31, 2015
Floating Rate Due December 15, 2016 [Member]
Debt Instrument [Line Items]
Debt, maturity date		Dec. 15, 2016
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt, maturity date		Jul. 1, 2018
Debt interest rate, stated percentage		8.25%	8.25%
8.25% Due July 1, 2018 [Member] | Ocean Energy [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	8.25%
Fair value of notes assumed	$ 147
Effective interest rate of notes	5.50%
7.50% due September 15, 2027 [Member]
Debt Instrument [Line Items]
Debt, maturity date		Sep. 15, 2027
Debt interest rate, stated percentage		7.50%	7.50%
7.50% due September 15, 2027 [Member] | Ocean Energy [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.50%
Fair value of notes assumed	$ 169
Effective interest rate of notes	6.50%

Debt And Related Expenses (Sc98

Debt And Related Expenses (Schedule Of Debt Maturities) (Details) $ in Millions	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
2,018	$ 115
2,019	590
2,020	120
2,021	500
Thereafter	8,919
Total	$ 10,244

Debt And Related Expenses (Narr

Debt And Related Expenses (Narrative) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Nov. 30, 2014	Dec. 31, 2016	Dec. 31, 2014	Jul. 31, 2016	Dec. 31, 2015	Jun. 30, 2015	May 31, 2015
Debt Instrument [Line Items]
Outstanding letters of credit		$ 140,000,000
Repayment of commercial paper		626,000,000
Commercial paper		0			$ 626,000,000
Redemption of senior notes	$ 1,900,000,000	2,100,000,000
Loss on early retirement of debt		265,000,000	$ 51,000,000
EnLink [Member]
Debt Instrument [Line Items]
Outstanding credit facility borrowings		$ 148,000,000			$ 414,000,000
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
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
4.85% due July 15, 2026 [Member] | EnLink [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		4.85%
Debt, maturity date		Jul. 15, 2026
4.15% due June 1, 2025 [Member] | EnLink [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		4.15%			4.15%
Debt, maturity date		Jun. 1, 2025
5.05% due April 1, 2045 [Member] | EnLink [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		5.05%			5.05%
Debt, maturity date		Apr. 1, 2045
Senior Notes [Member]
Debt Instrument [Line Items]
Loss on early retirement of debt	$ 40,000,000	$ 265,000,000
Senior Notes [Member] | EnLink [Member]
Debt Instrument [Line Items]
Debt instrument, face amount							$ 900,000,000
Senior Notes [Member] | 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%
Debt, maturity date		Dec. 15, 2025
Senior Notes [Member] | 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%
Debt, maturity date		Jun. 15, 2045
Senior Notes [Member] | 4.85% due July 15, 2026 [Member] | EnLink [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 500,000,000
Debt interest rate, stated percentage				4.85%
Senior Notes [Member] | 4.15% due June 1, 2025 [Member] | EnLink [Member]
Debt Instrument [Line Items]
Debt instrument, face amount							$ 750,000,000
Debt interest rate, stated percentage							4.15%
Senior Notes [Member] | 5.05% due April 1, 2045 [Member] | EnLink [Member]
Debt Instrument [Line Items]
Debt instrument, face amount							$ 150,000,000
Debt interest rate, stated percentage							5.05%
Commercial Paper [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 3,000,000,000
Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 3,000,000,000
Frequency of payment		annual
Commitment fee amount		$ 7,600,000
Outstanding credit facility borrowings		0
Outstanding letters of credit		$ 57,000,000
Debt-to-capitalization ratio		0.187
Senior Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt-to-capitalization ratio		0.65
$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
Unsecured Revolving Credit Facility [Member] | EnLink [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 1,500,000,000
Line of credit facility expiration date		Mar. 6, 2020
Outstanding credit facility borrowings		$ 120,000,000
Outstanding letters of credit		$ 12,000,000
Line of credit average interest rate during period		2.30%
Revolving Credit Facility [Member] | General Partner [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		$ 28,000,000
Line of credit average interest rate during period		3.40%

Debt And Related Expenses (S100

Debt And Related Expenses (Schedule Of Net Financing Cost Components) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Capitalized interest	$ (251)
Total net financing costs	904	$ 517	$ 526
Devon [Member]
Debt Instrument [Line Items]
Interest based on debt outstanding	488	450	468
Early retirement of debt	269		48
Capitalized interest	(64)	(54)	(58)
Other	21	14	15
Total net financing costs	714	410	473
EnLink [Member]
Debt Instrument [Line Items]
Interest based on debt outstanding	144	115	64
Interest accretion on deferred installment payment	52
Other	(6)	(8)	(11)
Total net financing costs	$ 190	$ 107	$ 53

Asset Retirement Obligations (S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations as of beginning of period	$ 1,414	$ 1,399
Liabilities incurred and assumed through acquisitions	27	63
Liabilities settled and divested	(324)	(89)
Revision of estimated obligation	66	62
Asset retirement obligation accretion	75	75	$ 89
Foreign currency translation adjustment	14	(96)
Asset retirement obligations as of end of period	1,272	1,414	$ 1,399
Less current portion	46	44
Asset retirement obligations, long-term	$ 1,226	$ 1,370

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations [Line Items]
Liabilities settled and divested	$ (324)	$ (89)
Upstream U.S. Assets [Member]
Asset Retirement Obligations [Line Items]
Liabilities settled and divested	$ (287)

Retirement Plans (Narrative) (D

Retirement Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Value of trusts established for certain nonqualified plans	$ 16	$ 22
Projected benefit obligation	234	244
Accumulated benefit obligation in excess of plan assets	211	199
Pension benefits to be funded from the trust	13
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 funded from trust	16	$ 11
Net actuarial loss and prior service cost to be amortized from AOCI into net periodic benefit cost the next fiscal year	$ 18
Assumed compensation increase percentage	4.49%	4.49%	4.49%
Pension Benefits [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations	70.00%
Pension Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations	20.00%
Pension Benefits [Member] | Other Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations	10.00%
Nonqualified Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions funded from trust	$ 13	$ 11
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions funded from trust	2	$ 2
Net actuarial loss and prior service cost to be amortized from AOCI into net periodic benefit cost the next fiscal year	$ 1
Defined benefit plan health care cost trend rate assumed for next fiscal year	7.50%
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	$ 1,308	$ 1,377
Service cost	15	33	$ 30
Interest cost	42	52	55
Actuarial loss (gain)	63	(68)
Plan amendments	2
Plan curtailments	(31)
Plan settlements	(94)
Foreign exchange rate changes	1	(6)
Benefits paid	(57)	(80)
Benefit obligation at end of year	1,249	1,308	1,377
Change in plan assets:
Fair value of plan assets at beginning of year	1,059	1,149
Actual return on plan assets	61	(16)
Employer contributions	16	11
Plan settlements	(94)
Benefits paid	(57)	(80)
Foreign exchange rate changes		(5)
Fair value of plan assets at end of year	985	1,059	1,149
Funded status at end of year	(264)	(249)
Amounts recognized in balance sheet:
Other long-term assets	3	2
Other current liabilities	(13)	(12)
Other long-term liabilities	(254)	(239)
Net amount	(264)	(249)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	285	302
Prior service cost (credit)	8	14
Total	293	316
Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	23	24
Service cost		1	1
Interest cost	1	1	1
Actuarial loss (gain)	(1)	(2)
Plan amendments		1
Participant contributions		2
Benefits paid	(2)	(4)
Benefit obligation at end of year	21	23	$ 24
Change in plan assets:
Employer contributions	2	2
Participant contributions		2
Benefits paid	(2)	(4)
Funded status at end of year	(21)	(23)
Amounts recognized in balance sheet:
Other current liabilities	(3)	(3)
Other long-term liabilities	(18)	(20)
Net amount	(21)	(23)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	(11)	(11)
Prior service cost (credit)	(5)	(6)
Total	$ (16)	$ (17)

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Net periodic benefit cost:
Service cost		$ 15	$ 33	$ 30
Interest cost		42	52	55
Expected return on plan assets		(55)	(58)	(54)
Curtailment and settlement expense				1
Recognition of net actuarial loss (gain)	[1]	25	20	18
Recognition of prior service cost	[1]	3	4	4
Total net periodic benefit cost	[2]	30	51	54
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year		26	5	57
Prior service cost (credit) arising in current year		2
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost	[3]	(43)	(20)	(19)
Recognition of prior service cost, including curtailment, in net periodic benefit cost	[3]	(9)	(4)	(4)
Total other comprehensive loss (earnings)		(24)	(19)	34
Total recognized		6	32	88
Postretirement Benefits [Member]
Net periodic benefit cost:
Service cost			1	1
Interest cost		1	1	1
Recognition of net actuarial loss (gain)	[1]	(1)	(1)	(1)
Recognition of prior service cost	[1]	(1)	(2)	(2)
Total net periodic benefit cost	[2]	(1)	(1)	(1)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year			(1)
Prior service cost (credit) arising in current year			1
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost	[3]	1	1	1
Recognition of prior service cost, including curtailment, in net periodic benefit cost	[3]	1	1	2
Total other comprehensive loss (earnings)		2	2	3
Total recognized		$ 1	$ 1	$ 2
[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.
[3]	These amounts include restructuring costs that were reclassified out of other comprehensive earnings in the current period. See Note 6 for further discussion.

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	4.07%	4.25%	3.90%
Rate of compensation increase	4.49%	4.49%	4.49%
Assumptions to determine net periodic benefit cost:
Discount rate	4.39%	3.90%	4.80%
Rate of compensation increase	4.49%	4.49%	4.49%
Expected return on plan assets	5.20%	5.22%	5.42%
Postretirement Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	3.46%	3.63%	3.25%
Assumptions to determine net periodic benefit cost:
Discount rate	3.63%	3.25%	3.65%

Retirement Plans (Schedule of F

Retirement Plans (Schedule of Fair Value of Pension Assets By Asset Class) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 112	$ 120	$ 112
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	100.00%	100.00%
Fair value of plan assets	$ 985	$ 1,059	$ 1,149
Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	319	500
Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	554	439
Pension Benefits [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 112	$ 120
Corporate Bonds [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	30.00%	48.00%
Fair value of plan assets	$ 297	$ 507
Corporate Bonds [Member] | Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	205	371
Corporate Bonds [Member] | Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 92	$ 136
Other Bonds [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	4.00%	3.00%
Fair value of plan assets	$ 38	$ 35
Other Bonds [Member] | Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 38	$ 35
Short-Term Investments [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	3.00%	3.00%
Fair value of plan assets	$ 24	$ 32
Short-Term Investments [Member] | Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8	6
Short-Term Investments [Member] | Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 16	$ 26
United States Treasuries [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	35.00%	17.00%
Fair value of plan assets	$ 343	$ 179
United States Treasuries [Member] | Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	68	88
United States Treasuries [Member] | Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 275	$ 91
Fixed Income Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	69.00%	68.00%
Fair value of plan assets	$ 678	$ 721
Fixed Income Securities [Member] | Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	311	494
Fixed Income Securities [Member] | Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 367	$ 227
Equity Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	17.00%	18.00%
Fair value of plan assets	$ 171	$ 186
Equity Securities [Member] | Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 171	$ 186
Hedge Fund And Alternative Investments [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	11.00%	11.00%
Fair value of plan assets	$ 112	$ 120
Hedge Fund And Alternative Investments [Member] | Pension Benefits [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 112	$ 120
Other Securities [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual allocation	14.00%	14.00%
Fair value of plan assets	$ 136	$ 152
Other Securities [Member] | Pension Benefits [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8	6
Other Securities [Member] | Pension Benefits [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	16	26
Other Securities [Member] | Pension Benefits [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 112	$ 120

Retirement Plans (Schedule o108

Retirement Plans (Schedule of Changes In Level 3 Plan Assets) (Details) - Level 3 Inputs [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$ 120	$ 112
Purchases (Investments sold)	(12)	5
Investment returns	4	3
Fair value of plan assets at end of year	$ 112	$ 120

Retirement Plans (Schedule Of E

Retirement Plans (Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans) (Details) $ in Millions	Dec. 31, 2016USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,017	$ 60
2,018	61
2,019	62
2,020	64
2,021	67
2022 to 2026	374
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,017	3
2,018	3
2,019	3
2,020	2
2,021	2
2022 to 2026	$ 7

Retirement Plans (Schedule O110

Retirement Plans (Schedule Of Expense Related To These Defined Contribution Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plan Disclosure [Line Items]
Expense related to defined contribution plans	$ 64	$ 79	$ 69
401(k) Plan And Enhanced Contribution Plans [Member]
Defined Contribution Plan Disclosure [Line Items]
Expense related to defined contribution plans	53	63	49
Canadian Pension And Savings Plans [Member]
Defined Contribution Plan Disclosure [Line Items]
Expense related to defined contribution plans	$ 11	$ 16	$ 20

Stockholders' Equity (Narrative

Stockholders' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Feb. 29, 2016	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Stockholders Equity [Abstract]
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, Shares Authorized				4,500,000
Preferred Stock, Par or Stated Value Per Share				$ 1
Net proceeds from offering				$ 1,469
Common Stock [Member]
Stockholders Equity [Abstract]
Common stock, shares issued				103,000,000	7,000,000
Common Stock Offering [Member]
Stockholders Equity [Abstract]
Common stock, shares issued	79,000,000
Net proceeds from offering	$ 1,500
Common Stock Offering [Member] | Underwriters [Member]
Stockholders Equity [Abstract]
Common stock, shares issued	10,000,000
Equity Issued in Business Combination [Member] | Common Stock [Member] | Powder River Basin [Member]
Stockholders Equity [Abstract]
Equity issued for acquisition			7,000,000
Equity Issued in Business Combination [Member] | Common Stock [Member] | STACK [Member]
Stockholders Equity [Abstract]
Equity issued for acquisition		23,000,000

Stockholders' Equity (Summary O

Stockholders' Equity (Summary Of Dividends Paid On Common Stock) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Stockholders Equity Note [Abstract]
Common stock dividends paid, Amount	$ 31	$ 32	$ 33	$ 125	$ 100	$ 99	$ 98	$ 99	$ 99	$ 98	$ 99	$ 90	$ 221	$ 396	$ 386
Common stock dividends, rate per share	$ 0.06	$ 0.06	$ 0.06	$ 0.24	$ 0.24	$ 0.24	$ 0.24	$ 0.24	$ 0.24	$ 0.24	$ 0.24	$ 0.22

Noncontrolling Interests (Narra

Noncontrolling Interests (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	Mar. 07, 2014	Oct. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Net proceeds of common units sold			$ 892	$ 25	$ 410
Sale of subsidiary units				654
Distributions to unitholders other than Devon			$ 304	$ 254	$ 235
EnLink [Member]
Noncontrolling Interest [Line Items]
Number of units sold to public for interests in EnLink				26.2
Sale of subsidiary units				$ 654
EnLink [Member] | Equity Distribution Agreements [Member]
Noncontrolling Interest [Line Items]
Number of units sold to public for interests in EnLink			10	1.3	14.8
Net proceeds of common units sold			$ 167	$ 25	$ 410
EnLink [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Common units issued in private placement		2.8
Proceeds of private placement transaction		$ 50
General Partner And EnLink [Member]
Noncontrolling Interest [Line Items]
Cash payment to acquire interest	$ 100
Distributions to unitholders other than Devon			$ 304	$ 254	$ 135

Noncontrolling Interests (Summa

Noncontrolling Interests (Summary of Ownership Interest Activity in the General Partner and EnLink) (Details)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 07, 2014
EnLink [Member]
Noncontrolling Interest [Line Items]
Ownership interest by Devon	24.00%	28.00%	49.00%	52.00%
EnLink [Member] | Non-Devon Unitholders [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners	53.00%	45.00%	43.00%	41.00%
EnLink [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners	23.00%	27.00%	8.00%	7.00%
General Partner [Member]
Noncontrolling Interest [Line Items]
Ownership interest by Devon	64.00%	70.00%	70.00%	70.00%
General Partner [Member] | Non-Devon Unitholders [Member]
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners	36.00%	30.00%	30.00%	30.00%

Commitments And Contingencie115

Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details) $ in Millions	Dec. 31, 2016USD ($)
Purchase Obligations [Member]
Long Term Purchase Commitment [Line Items]
2,017	$ 609
2,018	649
2,019	762
2,020	748
2,021	181
Total	2,949
Drilling And Facility Obligations [Member]
Long Term Purchase Commitment [Line Items]
2,017	76
2,018	66
2,019	67
2,020	57
2,021	37
Thereafter	85
Total	388
Operational Agreements [Member]
Long Term Purchase Commitment [Line Items]
2,017	1,145
2,018	1,134
2,019	627
2,020	457
2,021	285
Thereafter	2,667
Total	6,315
Office And Equipment Leases [Member]
Long Term Purchase Commitment [Line Items]
2,017	50
2,018	85
2,019	83
2,020	59
2,021	39
Thereafter	55
Total	371
EnLink Obligations [Member]
Long Term Purchase Commitment [Line Items]
2,017	50
2,018	51
2,019	33
2,020	18
2,021	17
Thereafter	102
Total	$ 271

Commitments And Contingencie116

Commitments And Contingencies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments And Contingencies Disclosure [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	$ 78	$ 88	$ 64

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, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	$ 11	$ 45
Derivatives, liabilities	(244)	(48)
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,542	1,871
Debt	(10,154)	(13,032)
Installment payment	(473)
Capital lease obligations	(7)	(17)
Carrying Amount [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	10	35
Derivatives, liabilities	(203)	(18)
Carrying Amount [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	1	2
Derivatives, liabilities	(41)	(22)
Carrying Amount [Member] | Foreign Currency Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		8
Derivatives, liabilities		(8)
Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,542	1,871
Debt	(10,760)	(11,927)
Installment payment	(477)
Capital lease obligations	(6)	(16)
Total Fair Value [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	10	35
Derivatives, liabilities	(203)	(18)
Total Fair Value [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	1	2
Derivatives, liabilities	(41)	(22)
Total Fair Value [Member] | Foreign Currency Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		8
Derivatives, liabilities		(8)
Level 1 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,298	1,471
Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	244	400
Debt	(10,760)	(11,927)
Installment payment	(477)
Capital lease obligations	(6)	(16)
Level 2 Inputs [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	10	35
Derivatives, liabilities	(203)	(18)
Level 2 Inputs [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	1	2
Derivatives, liabilities	$ (41)	(22)
Level 2 Inputs [Member] | Foreign Currency Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		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, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Revenues from external customers										$ 10,304	$ 13,145	$ 19,566
Asset dispositions and other		$ 540	$ 1,400							1,893		1,072
Depreciation, depletion and amortization										1,792	3,129	3,319
Asset impairments		100	300	$ 1,500	$ 3,000	$ 5,300	$ 5,900	$ 4,200	$ 5,500	4,975	20,820	1,953
Restructuring and transaction costs										267	78	46
Interest expense										911	523	536
Earnings (loss) before income taxes		375	1,178	(1,745)	(3,685)	(5,542)	(5,623)	(4,479)	(5,624)	(3,877)	(21,268)	4,059
Income tax expense (benefit)										(173)	(6,065)	2,368
Net earnings (loss)										(3,704)	(15,203)	1,691
Net earnings (loss) attributable to noncontrolling interests										(402)	(749)	84
Net earnings (loss) attributable to Devon		331	$ 993	$ (1,570)	$ (3,056)	(4,532)	$ (3,507)	$ (2,816)	$ (3,599)	(3,302)	(14,454)	1,607
Property and equipment, net		16,190				19,068				16,190	19,068	36,296
Total assets		25,913				29,451				25,913	29,451	50,568
Capital expenditures, including acquisitions										4,191	6,233	13,559
Eliminations [Member]
Segment Reporting Information [Line Items]
Interest expense										(84)	(46)	(44)
Total assets		(62)				(97)				(62)	(97)	(124)
Eliminations [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										$ (701)	(679)	(859)
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]									$ 5,722	8,360	14,854
Asset dispositions and other	[1]									1,367		(5)
Depreciation, depletion and amortization	[1]									928	2,220	2,475
Asset impairments	[1]									2,809	18,000	12
Restructuring and transaction costs	[1]									242	54
Interest expense	[1]									624	368	441
Earnings (loss) before income taxes	[1]									(2,051)	(18,214)	4,390
Income tax expense (benefit)	[1]									(8)	(5,650)	1,797
Net earnings (loss)	[1]									(2,043)	(12,564)	2,593
Net earnings (loss) attributable to noncontrolling interests	[1]									1	1	1
Net earnings (loss) attributable to Devon	[1]									(2,044)	(12,565)	2,592
Property and equipment, net	[1]	7,358				8,811				7,358	8,811	24,463
Total assets	[1]	12,163				14,550				12,163	14,550	31,994
Capital expenditures, including acquisitions	[1]									2,880	4,575	11,214
Canada [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues from external customers										1,031	1,012	2,063
Asset dispositions and other										542		1,077
Depreciation, depletion and amortization										360	522	560
Asset impairments										1,293	1,257	1,941
Restructuring and transaction costs										19	24	46
Interest expense										181	94	85
Earnings (loss) before income taxes										(942)	(1,670)	(657)
Income tax expense (benefit)										(165)	(445)	495
Net earnings (loss)										(777)	(1,225)	(1,152)
Net earnings (loss) attributable to Devon										(777)	(1,225)	(1,152)
Property and equipment, net		2,575				4,590				2,575	4,590	6,790
Total assets		3,536				5,457				3,536	5,457	8,509
Capital expenditures, including acquisitions										229	680	1,344
General Partner And EnLink [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues from external customers	[1]									3,551	3,773	2,649
Asset dispositions and other	[1]									(16)
Depreciation, depletion and amortization	[1]									504	387	284
Asset impairments	[1]									873	1,563
Restructuring and transaction costs	[1]									6
Interest expense	[1]									190	107	54
Earnings (loss) before income taxes	[1]									(884)	(1,384)	326
Income tax expense (benefit)	[1]										30	76
Net earnings (loss)	[1]									(884)	(1,414)	250
Net earnings (loss) attributable to noncontrolling interests	[1]									(403)	(750)	83
Net earnings (loss) attributable to Devon	[1]									(481)	(664)	167
Property and equipment, net	[1]	6,257				5,667				6,257	5,667	5,043
Total assets	[1]	$ 10,276				$ 9,541				10,276	9,541	10,189
Capital expenditures, including acquisitions	[1]									1,082	978	1,001
General Partner And EnLink [Member] | Operating Segments [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Revenues from external customers	[1]									$ 701	$ 679	$ 859
[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 119

Supplemental Information On Oil And Gas Operations (Costs Incurred) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property acquisition costs:
Proved properties	$ 237	$ 195	$ 5,210
Unproved properties	1,358	717	1,177
Exploration costs	394	587	322
Development costs	1,143	3,671	5,463
Costs incurred	3,132	5,170	12,172
United States [Member]
Property acquisition costs:
Proved properties	237	193	5,210
Unproved properties	1,356	634	1,176
Exploration costs	345	478	270
Development costs	1,034	3,269	4,400
Costs incurred	2,972	4,574	11,056
Canada [Member]
Property acquisition costs:
Proved properties		2
Unproved properties	2	83	1
Exploration costs	49	109	52
Development costs	109	402	1,063
Costs incurred	$ 160	$ 596	$ 1,116

Supplemental Information On 120

Supplemental Information On Oil And Gas Operations (Narrative) (Details) $ in Millions		12 Months Ended
		Dec. 31, 2016USD ($)MBbls / dMMBoe$ / bbl$ / Mcf	Dec. 31, 2015USD ($)MMBoe	Dec. 31, 2014USD ($)MMBoe	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2013MMBoe
Reserve Quantities [Line Items]
Costs incurred | $		$ 3,132	$ 5,170	$ 12,172
Capitalized interest costs | $		251
Oil and gas properties not subject to amortization | $		$ 3,437
Increase (decrease) in proved undeveloped reserves		9.00%
Proved undeveloped reserves as a percentage of total proved reserves		20.00%
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)		41
Cost incurred related to development and conversion | $		$ 586
Proved undeveloped reserves (MMBoe)	[1]	409	376	689				701
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	(27)	(302)	9
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	126	118	211
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)		74	13	5
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)	[1]	20	9	265
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]	157	7	383
Average estimated future realized price per barrel of oil used to estimate future cash inflows for proved oil reserves | $ / bbl		37.37
Average estimated future realized price per barrel of bitumen used to estimate future cash inflows for proved bitumen reserves | $ / bbl		15.74
Average estimated future realized price per Mcf of gas used to estimate future cash inflows for proved gas reserves | $ / Mcf		1.98
Average estimated future realized price per barrel of natural gas liquids used to estimate future cash inflows for proved NGL reserves | $ / bbl		9.91
Future development costs | $		$ 4,985	$ 6,065	$ 10,787
Future dismantlement, abandonment and rehabilitation costs | $		$ 1,300
Forecast [Member]
Reserve Quantities [Line Items]
Future development costs | $					$ 500	$ 800	$ 400
Maximum [Member]
Reserve Quantities [Line Items]
Increase in total proved reserves, percentage, due to higher commodity prices				1.00%
STACK And Powder River Basin [Member] | Minimum [Member]
Reserve Quantities [Line Items]
Years until development and evaluation will be complete		4 years
STACK And Powder River Basin [Member] | Maximum [Member]
Reserve Quantities [Line Items]
Years until development and evaluation will be complete		5 years
STACK and Delaware Basin [Member]
Reserve Quantities [Line Items]
Increase (decrease) in proved undeveloped reserves due to drilling and development activities (MMBoe)		78
Eagle Ford and Jackfish [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)		41
Proved undeveloped reserves to proved developed reserves, conversion, percentage		11.00%
Jackfish [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe)		294	301
Daily barrel facility capacity (MBbls/d) | MBbls / d		35
Year development schedule will be complete		Dec. 31, 2029
Proved undeveloped reserves, remaining undeveloped 5 years or more after initial booking (energy)		199
Proved undeveloped reserve, requiring excess of five years to develop		119
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)			11	8
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)			11
Delaware Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)		18	38
STACK [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)		97
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)		73
Eagle Ford [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)		7	21	54
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)				246
Anadarko Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)			30	14
Permian Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)				70
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)				4
Barnett Shale [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)				36
Mississippian-Woodford Trend [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)				14
General and Administrative Expense [Member]
Reserve Quantities [Line Items]
Costs incurred | $		$ 244	$ 372	$ 376
Oil and Gas Properties [Member]
Reserve Quantities [Line Items]
Capitalized interest costs | $		64	$ 54	$ 45
Costs Deemed For Individual Assessment [Member] | STACK, Powder River Basin And Pike thermal oil [Member]
Reserve Quantities [Line Items]
Oil and gas properties not subject to amortization | $		$ 2,900
[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 121

Supplemental Information On Oil And Gas Operations (Capitalized Costs) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	$ 75,648	$ 78,190
Unproved properties	3,437	2,584
Total oil and gas properties	79,085	80,774
Accumulated DD&A	(70,430)	(69,497)
Net capitalized costs	8,655	11,277
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	61,401	64,443
Unproved properties	2,092	1,352
Total oil and gas properties	63,493	65,795
Accumulated DD&A	(57,323)	(58,312)
Net capitalized costs	6,170	7,483
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	14,247	13,747
Unproved properties	1,345	1,232
Total oil and gas properties	15,592	14,979
Accumulated DD&A	(13,107)	(11,185)
Net capitalized costs	$ 2,485	$ 3,794

Supplemental Information On 122

Supplemental Information On Oil And Gas Operations (Oil And Gas Properties Not Subject To Amortization) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$ 2,465
Exploration costs	536
Development costs	185
Capitalized interest	251
Total oil and gas properties not subject to amortization	3,437
2016 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	1,176
Exploration costs	107
Development costs	12
Capitalized interest	63
Total oil and gas properties not subject to amortization	1,358
2015 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	579
Exploration costs	134
Capitalized interest	52
Total oil and gas properties not subject to amortization	765
2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	246
Exploration costs	89
Development costs	23
Capitalized interest	37
Total oil and gas properties not subject to amortization	395
Prior to 2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	464
Exploration costs	206
Development costs	150
Capitalized interest	99
Total oil and gas properties not subject to amortization	$ 919

Supplemental Information On 123

Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / Boe	Dec. 31, 2015USD ($)$ / Boe	Dec. 31, 2014USD ($)$ / Boe
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 4,182	$ 5,382	$ 9,910
Lease operating expenses	(1,582)	(2,104)	(2,332)
General and administrative expenses	(168)	(224)	(210)
Production and property taxes	(231)	(342)	(503)
Depreciation, depletion and amortization	(1,143)	(2,581)	(2,896)
Gains on asset sales	1,351		1,077
Asset impairments	(4,100)	(19,249)
Accretion of asset retirement obligations	(74)	(74)	(88)
Income tax benefit (expense)	245	5,861	(1,767)
Results of operations	$ (1,520)	$ (13,331)	$ 3,191	[1]
Depreciation, depletion and amortization per Boe | $ / Boe	5.11	10.40	11.79
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 3,198	$ 4,356	$ 7,867
Lease operating expenses	(1,123)	(1,551)	(1,559)
General and administrative expenses	(148)	(196)	(153)
Production and property taxes	(200)	(309)	(466)
Depreciation, depletion and amortization	(817)	(2,107)	(2,365)
Gains on asset sales	1,351
Asset impairments	(2,809)	(17,992)
Accretion of asset retirement obligations	(49)	(47)	(49)
Income tax benefit (expense)		5,547	(1,199)
Results of operations	$ (597)	$ (12,299)	$ 2,076	[1]
Depreciation, depletion and amortization per Boe | $ / Boe	4.68	10.21	11.41
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 984	$ 1,026	$ 2,043
Lease operating expenses	(459)	(553)	(773)
General and administrative expenses	(20)	(28)	(57)
Production and property taxes	(31)	(33)	(37)
Depreciation, depletion and amortization	(326)	(474)	(531)
Gains on asset sales			1,077
Asset impairments	(1,291)	(1,257)
Accretion of asset retirement obligations	(25)	(27)	(39)
Income tax benefit (expense)	245	314	(568)
Results of operations	$ (923)	$ (1,032)	$ 1,115	[1]
Depreciation, depletion and amortization per Boe | $ / Boe	6.65	11.30	13.80
[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 124

Supplemental Information On Oil And Gas Operations (Proved Oil Reserves) (Details) MBbls in Thousands	12 Months Ended
	Dec. 31, 2016MBbls	Dec. 31, 2015MBbls	Dec. 31, 2014MBbls	Dec. 31, 2013MBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	264	374	285
Proved developed and undeveloped reserves, revisions due to prices	(20)	(49)	(1)
Proved developed and undeveloped reserves, revisions other than price	1	(50)	(37)
Proved developed and undeveloped reserves, extensions and discoveries	38	54	99
Proved developed and undeveloped reserves, purchase of reserves	8	5	132
Proved developed and undeveloped reserves, production	(55)	(70)	(58)
Proved developed and undeveloped reserves, sale of reserves	(25)		(46)
Proved developed and undeveloped reserves, ending balance	211	264	374
Proved developed reserves	177	225	278	250
Proved developed producing reserves	156	211	243	229
Proved undeveloped reserves	34	39	96	35
Oil [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	242	351	229
Proved developed and undeveloped reserves, revisions due to prices	(18)	(53)	(1)
Proved developed and undeveloped reserves, revisions other than price	(2)	(52)	(38)
Proved developed and undeveloped reserves, extensions and discoveries	36	51	94
Proved developed and undeveloped reserves, purchase of reserves	8	5	132
Proved developed and undeveloped reserves, production	(47)	(60)	(48)
Proved developed and undeveloped reserves, sale of reserves	(25)		(17)
Proved developed and undeveloped reserves, ending balance	194	242	351
Proved developed reserves	160	203	255	194
Proved developed producing reserves	143	192	224	178
Proved undeveloped reserves	34	39	96	35
Oil [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	22	23	56
Proved developed and undeveloped reserves, revisions due to prices	(2)	4
Proved developed and undeveloped reserves, revisions other than price	3	2	1
Proved developed and undeveloped reserves, extensions and discoveries	2	3	5
Proved developed and undeveloped reserves, production	(8)	(10)	(10)
Proved developed and undeveloped reserves, sale of reserves			(29)
Proved developed and undeveloped reserves, ending balance	17	22	23
Proved developed reserves	17	22	23	56
Proved developed producing reserves	13	19	19	51

Supplemental Information On 125

Supplemental Information On Oil And Gas Operations (Proved Bitumen Reserves) (Details) MBbls in Thousands	12 Months Ended
	Dec. 31, 2016MBbls	Dec. 31, 2015MBbls	Dec. 31, 2014MBbls	Dec. 31, 2013MBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Bitumen [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	520	521	552
Proved developed and undeveloped reserves, revisions due to prices	23	103	(37)
Proved developed and undeveloped reserves, revisions other than price	(19)	(84)	18
Proved developed and undeveloped reserves, extensions and discoveries		11	8
Proved developed and undeveloped reserves, production	(40)	(31)	(20)
Proved developed and undeveloped reserves, ending balance	484	520	521
Proved developed reserves	190	219	137	111
Proved developed producing reserves	190	219	137	111
Proved undeveloped reserves	294	301	384	441
Bitumen [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	520	521	552
Proved developed and undeveloped reserves, revisions due to prices	23	103	(37)
Proved developed and undeveloped reserves, revisions other than price	(19)	(84)	18
Proved developed and undeveloped reserves, extensions and discoveries		11	8
Proved developed and undeveloped reserves, production	(40)	(31)	(20)
Proved developed and undeveloped reserves, ending balance	484	520	521
Proved developed reserves	190	219	137	111
Proved developed producing reserves	190	219	137	111
Proved undeveloped reserves	294	301	384	441

Supplemental Information On 126

Supplemental Information On Oil And Gas Operations (Proved Natural Gas Reserves) (Details) Mcf in Millions	12 Months Ended
	Dec. 31, 2016Mcf	Dec. 31, 2015Mcf	Dec. 31, 2014Mcf	Dec. 31, 2013Mcf
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	5,821	7,687	9,308
Proved developed and undeveloped reserves, revisions due to prices	(103)	(1,421)	236
Proved developed and undeveloped reserves, revisions other than price	638	(9)	(295)
Proved developed and undeveloped reserves, extensions and discoveries	280	171	343
Proved developed and undeveloped reserves, purchase of reserves	33	17	457
Proved developed and undeveloped reserves, production	(517)	(587)	(701)
Proved developed and undeveloped reserves, sale of reserves	(521)	(37)	(1,661)
Proved developed and undeveloped reserves, ending balance	5,631	5,821	7,687
Proved developed reserves	5,377	5,707	6,984	8,459
Proved developed producing reserves	5,259	5,559	6,780	8,105
Proved undeveloped reserves	254	114	703	849
Natural Gas [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	5,808	7,651	8,550
Proved developed and undeveloped reserves, revisions due to prices	(103)	(1,412)	191
Proved developed and undeveloped reserves, revisions other than price	628	(3)	(299)
Proved developed and undeveloped reserves, extensions and discoveries	280	171	335
Proved developed and undeveloped reserves, purchase of reserves	33	17	457
Proved developed and undeveloped reserves, production	(510)	(579)	(660)
Proved developed and undeveloped reserves, sale of reserves	(521)	(37)	(923)
Proved developed and undeveloped reserves, ending balance	5,615	5,808	7,651
Proved developed reserves	5,361	5,694	6,948	7,707
Proved developed producing reserves	5,243	5,546	6,746	7,425
Proved undeveloped reserves	254	114	703	843
Natural Gas [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	13	36	758
Proved developed and undeveloped reserves, revisions due to prices		(9)	45
Proved developed and undeveloped reserves, revisions other than price	10	(6)	4
Proved developed and undeveloped reserves, extensions and discoveries			8
Proved developed and undeveloped reserves, production	(7)	(8)	(41)
Proved developed and undeveloped reserves, sale of reserves			(738)
Proved developed and undeveloped reserves, ending balance	16	13	36
Proved developed reserves	16	13	36	752
Proved developed producing reserves	16	13	34	680
Proved undeveloped reserves				6

Supplemental Information On 127

Supplemental Information On Oil And Gas Operations (Proved Natural Gas Liquids Reserves) (Details) MBbls in Thousands	12 Months Ended
	Dec. 31, 2016MBbls	Dec. 31, 2015MBbls	Dec. 31, 2014MBbls	Dec. 31, 2013MBbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	428	578	575
Proved developed and undeveloped reserves, revisions due to prices	(13)	(119)	8
Proved developed and undeveloped reserves, revisions other than price	48	(6)	2
Proved developed and undeveloped reserves, extensions and discoveries	42	24	47
Proved developed and undeveloped reserves, purchase of reserves	7	1	57
Proved developed and undeveloped reserves, production	(42)	(50)	(51)
Proved developed and undeveloped reserves, sale of reserves	(45)		(60)
Proved developed and undeveloped reserves, ending balance	425	428	578
Proved developed reserves	387	411	486	491
Proved developed producing reserves	370	393	467	463
Proved undeveloped reserves	38	17	92	84
Natural Gas Liquids [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance	428	578	552
Proved developed and undeveloped reserves, revisions due to prices	(13)	(119)	7
Proved developed and undeveloped reserves, revisions other than price	48	(6)	2
Proved developed and undeveloped reserves, extensions and discoveries	42	24	47
Proved developed and undeveloped reserves, purchase of reserves	7	1	57
Proved developed and undeveloped reserves, production	(42)	(50)	(50)
Proved developed and undeveloped reserves, sale of reserves	(45)		(37)
Proved developed and undeveloped reserves, ending balance	425	428	578
Proved developed reserves	387	411	486	468
Proved developed producing reserves	370	393	467	442
Proved undeveloped reserves	38	17	92	84
Natural Gas Liquids [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance			23
Proved developed and undeveloped reserves, revisions due to prices			1
Proved developed and undeveloped reserves, production			(1)
Proved developed and undeveloped reserves, sale of reserves			(23)
Proved developed reserves				23
Proved developed producing reserves				21

Supplemental Information On 128

Supplemental Information On Oil And Gas Operations (Proved Total MMBoe Reserves) (Details)		12 Months Ended
		Dec. 31, 2016MMBoe	Dec. 31, 2015MMBoe	Dec. 31, 2014MMBoe	Dec. 31, 2013MMBoe
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	[1]	2,182	2,754	2,963
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	(27)	(302)	9
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	137	(142)	(65)
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	126	118	211
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)	[1]	20	9	265
Proved developed and undeveloped reserves, production (MMBoe)	[1]	(223)	(248)	(246)
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]	(157)	(7)	(383)
Proved developed and undeveloped reserves, ending balance (MMBoe)	[1]	2,058	2,182	2,754
Proved developed reserves (MMBoe)	[1]	1,649	1,806	2,065	2,262
Proved developed producing reserves (MMBoe)	[1]	1,593	1,749	1,977	2,154
Proved undeveloped reserves (MMBoe)	[1]	409	376	689	701
Conversion rate of gas reserves from barrels of oil to Boe		6
United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	[1]	1,638	2,205	2,205
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	(48)	(408)	38
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	151	(59)	(86)
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	124	104	197
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)	[1]	20	9	265
Proved developed and undeveloped reserves, production (MMBoe)	[1]	(174)	(206)	(207)
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]	(157)	(7)	(207)
Proved developed and undeveloped reserves, ending balance (MMBoe)	[1]	1,554	1,638	2,205
Proved developed reserves (MMBoe)	[1]	1,439	1,563	1,900	1,947
Proved developed producing reserves (MMBoe)	[1]	1,386	1,509	1,815	1,857
Proved undeveloped reserves (MMBoe)	[1]	115	75	305	258
Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance (MMBoe)	[1]	544	549	758
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)	[1]	21	106	(29)
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	[1]	(14)	(83)	21
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)	[1]	2	14	14
Proved developed and undeveloped reserves, production (MMBoe)	[1]	(49)	(42)	(39)
Proved developed and undeveloped reserves, sale of reserves (MMBoe)	[1]			(176)
Proved developed and undeveloped reserves, ending balance (MMBoe)	[1]	504	544	549
Proved developed reserves (MMBoe)	[1]	210	243	165	315
Proved developed producing reserves (MMBoe)	[1]	207	240	162	297
Proved undeveloped reserves (MMBoe)	[1]	294	301	384	443
[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 129

Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2016MMBoe
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	376	[1]
Proved undeveloped reserves, extensions and discoveries	78
Proved undeveloped reserves, revisions due to prices	2
Proved undeveloped reserves, revisions other than price	(5)
Proved undeveloped reserves, sale of reserves	(1)
Proved undeveloped reserves, conversion to proved developed reserves	(41)
Proved undeveloped reserves (MMBoe) ending balance	409	[1]
United States [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	75	[1]
Proved undeveloped reserves, extensions and discoveries	78
Proved undeveloped reserves, revisions due to prices	(8)
Proved undeveloped reserves, revisions other than price	(1)
Proved undeveloped reserves, sale of reserves	(1)
Proved undeveloped reserves, conversion to proved developed reserves	(28)
Proved undeveloped reserves (MMBoe) ending balance	115	[1]
Canada [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	301	[1]
Proved undeveloped reserves, revisions due to prices	10
Proved undeveloped reserves, revisions other than price	(4)
Proved undeveloped reserves, conversion to proved developed reserves	(13)
Proved undeveloped reserves (MMBoe) ending balance	294	[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 130

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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 32,519	$ 40,445	$ 107,218
Future costs:
Development	(4,985)	(6,065)	(10,787)
Production	(20,771)	(24,142)	(43,972)
Future income tax expense	(57)	(475)	(14,047)
Future net cash flow	6,706	9,763	38,412
10% discount to reflect timing of cash flows	(2,508)	(3,075)	(17,938)
Standardized measure of discounted future net cash flows	4,198	6,688	20,474	$ 15,741
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	22,847	27,398	75,847
Future costs:
Development	(2,784)	(3,306)	(7,168)
Production	(14,484)	(17,251)	(29,740)
Future income tax expense			(11,021)
Future net cash flow	5,579	6,841	27,918
10% discount to reflect timing of cash flows	(2,128)	(1,973)	(12,819)
Standardized measure of discounted future net cash flows	3,451	4,868	15,099
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	9,672	13,047	31,371
Future costs:
Development	(2,201)	(2,759)	(3,619)
Production	(6,287)	(6,891)	(14,232)
Future income tax expense	(57)	(475)	(3,026)
Future net cash flow	1,127	2,922	10,494
10% discount to reflect timing of cash flows	(380)	(1,102)	(5,119)
Standardized measure of discounted future net cash flows	$ 747	$ 1,820	$ 5,375

Supplemental Information On 131

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Information On Oil And Gas Operations [Abstract]
Standardized measure of discounted future net cash flows, beginning balance	$ 6,688	$ 20,474	$ 15,741
Net changes in prices and production costs	(2,128)	(20,756)	2,561
Oil, bitumen, gas and NGL sales, net of production costs	(2,163)	(2,704)	(6,865)
Changes in estimated future development costs	112	1,313	(768)
Extensions and discoveries, net of future development costs	660	1,129	4,836
Purchase of reserves	222	95	6,422
Sales of reserves in place	(560)	(79)	(2,384)
Revisions of quantity estimates	(32)	(1,451)	(746)
Previously estimated development costs incurred during the period	663	2,158	1,933
Accretion of discount	403	567	1,746
Foreign exchange and other	105	(1,254)	(107)
Net change in income taxes	228	7,196	(1,895)
Standardized measure of discounted future net cash flows, ending balance	$ 4,198	$ 6,688	$ 20,474

Supplemental Quarterly Finan132

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Total revenues and other	$ 3,350	$ 4,233	$ 2,488	$ 2,126	$ 2,886	$ 3,601	$ 3,393	$ 3,265	$ 12,197	$ 13,145	$ 20,638
Earnings (loss) before income taxes	375	1,178	(1,745)	(3,685)	(5,542)	(5,623)	(4,479)	(5,624)	(3,877)	(21,268)	4,059
Net earnings (loss) attributable to Devon	$ 331	$ 993	$ (1,570)	$ (3,056)	$ (4,532)	$ (3,507)	$ (2,816)	$ (3,599)	$ (3,302)	$ (14,454)	$ 1,607
Basic net earnings (loss) per share attributable to Devon	$ 0.63	$ 1.90	$ (3.04)	$ (6.44)	$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (6.52)	$ (35.55)	$ 3.93
Diluted net earnings (loss) per share attributable to Devon	$ 0.63	$ 1.89	$ (3.04)	$ (6.44)	$ (11.12)	$ (8.64)	$ (6.94)	$ (8.88)	$ (6.52)	$ (35.55)	$ 3.91

Supplemental Quarterly Finan133

Supplemental Quarterly Financial Information (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Asset impairments	$ 100	$ 300	$ 1,500	$ 3,000	$ 5,300	$ 5,900	$ 4,200	$ 5,500	$ 4,975	$ 20,820	$ 1,953
Asset impairment per diluted share	$ 0.24	$ 0.61	$ 2.89	$ 6.40	$ 13.09	$ 14.41	$ 10.27	$ 13.46
Asset dispositions and other	$ 540	$ 1,400							$ 1,893		$ 1,072
Gain on disposition of assets per diluted share	$ 1.04	$ 2.59