Devon Energy (DVN) 10-K 20 Feb 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) shares in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2018	Feb. 06, 2019	Jun. 29, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2018
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	2,018
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Document Fiscal Period Focus	FY
Entity Public Float			$ 22.5
Entity Common Stock, Shares Outstanding		438.3

Consolidated Comprehensive Stat

Consolidated Comprehensive Statements Of Earnings - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Income Statement [Abstract]
Upstream revenues	$ 6,285		$ 5,307		$ 3,981
Revenues	$ 4,449		$ 3,571		$ 2,772
Type of Revenue [Extensible List]	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember		us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember		us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember
Total revenues	$ 10,734	[1]	$ 8,878		$ 6,753
Production expenses	2,225		1,823		1,805
Exploration expenses	177		380		215
Expenses	$ 4,363		$ 3,619		$ 2,821
Type of Cost, Good or Service [Extensible List]	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember		us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember		us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember
Depreciation, depletion and amortization	$ 1,658		$ 1,529		$ 1,592
Asset impairments	156				437
Asset dispositions	(263)	[2]	(217)	[2]	(1,496)
General and administrative expenses	650		737		733
Financing costs, net	594		317		717
Restructuring and transaction costs	114				261
Other expenses	140		(83)		101
Total expenses	9,814		8,105		7,186
Earnings (loss) from continuing operations before income taxes	920	[3]	773		(433)
Income tax expense	156		15		141
Net earnings (loss) from continuing operations	764		758		(574)
Net earnings (loss) from discontinued operations, net of income tax expense	2,460	[4]	320		(884)
Net earnings (loss)	3,224		1,078		(1,458)
Net earnings (loss) attributable to noncontrolling interests	160		180		(402)
Net earnings (loss) attributable to Devon	$ 3,064		$ 898		$ (1,056)
Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share	$ 1.53		$ 1.44		$ (1.14)
Basic earnings (loss) from discontinued operations per share	4.61		0.27		(0.95)
Basic net earnings (loss) per share	6.14		1.71		(2.09)
Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share	1.52		1.43		(1.14)
Diluted earnings (loss) from discontinued operations per share	4.58		0.27		(0.95)
Diluted net earnings (loss) per share	$ 6.10		$ 1.70		$ (2.09)
Comprehensive earnings (loss):
Net earnings (loss)	$ 3,224		$ 1,078		$ (1,458)
Other comprehensive earnings (loss), net of tax:
Foreign currency translation	(152)		83		11
Pension and postretirement plans	44		29		22
Other comprehensive earnings (loss), net of tax	(108)		112		33
Comprehensive earnings (loss)	3,116		1,190		(1,425)
Comprehensive earnings (loss) attributable to noncontrolling interests	160		180		(402)
Comprehensive earnings (loss) attributable to Devon	$ 2,956		$ 1,010		$ (1,023)
[1]	Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers.
[2]	(1) Additional discussion regarding asset dispositions can be found in Note 2.
[3]	(2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5
[4]	(3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net earnings (loss)	$ 3,224		$ 1,078	$ (1,458)
Adjustments to reconcile net earnings to net cash from operating activities:
Net (earnings) loss from discontinued operations, net of income tax expense	(2,460)	[1]	(320)	884
Depreciation, depletion and amortization	1,658		1,529	1,592
Asset impairments	156			437
Leasehold impairments	95		219	113
Accretion on discounted liabilities	61		63	75
Total (gains) losses on commodity derivatives	(608)		(157)	201
Cash settlements on commodity derivatives	(84)		53	1
Gains on asset dispositions	(263)		(217)	(1,496)
Deferred income tax expense (benefit)	226		(97)	43
Share-based compensation	161		150	203
Early retirement of debt	312			269
Total (gains) losses on foreign exchange	139		(132)	(121)
Settlements of intercompany foreign denominated assets/liabilities	(241)		9	63
Other	(5)		(1)	4
Changes in assets and liabilities, net	(143)		32	24
Net cash from operating activities - continuing operations	2,228		2,209	834
Cash flows from investing activities:
Capital expenditures	(2,451)		(1,968)	(1,384)
Acquisitions of property and equipment	(55)		(46)	(849)
Divestitures of property and equipment	1,013		426	3,020
Net cash from investing activities - continuing operations	(1,493)		(1,588)	787
Cash flows from financing activities:
Repayments of long-term debt principal	(922)			(2,492)
Net short-term debt repayments				(626)
Early retirement of debt	(304)			(265)
Issuance of common stock				1,469
Repurchases of common stock	(2,956)
Dividends paid on common stock	(149)		(127)	(221)
Shares exchanged for tax withholdings	(48)		(59)	(35)
Other	(7)
Net cash from financing activities - continuing operations	(4,386)		(186)	(2,170)
Effect of exchange rate changes on cash:
Settlements of intercompany foreign denominated assets/liabilities	241		(9)	(63)
Other	(35)		15	2
Total effect of exchange rate changes on cash - continuing operations	206		6	(61)
Net change in cash, cash equivalents and restricted cash of continuing operations	(3,445)		441	(610)
Cash flows from discontinued operations:
Operating activities	476		700	666
Investing activities	2,548		(611)	(1,381)
Financing activities	183		195	974
Net change in cash, cash equivalents and restricted cash of discontinued operations	3,207		284	259
Net change in cash, cash equivalents and restricted cash	(238)		725	(351)
Cash, cash equivalents and restricted cash at beginning of period	2,684		1,959	2,310
Cash, cash equivalents and restricted cash at end of period	2,446		2,684	1,959
Reconciliation of cash, cash equivalents and restricted cash:
Cash and cash equivalents	2,414		2,642	1,947
Restricted cash included in other current assets	32		11
Cash and cash equivalents included in current assets held for sale			31	12
Cash, cash equivalents and restricted cash at end of period	$ 2,446		$ 2,684	$ 1,959
[1]	(3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
ASSETS
Cash and cash equivalents		$ 2,414	$ 2,642
Accounts receivable		885	989
Current assets held for sale		197	760
Other current assets		941	400
Total current assets		4,437	4,791
Oil and gas property and equipment, based on successful efforts accounting, net		12,813	13,318
Other property and equipment, net		1,122	1,266
Total property and equipment, net		13,935	14,584
Goodwill		841	841
Other long-term assets		353	296
Long-term assets held for sale			9,729
Total assets		19,566	30,241
LIABILITIES AND EQUITY
Accounts payable		662	633
Revenues and royalties payable		898	748
Short-term debt	[1]	162	115
Current liabilities held for sale		69	991
Other current liabilities		435	828
Total current liabilities		2,226	3,315
Long-term debt		5,785	6,749
Asset retirement obligations		1,030	1,099
Other long-term liabilities		462	549
Long-term liabilities held for sale			3,936
Deferred income taxes		877	489
Equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 450 million and 525 million shares in 2018 and 2017, respectively		45	53
Additional paid-in capital		4,486	7,333
Retained earnings		3,650	702
Accumulated other comprehensive earnings		1,027	1,166
Treasury stock, at cost, 1.0 million shares in 2018		(22)
Total stockholders’ equity attributable to Devon		9,186	9,254
Noncontrolling interests			4,850
Total equity		9,186	14,104
Total liabilities and equity		$ 19,566	$ 30,241
[1]	2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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)	450,000,000	525,000,000
Treasury stock, shares	1,000,000

Consolidated Statements Of Equi

Consolidated Statements Of 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, 2015	$ 11,111	$ 42	$ 4,996	$ 1,112	$ 1,021		$ 3,940
Balance, shares at Dec. 31, 2015		418
Net earnings (loss)	(1,458)			(1,056)			(402)
Other comprehensive earnings (loss), net of tax	33				33
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	12,722	$ 52	7,237	(69)	1,054		4,448
Balance, shares at Dec. 31, 2016		523
Net earnings (loss)	1,078			898			180
Other comprehensive earnings (loss), net of tax	112				112
Restricted stock grants, net of cancellations, value	1	$ 1
Restricted stock grants, net of cancellations, shares		1
Common stock repurchased	(44)					(44)
Common stock retired			(44)			44
Common stock dividends	(127)			(127)
Share-based compensation	126		126
Share-based compensation, shares		1
Subsidiary equity transactions	590		14				576
Distributions to noncontrolling interests	(354)						(354)
Balance at Dec. 31, 2017	14,104	$ 53	7,333	702	1,166		4,850
Balance, shares at Dec. 31, 2017		525
Net earnings (loss)	3,224			3,064			160
Other comprehensive earnings (loss), net of tax	(108)				(108)
Restricted stock grants, net of cancellations, shares		3
Common stock repurchased	(3,017)					(3,017)
Common stock retired		$ (8)	(2,987)			2,995
Common stock retired, shares		(79)
Common stock dividends	(149)			(149)
Share-based compensation	140		140
Share-based compensation, shares		1
Divestment of subsidiary equity investment	(4,861)				2		(4,863)
Subsidiary equity transactions	72						72
Distributions to noncontrolling interests	(219)						$ (219)
Other				33	(33)
Balance at Dec. 31, 2018	$ 9,186	$ 45	$ 4,486	$ 3,650	$ 1,027	$ (22)
Balance, shares at Dec. 31, 2018		450

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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. As further discussed in Note 2 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, contributions and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets. 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; • evaluation of suspended well costs; • the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; • derivative financial instruments; • the fair value of reporting units and related assessment of goodwill for impairment; • 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 Impact of ASC 606 Adoption In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. The impact of adoption in the current period results is as follows: Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) Upstream revenues $ 6,285 $ 6,031 $ 254 Marketing revenues 4,449 4,449 — Total impacted revenues $ 10,734 $ 10,480 $ 254 Production expenses $ 2,225 $ 1,971 $ 254 Marketing expenses 4,363 4,363 — Total impacted expenses $ 6,588 $ 6,334 $ 254 Earnings from continuing operations before income taxes $ 920 $ 920 $ — Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses. Upstream Revenues Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. 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. Natural gas and NGL sales Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statements of earnings. In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Oil sales Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Marketing Revenues Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership. Satisfaction of Performance Obligations and Revenue Recognitions Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the natural gas, NGLs or crude oil are delivered at a fixed or determinable price. Transaction Price Allocated to Remaining Performance Obligations Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets. Disaggregation of Revenue Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. Disaggregation of revenue disclosures can be found in Note 22 Customers During 2018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue. During 2017 and 2016, 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. 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 and costless price collars. 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. For price collars, Devon utilizes both two-way price collars and three-way price collars. The two-way 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. The three-way price collars consist of a two-way collar with an additional short put option sold by Devon, and cash-settle similarly to the two-way collars unless the market price falls below the additional short put causing the company to receive the market price plus the long put to short put price differential. 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, 2018, 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, 2018, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2018, Devon held no cash collateral of its counterparties nor posted collateral to 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. Share-Based Compensation Devon grants 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 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 generally 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 8 for further discussion. 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 unvested performance share units. 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 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, including joint interest receivables, 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 Oil and Gas Property and Equipment Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly. Capitalized costs of proved oil and gas properties 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. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production. 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 annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are amortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms. Proved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. generally accounted for as adjustments to capitalized costs with no gain or loss recognized. Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major development projects of oil and gas properties. Other Property and Equipment 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 corporate construction projects are also capitalized. Asset Retirement Obligations Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites 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 also 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 a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of each reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. Devon performed impairment tests of goodwill in the fourth quarters of 2018, 2017 and 2016. No impairment was required as a result of the annual tests in these time periods. 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 allegations of 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 2018, Devon adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash . This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon made changes to the statement of cash flows to include the required presentation and reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows. In the fourth quarter of 2018, Devon early adopted ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220) In the fourth quarter of 2018, Devon early adopted ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification Issued Accounting Standards Not Yet Adopted The FASB issued ASU 2016-02, Leases (Topic 842) Leases Devon will apply the guidance using a modified retrospective transition method at the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also has elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases. Devon will be allowed to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented with the 2019 adoption year. Devon has implemented processe

Acquisitions And Divestitures

Acquisitions And Divestitures	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions And Divestitures	2. Acquisitions and Divestitures Acquisitions In January 2016, Devon acquired approximately 80,000 net acres and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of equity. The allocation of the purchase price was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties. Divestitures EnLink and General Partner During the third quarter of 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). The proceeds from the sale were utilized to increase Devon’s share repurchase program to $4.0 billion, which is discussed further in Note 18 Note 19 Upstream Assets During 2018, Devon received proceeds of approximately $1.0 billion and recognized a net gain on asset dispositions of approximately $260 million, primarily from sales of non-core assets in the Barnett Shale and Delaware Basin. As part of the transactions, approximately $84 million of asset retirement obligations were assumed by the purchasers. In conjunction with the divestitures, Devon settled certain gas processing contracts and recognized $40 million in settlement expense, which is included in asset dispositions within the 2018 consolidated statements of earnings. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 267 MMBoe, or 18%, of total U.S. proved reserves. Additionally, in the first quarter of 2019, Devon completed two separate divestitures of non-core assets in the Permian Basin totaling $300 million. One of the divestitures related to the sale of an entire common operating field, and Devon expects to recognize a gain of approximately $35 million during the first quarter of 2019. As of December 31, 2018, these associated assets and liabilities were classified as held for sale in the accompanying consolidated balance sheet. See Note 19 During 2017, Devon received proceeds totaling approximately $420 million, and recognized a net gain on asset dispositions of $212 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves. During 2016, Devon received proceeds totaling approximately $1.9 billion and recognized a net gain on asset dispositions of $809 million, primarily from sales of non-core assets in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. Estimated proved reserves associated with these assets were approximately 157 MMBoe, or 10%, of total U.S. proved reserves. As part of the transactions, approximately $290 million of asset retirement obligations were assumed by purchasers and approximately $80 million of goodwill was allocated to these divested assets. Access Pipeline In October 2016, Devon divested its 50% interest in 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. Canada and Barnett Shale (Subsequent Event) In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from the Company, based on authorizations provided by its Board of Directors subsequent to December 31, 2018. Devon will evaluate multiple methods of separation for these assets, including potential sales or spin-offs. Devon is in the early stages of marketing these assets and does not currently have any indications that it would recognize an impairment upon separating its Canadian business or its Barnett Shale assets. Devon anticipates reporting all financial information for its Canadian business and Barnett Shale assets as discontinued operations in 2019 when all the requisite criteria are met for such financial statement presentation.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	3. Derivative Financial Instruments Commodity Derivatives As of December 31, 2018, Devon had the following open oil derivative positions. The first two tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The third 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 2019 51,719 $ 59.48 87,921 $ 54.48 $ 64.49 Q1-Q4 2020 1,740 $ 62.88 8,951 $ 52.85 $ 63.13 Three-Way Price Collars Period Volume (Bbls/d) Weighted Average Floor Sold Price ($/Bbl) Weighted Average Floor Purchased Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2019 5,000 $ 50.00 $ 63.00 $ 74.80 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2019 Midland Sweet 28,000 $ (0.46 ) Q1-Q4 2019 Argus LLS 17,500 $ 5.00 Q1-Q4 2019 Argus MEH 16,000 $ 2.84 Q1-Q4 2019 NYMEX Roll 38,000 $ 0.45 Q1-Q4 2019 Western Canadian Select 31,505 $ (21.73 ) Q1-Q4 2020 NYMEX Roll 38,000 $ 0.31 Q1-Q4 2020 Western Canadian Select 915 $ (20.75 ) As of December 31, 2018, 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 2019 266,293 $ 2.86 231,474 $ 2.69 $ 3.06 Q1-Q4 2020 26,480 $ 2.92 24,490 $ 2.74 $ 3.04 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2019 Panhandle Eastern Pipe Line 84,466 $ (0.73 ) Q1-Q4 2019 El Paso Natural Gas 130,000 $ (1.46 ) Q1-Q4 2019 Houston Ship Channel 142,637 $ 0.01 Q1-Q4 2019 Transco Zone 4 7,397 $ (0.03 ) As of December 31, 2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index. Price Swaps Period Product Volume (Bbls/d) Weighted Average Price ($/Bbl) Q1-Q4 2019 Ethane 1,000 $ 11.55 Q1-Q4 2019 Natural Gasoline 4,500 $ 55.93 Q1-Q4 2019 Normal Butane 4,000 $ 33.69 Q1-Q4 2019 Propane 8,500 $ 30.01 Interest Rate Derivatives As of December 31, 2018, Devon had the following open interest rate derivative positions: Notional Rate Received Rate Paid Expiration $ 100 1.76% Three Month LIBOR January 2019 In January 2019, this interest rate derivative position settled. 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, 2018 2017 2016 Commodity derivatives: Upstream revenues $ 608 $ 157 $ (201 ) Marketing revenues (1 ) 3 (2 ) Interest rate derivatives: Other expenses 65 (22 ) (19 ) Foreign currency derivatives: Other expenses — — (153 ) Net gains (losses) recognized $ 672 $ 138 $ (375 ) The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2018 December 31, 2017 Commodity derivative assets: Other current assets $ 637 $ 203 Other long-term assets 40 2 Interest rate derivative assets: Other current assets — 1 Total derivative assets $ 677 $ 206 Commodity derivative liabilities: Other current liabilities $ 67 $ 259 Other long-term liabilities 1 27 Interest rate derivative liabilities: Other current liabilities — 64 Total derivative liabilities $ 68 $ 350

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-Based Compensation	4. Share-Based Compensation In 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards that were transferred to the 2017 Plan in accordance with its terms). The 2017 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 units and stock appreciation rights to eligible employees. The 2017 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 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares. The vesting for certain share-based awards was accelerated in 2018 and 2016 in conjunction with the reduction of workforce activities described in Note 6 The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 G&A $ 122 $ 141 $ 124 Exploration expenses 4 7 6 Restructuring and transaction costs 31 — 60 Total $ 157 $ 148 $ 190 Related income tax benefit $ 22 $ 6 $ 6 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 12/31/17 6,328 $ 36.81 575 $ 38.92 2,758 $ 41.21 Granted 3,592 $ 35.98 — $ — 845 $ 37.40 Vested (3,114 ) $ 38.75 (273 ) $ 42.22 (571 ) $ 84.22 Forfeited (843 ) $ 35.58 — $ — (164 ) $ 33.92 Unvested at 12/31/18 5,963 $ 35.47 302 $ 35.93 2,868 (1 ) $ 30.14 (1) A maximum of 5.7 million common shares could be awarded based upon Devon’s final TSR ranking. The following table presents the aggregate fair value of awards and units that vested during the indicated period. 2018 2017 2016 Restricted Stock Awards and Units $ 111 $ 105 $ 73 Performance-Based Restricted Stock Awards $ 10 $ 10 $ 5 Performance Share Units $ 20 $ 38 $ 13 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, 2018. Performance-Based Restricted Stock Restricted Stock Performance Awards and Units Awards Share Units Unrecognized compensation cost $ 117 $ 1 $ 23 Weighted average period for recognition (years) 2.4 1.0 1.7 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 made under the 2015 Plan or 2009 Plan receive dividends that are not subject to restrictions or other limitations. However, dividends declared during the vesting period with respect to restricted stock awards made under the 2017 Plan and all restricted stock units will not be paid until the underlying award vests. 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 were 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. If the performance target is met, the recipient is entitled to dividends under the same terms described above for nonperformance-based restricted stock. 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. 2018 2017 2016 Grant-date fair value $36.23 — $ 37.88 $51.05 — $53.12 $9.24 — $10.61 Risk-free interest rate 2.28% 1.50% 0.94% Volatility factor 45.8% 45.8% 37.7% Contractual term (years) 2.89 2.89 2.83 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. No stock options were granted in 2018, 2017 and 2016. The following table presents a summary of Devon’s outstanding stock options. Weighted Average Options Exercise Price Remaining Term Intrinsic Value (Thousands) (Years) Outstanding at December 31, 2017 1,746 $ 70.04 Expired (1,029 ) $ 72.51 Outstanding at December 31, 2018 717 $ 66.49 0.87 $ — Exercisable at December 31, 2018 717 $ 66.49 0.87 $ — As of December 31, 2018, Devon had no unrecognized compensation cost related to unvested stock options.

Asset Impairments

Asset Impairments	12 Months Ended
	Dec. 31, 2018
Asset Impairment Charges [Abstract]
Asset Impairments	5. Asset Impairments The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 Proved oil and gas assets $ 109 $ — $ 435 Other assets 47 — 2 Total asset impairments $ 156 $ — $ 437 Unproved impairments $ 95 $ 217 $ 77 Proved Oil and Gas and Other Asset Impairments In 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and approximately $47 million of non-oil and gas asset impairments. In 2016, Devon impaired a portion of its U.S. oil and gas portfolio due to lower forecasted oil, gas and NGL prices. Unproved In 2018, 2017 and 2016, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments.

Restructuring and Transaction C

Restructuring and Transaction Costs	12 Months Ended
	Dec. 31, 2018
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 Balance as of December 31, 2016 $ 48 $ 62 $ 110 Changes related to prior years’ restructurings (29 ) (31 ) (60 ) Balance as of December 31, 2017 $ 19 $ 31 $ 50 Changes due to 2018 workforce reductions 30 — 30 Changes related to prior years’ restructurings (2 ) (15 ) (17 ) Balance as of December 31, 2018 $ 47 $ 16 $ 63 2018 Workforce Reductions In 2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized $114 million of restructuring expenses during 2018, primarily consisting of employee-related costs. Of these expenses, $31 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, $14 million resulted from estimated settlements of defined retirement benefits. Prior Years’ Restructurings In 2016, Devon recognized $227 million in employee-related and other costs associated with a reduction in workforce that was made in response to the depressed commodity price environment. 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. As a result of the reduction of workforce, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Devon recognized $23 million in restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using. Transaction Costs In 2016, Devon recognized $11 million in transaction costs primarily associated with the closing of the STACK acquisition discussed in Note 2

Other Expenses

Other Expenses	12 Months Ended
	Dec. 31, 2018
Other Income And Expenses [Abstract]
Other Expenses	7. Other Expenses The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 Foreign exchange (gain) loss, net $ 139 $ (132 ) $ 39 Asset retirement obligation accretion 59 62 75 Other, net (58 ) (13 ) (13 ) Total $ 140 $ (83 ) $ 101 Foreign exchange (gain) loss, net 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. The amounts in the table above include both unrealized and realized foreign exchange impacts of foreign currency denominated monetary assets and liabilities, including intercompany loans between subsidiaries with different functional currencies. Unrealized gains and losses arise from the remeasurement of these foreign currency denominated monetary assets and liabilities and intercompany loans. Realized gains and losses arise when there are settlements of these foreign currency denominated monetary assets and liabilities and intercompany loans. Foreign currency denominated intercompany loan activity during 2018 resulted in a realized loss of $ 241 195 Foreign currency denominated intercompany loan activity during 2016 resulted in a realized gain of $ 63

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	8. Income Taxes Income Tax Expense (Benefit) The following table presents Devon’s income tax components. Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit): U.S. federal $ (14 ) $ 9 $ 3 Various states (3 ) — (11 ) Canada and various provinces (53 ) 103 106 Total current tax expense (benefit) (70 ) 112 98 Deferred income tax expense (benefit): U.S. federal 248 — — Various states 63 — — Canada and various provinces (85 ) (97 ) 43 Total deferred tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141 Total income tax expense 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, 2018 2017 2016 Current income tax expense (benefit) $ (70 ) $ 112 $ 98 Deferred income tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141 U.S. statutory income tax rate 21 % 35 % 35 % U.S. Tax Reform 0 % 36 % 0 % Legal entity restructuring 2 % (94 %) 19 % State income taxes 5 % 0 % 10 % Change in unrecognized tax benefits (5 %) 2 % (16 %) Other (0 %) (13 %) 8 % Deferred tax asset valuation allowance (6 %) 36 % (89 %) Effective income tax rate 17 % 2 % (33 %) 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 judgments 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. 2018 In the second quarter of 2018, Devon’s Canadian segment utilized a portion of its capital losses as a part of an internal legal entity restructuring. A valuation allowance remains recorded against the remaining balance of the capital losses. During 2018, Devon recorded a tax benefit of $42 million related to unrecognized tax benefits, primarily as a result of a favorable Canadian court decision and the closure of prior year IRS audits. Throughout 2017 and through the first two quarters of 2018, Devon’s U.S. segment maintained a 100% valuation allowance against its U.S. deferred tax assets. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period projected net operating loss utilization, and projections of future taxable income, Devon reassessed its position and determined that its U.S. segment is no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses. As part of its reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon’s U.S. segment would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the $259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations. A partial valuation allowance continues to be held against certain Canadian segment deferred tax assets. During 2018, the Canadian segment reduced its valuation allowance by approximately $59 million. 2017 T he Tax Reform Legislation, enacted on December 22, 2017, contained several key tax provisions that affected Devon, including a one-time mandatory transition tax on accumulated foreign earnings and a reduction of the corporate income tax rate to 21% effective January 1, 2018. Devon was required to recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax, remeasuring U.S. deferred tax assets and liabilities and reassessing the net realizability of deferred tax assets and liabilities . Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings, and $108 million in deferred tax expense related to the reduction of the U.S. corporate income tax rate to 21%. In the fourth quarter of 2017, Devon’s Canadian segment generated nonrecurring capital losses from internal legal entity restructuring. A deferred tax asset of $727 million was recognized related to the capital losses, offset by a $641 million increase in the valuation allowance Devon maintained a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to asset impairments and significant net operating losses for U.S. federal and state income tax. Devon reduced its U.S. segment valuation allowance by $323 million in 2017 based primarily on the financial income recorded during the period. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets. Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in 2017 due to lower relative earnings during the period. 2016 Devon recorded a tax expense of $63 million related to unrecognized tax benefits during 2016, primarily as a result of Canadian audits and legal proceedings. During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its deferred tax assets. The allowance resulted from continued financial losses in 2016. As of December 31, 2016, the allowance continued 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. D uring the third quarter of 2016, Devon derecognized $83 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. 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, 2018 2017 Deferred tax assets: Asset retirement obligations $ 300 $ 313 Accrued liabilities 50 62 Net operating loss carryforwards 287 796 Pension benefit obligations 44 54 Canadian capital loss carryforwards 609 760 Other 87 135 Total deferred tax assets before valuation allowance 1,377 2,120 Less: valuation allowance (640 ) (968 ) Net deferred tax assets 737 1,152 Deferred tax liabilities: Property and equipment (1,473 ) (1,288 ) Long-term debt — (92 ) Other (141 ) (261 ) Total deferred tax liabilities (1,614 ) (1,641 ) Net deferred tax liability $ (877 ) $ (489 ) At December 31, 2018, Devon has recognized $287 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segment has $595 million of noncapital loss carryforwards expiring between 2029 and 2038. Devon’s U.S. segment has $389 million of U.S. federal net operating loss carryforwards expiring in 2037 and . As a result of Devon’s sale of its aggregate ownership interests in EnLink and the General Partner during the third quarter of 2018, Devon’s U.S. segment reassessed its position and released its full valuation allowance position, maintaining only $31 million of valuation allowance against certain deferred tax assets, including certain tax credits and state net operating losses. Also during 2018, Devon’s Canadian segment maintained a valuation allowance of $609 million against the deferred tax asset related to the Canadian capital loss carryforward due to projected lack of future capital gain income. 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. After enactment of the Tax Reform Legislation, Devon’s Canadian segment is the sole foreign operation to be considered for the indefinitely reinvested assertion of APB 23. Devon’s Canadian operations are robust and active and requires continuing capital investment. Accordingly, as of December 31, 2018, no income taxes should be accrued by Devon relative to its investment in its Canadian operations. In view of Devon’s decision in February 2019 to dispose of the Canadian business, the indefinitely reinvested assertion of APB 23 and any required accrual of income tax will be reevaluated in 2019. Unrecognized Tax Benefits The following table presents changes in Devon’s unrecognized tax benefits. December 31, 2018 2017 Balance at beginning of year $ 115 $ 202 Tax positions taken in prior periods (43 ) (7 ) Tax positions taken in current year (2 ) (3 ) Accrual of interest related to tax positions taken 3 16 Settlements — (101 ) Foreign currency translation (3 ) 8 Balance at end of year $ 70 $ 115 Devon’s unrecognized tax benefit balance at December 31, 2018 and 2017 included $12 million and $28 million, respectively, of interest and penalties. If recognized, $70 million of Devon’s unrecognized tax benefits as of December 31, 2018 would affect Devon’s effective income tax rate. Jurisdiction Tax Years Open U.S. Federal 2015-2018 Various U.S. states 2014-2018 Canada Federal 2004-2018 Various Canadian provinces 2004-2018 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 f

Net Earnings (Loss) Per Share from Continuing Operations	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Net Earnings (Loss) Per Share from Continuing Operations	9 . Net Earnings (Loss) Per Share from Continuing Operations The following table reconciles net earnings (loss) from continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share from continuing operations. Year Ended December 31, 2018 2017 2016 Net earnings (loss) from continuing operations: Net earnings (loss) from continuing operations $ 764 $ 758 $ (574 ) Attributable to participating securities (9 ) (8 ) (2 ) Basic and diluted earnings (loss) from continuing operations $ 755 $ 750 $ (576 ) Common shares: Common shares outstanding - total 499 525 513 Attributable to participating securities (5 ) (5 ) (6 ) Common shares outstanding - basic 494 520 507 Dilutive effect of potential common shares issuable 3 3 — Common shares outstanding - diluted 497 523 507 Net earnings (loss) per share from continuing operations: Basic $ 1.53 $ 1.44 $ (1.14 ) Diluted $ 1.52 $ 1.43 $ (1.14 ) Antidilutive options (1) 1 2 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, 2018
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease [Abstract]
Other Comprehensive Earnings	10. Other Comprehensive Earnings Components of other comprehensive earnings consist of the following: Year Ended December 31, 2018 2017 2016 Foreign currency translation: Beginning accumulated foreign currency translation $ 1,309 $ 1,226 $ 1,215 Change in cumulative translation adjustment (166 ) 113 22 Income tax benefit (expense) 14 (30 ) (11 ) Ending accumulated foreign currency translation 1,157 1,309 1,226 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (143 ) (172 ) (194 ) Net actuarial loss and prior service cost arising in current year (3 ) 10 (28 ) Recognition of net actuarial loss and prior service cost in earnings (1) 12 19 26 Curtailment and settlement of pension benefits 47 — 24 Income tax expense (12 ) — — Other (2) (33 ) — — Ending accumulated pension and postretirement benefits (132 ) (143 ) (172 ) Other 2 — — Accumulated other comprehensive earnings, net of tax $ 1,027 $ 1,166 $ 1,054 (1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 17 (2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1

Supplemental Information To Sta

Supplemental Information To Statements Of Cash Flows	12 Months Ended
	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Supplemental Information To Statements Of Cash Flows	11. Supplemental Information to Statements of Cash Flows Year Ended December 31, 2018 2017 2016 Changes in assets and liabilities, net Accounts receivable $ 88 $ (94 ) $ (58 ) Other current assets (128 ) 20 326 Other long-term assets (28 ) (47 ) 36 Accounts payable — 113 (196 ) Revenues and royalties payable 153 106 (26 ) Other current liabilities (150 ) (53 ) (74 ) Other long-term liabilities (78 ) (13 ) 16 Total $ (143 ) $ 32 $ 24 Supplementary cash flow data - total operations: Interest paid (net of capitalized interest) $ 385 $ 481 $ 569 Income taxes paid (received) $ 40 $ 78 $ (159 ) In 2016, Devon’s acquisition of certain STACK assets included the noncash issuance of Devon common stock. See Note 2

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2018
Accounts Receivable Net [Abstract]
Accounts Receivable	12. Accounts Receivable Components of accounts receivable include the following: December 31, 2018 December 31, 2017 Oil, gas and NGL sales $ 430 $ 559 Joint interest billings 155 134 Marketing revenues 285 278 Other 23 29 Gross accounts receivable 893 1,000 Allowance for doubtful accounts (8 ) (11 ) Net accounts receivable $ 885 $ 989

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Property, Plant and Equipment	13. Capitalized Costs The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities. December 31, 2018 U.S. Canada Total Property and equipment: Proved $ 40,378 $ 6,427 $ 46,805 Unproved and properties under development 833 1,434 2,267 Total oil and gas 41,211 7,861 49,072 Less accumulated DD&A (32,229 ) (4,030 ) (36,259 ) Oil and gas property and equipment, net $ 8,982 $ 3,831 $ 12,813 Other property and equipment 1,832 Less accumulated DD&A (710 ) Other property and equipment, net 1,122 Property and equipment, net $ 13,935 December 31, 2017 U.S. Canada Total Property and equipment: Proved $ 40,491 $ 6,804 $ 47,295 Unproved and properties under development 984 1,473 2,457 Total oil and gas 41,475 8,277 49,752 Less accumulated DD&A (32,379 ) (4,055 ) (36,434 ) Oil and gas property and equipment, net $ 9,096 $ 4,222 $ 13,318 Other property and equipment 1,955 Less accumulated DD&A (689 ) Other property and equipment, net 1,266 Property and equipment, net $ 14,584 Suspended Exploratory Well Costs The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2018. Year Ended December 31, 2018 2017 2016 Beginning balance $ 313 $ 261 $ 225 Additions pending determination of proved reserves 672 504 247 Charges to exploration expense — — (29 ) Reclassifications to proved properties (662 ) (466 ) (189 ) Foreign currency translation adjustment (19 ) 14 7 Ending balance $ 304 $ 313 $ 261 The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. Year Ended December 31, 2018 2017 2016 Exploratory well costs capitalized for a period of one year or less $ 110 $ 113 $ 88 Exploratory well costs capitalized for a period greater than one year 194 200 173 Ending balance $ 304 $ 313 $ 261 Number of projects with exploratory well costs capitalized for a period greater than one year 2 2 2 Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling relate to Devon’s heavy oil operations. Management believes these projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development. Currently, Devon has not planned additional exploratory work in the near future on these assets and will continue to assess its future development timeline of these long cycle projects as it competes for capital allocation within Devon’s portfolio. Devon’s interest in this acreage does not begin to expire until 2025.

Other Current Liabilities

Other Current Liabilities	12 Months Ended
	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	14. Other Current Liabilities Components of other current liabilities include the following: December 31, 2018 December 31, 2017 Derivative liabilities $ 67 $ 323 Accrued interest payable 80 96 Income taxes payable 14 144 Restructuring liabilities 47 19 Other 227 246 Other current liabilities $ 435 $ 828

Debt And Related Expenses

Debt And Related Expenses	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt and Related Expenses	15. 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, 2018 December 31, 2017 8.25% (1) $ — $ 20 2.25% — 95 6.30% 162 162 4.00% 500 500 3.25% 1,000 1,000 5.85% 485 485 7.50% (1) 73 73 7.875% (2) (3) 675 1,059 7.95% (2) 366 789 5.60% 1,250 1,250 4.75% 750 750 5.00% 750 750 Net discount on debentures and notes (24 ) (30 ) Debt issuance costs (40 ) (39 ) Total debt 5,947 6,864 Less amount classified as short-term debt (4) 162 115 Total long-term debt $ 5,785 $ 6,749 (1) 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.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. (2) These senior notes were included in 2018 tender offer repurchases discussed below. (3) Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. (4) 2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019. Debt maturities as of December 31, 2018, excluding debt issuance costs, premiums and discounts, are as follows: Total 2019 $ 162 2020 — 2021 500 2022 1,000 2023 — Thereafter 4,349 Total $ 6,011 Credit Lines Under its 2012 Senior Credit Facility, Devon had $3.0 billion of available credit. On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and subsequently entered into its new $3.0 billion revolving 2018 Senior Credit Facility. The 2018 Senior Credit Facility matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods subject to lender consent. Amounts borrowed under the 2018 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 2018 Senior Credit Facility currently provides for an annual facility fee of $6.1 million. As of December 31, 2018, Devon had $48 million in outstanding letters of credit under the 2018 Senior Credit Facility. There were no borrowings under the Senior Credit Facility as of December 31, 2018. The 2018 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. For example, total capitalization is adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 21.0%. Commercial Paper Devon’s 2018 Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the commercial paper market. As of December 31, 2018, Devon had no outstanding commercial paper borrowings. Retirement of Senior Notes During 2018, Devon completed tender offers to repurchase $807 million in aggregate principal amount of debt using cash on hand. This included $384 million of the 7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million loss on early retirement of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along with other charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings. In December 2018, Devon repaid the $95 million of 2.25% senior notes at maturity. Additionally, in January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity. During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 2 Financing Costs, Net The following schedule includes the components of net financing costs. Year Ended December 31, 2018 2017 2016 Interest based on debt outstanding $ 339 $ 390 $ 488 Early retirement of debt 312 — 269 Capitalized interest (41 ) (69 ) (61 ) Other (16 ) (4 ) 21 Total net financing costs $ 594 $ 317 $ 717

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	16. Asset Retirement Obligations The following table presents the changes in asset retirement obligations. Year Ended December 31, 2018 2017 Asset retirement obligations as of beginning of period $ 1,138 $ 1,258 Liabilities incurred 39 40 Liabilities settled and divested (116 ) (68 ) Revision of estimated obligation (25 ) (184 ) Accretion expense on discounted obligation 59 62 Foreign currency translation adjustment (38 ) 30 Asset retirement obligations as of end of period 1,057 1,138 Less current portion 27 39 Asset retirement obligations, long-term $ 1,030 $ 1,099 During 2018, Devon reduced its asset retirement obligation by $84 million, primarily as a result of Devon’s 2018 divestitures. For additional information, see Note 2 . During 2017, Devon reduced its asset retirement obligations by $184 million, primarily due to changes in the assumed inflation rate and retirement dates for its oil and gas assets.

Retirement Plans

Retirement Plans	12 Months Ended
	Dec. 31, 2018
Compensation And Retirement Disclosure [Abstract]
Retirement Plans	17. Retirement Plans Defined Contribution Plans Devon sponsors defined contribution plans covering its employees in the U.S. and Canada. Such plans include its 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. Devon contributed $50 million, $53 million and $57 million to these plans in 2018, 2017 and 2016, respectively. Defined Benefit Plans Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans covering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits under the defined benefit plans have been closed to new employees; however, eligible employees continue to accrue benefits based upon years of service and compensation. Benefits are primarily funded from assets held in the plans’ trusts. Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 70% fixed income, 20% equity and 10% other. See the following discussion for Devon’s pension assets by asset class. Fixed-income – 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 and were $193 million and $342 million at December 31, 2018 and 2017, respectively. Also, included are 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 securities are based upon the net asset values provided by the investment managers and were $301 million and $401 million at December 31, 2018 and 2017, respectively. Equity – Devon’s equity securities include commingled global equity funds that invest in large, mid and small capitalization stocks across the world’s developed and emerging markets and international large cap equity securities. These equity securities can be sold on demand but are not actively traded. The fair values of these securities are based upon the net asset values provided by the investment managers and were $84 million and $157 million at December 31, 2018 and 2017, respectively. Other – Devon’s other securities include short-term investment funds and a hedge fund that invest both long and short using a variety of investment strategies. The fair value of these securities is based upon the net asset values provided by investment managers and were $132 million and $135 million at December 31, 2018 and 2017, respectively. Defined Postretirement Plans Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. 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 summarizes the benefit obligations, assets, funded status and balance sheet impacts associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2018 and 2017. Pension Benefits Postretirement Benefits 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of year $ 1,279 $ 1,249 $ 19 $ 21 Service cost 10 15 — — Interest cost 39 42 — — Actuarial loss (gain) (83 ) 59 (3 ) — Plan amendments — — — — Plan curtailments 2 — 2 — Plan settlements (241 ) — — — Foreign exchange rate changes (3 ) 2 — — Participant contributions — — 2 1 Benefits paid (60 ) (88 ) (3 ) (3 ) Benefit obligation at end of year 943 1,279 17 19 Change in plan assets: Fair value of plan assets at beginning of year 1,035 985 — — Actual return on plan assets (36 ) 122 — — Employer contributions 14 14 1 2 Participant contributions — — 2 1 Plan settlements (241 ) — — — Benefits paid (60 ) (88 ) (3 ) (3 ) Foreign exchange rate changes (3 ) 2 — — Fair value of plan assets at end of year 709 1,035 — — Funded status at end of year $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in balance sheet: Other long-term assets $ 3 $ 4 $ — $ — Other current liabilities (14 ) (13 ) (3 ) (3 ) Other long-term liabilities (223 ) (235 ) (14 ) (16 ) Net amount $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 202 $ 257 $ (11 ) $ (11 ) Prior service cost (credit) 4 6 (2 ) (3 ) Total $ 206 $ 263 $ (13 ) $ (14 ) During the third quarter of 2018, Devon entered into a group annuity contract, under which a third party has permanently assumed certain of Devon’s defined benefit pension obligations. The purchase of this group annuity contract reduced Devon’s pension assets and liabilities and is the primary component of the $241 million of plan settlements within the preceding table. In connection with the group annuity contract transaction, Devon recorded a settlement expense of approximately $ 33 Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2018 and December 31, 2017, as presented in the table below. December 31, 2018 2017 Projected benefit obligation $ 922 $ 1,255 Accumulated benefit obligation $ 906 $ 1,226 Fair value of plan assets $ 685 $ 1,007 The following table presents the components of net periodic benefit cost and other comprehensive earnings. Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Net periodic benefit cost: Service cost $ 10 $ 15 $ 15 $ — $ — $ — Interest cost 39 42 42 — — 1 Expected return on plan assets (49 ) (54 ) (55 ) — — — Recognition of net actuarial loss (gain) (1) 13 19 25 (1 ) (1 ) (1 ) Recognition of prior service cost (1) 1 2 3 (1 ) (1 ) (1 ) Total net periodic benefit cost (2) 14 24 30 (2 ) (2 ) (1 ) Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 4 (9 ) 26 (1 ) (1 ) — Prior service cost arising in current year — — 2 — — — Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) (60 ) (19 ) (43 ) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) (2 ) (2 ) (9 ) 1 1 1 Total other comprehensive loss (earnings) (58 ) (30 ) (24 ) 1 1 2 Total recognized $ (44 ) $ (6 ) $ 6 $ (1 ) $ (1 ) $ 1 (1) These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. (2) The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings. (3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6 Assumptions Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Assumptions to determine benefit obligations: Discount rate 4.21% 3.59% 4.07% 4.01% 3.25% 3.46% Rate of compensation increase 2.50% 2.50% 4.49% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate - service cost 3.98% 4.29% 4.39% 4.13% 4.22% 3.63% Discount rate - interest cost 3.22% 2.99% 4.39% 2.67% 2.39% 3.63% Rate of compensation increase 2.50% 4.48% 4.49% N/A N/A N/A Expected return on plan assets 5.67% 5.69% 5.20% N/A N/A N/A Discount Rate - Future pension and post-retirement obligations are discounted based on the rate at which obligations could be effectively settled, considering the timing of expected future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types. Mortality rate – Devon utilized the Society of Actuaries produced mortality tables and an improvement scale derived from the updated tables for 2017 and 2018 and the actuary’s best estimate of mortality for 2016 for the population of participants in Devon’s plans. Other assumptions – For measurement of the 2018 benefit obligation for the other postretirement medical plans, a 7.1% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Expected Cash Flows Devon expects benefit plan payments to average approximately $59 million a year for the next five years and $153 million total for the five years thereafter. Of these payments to be paid in 2019, $17 million is expected to be funded from Devon’s available cash, cash equivalents and other assets.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2018
Stockholders Equity Note [Abstract]
Stockholders' Equity	18. 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 Share Repurchase Program In March 2018, Devon announced a share repurchase program to buy up to $1.0 billion of shares of common stock. In June 2018, in conjunction with the announced divestiture of its investment in EnLink and the General Partner, Devon increased its program by an additional $3.0 billion. In February 2019, Devon’s Board of Directors authorized an expansion of the share repurchase program by an additional $1.0 billion, bringing the total to $5.0 billion. The share repurchase program expires December 31, 2019. During the third quarter of 2018, Devon entered into and completed an ASR transaction to repurchase $1.0 billion of the $4.0 billion program. The table below provides information regarding purchases of Devon’s common stock that were made during 2018 (shares in thousands). Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid per Share First quarter 2018: Open-Market 2,561 $ 82 $ 32.19 Second quarter 2018: Open-Market 11,154 439 39.35 Third quarter 2018: Open-Market 16,492 712 43.13 ASR 24,330 1,000 41.10 Total 40,822 1,712 41.92 Fourth quarter 2018: Open-Market 23,612 745 31.57 Total year-to-date 78,149 $ 2,978 $ 38.11 Dividends The table below summarizes the dividends Devon paid on its common stock. Amounts Rate Per Share Year Ended 2018: First quarter $ 32 $ 0.06 Second quarter 42 $ 0.08 Third quarter 38 $ 0.08 Fourth quarter 37 $ 0.08 Total year-to-date $ 149 Year Ended 2017: First quarter $ 32 $ 0.06 Second quarter 33 $ 0.06 Third quarter 30 $ 0.06 Fourth quarter 32 $ 0.06 Total year-to-date $ 127 Year Ended 2016: First quarter $ 125 $ 0.24 Second quarter 33 $ 0.06 Third quarter 32 $ 0.06 Fourth quarter 31 $ 0.06 Total year-to-date $ 221 In response to the depressed commodity price environment, Devon reduced the quarterly dividend rate from $0.24 to $0.06 per share in the second quarter of 2016. Devon increased the quarterly dividend by 33% to $0.08 per share in the second quarter of 2018. In February 2019, Devon announced a 12.5% increase to its quarterly dividend, to $0.09 per share, beginning in the second quarter of 2019.

Discontinued Operations and Ass

Discontinued Operations and Assets Held for Sale	12 Months Ended
	Dec. 31, 2018
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations and Assets Held for Sale	19. Discontinued Operations and Assets Held For Sale On June 6, 2018, Devon announced that it had entered into an agreement to sell its aggregate ownership interests in EnLink and the General Partner for $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire midstream business ownership; 2) EnLink and the General Partner are a separate reportable segment and are a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, debt, revenues, net earnings and operating cash flows. As a result, Devon classified the results of operations and cash flows related to EnLink and the General Partner as discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was signed. On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $ 3.125 2.6 2.2 12 Note 8 As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon has minimum volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant through early 2021. From the period of July 19, 2018 through December 31, 2018, Devon had net outflows of approximately $380 million with EnLink, which primarily related to gathering and processing expenses. These net outflows represent gross cash amounts and not net working interest amounts. Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation. The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations. Year Ended December 31, 2018 2017 2016 Marketing and midstream revenues $ 3,567 $ 5,071 $ 3,551 Marketing and midstream expenses 2,912 4,111 2,712 Depreciation, depletion and amortization 244 545 504 General and administrative expenses 65 128 118 Financing costs, net 98 181 190 Asset impairments — 17 873 Asset dispositions (2,607 ) — 13 Other expenses (8 ) (34 ) 25 Total expenses 704 4,948 4,435 Earnings (loss) from discontinued operations before income taxes 2,863 123 (884 ) Income tax expense (benefit) 403 (197 ) — Net earnings (loss) from discontinued operations, net of income tax expense 2,460 320 (884 ) Net earnings (loss) attributable to noncontrolling interests 160 180 (403 ) Net earnings (loss) from discontinued operations attributable to Devon $ 2,300 $ 140 $ (481 ) The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets. The assets and liabilities classified as held for sale at December 31, 2018 are related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2 The assets and liabilities classified as held for sale at December 31, 2017 are related to the divestiture of EnLink and the General Partner. December 31, 2018 December 31, 2017 Cash and cash equivalents $ — $ 31 Accounts receivable 7 681 Other current assets — 48 Oil and gas property and equipment, based on successful efforts accounting, net 190 — Midstream and other property and equipment, net — 6,587 Goodwill — 1,542 Other long-term assets — 1,600 Total assets held for sale $ 197 $ 10,489 Accounts payable $ 3 $ 186 Revenues and royalties payable — 432 Other current liabilities 19 373 Long-term debt — 3,542 Deferred income taxes — 346 Asset retirement obligations 47 14 Other long-term liabilities — 34 Total liabilities held for sale $ 69 $ 4,927

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments And Contingencies	20. 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 likely 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 oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon 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 royalty audits 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. Beginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although we cannot predict the ultimate outcome of these matters, Devon is vigorously defending against these claims. Other Matters Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no 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, 2018. Year Ending December 31, Purchase Obligations Drilling and Facility Obligations Operational Agreements Office and Equipment Leases 2019 $ 541 $ 274 $ 587 $ 64 2020 567 85 519 43 2021 140 48 373 31 2022 — 14 419 26 2023 — 8 354 25 Thereafter — 16 3,374 311 Total $ 1,248 $ 445 $ 5,626 $ 500 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 recognized for operating leases, net of sublease income, was $11 million, $7 million and $11 million in 2018, 2017 and 2016, respectively.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	21. 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, 2018 and December 31, 2017, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets and related impairments are measured as of the impairment date using Level 3 inputs. Additional information on asset impairments and the pension plan assets is provided in Note 5 Note 17 Fair Value Measurements Using: Carrying Total Fair Level 1 Level 2 Amount Value Inputs Inputs December 31, 2018 assets (liabilities): Cash equivalents $ 1,505 $ 1,505 $ 1,405 $ 100 Commodity derivatives $ 677 $ 677 $ — $ 677 Commodity derivatives $ (68 ) $ (68 ) $ — $ (68 ) Debt $ (5,947 ) $ (5,965 ) $ — $ (5,965 ) December 31, 2017 assets (liabilities): Cash equivalents $ 1,533 $ 1,533 $ 1,454 $ 79 Commodity derivatives $ 205 $ 205 $ — $ 205 Commodity derivatives $ (286 ) $ (286 ) $ — $ (286 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (64 ) $ (64 ) $ — $ (64 ) Debt $ (6,864 ) $ (8,131 ) $ — $ (8,131 ) The following methods and assumptions were used to estimate the fair values in the tables above. Level 1 Fair Value Measurements Cash equivalents – Amounts consist primarily of money market investments and 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 and interest rate – The fair values of commodity and interest rate 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.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Information	22. 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 23 Devon considers EnLink, combined with the General Partner, to be a segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located in the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. However, with Devon’s closing of the divestment of EnLink and the General Partner in July 2018, activity related to EnLink and the General Partner have now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows, and the associated assets and liabilities of EnLink and the General Partner are presented as assets and liabilities held for sale on the consolidated balance sheets. Additional information can be found in Note 19 U.S. Canada Total Year Ended December 31, 2018: Revenues from external customers (1) $ 9,674 $ 1,060 $ 10,734 Depreciation, depletion and amortization $ 1,328 $ 330 $ 1,658 Interest expense $ 469 $ 166 $ 635 Asset impairments $ 156 $ — $ 156 Asset dispositions $ (263 ) $ — $ (263 ) Restructuring and transaction costs $ 97 $ 17 $ 114 Earnings (loss) from continuing operations before income taxes $ 1,294 $ (374 ) $ 920 Income tax expense (benefit) $ 294 $ (138 ) $ 156 Net earnings (loss) from continuing operations $ 1,000 $ (236 ) $ 764 Property and equipment, net $ 10,026 $ 3,909 $ 13,935 Total assets (2) $ 14,853 $ 4,516 $ 19,369 Capital expenditures, including acquisitions $ 2,294 $ 282 $ 2,576 Year Ended December 31, 2017: Revenues from external customers $ 7,326 $ 1,552 $ 8,878 Depreciation, depletion and amortization $ 1,149 $ 380 $ 1,529 Interest expense $ 324 $ 12 $ 336 Asset dispositions $ (218 ) $ 1 $ (217 ) Earnings from continuing operations before income taxes $ 443 $ 330 $ 773 Income tax expense $ 9 $ 6 $ 15 Net earnings from continuing operations $ 434 $ 324 $ 758 Property and equipment, net $ 10,274 $ 4,310 $ 14,584 Total assets (3) $ 14,254 $ 5,498 $ 19,752 Capital expenditures, including acquisitions $ 1,821 $ 348 $ 2,169 Year Ended December 31, 2016: Revenues from external customers $ 5,722 $ 1,031 $ 6,753 Depreciation, depletion and amortization $ 1,178 $ 414 $ 1,592 Interest expense $ 624 $ 100 $ 724 Asset impairments $ 435 $ 2 $ 437 Asset dispositions $ (955 ) $ (541 ) $ (1,496 ) Restructuring and transaction costs $ 242 $ 19 $ 261 Earnings (loss) from continuing operations before income taxes $ (757 ) $ 324 $ (433 ) Income tax expense (benefit) $ (8 ) $ 149 $ 141 Net earnings (loss) from continuing operations $ (749 ) $ 175 $ (574 ) Property and equipment, net $ 10,166 $ 4,110 $ 14,276 Total assets (3) $ 13,390 $ 5,071 $ 18,461 Capital expenditures, including acquisitions $ 2,640 $ 186 $ 2,826 (1) Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. (2) Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million. (3) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively. The following table presents revenue from contracts with customers that are disaggregated based on the type of good. Year Ended December 31, 2018 U.S. Canada Total Oil $ 2,957 $ 814 $ 3,771 Gas 950 — 950 NGL 956 — 956 Oil, gas and NGL revenues from contracts with customers 4,863 814 5,677 Oil, gas and NGL derivatives 457 151 608 Upstream revenues 5,320 965 6,285 Oil 2,745 95 2,840 Gas 738 — 738 NGL 871 — 871 Total marketing revenues from contracts with customers 4,354 95 4,449 Total revenues $ 9,674 $ 1,060 $ 10,734

Supplemental Information On Oil

Supplemental Information On Oil And Gas Operations	12 Months Ended
	Dec. 31, 2018
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Supplemental Information on Oil and Gas Operations	23. 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, 2018 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 71 — 71 Exploration costs 679 85 764 Development costs 1,537 249 1,786 Costs incurred $ 2,289 $ 334 $ 2,623 Year Ended December 31, 2017 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 50 4 54 Exploration costs 590 87 677 Development costs 1,036 225 1,261 Costs incurred $ 1,678 $ 316 $ 1,994 Year Ended December 31, 2016 U.S. Canada Total Property acquisition costs: Proved properties $ 237 $ — $ 237 Unproved properties 1,356 2 1,358 Exploration costs 282 78 360 Development costs 875 54 929 Costs incurred $ 2,750 $ 134 $ 2,884 Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations. 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. Year Ended December 31, 2018 U.S. Canada Total Oil, gas and NGL sales $ 4,863 $ 814 $ 5,677 Production expenses (1,620 ) (605 ) (2,225 ) Exploration expenses (129 ) (48 ) (177 ) Depreciation, depletion and amortization (1,234 ) (325 ) (1,559 ) Asset dispositions 262 — 262 Asset impairments (109 ) — (109 ) Accretion of asset retirement obligations (35 ) (24 ) (59 ) Income tax (expense) benefit (460 ) 51 (409 ) Results of operations $ 1,538 $ (137 ) $ 1,401 Depreciation, depletion and amortization per Boe $ 8.08 $ 7.63 $ 7.98 Year Ended December 31, 2017 U.S. Canada Total Oil, gas and NGL sales $ 3,746 $ 1,404 $ 5,150 Production expenses (1,232 ) (591 ) (1,823 ) Exploration expenses (346 ) (34 ) (380 ) Depreciation, depletion and amortization (1,050 ) (369 ) (1,419 ) Asset dispositions 211 1 212 Accretion of asset retirement obligations (38 ) (24 ) (62 ) Income tax expense — (104 ) (104 ) Results of operations $ 1,291 $ 283 $ 1,574 Depreciation, depletion and amortization per Boe $ 6.97 $ 7.73 $ 7.15 Year Ended December 31, 2016 U.S. Canada Total Oil, gas and NGL sales $ 3,198 $ 984 $ 4,182 Production expenses (1,313 ) (492 ) (1,805 ) Exploration expenses (176 ) (39 ) (215 ) Depreciation, depletion and amortization (1,066 ) (380 ) (1,446 ) Asset dispositions 946 1 947 Asset impairments (435 ) — (435 ) Accretion of asset retirement obligations (49 ) (26 ) (75 ) Income tax expense — (13 ) (13 ) Results of operations $ 1,105 $ 35 $ 1,140 Depreciation, depletion and amortization per Boe $ 6.11 $ 7.75 $ 6.47 Proved Reserves The following table presents Devon’s estimated proved reserves by product and by country. Bitumen NGL Oil (MMBbls) (MMBbls) Gas (Bcf) (MMBbls) Combined (MMBoe) (1) U.S. Canada Total Canada U.S. Canada Total U.S. U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2015 242 22 264 520 5,808 13 5,821 428 1,638 544 2,182 Revisions due to prices (18 ) (2 ) (20 ) 23 (103 ) — (103 ) (13 ) (48 ) 21 (27 ) Revisions other than price (2 ) 3 1 (19 ) 628 10 638 48 151 (14 ) 137 Extensions and discoveries 36 2 38 — 280 — 280 42 124 2 126 Purchase of reserves 8 — 8 — 33 — 33 7 20 — 20 Production (47 ) (8 ) (55 ) (40 ) (510 ) (7 ) (517 ) (42 ) (174 ) (49 ) (223 ) Sale of reserves (25 ) — (25 ) — (521 ) — (521 ) (45 ) (157 ) — (157 ) December 31, 2016 194 17 211 484 5,615 16 5,631 425 1,554 504 2,058 Revisions due to prices 12 (1 ) 11 (37 ) 398 1 399 32 111 (38 ) 73 Revisions other than price 6 2 8 (10 ) — 2 2 (10 ) (5 ) (7 ) (12 ) Extensions and discoveries 90 4 94 12 403 — 403 63 221 16 237 Production (42 ) (7 ) (49 ) (40 ) (433 ) (6 ) (439 ) (36 ) (150 ) (48 ) (198 ) Sale of reserves (3 ) — (3 ) — (9 ) — (9 ) (1 ) (6 ) — (6 ) December 31, 2017 257 15 272 409 5,974 13 5,987 473 1,725 427 2,152 Revisions due to prices 12 1 13 10 94 (3 ) 91 12 40 11 51 Revisions other than price (10 ) 2 (8 ) 2 (163 ) (4 ) (167 ) (23 ) (60 ) 3 (57 ) Extensions and discoveries 93 5 98 7 446 — 446 64 232 11 243 Production (47 ) (7 ) (54 ) (35 ) (397 ) (4 ) (401 ) (39 ) (153 ) (42 ) (195 ) Sale of reserves (7 ) — (7 ) — (1,195 ) — (1,195 ) (61 ) (267 ) — (267 ) December 31, 2018 298 16 314 393 4,759 2 4,761 426 1,517 410 1,927 Proved developed reserves: December 31, 2015 203 22 225 219 5,694 13 5,707 411 1,563 243 1,806 December 31, 2016 160 17 177 190 5,361 16 5,377 387 1,439 210 1,649 December 31, 2017 178 15 193 200 5,619 13 5,632 410 1,524 218 1,742 December 31, 2018 198 16 214 187 4,331 2 4,333 359 1,278 204 1,482 Proved developed-producing reserves: December 31, 2015 192 19 211 219 5,546 13 5,559 393 1,509 240 1,749 December 31, 2016 143 13 156 190 5,243 16 5,259 370 1,386 207 1,593 December 31, 2017 165 12 177 197 5,512 13 5,525 397 1,481 212 1,693 December 31, 2018 189 12 201 187 4,261 2 4,263 349 1,249 199 1,448 Proved undeveloped reserves: December 31, 2015 39 — 39 301 114 — 114 17 75 301 376 December 31, 2016 34 — 34 294 254 — 254 38 115 294 409 December 31, 2017 79 — 79 209 355 — 355 63 201 209 410 December 31, 2018 100 — 100 206 428 — 428 67 239 206 445 (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 2018 (MMBoe). U.S. Canada Total Proved undeveloped reserves as of December 31, 2017 201 209 410 Extensions and discoveries 107 6 113 Revisions due to prices 1 6 7 Revisions other than price (8 ) (15 ) (23 ) Sale of reserves (10 ) — (10 ) Conversion to proved developed reserves (52 ) — (52 ) Proved undeveloped reserves as of December 31, 2018 239 206 445 Total proved undeveloped reserves increased 9% from 2017 to 2018 with the year-end 2018 balance representing 23% of total proved reserves. Devon’s focus on drilling and development activities in the STACK and Delaware Basin was the primary driver of the 113 MMBoe in extensions and discoveries. Continued development primarily in the STACK and Delaware Basin led to the conversion of 52 MMBoe, or 26%, of the 2017 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $691 million for 2018. A significant amount of Devon’s proved undeveloped reserves at the end of 2018 related to its Jackfish operations. At December 31, 2018 and 2017, Devon’s Jackfish proved undeveloped reserves were 206 MMBoe and 209 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 five 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 2032. At the end of 2018, approximately 125 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 81 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 increased 40 MMBoe in the U.S. primarily due to price increases in the trailing 12 month average for oil, gas and NGLs in 2018. Reserves increased 11 MMBoe in Canada due to a decrease in the trailing 12 month average price for bitumen in 2018. The decreased price has the effect of decreasing the applicable royalties, which increases the after-royalty volumes. Reserves increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12 month average for oil, gas and NGLs in 2017. Reserves decreased 38 MMBoe in Canada due to a significant increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing the royalties, which decreases the after-royalty volumes. Reserves decreased 27 MMBoe during 2016 primarily due to lower commodity prices for oil and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes. Revisions Other Than Price Total revisions other than price in 2018 primarily related to Devon’s evaluation of certain oil and dry gas regions, with the largest revisions being made in the STACK. 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). Extensions and Discoveries 2018 – Approximately 72% of the additions were through our focused efforts in the STACK (87 MMBoe) and the Delaware Basin (88 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio. The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling activities, primarily relating to the STACK. 2017 – Over 80% of the additions were through our focused efforts in the STACK (120 MMBoe) and the Delaware Basin (79 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio. The 2017 extensions and discoveries included 66 MMBoe related to additions from Devon’s infill drilling activities primarily related to the STACK. 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 related to the STACK. Purchase of Reserves 2016 – Primarily related to Devon’s acquisition in the STACK play. Sale of Reserves Related to Devon’s 2018, 2017 and 2016 U.S. non-core asset divestitures as discussed further in Note 2 Standardized Measure The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves. Year Ended December 31, 2018 U.S. Canada Total Future cash inflows $ 40,183 $ 9,146 $ 49,329 Future costs: Development (3,444 ) (1,558 ) (5,002 ) Production (18,107 ) (5,445 ) (23,552 ) Future income tax expense (2,969 ) — (2,969 ) Future net cash flow 15,663 2,143 17,806 10% discount to reflect timing of cash flows (6,897 ) (717 ) (7,614 ) Standardized measure of discounted future net cash flows $ 8,766 $ 1,426 $ 10,192 Year Ended December 31, 2017 U.S. Canada Total Future cash inflows $ 34,701 $ 13,602 $ 48,303 Future costs: Development (3,316 ) (1,853 ) (5,169 ) Production (15,526 ) (5,986 ) (21,512 ) Future income tax expense — (988 ) (988 ) Future net cash flow 15,859 4,775 20,634 10% discount to reflect timing of cash flows (7,541 ) (1,756 ) (9,297 ) Standardized measure of discounted future net cash flows $ 8,318 $ 3,019 $ 11,337 Year Ended December 31, 2016 U.S. Canada Total Future cash inflows $ 22,847 $ 9,672 $ 32,519 Future costs: Development (2,784 ) (2,201 ) (4,985 ) Production (11,934 ) (6,049 ) (17,983 ) Future income tax expense — (121 ) (121 ) Future net cash flow 8,129 1,301 9,430 10% discount to reflect timing of cash flows (3,524 ) (466 ) (3,990 ) Standardized measure of discounted future net cash flows $ 4,605 $ 835 $ 5,440 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 2018 estimates, Devon’s future realized prices were assumed to be $58.64 per Bbl of oil, $22.12 per Bbl of bitumen, $2.45 per Mcf of gas and $24.72 per Bbl of NGLs. Of the $5.0 billion of future development costs as of the end of 2018, $1.2 billion, $0.6 billion and $0.3 billion are estimated to be spent in 2019, 2020 and 2021, 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 $1.4 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, 2018 2017 2016 Beginning balance $ 11,337 $ 5,440 $ 7,883 Net changes in prices and production costs (243 ) 5,218 (2,027 ) Oil, bitumen, gas and NGL sales, net of production costs (3,452 ) (3,327 ) (2,377 ) Changes in estimated future development costs (216 ) 789 112 Extensions and discoveries, net of future development costs 3,139 2,497 674 Purchase of reserves — 2 224 Sales of reserves in place (588 ) (3 ) (577 ) Revisions of quantity estimates (414 ) (318 ) (21 ) Previously estimated development costs incurred during the period 962 559 663 Accretion of discount 960 1,034 537 Foreign exchange and other (329 ) (7 ) 72 Net change in income taxes (964 ) (547 ) 277 Ending balance $ 10,192 $ 11,337 $ 5,440

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Data [Abstract]
Supplemental Quarterly Financial Information	24. Supplemental Quarterly Financial Information (Unaudited) The following tables present a summary of Devon’s unaudited interim results of operations. 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,198 $ 2,249 $ 2,579 $ 3,708 $ 10,734 Asset dispositions (1) $ (12 ) $ 23 $ (6 ) $ (268 ) $ (263 ) Earnings (loss) from continuing operations before income taxes (2) $ (245 ) $ (481 ) $ 162 $ 1,484 $ 920 Net earnings (loss) from continuing operations $ (211 ) $ (474 ) $ 300 $ 1,149 $ 764 Net earnings from discontinued operations, net of income tax expense (3) $ 58 $ 139 $ 2,263 $ — $ 2,460 Net earnings (loss) attributable to Devon $ (197 ) $ (425 ) $ 2,537 $ 1,149 $ 3,064 Basic net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.17 $ 2.50 $ 6.14 Diluted net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.14 $ 2.48 $ 6.10 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,400 $ 2,165 $ 1,933 $ 2,380 $ 8,878 Asset dispositions (1) $ (8 ) $ (22 ) $ (170 ) $ (17 ) $ (217 ) Earnings from continuing operations before income taxes $ 313 $ 207 $ 207 $ 46 $ 773 Net earnings from continuing operations $ 308 $ 212 $ 194 $ 44 $ 758 Net earnings from discontinued operations, net of income tax expense $ 9 $ 33 $ 18 $ 260 $ 320 Net earnings attributable to Devon $ 303 $ 219 $ 193 $ 183 $ 898 Basic net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.71 Diluted net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.70 (1) Additional discussion regarding asset dispositions can be found in Note 2. (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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, contributions and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.
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; • evaluation of suspended well costs; • the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; • derivative financial instruments; • the fair value of reporting units and related assessment of goodwill for impairment; • 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 Impact of ASC 606 Adoption In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. The impact of adoption in the current period results is as follows: Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) Upstream revenues $ 6,285 $ 6,031 $ 254 Marketing revenues 4,449 4,449 — Total impacted revenues $ 10,734 $ 10,480 $ 254 Production expenses $ 2,225 $ 1,971 $ 254 Marketing expenses 4,363 4,363 — Total impacted expenses $ 6,588 $ 6,334 $ 254 Earnings from continuing operations before income taxes $ 920 $ 920 $ — Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses. Upstream Revenues Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. 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. Natural gas and NGL sales Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statements of earnings. In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Oil sales Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Marketing Revenues Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership. Satisfaction of Performance Obligations and Revenue Recognitions Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the natural gas, NGLs or crude oil are delivered at a fixed or determinable price. Transaction Price Allocated to Remaining Performance Obligations Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets. Disaggregation of Revenue Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. Disaggregation of revenue disclosures can be found in Note 22 Customers During 2018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue. During 2017 and 2016, 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. 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 and costless price collars. 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. For price collars, Devon utilizes both two-way price collars and three-way price collars. The two-way 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. The three-way price collars consist of a two-way collar with an additional short put option sold by Devon, and cash-settle similarly to the two-way collars unless the market price falls below the additional short put causing the company to receive the market price plus the long put to short put price differential. 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, 2018, 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, 2018, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2018, Devon held no cash collateral of its counterparties nor posted collateral to 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.
Share-Based Compensation	Share-Based Compensation Devon grants 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 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 generally 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 8 for further discussion. 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 unvested performance share units.
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 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, including joint interest receivables, 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 Oil and Gas Property and Equipment Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly. Capitalized costs of proved oil and gas properties 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. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production. 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 annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are amortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms. Proved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. generally accounted for as adjustments to capitalized costs with no gain or loss recognized. Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major development projects of oil and gas properties. Other Property and Equipment 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 corporate construction projects are also capitalized. Asset Retirement Obligations Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites 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 also 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 a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of each reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. Devon performed impairment tests of goodwill in the fourth quarters of 2018, 2017 and 2016. No impairment was required as a result of the annual tests in these time periods.
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 allegations of 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 likely 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 2018, Devon adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash . This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon made changes to the statement of cash flows to include the required presentation and reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows. In the fourth quarter of 2018, Devon early adopted ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220) In the fourth quarter of 2018, Devon early adopted ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification Issued Accounting Standards Not Yet Adopted The FASB issued ASU 2016-02, Leases (Topic 842) Leases Devon will apply the guidance using a modified retrospective transition method at the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also has elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases. Devon will be allowed to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented with the 2019 adoption year. Devon has implemented processes, controls, and a technology solution needed to comply with the requirements of this ASU. To adopt Topic 842, Devon expects to recognize right-of-use assets of approximately $400 million with a corresponding lease liability based on the present value of the remaining term minimum lease payments. Devon’s right-of-use assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Additionally, Devon will recognize a $24 million before tax, $19 million net of tax cumulative-effect adjustment to reduce retained earnings. The FASB issued ASU 2018-04, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement The FASB issued ASU 2018-05-15, Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of Impact of Adoption for Revenue Recognition	The impact of adoption in the current period results is as follows: Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) Upstream revenues $ 6,285 $ 6,031 $ 254 Marketing revenues 4,449 4,449 — Total impacted revenues $ 10,734 $ 10,480 $ 254 Production expenses $ 2,225 $ 1,971 $ 254 Marketing expenses 4,363 4,363 — Total impacted expenses $ 6,588 $ 6,334 $ 254 Earnings from continuing operations before income taxes $ 920 $ 920 $ —

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 Commodity derivatives: Upstream revenues $ 608 $ 157 $ (201 ) Marketing revenues (1 ) 3 (2 ) Interest rate derivatives: Other expenses 65 (22 ) (19 ) Foreign currency derivatives: Other expenses — — (153 ) Net gains (losses) recognized $ 672 $ 138 $ (375 ) The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2018 December 31, 2017 Commodity derivative assets: Other current assets $ 637 $ 203 Other long-term assets 40 2 Interest rate derivative assets: Other current assets — 1 Total derivative assets $ 677 $ 206 Commodity derivative liabilities: Other current liabilities $ 67 $ 259 Other long-term liabilities 1 27 Interest rate derivative liabilities: Other current liabilities — 64 Total derivative liabilities $ 68 $ 350
Interest Rate Derivatives [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Notional Rate Received Rate Paid Expiration $ 100 1.76% Three Month LIBOR January 2019
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 2019 51,719 $ 59.48 87,921 $ 54.48 $ 64.49 Q1-Q4 2020 1,740 $ 62.88 8,951 $ 52.85 $ 63.13 Three-Way Price Collars Period Volume (Bbls/d) Weighted Average Floor Sold Price ($/Bbl) Weighted Average Floor Purchased Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2019 5,000 $ 50.00 $ 63.00 $ 74.80 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2019 Midland Sweet 28,000 $ (0.46 ) Q1-Q4 2019 Argus LLS 17,500 $ 5.00 Q1-Q4 2019 Argus MEH 16,000 $ 2.84 Q1-Q4 2019 NYMEX Roll 38,000 $ 0.45 Q1-Q4 2019 Western Canadian Select 31,505 $ (21.73 ) Q1-Q4 2020 NYMEX Roll 38,000 $ 0.31 Q1-Q4 2020 Western Canadian Select 915 $ (20.75 )
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 2019 266,293 $ 2.86 231,474 $ 2.69 $ 3.06 Q1-Q4 2020 26,480 $ 2.92 24,490 $ 2.74 $ 3.04 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2019 Panhandle Eastern Pipe Line 84,466 $ (0.73 ) Q1-Q4 2019 El Paso Natural Gas 130,000 $ (1.46 ) Q1-Q4 2019 Houston Ship Channel 142,637 $ 0.01 Q1-Q4 2019 Transco Zone 4 7,397 $ (0.03 )
Open NGL Derivative Positions [Member]
Derivative [Line Items]
Schedule Of Open Derivative Positions	Price Swaps Period Product Volume (Bbls/d) Weighted Average Price ($/Bbl) Q1-Q4 2019 Ethane 1,000 $ 11.55 Q1-Q4 2019 Natural Gasoline 4,500 $ 55.93 Q1-Q4 2019 Normal Butane 4,000 $ 33.69 Q1-Q4 2019 Propane 8,500 $ 30.01

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Schedule Of Share-Based Compensation Expense Included In The Consolidated Comprehensive Statements Of Earnings	Year Ended December 31, 2018 2017 2016 G&A $ 122 $ 141 $ 124 Exploration expenses 4 7 6 Restructuring and transaction costs 31 — 60 Total $ 157 $ 148 $ 190 Related income tax benefit $ 22 $ 6 $ 6
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 12/31/17 6,328 $ 36.81 575 $ 38.92 2,758 $ 41.21 Granted 3,592 $ 35.98 — $ — 845 $ 37.40 Vested (3,114 ) $ 38.75 (273 ) $ 42.22 (571 ) $ 84.22 Forfeited (843 ) $ 35.58 — $ — (164 ) $ 33.92 Unvested at 12/31/18 5,963 $ 35.47 302 $ 35.93 2,868 (1 ) $ 30.14 (1) A maximum of 5.7 million common shares could be awarded based upon Devon’s final TSR ranking.
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Aggregate Fair Value Of Awards And Units Table Text Block	2018 2017 2016 Restricted Stock Awards and Units $ 111 $ 105 $ 73 Performance-Based Restricted Stock Awards $ 10 $ 10 $ 5 Performance Share Units $ 20 $ 38 $ 13
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 $ 117 $ 1 $ 23 Weighted average period for recognition (years) 2.4 1.0 1.7
Summary Of Performance Share Units Grant-Date Fair Values And Their Related Assumptions	2018 2017 2016 Grant-date fair value $36.23 — $ 37.88 $51.05 — $53.12 $9.24 — $10.61 Risk-free interest rate 2.28% 1.50% 0.94% Volatility factor 45.8% 45.8% 37.7% Contractual term (years) 2.89 2.89 2.83
Summary Of Outstanding Stock Options, Including Changes During The Year	Weighted Average Options Exercise Price Remaining Term Intrinsic Value (Thousands) (Years) Outstanding at December 31, 2017 1,746 $ 70.04 Expired (1,029 ) $ 72.51 Outstanding at December 31, 2018 717 $ 66.49 0.87 $ — Exercisable at December 31, 2018 717 $ 66.49 0.87 $ —

Asset Impairments (Tables)

Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Impairment Charges [Abstract]
Summary of Asset Impairments	Year Ended December 31, 2018 2017 2016 Proved oil and gas assets $ 109 $ — $ 435 Other assets 47 — 2 Total asset impairments $ 156 $ — $ 437 Unproved impairments $ 95 $ 217 $ 77

Restructuring and Transaction_2

Restructuring and Transaction Costs (Tables)	12 Months Ended
	Dec. 31, 2018
Restructuring And Related Activities [Abstract]
Schedule Of The Activity And Balances Associated With Restructuring Liabilities	The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets. Other Other Current Long-term Liabilities Liabilities Total Balance as of December 31, 2016 $ 48 $ 62 $ 110 Changes related to prior years’ restructurings (29 ) (31 ) (60 ) Balance as of December 31, 2017 $ 19 $ 31 $ 50 Changes due to 2018 workforce reductions 30 — 30 Changes related to prior years’ restructurings (2 ) (15 ) (17 ) Balance as of December 31, 2018 $ 47 $ 16 $ 63

Other Expenses (Tables)

Other Expenses (Tables)	12 Months Ended
	Dec. 31, 2018
Other Income And Expenses [Abstract]
Schedule Of Other Expenses Presented In The Accompanying Consolidated Comprehensive Statements of Earnings	The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 Foreign exchange (gain) loss, net $ 139 $ (132 ) $ 39 Asset retirement obligation accretion 59 62 75 Other, net (58 ) (13 ) (13 ) Total $ 140 $ (83 ) $ 101

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule Of Income Tax Expense (Benefit)	The following table presents Devon’s income tax components. Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit): U.S. federal $ (14 ) $ 9 $ 3 Various states (3 ) — (11 ) Canada and various provinces (53 ) 103 106 Total current tax expense (benefit) (70 ) 112 98 Deferred income tax expense (benefit): U.S. federal 248 — — Various states 63 — — Canada and various provinces (85 ) (97 ) 43 Total deferred tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141
Schedule Of Effective Income Tax Rate Reconciliation	Total income tax expense 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, 2018 2017 2016 Current income tax expense (benefit) $ (70 ) $ 112 $ 98 Deferred income tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141 U.S. statutory income tax rate 21 % 35 % 35 % U.S. Tax Reform 0 % 36 % 0 % Legal entity restructuring 2 % (94 %) 19 % State income taxes 5 % 0 % 10 % Change in unrecognized tax benefits (5 %) 2 % (16 %) Other (0 %) (13 %) 8 % Deferred tax asset valuation allowance (6 %) 36 % (89 %) Effective income tax rate 17 % 2 % (33 %)
Schedule Of 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, 2018 2017 Deferred tax assets: Asset retirement obligations $ 300 $ 313 Accrued liabilities 50 62 Net operating loss carryforwards 287 796 Pension benefit obligations 44 54 Canadian capital loss carryforwards 609 760 Other 87 135 Total deferred tax assets before valuation allowance 1,377 2,120 Less: valuation allowance (640 ) (968 ) Net deferred tax assets 737 1,152 Deferred tax liabilities: Property and equipment (1,473 ) (1,288 ) Long-term debt — (92 ) Other (141 ) (261 ) Total deferred tax liabilities (1,614 ) (1,641 ) Net deferred tax liability $ (877 ) $ (489 )
Schedule Of Changes In Unrecognized Tax Benefits	The following table presents changes in Devon’s unrecognized tax benefits. December 31, 2018 2017 Balance at beginning of year $ 115 $ 202 Tax positions taken in prior periods (43 ) (7 ) Tax positions taken in current year (2 ) (3 ) Accrual of interest related to tax positions taken 3 16 Settlements — (101 ) Foreign currency translation (3 ) 8 Balance at end of year $ 70 $ 115
Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities	Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities. Jurisdiction Tax Years Open U.S. Federal 2015-2018 Various U.S. states 2014-2018 Canada Federal 2004-2018 Various Canadian provinces 2004-2018

Net Earnings (Loss) Per Share_2

Net Earnings (Loss) Per Share from Continuing Operations (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Net Earnings (Loss) Per Share Computations from Continuing Operations	Year Ended December 31, 2018 2017 2016 Net earnings (loss) from continuing operations: Net earnings (loss) from continuing operations $ 764 $ 758 $ (574 ) Attributable to participating securities (9 ) (8 ) (2 ) Basic and diluted earnings (loss) from continuing operations $ 755 $ 750 $ (576 ) Common shares: Common shares outstanding - total 499 525 513 Attributable to participating securities (5 ) (5 ) (6 ) Common shares outstanding - basic 494 520 507 Dilutive effect of potential common shares issuable 3 3 — Common shares outstanding - diluted 497 523 507 Net earnings (loss) per share from continuing operations: Basic $ 1.53 $ 1.44 $ (1.14 ) Diluted $ 1.52 $ 1.43 $ (1.14 ) Antidilutive options (1) 1 2 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, 2018
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease [Abstract]
Components Of Other Comprehensive Earnings	Components of other comprehensive earnings consist of the following: Year Ended December 31, 2018 2017 2016 Foreign currency translation: Beginning accumulated foreign currency translation $ 1,309 $ 1,226 $ 1,215 Change in cumulative translation adjustment (166 ) 113 22 Income tax benefit (expense) 14 (30 ) (11 ) Ending accumulated foreign currency translation 1,157 1,309 1,226 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (143 ) (172 ) (194 ) Net actuarial loss and prior service cost arising in current year (3 ) 10 (28 ) Recognition of net actuarial loss and prior service cost in earnings (1) 12 19 26 Curtailment and settlement of pension benefits 47 — 24 Income tax expense (12 ) — — Other (2) (33 ) — — Ending accumulated pension and postretirement benefits (132 ) (143 ) (172 ) Other 2 — — Accumulated other comprehensive earnings, net of tax $ 1,027 $ 1,166 $ 1,054 (1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 17 (2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1

Supplemental Information To S_2

Supplemental Information To Statements Of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Schedule Of Supplemental Information To Statements Of Cash Flows	Year Ended December 31, 2018 2017 2016 Changes in assets and liabilities, net Accounts receivable $ 88 $ (94 ) $ (58 ) Other current assets (128 ) 20 326 Other long-term assets (28 ) (47 ) 36 Accounts payable — 113 (196 ) Revenues and royalties payable 153 106 (26 ) Other current liabilities (150 ) (53 ) (74 ) Other long-term liabilities (78 ) (13 ) 16 Total $ (143 ) $ 32 $ 24 Supplementary cash flow data - total operations: Interest paid (net of capitalized interest) $ 385 $ 481 $ 569 Income taxes paid (received) $ 40 $ 78 $ (159 )

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2018
Accounts Receivable Net [Abstract]
Schedule Of Components Of Accounts Receivable	Components of accounts receivable include the following: December 31, 2018 December 31, 2017 Oil, gas and NGL sales $ 430 $ 559 Joint interest billings 155 134 Marketing revenues 285 278 Other 23 29 Gross accounts receivable 893 1,000 Allowance for doubtful accounts (8 ) (11 ) Net accounts receivable $ 885 $ 989

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Table of Property and Equipment, net	The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities. December 31, 2018 U.S. Canada Total Property and equipment: Proved $ 40,378 $ 6,427 $ 46,805 Unproved and properties under development 833 1,434 2,267 Total oil and gas 41,211 7,861 49,072 Less accumulated DD&A (32,229 ) (4,030 ) (36,259 ) Oil and gas property and equipment, net $ 8,982 $ 3,831 $ 12,813 Other property and equipment 1,832 Less accumulated DD&A (710 ) Other property and equipment, net 1,122 Property and equipment, net $ 13,935 December 31, 2017 U.S. Canada Total Property and equipment: Proved $ 40,491 $ 6,804 $ 47,295 Unproved and properties under development 984 1,473 2,457 Total oil and gas 41,475 8,277 49,752 Less accumulated DD&A (32,379 ) (4,055 ) (36,434 ) Oil and gas property and equipment, net $ 9,096 $ 4,222 $ 13,318 Other property and equipment 1,955 Less accumulated DD&A (689 ) Other property and equipment, net 1,266 Property and equipment, net $ 14,584
Summary of Changes in Suspended Exploratory Well Costs	The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2018. Year Ended December 31, 2018 2017 2016 Beginning balance $ 313 $ 261 $ 225 Additions pending determination of proved reserves 672 504 247 Charges to exploration expense — — (29 ) Reclassifications to proved properties (662 ) (466 ) (189 ) Foreign currency translation adjustment (19 ) 14 7 Ending balance $ 304 $ 313 $ 261
Schedule of Aging of Capitalized Exploratory Well Costs	The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. Year Ended December 31, 2018 2017 2016 Exploratory well costs capitalized for a period of one year or less $ 110 $ 113 $ 88 Exploratory well costs capitalized for a period greater than one year 194 200 173 Ending balance $ 304 $ 313 $ 261 Number of projects with exploratory well costs capitalized for a period greater than one year 2 2 2

Other Current Liabilities (Tabl

Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Schedule Of Other Current Liabilities	December 31, 2018 December 31, 2017 Derivative liabilities $ 67 $ 323 Accrued interest payable 80 96 Income taxes payable 14 144 Restructuring liabilities 47 19 Other 227 246 Other current liabilities $ 435 $ 828

Debt And Related Expenses (Tabl

Debt And Related Expenses (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule Of Debt Instruments and Balances	See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon. December 31, 2018 December 31, 2017 8.25% (1) $ — $ 20 2.25% — 95 6.30% 162 162 4.00% 500 500 3.25% 1,000 1,000 5.85% 485 485 7.50% (1) 73 73 7.875% (2) (3) 675 1,059 7.95% (2) 366 789 5.60% 1,250 1,250 4.75% 750 750 5.00% 750 750 Net discount on debentures and notes (24 ) (30 ) Debt issuance costs (40 ) (39 ) Total debt 5,947 6,864 Less amount classified as short-term debt (4) 162 115 Total long-term debt $ 5,785 $ 6,749 (1) 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.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. (2) These senior notes were included in 2018 tender offer repurchases discussed below. (3) Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. (4) 2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019.
Schedule of Debt Maturities	Total 2019 $ 162 2020 — 2021 500 2022 1,000 2023 — Thereafter 4,349 Total $ 6,011
Schedule Of Net Financing Cost Components	Year Ended December 31, 2018 2017 2016 Interest based on debt outstanding $ 339 $ 390 $ 488 Early retirement of debt 312 — 269 Capitalized interest (41 ) (69 ) (61 ) Other (16 ) (4 ) 21 Total net financing costs $ 594 $ 317 $ 717

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Summary Of Changes In Asset Retirement Obligations	Year Ended December 31, 2018 2017 Asset retirement obligations as of beginning of period $ 1,138 $ 1,258 Liabilities incurred 39 40 Liabilities settled and divested (116 ) (68 ) Revision of estimated obligation (25 ) (184 ) Accretion expense on discounted obligation 59 62 Foreign currency translation adjustment (38 ) 30 Asset retirement obligations as of end of period 1,057 1,138 Less current portion 27 39 Asset retirement obligations, long-term $ 1,030 $ 1,099

Retirement Plans (Tables)

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Compensation And Retirement Disclosure [Abstract]
Schedule Of Changes In Defined Benefit Plan Obligations	Pension Benefits Postretirement Benefits 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of year $ 1,279 $ 1,249 $ 19 $ 21 Service cost 10 15 — — Interest cost 39 42 — — Actuarial loss (gain) (83 ) 59 (3 ) — Plan amendments — — — — Plan curtailments 2 — 2 — Plan settlements (241 ) — — — Foreign exchange rate changes (3 ) 2 — — Participant contributions — — 2 1 Benefits paid (60 ) (88 ) (3 ) (3 ) Benefit obligation at end of year 943 1,279 17 19 Change in plan assets: Fair value of plan assets at beginning of year 1,035 985 — — Actual return on plan assets (36 ) 122 — — Employer contributions 14 14 1 2 Participant contributions — — 2 1 Plan settlements (241 ) — — — Benefits paid (60 ) (88 ) (3 ) (3 ) Foreign exchange rate changes (3 ) 2 — — Fair value of plan assets at end of year 709 1,035 — — Funded status at end of year $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in balance sheet: Other long-term assets $ 3 $ 4 $ — $ — Other current liabilities (14 ) (13 ) (3 ) (3 ) Other long-term liabilities (223 ) (235 ) (14 ) (16 ) Net amount $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 202 $ 257 $ (11 ) $ (11 ) Prior service cost (credit) 4 6 (2 ) (3 ) Total $ 206 $ 263 $ (13 ) $ (14 )
Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets	Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2018 and December 31, 2017, as presented in the table below. December 31, 2018 2017 Projected benefit obligation $ 922 $ 1,255 Accumulated benefit obligation $ 906 $ 1,226 Fair value of plan assets $ 685 $ 1,007
Schedule Of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Postretirement Benefit Plans	Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Net periodic benefit cost: Service cost $ 10 $ 15 $ 15 $ — $ — $ — Interest cost 39 42 42 — — 1 Expected return on plan assets (49 ) (54 ) (55 ) — — — Recognition of net actuarial loss (gain) (1) 13 19 25 (1 ) (1 ) (1 ) Recognition of prior service cost (1) 1 2 3 (1 ) (1 ) (1 ) Total net periodic benefit cost (2) 14 24 30 (2 ) (2 ) (1 ) Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 4 (9 ) 26 (1 ) (1 ) — Prior service cost arising in current year — — 2 — — — Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) (60 ) (19 ) (43 ) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) (2 ) (2 ) (9 ) 1 1 1 Total other comprehensive loss (earnings) (58 ) (30 ) (24 ) 1 1 2 Total recognized $ (44 ) $ (6 ) $ 6 $ (1 ) $ (1 ) $ 1 (1) These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. (2) The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings. (3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6
Schedule Of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost	Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Assumptions to determine benefit obligations: Discount rate 4.21% 3.59% 4.07% 4.01% 3.25% 3.46% Rate of compensation increase 2.50% 2.50% 4.49% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate - service cost 3.98% 4.29% 4.39% 4.13% 4.22% 3.63% Discount rate - interest cost 3.22% 2.99% 4.39% 2.67% 2.39% 3.63% Rate of compensation increase 2.50% 4.48% 4.49% N/A N/A N/A Expected return on plan assets 5.67% 5.69% 5.20% N/A N/A N/A

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2018
Stockholders Equity Note [Abstract]
Summary of Purchases of Common Stock	The table below provides information regarding purchases of Devon’s common stock that were made during 2018 (shares in thousands). Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid per Share First quarter 2018: Open-Market 2,561 $ 82 $ 32.19 Second quarter 2018: Open-Market 11,154 439 39.35 Third quarter 2018: Open-Market 16,492 712 43.13 ASR 24,330 1,000 41.10 Total 40,822 1,712 41.92 Fourth quarter 2018: Open-Market 23,612 745 31.57 Total year-to-date 78,149 $ 2,978 $ 38.11
Summary Of Dividends Paid On Common Stock	The table below summarizes the dividends Devon paid on its common stock. Amounts Rate Per Share Year Ended 2018: First quarter $ 32 $ 0.06 Second quarter 42 $ 0.08 Third quarter 38 $ 0.08 Fourth quarter 37 $ 0.08 Total year-to-date $ 149 Year Ended 2017: First quarter $ 32 $ 0.06 Second quarter 33 $ 0.06 Third quarter 30 $ 0.06 Fourth quarter 32 $ 0.06 Total year-to-date $ 127 Year Ended 2016: First quarter $ 125 $ 0.24 Second quarter 33 $ 0.06 Third quarter 32 $ 0.06 Fourth quarter 31 $ 0.06 Total year-to-date $ 221

Discontinued Operations and A_2

Discontinued Operations and Assets Held for Sale (Tables)	12 Months Ended
	Dec. 31, 2018
Discontinued Operations And Disposal Groups [Abstract]
Summary of Amounts Reported as Discontinued Operations in the Consolidated Comprehensive Statements of Earnings and Carrying Amounts of Assets and Liabilities Classified as Held for Sale on the Consolidated Balance Sheets	The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations. Year Ended December 31, 2018 2017 2016 Marketing and midstream revenues $ 3,567 $ 5,071 $ 3,551 Marketing and midstream expenses 2,912 4,111 2,712 Depreciation, depletion and amortization 244 545 504 General and administrative expenses 65 128 118 Financing costs, net 98 181 190 Asset impairments — 17 873 Asset dispositions (2,607 ) — 13 Other expenses (8 ) (34 ) 25 Total expenses 704 4,948 4,435 Earnings (loss) from discontinued operations before income taxes 2,863 123 (884 ) Income tax expense (benefit) 403 (197 ) — Net earnings (loss) from discontinued operations, net of income tax expense 2,460 320 (884 ) Net earnings (loss) attributable to noncontrolling interests 160 180 (403 ) Net earnings (loss) from discontinued operations attributable to Devon $ 2,300 $ 140 $ (481 ) The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets. The assets and liabilities classified as held for sale at December 31, 2018 are related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2 The assets and liabilities classified as held for sale at December 31, 2017 are related to the divestiture of EnLink and the General Partner. December 31, 2018 December 31, 2017 Cash and cash equivalents $ — $ 31 Accounts receivable 7 681 Other current assets — 48 Oil and gas property and equipment, based on successful efforts accounting, net 190 — Midstream and other property and equipment, net — 6,587 Goodwill — 1,542 Other long-term assets — 1,600 Total assets held for sale $ 197 $ 10,489 Accounts payable $ 3 $ 186 Revenues and royalties payable — 432 Other current liabilities 19 373 Long-term debt — 3,542 Deferred income taxes — 346 Asset retirement obligations 47 14 Other long-term liabilities — 34 Total liabilities held for sale $ 69 $ 4,927

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
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 2019 $ 541 $ 274 $ 587 $ 64 2020 567 85 519 43 2021 140 48 373 31 2022 — 14 419 26 2023 — 8 354 25 Thereafter — 16 3,374 311 Total $ 1,248 $ 445 $ 5,626 $ 500

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
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 December 31, 2018 assets (liabilities): Cash equivalents $ 1,505 $ 1,505 $ 1,405 $ 100 Commodity derivatives $ 677 $ 677 $ — $ 677 Commodity derivatives $ (68 ) $ (68 ) $ — $ (68 ) Debt $ (5,947 ) $ (5,965 ) $ — $ (5,965 ) December 31, 2017 assets (liabilities): Cash equivalents $ 1,533 $ 1,533 $ 1,454 $ 79 Commodity derivatives $ 205 $ 205 $ — $ 205 Commodity derivatives $ (286 ) $ (286 ) $ — $ (286 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (64 ) $ (64 ) $ — $ (64 ) Debt $ (6,864 ) $ (8,131 ) $ — $ (8,131 )

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments	U.S. Canada Total Year Ended December 31, 2018: Revenues from external customers (1) $ 9,674 $ 1,060 $ 10,734 Depreciation, depletion and amortization $ 1,328 $ 330 $ 1,658 Interest expense $ 469 $ 166 $ 635 Asset impairments $ 156 $ — $ 156 Asset dispositions $ (263 ) $ — $ (263 ) Restructuring and transaction costs $ 97 $ 17 $ 114 Earnings (loss) from continuing operations before income taxes $ 1,294 $ (374 ) $ 920 Income tax expense (benefit) $ 294 $ (138 ) $ 156 Net earnings (loss) from continuing operations $ 1,000 $ (236 ) $ 764 Property and equipment, net $ 10,026 $ 3,909 $ 13,935 Total assets (2) $ 14,853 $ 4,516 $ 19,369 Capital expenditures, including acquisitions $ 2,294 $ 282 $ 2,576 Year Ended December 31, 2017: Revenues from external customers $ 7,326 $ 1,552 $ 8,878 Depreciation, depletion and amortization $ 1,149 $ 380 $ 1,529 Interest expense $ 324 $ 12 $ 336 Asset dispositions $ (218 ) $ 1 $ (217 ) Earnings from continuing operations before income taxes $ 443 $ 330 $ 773 Income tax expense $ 9 $ 6 $ 15 Net earnings from continuing operations $ 434 $ 324 $ 758 Property and equipment, net $ 10,274 $ 4,310 $ 14,584 Total assets (3) $ 14,254 $ 5,498 $ 19,752 Capital expenditures, including acquisitions $ 1,821 $ 348 $ 2,169 Year Ended December 31, 2016: Revenues from external customers $ 5,722 $ 1,031 $ 6,753 Depreciation, depletion and amortization $ 1,178 $ 414 $ 1,592 Interest expense $ 624 $ 100 $ 724 Asset impairments $ 435 $ 2 $ 437 Asset dispositions $ (955 ) $ (541 ) $ (1,496 ) Restructuring and transaction costs $ 242 $ 19 $ 261 Earnings (loss) from continuing operations before income taxes $ (757 ) $ 324 $ (433 ) Income tax expense (benefit) $ (8 ) $ 149 $ 141 Net earnings (loss) from continuing operations $ (749 ) $ 175 $ (574 ) Property and equipment, net $ 10,166 $ 4,110 $ 14,276 Total assets (3) $ 13,390 $ 5,071 $ 18,461 Capital expenditures, including acquisitions $ 2,640 $ 186 $ 2,826 (1) Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. (2) Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million. (3) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively.
Schedule of Revenue from Contracts with Customers Disaggregated Based on Type of Good	Year Ended December 31, 2018 U.S. Canada Total Oil $ 2,957 $ 814 $ 3,771 Gas 950 — 950 NGL 956 — 956 Oil, gas and NGL revenues from contracts with customers 4,863 814 5,677 Oil, gas and NGL derivatives 457 151 608 Upstream revenues 5,320 965 6,285 Oil 2,745 95 2,840 Gas 738 — 738 NGL 871 — 871 Total marketing revenues from contracts with customers 4,354 95 4,449 Total revenues $ 9,674 $ 1,060 $ 10,734 The following table presents revenue from contracts with customers that are disaggregated based on the type of good.

Supplemental Information On O_2

Supplemental Information On Oil And Gas Operations (Tables)	12 Months Ended
	Dec. 31, 2018
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Costs Incurred	Year Ended December 31, 2018 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 71 — 71 Exploration costs 679 85 764 Development costs 1,537 249 1,786 Costs incurred $ 2,289 $ 334 $ 2,623 Year Ended December 31, 2017 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 50 4 54 Exploration costs 590 87 677 Development costs 1,036 225 1,261 Costs incurred $ 1,678 $ 316 $ 1,994 Year Ended December 31, 2016 U.S. Canada Total Property acquisition costs: Proved properties $ 237 $ — $ 237 Unproved properties 1,356 2 1,358 Exploration costs 282 78 360 Development costs 875 54 929 Costs incurred $ 2,750 $ 134 $ 2,884
Results Of Operations	Year Ended December 31, 2018 U.S. Canada Total Oil, gas and NGL sales $ 4,863 $ 814 $ 5,677 Production expenses (1,620 ) (605 ) (2,225 ) Exploration expenses (129 ) (48 ) (177 ) Depreciation, depletion and amortization (1,234 ) (325 ) (1,559 ) Asset dispositions 262 — 262 Asset impairments (109 ) — (109 ) Accretion of asset retirement obligations (35 ) (24 ) (59 ) Income tax (expense) benefit (460 ) 51 (409 ) Results of operations $ 1,538 $ (137 ) $ 1,401 Depreciation, depletion and amortization per Boe $ 8.08 $ 7.63 $ 7.98 Year Ended December 31, 2017 U.S. Canada Total Oil, gas and NGL sales $ 3,746 $ 1,404 $ 5,150 Production expenses (1,232 ) (591 ) (1,823 ) Exploration expenses (346 ) (34 ) (380 ) Depreciation, depletion and amortization (1,050 ) (369 ) (1,419 ) Asset dispositions 211 1 212 Accretion of asset retirement obligations (38 ) (24 ) (62 ) Income tax expense — (104 ) (104 ) Results of operations $ 1,291 $ 283 $ 1,574 Depreciation, depletion and amortization per Boe $ 6.97 $ 7.73 $ 7.15 Year Ended December 31, 2016 U.S. Canada Total Oil, gas and NGL sales $ 3,198 $ 984 $ 4,182 Production expenses (1,313 ) (492 ) (1,805 ) Exploration expenses (176 ) (39 ) (215 ) Depreciation, depletion and amortization (1,066 ) (380 ) (1,446 ) Asset dispositions 946 1 947 Asset impairments (435 ) — (435 ) Accretion of asset retirement obligations (49 ) (26 ) (75 ) Income tax expense — (13 ) (13 ) Results of operations $ 1,105 $ 35 $ 1,140 Depreciation, depletion and amortization per Boe $ 6.11 $ 7.75 $ 6.47
Proved Reserves	Bitumen NGL Oil (MMBbls) (MMBbls) Gas (Bcf) (MMBbls) Combined (MMBoe) (1) U.S. Canada Total Canada U.S. Canada Total U.S. U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2015 242 22 264 520 5,808 13 5,821 428 1,638 544 2,182 Revisions due to prices (18 ) (2 ) (20 ) 23 (103 ) — (103 ) (13 ) (48 ) 21 (27 ) Revisions other than price (2 ) 3 1 (19 ) 628 10 638 48 151 (14 ) 137 Extensions and discoveries 36 2 38 — 280 — 280 42 124 2 126 Purchase of reserves 8 — 8 — 33 — 33 7 20 — 20 Production (47 ) (8 ) (55 ) (40 ) (510 ) (7 ) (517 ) (42 ) (174 ) (49 ) (223 ) Sale of reserves (25 ) — (25 ) — (521 ) — (521 ) (45 ) (157 ) — (157 ) December 31, 2016 194 17 211 484 5,615 16 5,631 425 1,554 504 2,058 Revisions due to prices 12 (1 ) 11 (37 ) 398 1 399 32 111 (38 ) 73 Revisions other than price 6 2 8 (10 ) — 2 2 (10 ) (5 ) (7 ) (12 ) Extensions and discoveries 90 4 94 12 403 — 403 63 221 16 237 Production (42 ) (7 ) (49 ) (40 ) (433 ) (6 ) (439 ) (36 ) (150 ) (48 ) (198 ) Sale of reserves (3 ) — (3 ) — (9 ) — (9 ) (1 ) (6 ) — (6 ) December 31, 2017 257 15 272 409 5,974 13 5,987 473 1,725 427 2,152 Revisions due to prices 12 1 13 10 94 (3 ) 91 12 40 11 51 Revisions other than price (10 ) 2 (8 ) 2 (163 ) (4 ) (167 ) (23 ) (60 ) 3 (57 ) Extensions and discoveries 93 5 98 7 446 — 446 64 232 11 243 Production (47 ) (7 ) (54 ) (35 ) (397 ) (4 ) (401 ) (39 ) (153 ) (42 ) (195 ) Sale of reserves (7 ) — (7 ) — (1,195 ) — (1,195 ) (61 ) (267 ) — (267 ) December 31, 2018 298 16 314 393 4,759 2 4,761 426 1,517 410 1,927 Proved developed reserves: December 31, 2015 203 22 225 219 5,694 13 5,707 411 1,563 243 1,806 December 31, 2016 160 17 177 190 5,361 16 5,377 387 1,439 210 1,649 December 31, 2017 178 15 193 200 5,619 13 5,632 410 1,524 218 1,742 December 31, 2018 198 16 214 187 4,331 2 4,333 359 1,278 204 1,482 Proved developed-producing reserves: December 31, 2015 192 19 211 219 5,546 13 5,559 393 1,509 240 1,749 December 31, 2016 143 13 156 190 5,243 16 5,259 370 1,386 207 1,593 December 31, 2017 165 12 177 197 5,512 13 5,525 397 1,481 212 1,693 December 31, 2018 189 12 201 187 4,261 2 4,263 349 1,249 199 1,448 Proved undeveloped reserves: December 31, 2015 39 — 39 301 114 — 114 17 75 301 376 December 31, 2016 34 — 34 294 254 — 254 38 115 294 409 December 31, 2017 79 — 79 209 355 — 355 63 201 209 410 December 31, 2018 100 — 100 206 428 — 428 67 239 206 445 (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, 2017 201 209 410 Extensions and discoveries 107 6 113 Revisions due to prices 1 6 7 Revisions other than price (8 ) (15 ) (23 ) Sale of reserves (10 ) — (10 ) Conversion to proved developed reserves (52 ) — (52 ) Proved undeveloped reserves as of December 31, 2018 239 206 445
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended December 31, 2018 U.S. Canada Total Future cash inflows $ 40,183 $ 9,146 $ 49,329 Future costs: Development (3,444 ) (1,558 ) (5,002 ) Production (18,107 ) (5,445 ) (23,552 ) Future income tax expense (2,969 ) — (2,969 ) Future net cash flow 15,663 2,143 17,806 10% discount to reflect timing of cash flows (6,897 ) (717 ) (7,614 ) Standardized measure of discounted future net cash flows $ 8,766 $ 1,426 $ 10,192 Year Ended December 31, 2017 U.S. Canada Total Future cash inflows $ 34,701 $ 13,602 $ 48,303 Future costs: Development (3,316 ) (1,853 ) (5,169 ) Production (15,526 ) (5,986 ) (21,512 ) Future income tax expense — (988 ) (988 ) Future net cash flow 15,859 4,775 20,634 10% discount to reflect timing of cash flows (7,541 ) (1,756 ) (9,297 ) Standardized measure of discounted future net cash flows $ 8,318 $ 3,019 $ 11,337 Year Ended December 31, 2016 U.S. Canada Total Future cash inflows $ 22,847 $ 9,672 $ 32,519 Future costs: Development (2,784 ) (2,201 ) (4,985 ) Production (11,934 ) (6,049 ) (17,983 ) Future income tax expense — (121 ) (121 ) Future net cash flow 8,129 1,301 9,430 10% discount to reflect timing of cash flows (3,524 ) (466 ) (3,990 ) Standardized measure of discounted future net cash flows $ 4,605 $ 835 $ 5,440
Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves	Year Ended December 31, 2018 2017 2016 Beginning balance $ 11,337 $ 5,440 $ 7,883 Net changes in prices and production costs (243 ) 5,218 (2,027 ) Oil, bitumen, gas and NGL sales, net of production costs (3,452 ) (3,327 ) (2,377 ) Changes in estimated future development costs (216 ) 789 112 Extensions and discoveries, net of future development costs 3,139 2,497 674 Purchase of reserves — 2 224 Sales of reserves in place (588 ) (3 ) (577 ) Revisions of quantity estimates (414 ) (318 ) (21 ) Previously estimated development costs incurred during the period 962 559 663 Accretion of discount 960 1,034 537 Foreign exchange and other (329 ) (7 ) 72 Net change in income taxes (964 ) (547 ) 277 Ending balance $ 10,192 $ 11,337 $ 5,440

Supplemental Quarterly Financ_2

Supplemental Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Data [Abstract]
Schedule Of Quarterly Financial Information	The following tables present a summary of Devon’s unaudited interim results of operations. 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,198 $ 2,249 $ 2,579 $ 3,708 $ 10,734 Asset dispositions (1) $ (12 ) $ 23 $ (6 ) $ (268 ) $ (263 ) Earnings (loss) from continuing operations before income taxes (2) $ (245 ) $ (481 ) $ 162 $ 1,484 $ 920 Net earnings (loss) from continuing operations $ (211 ) $ (474 ) $ 300 $ 1,149 $ 764 Net earnings from discontinued operations, net of income tax expense (3) $ 58 $ 139 $ 2,263 $ — $ 2,460 Net earnings (loss) attributable to Devon $ (197 ) $ (425 ) $ 2,537 $ 1,149 $ 3,064 Basic net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.17 $ 2.50 $ 6.14 Diluted net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.14 $ 2.48 $ 6.10 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,400 $ 2,165 $ 1,933 $ 2,380 $ 8,878 Asset dispositions (1) $ (8 ) $ (22 ) $ (170 ) $ (17 ) $ (217 ) Earnings from continuing operations before income taxes $ 313 $ 207 $ 207 $ 46 $ 773 Net earnings from continuing operations $ 308 $ 212 $ 194 $ 44 $ 758 Net earnings from discontinued operations, net of income tax expense $ 9 $ 33 $ 18 $ 260 $ 320 Net earnings attributable to Devon $ 303 $ 219 $ 193 $ 183 $ 898 Basic net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.71 Diluted net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.70 (1) Additional discussion regarding asset dispositions can be found in Note 2. (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Schedule of Impact of Adoption for Revenue Recognition) (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Upstream revenues													$ 6,285		$ 5,307	$ 3,981
Revenues													$ 4,449		$ 3,571	$ 2,772
Type of Revenue [Extensible List]													us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember		us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember
Total impacted revenues	$ 3,708		$ 2,579		$ 2,249		$ 2,198		$ 2,380	$ 1,933	$ 2,165	$ 2,400	$ 10,734	[1]	$ 8,878	$ 6,753
Production expenses													2,225		1,823	1,805
Expenses													$ 4,363		$ 3,619	$ 2,821
Type of Cost, Good or Service [Extensible List]													us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember		us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember
Total impacted expenses													$ 6,588
Earnings from continuing operations before income taxes	$ 1,484	[2]	$ 162	[2]	$ (481)	[2]	$ (245)	[2]	$ 46	$ 207	$ 207	$ 313	920	[2]	$ 773	$ (433)
Under ASC 605 [Member] | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Upstream revenues													6,031
Revenues													$ 4,449
Type of Revenue [Extensible List]													us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember
Total impacted revenues													$ 10,480
Production expenses													1,971
Expenses													$ 4,363
Type of Cost, Good or Service [Extensible List]													us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember
Total impacted expenses													$ 6,334
Earnings from continuing operations before income taxes													920
Increase/(Decrease) of Under ASC 606 and Under ASC 605 [Member] | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Upstream revenues													254
Total impacted revenues													254
Production expenses													254
Total impacted expenses													$ 254
[1]	Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers.
[2]	(2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)Customer	Dec. 31, 2017USD ($)Customer	Dec. 31, 2016USD ($)Customer
Summary Of Significant Accounting Policies [Line Items]
Concentration risk percentage | Customer	1	0	0
Derivative collateral held	$ 0
Cash collateral posted	0
ASU 2017-07 [Member]
Summary Of Significant Accounting Policies [Line Items]
Reclassification of non-service cost components of net periodic benefit costs		$ 7,000,000	$ 14,000,000
ASU 2018-02 [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative effect on retained earnings	33,000,000
ASU 2016-02 [Member] | Scenario Plan [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative effect on retained earnings	(19,000,000)
Right-of-use assets expects to recognize	400,000,000
Cumulative effect on retained earnings, before tax	$ (24,000,000)
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, useful life	3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, useful life	60 years
Customer Concentration Risk [Member] | One Customer [Member] | Consolidated Sales Revenue [Member]
Summary Of Significant Accounting Policies [Line Items]
Concentration risk percentage	11.00%
Upstream Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days allowed for payment from end of production month	30 days
Marketing Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days allowed for payment of invoiced amount	30 days

Acquisitions And Divestitures (

Acquisitions And Divestitures (Narrative) (Details) $ in Millions, $ in Millions		Jan. 07, 2016USD ($)a	Oct. 31, 2016USD ($)	Oct. 31, 2016CAD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)		Sep. 30, 2018USD ($)		Jun. 30, 2018USD ($)	[1]	Mar. 31, 2018USD ($)		Dec. 31, 2017USD ($)	[1]	Sep. 30, 2017USD ($)	[1]	Jun. 30, 2017USD ($)	[1]	Mar. 31, 2017USD ($)	[1]	Dec. 31, 2018USD ($)MMBoe		Dec. 31, 2017USD ($)MMBoe		Dec. 31, 2016USD ($)MMBoe
Business Acquisition [Line Items]
Gain on sale of aggregate ownership interests, before-tax																						$ 2,607				$ (13)
Gain on asset dispositions						$ 268	[1]	$ 6	[1]	$ (23)		$ 12	[1]	$ 17		$ 170		$ 22		$ 8		263	[1]	$ 217	[1]	$ 1,496
Asset retirement obligations assumed by purchasers																						$ 116		$ 68
Total estimated proved reserves | MMBoe	[2]																					267		6		157
US [Member]
Business Acquisition [Line Items]
Total estimated proved reserves | MMBoe	[2]																					267		6		157
Non Core Assets [Member] | US [Member]
Business Acquisition [Line Items]
Divestitures of property and equipment																						$ 1,000		$ 420		$ 1,900
Gain on asset dispositions																						260		$ 212		809
Asset retirement obligations assumed by purchasers																						84				$ 290
Settlement expenses relating to gas processing contracts																						$ 40
Total estimated proved reserves | MMBoe																						267				157
Percentage of Estimated proved reserves associated with divestiture assets																						18.00%				10.00%
Goodwill allocated to divested assets																										$ 80
Non Core Assets [Member] | Permian Basin [Member]
Business Acquisition [Line Items]
Total estimated proved reserves | MMBoe																						25
Non Core Assets [Member] | Permian Basin [Member] | Scenario, Forecast [Member]
Business Acquisition [Line Items]
Divestitures of property and equipment					$ 300
Gain on asset dispositions					$ 35
Access Pipeline [Member]
Business Acquisition [Line Items]
Divestitures of property and equipment			$ 1,100	$ 1,400
Gain on asset dispositions			$ 540
Ownership interest			50.00%	50.00%
Divestiture agreement dedication initial term			25 years	25 years
Access Pipeline [Member] | Scenario Plan [Member]
Business Acquisition [Line Items]
Divestitures of property and equipment				$ 150
EnLink and General Partner [Member]
Business Acquisition [Line Items]
Proceeds from sale of aggregate ownership interest								3,125														$ 3,125
Gain on sale of aggregate ownership interests, after-tax								2,200														2,200
Gain on sale of aggregate ownership interests, before-tax								2,600														$ 2,600
Maximum [Member] | Non Core Assets [Member] | US [Member]
Business Acquisition [Line Items]
Percentage of Estimated proved reserves associated with divestiture assets																								1.00%
Maximum [Member] | Non Core Assets [Member] | Permian Basin [Member]
Business Acquisition [Line Items]
Percentage of Estimated proved reserves associated with divestiture assets																						2.00%
Maximum [Member] | Access Pipeline [Member]
Business Acquisition [Line Items]
Potential pipeline capacity committed, percentage			90.00%	90.00%
Maximum [Member] | Share Repurchase Program [Member]
Business Acquisition [Line Items]
Share repurchase program, maximum authorized amount								$ 4,000				$ 1,000
STACK [Member]
Business Acquisition [Line Items]
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
Proved properties						$ 200																$ 200
STACK [Member] | Common Stock [Member] | Equity Issued in Business Combination [Member]
Business Acquisition [Line Items]
Equity units value		$ 659
[1]	(1) Additional discussion regarding asset dispositions can be found in Note 2.
[2]	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.

Derivative Financial Instrume_3

Derivative Financial Instruments (Schedule Of Open Oil Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2018$ / bblbbl
NYMEX West Texas Intermediate Price Swaps Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	51,719
Weighted Average Price Swap	59.48
NYMEX West Texas Intermediate Price Swaps Oil Q1-Q4 2020 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	1,740
Weighted Average Price Swap	62.88
NYMEX West Texas Intermediate Price Collars Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	87,921
Weighted Average Floor Price	54.48
Weighted Average Ceiling Price	64.49
NYMEX West Texas Intermediate Price Collars Oil Q1-Q4 2020 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	8,951
Weighted Average Floor Price	52.85
Weighted Average Ceiling Price	63.13
NYMEX West Texas Intermediate Three-Way Price Collars Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	5,000
Weighted Average Ceiling Price	74.80
Weighted Average Floor Sold Price	50
Weighted Average Floor Purchased Price	63
Midland Sweet Basis Swaps Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	28,000
Weighted Average Differential To WTI	(0.46)
Argus LLS Basis Swaps Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	17,500
Weighted Average Differential To WTI	5
Argus MEH Basis Swaps Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	16,000
Weighted Average Differential To WTI	2.84
NYMEX Roll Basis Swaps Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	38,000
Weighted Average Differential To WTI	0.45
Western Canadian Select Basis Swaps Oil Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	31,505
Weighted Average Differential To WTI	(21.73)
NYMEX Roll Basis Swaps Oil Q1-Q4 2020 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	38,000
Weighted Average Differential To WTI	0.31
Western Canadian Select Basis Swaps Oil Q1-Q4 2020 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	915
Weighted Average Differential To WTI	(20.75)

Derivative Financial Instrume_4

Derivative Financial Instruments (Schedule Of Open Natural Gas Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2018MMBTU$ / MMBTU
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	266,293
Weighted Average Price Swap	2.86
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2020 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	26,480
Weighted Average Price Swap	2.92
FERC Henry Hub Price Collars Natural Gas Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	231,474
Weighted Average Floor Price	2.69
Weighted Average Ceiling Price	3.06
FERC Henry Hub Price Collars Natural Gas Q1-Q4 2020 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	24,490
Weighted Average Floor Price	2.74
Weighted Average Ceiling Price	3.04
PEPL Basis Swaps Natural Gas Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	84,466
Weighted Average Differential To Henry Hub	(0.73)
El Paso Natural Gas Basis Swaps Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	130,000
Weighted Average Differential To Henry Hub	(1.46)
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	142,637
Weighted Average Differential To Henry Hub	0.01
Transco Zone 4 Natural Gas Basis Swaps Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) | MMBTU	7,397
Weighted Average Differential To Henry Hub	(0.03)

Derivative Financial Instrume_5

Derivative Financial Instruments (Schedule Of Open NGL Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2018$ / bblbbl
OPIS Mont Belvieu Texas Ethane Price Swaps NGL Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	1,000
Weighted Average Price Swap | $ / bbl	11.55
OPIS Mont Belvieu Texas Natural Gasoline Price Swaps NGL Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	4,500
Weighted Average Price Swap | $ / bbl	55.93
OPIS Mont Belvieu Texas Normal Butane Price Swaps NGL Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	4,000
Weighted Average Price Swap | $ / bbl	33.69
OPIS Mont Belvieu Texas Propane Price Swaps NGL Q1-Q4 2019 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) | bbl	8,500
Weighted Average Price Swap | $ / bbl	30.01

Derivative Financial Instrume_6

Derivative Financial Instruments (Schedule Of Open Interest Rate Swap Derivative Positions) (Details) - Interest Rate Contract 1.76% Expiration January 2019 [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Derivative [Line Items]
Notional	$ 100
Rate Received, percent	1.76%
Rate Paid	Three Month LIBOR
Expiration	Jan. 31, 2019

Derivative Financial Instrume_7

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	$ 672	$ 138	$ (375)
Commodity Derivatives [Member] | Upstream Revenues [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	608	157	(201)
Commodity Derivatives [Member] | Marketing Revenues [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	(1)	3	(2)
Interest Rate Derivatives [Member] | Other Expenses [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings	$ 65	$ (22)	(19)
Foreign Currency Derivatives [Member] | Other Expenses [Member]
Derivative [Line Items]
Net gains (losses) recognized in consolidated comprehensive statements of earnings			$ (153)

Derivative Financial Instrume_8

Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Fair value of derivative assets	$ 677	$ 206
Fair value of derivative liabilities	68	350
Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities	67	323
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative assets	637	203
Commodity Derivatives [Member] | Other Long-Term Assets [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative assets	40	2
Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities	67	259
Commodity Derivatives [Member] | Other Long-Term Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities	$ 1	27
Interest Rate Derivatives [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative assets		1
Interest Rate Derivatives [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Fair value of derivative liabilities		$ 64

Share-Based Compensation (Narra

Share-Based Compensation (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)Companyshares	Dec. 31, 2017shares	Dec. 31, 2016shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock options granted	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
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
2017 Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares authorized for issuance		33,500,000
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, options and stock appreciation rights		1
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, other awards		2.3

Share-Based Compensation (Sched

Share-Based Compensation (Schedule Of Share-Based Compensation Expense Included In The Consolidated Comprehensive Statements Of Earnings) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	$ 157	$ 148	$ 190
Related income tax benefit	22	6	6
G&A [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	122	141	124
Exploration Expenses [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	4	$ 7	6
Restructuring and Transaction Costs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Accelerated share-based compensation expense	$ 31		$ 60

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, 2018$ / sharesshares
Restricted Stock Awards And Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested at December 31, 2017 | shares	6,328
Granted, awards and units | shares	3,592
Vested, awards and units | shares	(3,114)
Forfeited, awards and units | shares	(843)
Unvested at December 31, 2018 | shares	5,963
Unvested weighted average grant-date fair value at December 31, 2017 | $ / shares	$ 36.81
Granted, weighted average grant-date fair value | $ / shares	35.98
Vested, weighted average grant-date fair value | $ / shares	38.75
Forfeited, weighted average grant-date fair value | $ / shares	35.58
Unvested weighted average grant-date fair value at December 31, 2018 | $ / shares	$ 35.47
Performance-Based Restricted Stock Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested at December 31, 2017 | shares	575
Vested, awards and units | shares	(273)
Unvested at December 31, 2018 | shares	302
Unvested weighted average grant-date fair value at December 31, 2017 | $ / shares	$ 38.92
Vested, weighted average grant-date fair value | $ / shares	42.22
Unvested weighted average grant-date fair value at December 31, 2018 | $ / shares	$ 35.93
Performance Share Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested at December 31, 2017 | shares	2,758
Granted, awards and units | shares	845
Vested, awards and units | shares	(571)
Forfeited, awards and units | shares	(164)
Unvested at December 31, 2018 | shares	2,868	[1]
Unvested weighted average grant-date fair value at December 31, 2017 | $ / shares	$ 41.21
Granted, weighted average grant-date fair value | $ / shares	37.40
Vested, weighted average grant-date fair value | $ / shares	84.22
Forfeited, weighted average grant-date fair value | $ / shares	33.92
Unvested weighted average grant-date fair value at December 31, 2018 | $ / shares	$ 30.14
[1]	A maximum of 5.7 million common shares could be awarded based upon Devon’s final TSR ranking.

Share-Based Compensation (Sum_2

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, 2018shares
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	5.7

Share-Based Compensation (Sch_2

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, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ 111	$ 105	$ 73
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	10	10	5
Performance Share Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate fair value of awards and units, vested	$ 20	$ 38	$ 13

Share-Based Compensation (Sum_3

Share-Based Compensation (Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Restricted Stock Awards And Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost	$ 117
Weighted average period for recognition (years)	2 years 4 months 24 days
Performance-Based Restricted Stock Awards [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost	$ 1
Weighted average period for recognition (years)	1 year
Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost	$ 23
Weighted average period for recognition (years)	1 year 8 months 12 days

Share-Based Compensation (Sum_4

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant-date fair value	$ 37.40
Risk-free interest rate	2.28%	1.50%	0.94%
Volatility factor	45.80%	45.80%	37.70%
Contractual term (years)	2 years 10 months 20 days	2 years 10 months 20 days	2 years 9 months 29 days
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant-date fair value	$ 36.23	$ 51.05	$ 9.24
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant-date fair value	$ 37.88	$ 53.12	$ 10.61

Share-Based Compensation (Sum_5

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, 2018$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding at December 31, 2017 | shares	1,746
Options, Expired | shares	(1,029)
Outstanding at December 31, 2018 | shares	717
Exercisable at December 31, 2018 | shares	717
Weighted average exercise price, Outstanding, December 31, 2017 | $ / shares	$ 70.04
Expired, weighted average exercise price | $ / shares	72.51
Weighted average exercise price, Outstanding, December 31, 2018 | $ / shares	66.49
Exercisable at December 31, 2018 | $ / shares	$ 66.49
Outstanding, weighted average remaining term	10 months 13 days
Excercisable, weighted average remaining term	10 months 13 days

Asset Impairments (Summary of A

Asset Impairments (Summary of Asset Impairments) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Impaired Long Lived Assets Held And Used [Line Items]
Asset impairment charges	$ 150	$ 156		$ 437
Proved Oil and Gas Assets [Member]
Impaired Long Lived Assets Held And Used [Line Items]
Asset impairment charges		109		435
Unproved Impairments [Member]
Impaired Long Lived Assets Held And Used [Line Items]
Asset impairment charges		95	$ 217	77
Other Assets [Member]
Impaired Long Lived Assets Held And Used [Line Items]
Asset impairment charges		$ 47		$ 2

Asset Impairments (Narrative) (

Asset Impairments (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2016
Impaired Long Lived Assets Held And Used [Line Items]
Asset impairments	$ 150	$ 156	$ 437
Proved Asset Impairments [Member]
Impaired Long Lived Assets Held And Used [Line Items]
Asset impairments		109
Non-oil and Gas Asset Impairments [Member]
Impaired Long Lived Assets Held And Used [Line Items]
Asset impairments		$ 47

Restructuring and Transaction_3

Restructuring and Transaction Costs (Schedule Of The Activity And Balances Associated With Restructuring Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Restructuring Cost And Reserve [Line Items]
Beginning balance	$ 50	$ 110
Ending balance	63	50
Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	30
Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	(17)	(60)
Other Current Liabilities [Member]
Restructuring Cost And Reserve [Line Items]
Beginning balance	19	48
Ending balance	47	19
Other Current Liabilities [Member] | Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	30
Other Current Liabilities [Member] | Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	(2)	(29)
Other Long-Term Liabilities [Member]
Restructuring Cost And Reserve [Line Items]
Beginning balance	31	62
Ending balance	16	31
Other Long-Term Liabilities [Member] | Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring reserve activity	$ (15)	$ (31)

Restructuring and Transaction_4

Restructuring and Transaction Costs (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2016
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	$ 114	$ 261
Transaction Costs [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs		11
Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	114
Expense associated with accelerated awards	31	60
Reduction of workforce [Member] | Estimated Defined Benefit Settlements [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	$ 14	24
Reduction of workforce [Member] | Employee Related Costs [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs		227
Reduction of workforce [Member] | Lease Obligations [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs		$ 23

Other Expenses (Schedule Of Oth

Other Expenses (Schedule Of Other Expenses Presented In The Accompanying Consolidated Comprehensive Statements of Earnings) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Income And Expenses [Abstract]
Foreign exchange (gain) loss, net	$ 139	$ (132)	$ 39
Asset retirement obligation accretion	59	62	75
Other, net	(58)	(13)	(13)
Total	$ 140	$ (83)	$ 101

Other Expenses (Narrative) (Det

Other Expenses (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2016
Other Income And Expenses [Abstract]
Foreign currency realized gain (loss)	$ (241)	$ 63
Foreign currency unrealized gain (losses)	$ (195)	$ 10

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current income tax expense (benefit):
United States federal, current income tax expense (benefit)	$ (14)	$ 9	$ 3
Various states, current income tax expense (benefit)	(3)		(11)
Canada and various provinces, current income tax expense (benefit)	(53)	103	106
Total current tax expense (benefit)	(70)	112	98
Deferred income tax expense (benefit):
United States federal, deferred income tax expense (benefit)	248
Various states, deferred income tax expense (benefit)	63
Canada and various provinces, deferred income tax expense (benefit)	(85)	(97)	43
Total deferred tax expense (benefit)	226	(97)	43
Total income tax expense	$ 156	$ 15	$ 141

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Current income tax expense (benefit)	$ (70)	$ 112	$ 98
Deferred income tax expense (benefit)	226	(97)	43
Total income tax expense	$ 156	$ 15	$ 141
U.S. statutory income tax rate	21.00%	35.00%	35.00%
U.S. Tax Reform	0.00%	36.00%	0.00%
Legal entity restructuring	2.00%	(94.00%)	19.00%
State income taxes	5.00%	0.00%	10.00%
Change in unrecognized tax benefits	(5.00%)	2.00%	(16.00%)
Other	0.00%	(13.00%)	8.00%
Deferred tax asset valuation allowance	(6.00%)	36.00%	(89.00%)
Effective income tax rate	17.00%	2.00%	(33.00%)

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2016	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax [Line Items]
Tax benefit related to unrecognized tax benefits					$ 42
Valuation allowance against U.S. deferred tax assets, percent				100.00%		100.00%	100.00%
Gain on sale of aggregate ownership interests, before-tax					2,607		$ (13)
Deferred tax benefit resulting from release of valuation allowance position; allocated to discontinued operations					$ 259
U.S. statutory income tax rate					21.00%	35.00%	35.00%
Deferred income tax expense (benefit)					$ 226	$ (97)	$ 43
Capital loss carryforward, deferred tax asset		$ 760			609	760
Tax expense related to unrecognized tax benefits							63
Deferred tax assets, valuation allowance		968			640	968
Net operating loss carryforwards, deferred tax assets		796			287	796
Unrecognized tax benefits, interest and penalties		28			12	28
Unrecognized tax benefit that would impact effective tax rate					70
Unrecognized tax benefits removed					43	7
Interest associated with tax examinations					$ 20
United States Federal [Member]
Income Tax [Line Items]
Net operating loss carryforward, expiration date					Dec. 31, 2037
Net operating loss carryforwards					$ 389
Various U.S. States [Member]
Income Tax [Line Items]
Net operating loss carryforwards					$ 784
Minimum [Member] | United States Federal [Member]
Income Tax [Line Items]
Operating loss carryforward, utilization period					Dec. 31, 2019
Minimum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Net operating loss carryforward, expiration date					Dec. 31, 2019
Operating loss carryforward, utilization period					Dec. 31, 2019
Minimum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Net operating loss carryforward, expiration date					Dec. 31, 2029
Operating loss carryforward, utilization period					Dec. 31, 2019
Maximum [Member] | Various U.S. States [Member]
Income Tax [Line Items]
Net operating loss carryforward, expiration date					Dec. 31, 2038
Maximum [Member] | Canada Federal [Member]
Income Tax [Line Items]
Net operating loss carryforward, expiration date					Dec. 31, 2038
Canada [Member]
Income Tax [Line Items]
Change in deferred tax valuation allowance		641			$ (59)
Capital loss carryforward, deferred tax asset		727				727
Deferred tax assets, valuation allowance					609		71
Net operating loss carryforwards					595
U.S. [Member]
Income Tax [Line Items]
Change in deferred tax valuation allowance						$ (323)	$ 313
Deferred tax assets, valuation allowance					31
Allocated goodwill			$ 83
U.S. [Member] | Transition Tax [Member]
Income Tax [Line Items]
Deferred income tax expense (benefit)		167
U.S. [Member] | Change in Income Tax Rate [Member]
Income Tax [Line Items]
Deferred income tax expense (benefit)		$ 108
EnLink and General Partner [Member]
Income Tax [Line Items]
Gain on sale of aggregate ownership interests, before-tax	$ 2,600				$ 2,600

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Deferred tax assets, asset retirement obligations	$ 300	$ 313
Deferred tax assets, accrued liabilities	50	62
Deferred tax assets, net operating loss carryforwards	287	796
Deferred tax assets, pension benefit obligations	44	54
Deferred tax assets, Canadian capital loss carryforwards	609	760
Deferred tax assets, other	87	135
Total deferred tax assets before valuation allowance	1,377	2,120
Less: valuation allowance	(640)	(968)
Net deferred tax assets	737	1,152
Deferred tax liabilities, property and equipment	(1,473)	(1,288)
Deferred tax liabilities, long-term debt		(92)
Deferred tax liabilities, other	(141)	(261)
Total deferred tax liabilities	(1,614)	(1,641)
Net deferred tax liability	$ (877)	$ (489)

Income Taxes (Schedule Of Chang

Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Unrecognized tax benefits, Balance at beginning of year	$ 115	$ 202
Unrecognized tax benefits, Tax positions taken in prior periods	(43)	(7)
Unrecognized tax benefits, Tax positions taken in current year	(2)	(3)
Unrecognized tax benefits, Accrual of interest related to tax positions taken	3	16
Unrecognized tax benefits, Settlements		(101)
Unrecognized tax benefits, Foreign currency translation	(3)	8
Unrecognized tax benefits, Balance at end of year	$ 70	$ 115

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, 2018
Minimum [Member] | United States Federal [Member]
Tax years open	2,015
Minimum [Member] | Canada Federal [Member]
Tax years open	2,004
Maximum [Member] | United States Federal [Member]
Tax years open	2,018
Maximum [Member] | Canada Federal [Member]
Tax years open	2,018
Various U.S. States [Member] | Minimum [Member]
Tax years open	2,014
Various U.S. States [Member] | Maximum [Member]
Tax years open	2,018
Various Canadian Provinces [Member] | Minimum [Member]
Tax years open	2,004
Various Canadian Provinces [Member] | Maximum [Member]
Tax years open	2,018

Net Earnings (Loss) Per Share_3

Net Earnings (Loss) Per Share from Continuing Operations (Earnings Per Share Computations from Continuing Operations) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net earnings (loss) from continuing operations:
Net earnings (loss) from continuing operations		$ 1,149	$ 300	$ (474)	$ (211)	$ 44	$ 194	$ 212	$ 308	$ 764	$ 758	$ (574)
Attributable to participating securities										(9)	(8)	(2)
Basic and diluted earnings (loss) from continuing operations										$ 755	$ 750	$ (576)
Common shares:
Common shares outstanding - total										499	525	513
Attributable to participating securities										(5)	(5)	(6)
Common shares outstanding - basic										494	520	507
Dilutive effect of potential common shares issuable										3	3
Common shares outstanding - diluted										497	523	507
Net earnings (loss) per share from continuing operations:
Basic										$ 1.53	$ 1.44	$ (1.14)
Diluted										$ 1.52	$ 1.43	$ (1.14)
Antidilutive options	[1]									1	2	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, 2018	Dec. 31, 2017	Dec. 31, 2016
Foreign currency translation:
Beginning accumulated foreign currency translation		$ 1,309	$ 1,226	$ 1,215
Change in cumulative translation adjustment		(166)	113	22
Income tax benefit (expense)		14	(30)	(11)
Ending accumulated foreign currency translation		1,157	1,309	1,226
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(143)	(172)	(194)
Net actuarial loss and prior service cost arising in current year		(3)	10	(28)
Recognition of net actuarial loss and prior service cost in earnings	[1]	12	19	26
Curtailment and settlement of pension benefits		47		24
Income tax expense		(12)
Other	[2]	(33)
Ending accumulated pension and postretirement benefits		(132)	(143)	(172)
Other		2
Accumulated other comprehensive earnings, net of tax		$ 1,027	$ 1,166	$ 1,054
[1]	(1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 17
[2]	(2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1

Other Comprehensive Earnings _2

Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Accumulated Other Comprehensive Income Loss [Line Items]
Effect of new accounting pronouncement	$ (33)	[1]
ASU 2018-02 [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Effect of new accounting pronouncement	$ (33)
[1]	(2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1

Supplemental Information To S_3

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in assets and liabilities, net
Accounts receivable	$ 88	$ (94)	$ (58)
Other current assets	(128)	20	326
Other long-term assets	(28)	(47)	36
Accounts payable		113	(196)
Revenues and royalties payable	153	106	(26)
Other current liabilities	(150)	(53)	(74)
Other long-term liabilities	(78)	(13)	16
Total	(143)	32	24
Supplementary cash flow data - total operations:
Interest paid (net of capitalized interest)	385	481	569
Income taxes paid (received)	$ 40	$ 78	$ (159)

Accounts Receivable (Schedule O

Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Joint interest billings	$ 155	$ 134
Other	23	29
Gross accounts receivable	893	1,000
Allowance for doubtful accounts	(8)	(11)
Net accounts receivable	885	989
Oil, Gas and NGL Sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	430	559
Marketing Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	$ 285	$ 278

Property, Plant and Equipment_2

Property, Plant and Equipment (Table of Property and Equipment, net) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property and equipment:
Proved	$ 46,805	$ 47,295
Unproved and properties under development	2,267	2,457
Total oil and gas	49,072	49,752
Less accumulated DD&A	(36,259)	(36,434)
Oil and gas property and equipment, net	12,813	13,318
Other property and equipment	1,832	1,955
Less accumulated DD&A	(710)	(689)
Other property and equipment, net	1,122	1,266
Total property and equipment, net	13,935	14,584	$ 14,276
US [Member]
Property and equipment:
Proved	40,378	40,491
Unproved and properties under development	833	984
Total oil and gas	41,211	41,475
Less accumulated DD&A	(32,229)	(32,379)
Oil and gas property and equipment, net	8,982	9,096
Canada [Member]
Property and equipment:
Proved	6,427	6,804
Unproved and properties under development	1,434	1,473
Total oil and gas	7,861	8,277
Less accumulated DD&A	(4,030)	(4,055)
Oil and gas property and equipment, net	$ 3,831	$ 4,222

Property, Plant and Equipment_3

Property, Plant and Equipment (Summary of Changes in Suspended Exploratory Well Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase Decrease In Capitalized Exploratory Well Costs That Are Pending Determination Of Proved Reserves Roll Forward
Beginning balance	$ 313	$ 261	$ 225
Additions pending determination of proved reserves	672	504	247
Charges to exploration expense			(29)
Reclassifications to proved properties	(662)	(466)	(189)
Foreign currency translation adjustment	(19)	14	7
Ending balance	$ 304	$ 313	$ 261

Property, Plant and Equipment_4

Property, Plant and Equipment (Schedule of Aging of Capitalized Exploratory Well Costs (Details) $ in Millions	Dec. 31, 2018USD ($)Project	Dec. 31, 2017USD ($)Project	Dec. 31, 2016USD ($)Project	Dec. 31, 2015USD ($)
Schedule Of Aging Of Capitalized Exploratory Well Costs [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 110	$ 113	$ 88
Exploratory well costs capitalized for a period greater than one year	194	200	173
Ending balance	$ 304	$ 313	$ 261	$ 225
Number of projects with exploratory well costs capitalized for a period greater than one year | Project	2	2	2

Other Current Liabilities (Sche

Other Current Liabilities (Schedule Of Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Other Liabilities, Current [Abstract]
Derivative liabilities	$ 68	$ 350
Accrued interest payable	80	96
Income taxes payable	14	144
Restructuring liabilities	47	19
Other	227	246
Other current liabilities	435	828
Other Current Liabilities [Member]
Other Liabilities, Current [Abstract]
Derivative liabilities	$ 67	$ 323

Debt And Related Expenses (Sche

Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Short-term debt	[1]	$ 162	$ 115
Long-term debt, gross		6,011
Net discount on debentures and notes		(24)	(30)
Debt issuance costs		(40)	(39)
Total debt		5,947	6,864
Total long-term debt		$ 5,785	6,749
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Short-term debt	[2]		$ 20
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]
Short-term debt			$ 95
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]
Short-term debt		$ 162
Long-term debt, gross			$ 162
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		$ 485	$ 485
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]	$ 73	$ 73
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]	$ 675	$ 1,059
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	[4]	$ 366	$ 789
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%
[1]	2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019.
[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.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.
[3]	Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon.
[4]	These senior notes were included in 2018 tender offer repurchases discussed below.

Debt And Related Expenses (Sc_2

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, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Short-term debt	[1]		$ 162	$ 115
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage			8.25%	8.25%
Short-term debt	[2]			$ 20
Debt, maturity date			Jul. 1, 2018
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 interest rate, stated percentage			7.50%	7.50%
Debt, maturity date			Sep. 15, 2027
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%
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage			6.30%	6.30%
Short-term debt			$ 162
Debt, maturity date			Jan. 15, 2019
[1]	2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019.
[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.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.

Debt And Related Expenses (Sc_3

Debt And Related Expenses (Schedule Of Debt Maturities) (Details) $ in Millions	Dec. 31, 2018USD ($)
Debt Disclosure [Abstract]
2,019	$ 162
2,021	500
2,022	1,000
Thereafter	4,349
Total	$ 6,011

Debt And Related Expenses (Narr

Debt And Related Expenses (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2019	Dec. 31, 2018	Dec. 31, 2016	Oct. 05, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Commercial paper		$ 0
Redemption of senior notes		922	$ 2,492
Loss on early retirement of debt		(312)	(269)
Loss on early retirement of debt, cash retirement costs		304	265
Repurchase of debt securities			$ 2,100
Senior Notes [Member]
Debt Instrument [Line Items]
Redemption of senior notes		807
Loss on early retirement of debt		(312)
Loss on early retirement of debt, cash retirement costs		304
Loss on early retirement of debt, noncash charges		$ 8
7.875% due September 30, 2031 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		7.875%			7.875%
Debt, maturity date		Sep. 30, 2031
7.875% due September 30, 2031 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Redemption of senior notes		$ 384
Debt interest rate, stated percentage		7.875%
Debt, maturity date		Sep. 30, 2031
7.95% due April 15, 2032 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		7.95%			7.95%
Debt, maturity date		Apr. 15, 2032
7.95% due April 15, 2032 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Redemption of senior notes		$ 423
Debt interest rate, stated percentage		7.95%
Debt, maturity date		Apr. 15, 2032
2.25% Due December 15, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		2.25%			2.25%
Debt, maturity date		Dec. 15, 2018
2.25% Due December 15, 2018 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Redemption of senior notes		$ 95
Debt interest rate, stated percentage		2.25%
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage		6.30%			6.30%
Debt, maturity date		Jan. 15, 2019
6.30% Due January 15, 2019 [Member] | Senior Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Redemption of senior notes	$ 162
Debt interest rate, stated percentage	6.30%
Commercial Paper [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 3,000
2012 Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity				$ 3,000
2018 Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		$ 3,000
Credit facility maturity date		Oct. 5, 2023
Credit facility extension period description		The 2018 Senior Credit Facility matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods subject to lender consent.
Frequency of payment		annual
Commitment fee amount		$ 6.1
Outstanding credit facility borrowings		0
Outstanding letters of credit		$ 48
Debt-to-capitalization ratio		0.210
2018 Senior Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt-to-capitalization ratio		0.65

Debt And Related Expenses (Sc_4

Debt And Related Expenses (Schedule of Net Financing Cost Components) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Interest based on debt outstanding	$ 339	$ 390	$ 488
Early retirement of debt	312		269
Capitalized interest	(41)	(69)	(61)
Other	(16)	(4)	21
Total net financing costs	$ 594	$ 317	$ 717

Asset Retirement Obligations (S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations as of beginning of period	$ 1,138	$ 1,258
Liabilities incurred	39	40
Liabilities settled and divested	(116)	(68)
Revision of estimated obligation	(25)	(184)
Accretion expense on discounted obligation	59	62	$ 75
Foreign currency translation adjustment	(38)	30
Asset retirement obligations as of end of period	1,057	1,138	$ 1,258
Less current portion	27	39
Asset retirement obligations, long-term	$ 1,030	$ 1,099

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Decrease in asset retirement obligation	$ 116	$ 68
Revision of estimated obligation	(25)	$ (184)
Asset Divestitures [Member]
Asset Retirement Obligations [Line Items]
Decrease in asset retirement obligation	$ 84

Retirement Plans (Narrative) (D

Retirement Plans (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined contribution plans		$ 50	$ 53	$ 57
Settlement expense	$ 33
Expected benefit plan payments for each of the next five years		59
Benefit plan payments expected to be funded from cash and cash equivalents and other assets for next fiscal year		17
Expected total benefit plan payments for five years after the next five years		153
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		709	1,035	$ 985
Settlement expense	$ 241	$ 241
Pension Benefits [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations		70.00%
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 193	342
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 301	401
Pension Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations		20.00%
Fair value of plan assets		$ 84	157
Pension Benefits [Member] | Other Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations		10.00%
Fair value of plan assets		$ 132	$ 135
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan health care cost trend rate assumed for next fiscal year		7.10%
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	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Change in benefit obligation:
Plan settlements	$ (33)
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		$ 1,279	$ 1,249
Service cost		10	15	$ 15
Interest cost		39	42	42
Actuarial loss (gain)		(83)	59
Plan curtailments		2
Plan settlements	$ (241)	(241)
Foreign exchange rate changes		(3)	2
Benefits paid		(60)	(88)
Benefit obligation at end of year		943	1,279	1,249
Change in plan assets:
Fair value of plan assets at beginning of year		1,035	985
Actual return on plan assets		(36)	122
Employer contributions		14	14
Plan settlements		(241)
Benefits paid		(60)	(88)
Foreign exchange rate changes		(3)	2
Fair value of plan assets at end of year		709	1,035	985
Funded status at end of year		(234)	(244)
Amounts recognized in balance sheet:
Other long-term assets		3	4
Other current liabilities		(14)	(13)
Other long-term liabilities		(223)	(235)
Net amount		(234)	(244)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)		202	257
Prior service cost (credit)		4	6
Total		206	263
Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		19	21
Interest cost				1
Actuarial loss (gain)		(3)
Plan curtailments		2
Participant contributions		2	1
Benefits paid		(3)	(3)
Benefit obligation at end of year		17	19	$ 21
Change in plan assets:
Employer contributions		1	2
Participant contributions		2	1
Benefits paid		(3)	(3)
Funded status at end of year		(17)	(19)
Amounts recognized in balance sheet:
Other current liabilities		(3)	(3)
Other long-term liabilities		(14)	(16)
Net amount		(17)	(19)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)		(11)	(11)
Prior service cost (credit)		(2)	(3)
Total		$ (13)	$ (14)

Retirement Plans (Schedule Of P

Retirement Plans (Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Retirement Plans[Abstract]
Projected benefit obligation	$ 922	$ 1,255
Accumulated benefit obligation	906	1,226
Fair value of plan assets	$ 685	$ 1,007

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Net periodic benefit cost:
Service cost		$ 10	$ 15	$ 15
Interest cost		39	42	42
Expected return on plan assets		(49)	(54)	(55)
Recognition of net actuarial loss (gain)	[1]	13	19	25
Recognition of prior service cost	[1]	1	2	3
Total net periodic benefit cost	[2]	14	24	30
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year		4	(9)	26
Prior service cost arising in current year				2
Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost	[3]	(60)	(19)	(43)
Recognition of prior service cost, including curtailment, in net periodic benefit cost	[3]	(2)	(2)	(9)
Total other comprehensive loss (earnings)		(58)	(30)	(24)
Total recognized		(44)	(6)	6
Postretirement Benefits [Member]
Net periodic benefit cost:
Interest cost				1
Recognition of net actuarial loss (gain)	[1]	(1)	(1)	(1)
Recognition of prior service cost	[1]	(1)	(1)	(1)
Total net periodic benefit cost	[2]	(2)	(2)	(1)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year		(1)	(1)
Recognition of net actuarial gain (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	1
Total other comprehensive loss (earnings)		1	1	2
Total recognized		$ (1)	$ (1)	$ 1
[1]	These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
[2]	The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings.
[3]	(3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6

Retirement Plans (Schedule Of A

Retirement Plans (Schedule Of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	4.21%	3.59%	4.07%
Rate of compensation increase	2.50%	2.50%	4.49%
Assumptions to determine net periodic benefit cost:
Discount rate - service cost	3.98%	4.29%	4.39%
Discount rate - interest cost	3.22%	2.99%	4.39%
Rate of compensation increase	2.50%	4.48%	4.49%
Expected return on plan assets	5.67%	5.69%	5.20%
Postretirement Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	4.01%	3.25%	3.46%
Assumptions to determine net periodic benefit cost:
Discount rate - service cost	4.13%	4.22%	3.63%
Discount rate - interest cost	2.67%	2.39%	3.63%

Stockholders' Equity (Narrative

Stockholders' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Feb. 29, 2016

Jan. 31, 2016

Jun. 30, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2018

Dec. 31, 2016

Feb. 28, 2019

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

4,500,000

Preferred Stock, Par or Stated Value Per Share

$ 1

$ 1

Net proceeds from offering

$ 1,469

Shares repurchased, value

$ 1,712

$ 2,978

Percentage of increase to quarterly dividend

33.00%

Common stock dividends, rate per share

$ 0.08

$ 0.08

$ 0.08

$ 0.06

$ 0.06

$ 0.06

$ 0.06

$ 0.06

$ 0.06

$ 0.06

$ 0.06

$ 0.24

Subsequent Event [Member]

Stockholders Equity [Abstract]

Percentage of additional increase in quarterly dividend

12.50%

Common stock dividends, rate per share, declared

$ 0.09

Share Repurchase Program [Member]

Stockholders Equity [Abstract]

Share-repurchase program, additional authorized amount

$ 3,000

Share-repurchase program expiration date

Dec. 31, 2019

Share Repurchase Program [Member] | Subsequent Event [Member]

Stockholders Equity [Abstract]

Share-repurchase program, additional authorized amount

$ 1,000

Share Repurchase Program [Member] | Maximum [Member]

Stockholders Equity [Abstract]

Share-repurchase program, authorized amount

$ 4,000

$ 1,000

Share Repurchase Program [Member] | Maximum [Member] | Subsequent Event [Member]

Stockholders Equity [Abstract]

Share-repurchase program, authorized amount

$ 5,000

ASR Transaction [Member]

Stockholders Equity [Abstract]

Shares repurchased, value

$ 1,000

Common Stock [Member]

Stockholders Equity [Abstract]

Common stock, shares issued

103,000,000

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] | STACK [Member]

Stockholders Equity [Abstract]

Equity issued for acquisition

23,000,000

Stockholders' Equity (Summary o

Stockholders' Equity (Summary of Purchases of Common Stock) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018
Stockholders Equity [Line Items]
Total Number of Shares Purchased		40,822			78,149
Dollar Value of Shares Purchased		$ 1,712			$ 2,978
Average Price Paid per Share		$ 41.92			$ 38.11
Open-Market [Member]
Stockholders Equity [Line Items]
Total Number of Shares Purchased	23,612	16,492	11,154	2,561
Dollar Value of Shares Purchased	$ 745	$ 712	$ 439	$ 82
Average Price Paid per Share	$ 31.57	$ 43.13	$ 39.35	$ 32.19
ASR [Member]
Stockholders Equity [Line Items]
Total Number of Shares Purchased		24,330
Dollar Value of Shares Purchased		$ 1,000
Average Price Paid per Share		$ 41.10

Stockholders' Equity (Summary_2

Stockholders' Equity (Summary Of Dividends Paid On Common Stock) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stockholders Equity Note [Abstract]
Common stock dividends paid, Amount	$ 37	$ 38	$ 42	$ 32	$ 32	$ 30	$ 33	$ 32	$ 31	$ 32	$ 33	$ 125	$ 149	$ 127	$ 221
Common stock dividends, rate per share	$ 0.08	$ 0.08	$ 0.08	$ 0.06	$ 0.06	$ 0.06	$ 0.06	$ 0.06	$ 0.06	$ 0.06	$ 0.06	$ 0.24

Discontinued Operations and A_3

Discontinued Operations and Assets Held for Sale (Narrative) (Details) $ in Millions	3 Months Ended	5 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)MMcf	Dec. 31, 2016USD ($)
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain on sale of aggregate ownership interests, before-tax			$ 2,607	$ (13)
EnLink and General Partner [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of aggregate ownership interests	$ 3,125		$ 3,125
Effective close date of divestiture			Jul. 18, 2018
Gain on sale of aggregate ownership interests, before-tax	2,600		$ 2,600
Gain on sale of aggregate ownership interests, after-tax	$ 2,200		2,200
Cash income taxes			$ 12
Net cash outflows		$ 380
EnLink and General Partner [Member] | Chisholm Gathering and Processing Contract [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gathering and processing minimum volume commitments period end			early 2,021
EnLink and General Partner [Member] | Bridgeport and Cana Gathering and Processing Contracts [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Commitment Termination Date			Dec. 31, 2029
EnLink and General Partner [Member] | Minimum [Member] | Chisholm Gathering and Processing Contract [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Minimum gathering volume commitment | MMcf			77
Minimum processing volume commitment | MMcf			77
EnLink and General Partner [Member] | Maximum [Member] | Chisholm Gathering and Processing Contract [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Minimum gathering volume commitment | MMcf			128
Minimum processing volume commitment | MMcf			128

Discontinued Operations and A_4

Discontinued Operations and Assets Held for Sale (Amounts Reported as Discontinued Operations in the Consolidated Comprehensive Statements of Earnings) (Details) - USD ($) $ in Millions	3 Months Ended										12 Months Ended
	Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Discontinued Operations And Disposal Groups [Abstract]
Marketing and midstream revenues											$ 3,567		$ 5,071	$ 3,551
Marketing and midstream expenses											2,912		4,111	2,712
Depreciation, depletion and amortization											244		545	504
General and administrative expenses											65		128	118
Financing costs, net											98		181	190
Asset impairments													17	873
Asset dispositions											(2,607)			13
Other expenses											(8)		(34)	25
Total expenses											704		4,948	4,435
Earnings (loss) from discontinued operations before income taxes											2,863		123	(884)
Income tax expense (benefit)											403		(197)
Net earnings (loss) from discontinued operations, net of income tax expense	$ 2,263		$ 139		$ 58		$ 260	$ 18	$ 33	$ 9	2,460	[1]	320	(884)
Net earnings (loss) attributable to noncontrolling interests											160		180	(403)
Net earnings (loss) from discontinued operations attributable to Devon											$ 2,300		$ 140	$ (481)
[1]	(3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19

Discontinued Operations and A_5

Discontinued Operations and Assets Held for Sale (Carrying Amounts of Assets and Liabilities Classified as Held for Sale on Consolidated Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disposal Group Including Discontinued Operation Balance Sheet Disclosures [Abstract]
Cash and cash equivalents		$ 31	$ 12
Accounts receivable	$ 7	681
Other current assets		48
Oil and gas property and equipment, based on successful efforts accounting, net	190
Midstream and other property and equipment, net		6,587
Goodwill		1,542
Other long-term assets		1,600
Total assets held for sale	197	10,489	$ 10,200
Accounts payable	3	186
Revenues and royalties payable		432
Other current liabilities	19	373
Long-term debt		3,542
Deferred income taxes		346
Asset retirement obligations	47	14
Other long-term liabilities		34
Total liabilities held for sale	$ 69	$ 4,927

Commitments And Contingencies_2

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)Defendant	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Loss Contingencies [Line Items]
Obligation related to the purchase of condensate, year of expiration	2,021
Total rental expense recognized, including certain office space and equipment under operating lease agreements, net of sub-lease income | $	$ 11	$ 7	$ 11
Parishes in Louisiana [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Number of defendants | Defendant	100

Commitments And Contingencies_3

Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details) $ in Millions	Dec. 31, 2018USD ($)
Purchase Obligations [Member]
Long Term Purchase Commitment [Line Items]
2,019	$ 541
2,020	567
2,021	140
Total	1,248
Drilling And Facility Obligations [Member]
Long Term Purchase Commitment [Line Items]
2,019	274
2,020	85
2,021	48
2,022	14
2,023	8
Thereafter	16
Total	445
Operational Agreements [Member]
Long Term Purchase Commitment [Line Items]
2,019	587
2,020	519
2,021	373
2,022	419
2,023	354
Thereafter	3,374
Total	5,626
Office And Equipment Leases [Member]
Long Term Purchase Commitment [Line Items]
2,019	64
2,020	43
2,021	31
2,022	26
2,023	25
Thereafter	311
Total	$ 500

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, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	$ 677	$ 206
Derivatives, liabilities	(68)	(350)
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,505	1,533
Debt	(5,947)	(6,864)
Carrying Amount [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	677	205
Derivatives, liabilities	(68)	(286)
Carrying Amount [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1
Derivatives, liabilities		(64)
Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,505	1,533
Debt	(5,965)	(8,131)
Total Fair Value [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	677	205
Derivatives, liabilities	(68)	(286)
Total Fair Value [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1
Derivatives, liabilities		(64)
Level 1 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,405	1,454
Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	100	79
Debt	(5,965)	(8,131)
Level 2 Inputs [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	677	205
Derivatives, liabilities	$ (68)	(286)
Level 2 Inputs [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets		1
Derivatives, liabilities		$ (64)

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, 2018USD ($)		Sep. 30, 2018USD ($)		Jun. 30, 2018USD ($)		Mar. 31, 2018USD ($)		Dec. 31, 2017USD ($)		Sep. 30, 2017USD ($)		Jun. 30, 2017USD ($)		Mar. 31, 2017USD ($)		Dec. 31, 2018USD ($)segment		Dec. 31, 2017USD ($)		Dec. 31, 2016USD ($)
Segment Reporting Information [Line Items]
Total impacted revenues	$ 3,708		$ 2,579		$ 2,249		$ 2,198		$ 2,380		$ 1,933		$ 2,165		$ 2,400		$ 10,734	[1]	$ 8,878		$ 6,753
Depreciation, depletion and amortization																	1,658		1,529		1,592
Interest expense																	635		336		724
Asset impairments					150												156				437
Asset dispositions	(268)	[2]	(6)	[2]	23	[2]	(12)	[2]	(17)	[2]	(170)	[2]	(22)	[2]	(8)	[2]	(263)	[2]	(217)	[2]	(1,496)
Restructuring and transaction costs																	114				261
Earnings (loss) from continuing operations before income taxes	1,484	[3]	162	[3]	(481)	[3]	(245)	[3]	46		207		207		313		920	[3]	773		(433)
Income tax expense (benefit)																	156		15		141
Net earnings (loss) from continuing operations	1,149		$ 300		$ (474)		$ (211)		44		$ 194		$ 212		$ 308		764		758		(574)
Property and equipment, net	13,935								14,584								13,935		14,584		14,276
Total assets	19,566								30,241								19,566		30,241
Capital expenditures, including acquisitions																	2,576		2,169		2,826
Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total assets	19,369	[4]							19,752	[5]							$ 19,369	[4]	19,752	[5]	18,461	[5]
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]
Total impacted revenues																	$ 9,674	[1]	7,326		5,722
Depreciation, depletion and amortization																	1,328		1,149		1,178
Interest expense																	469		324		624
Asset impairments																	156				435
Asset dispositions																	(263)		(218)		(955)
Restructuring and transaction costs																	97				242
Earnings (loss) from continuing operations before income taxes																	1,294		443		(757)
Income tax expense (benefit)																	294		9		(8)
Net earnings (loss) from continuing operations																	1,000		434		(749)
Property and equipment, net	10,026								10,274								10,026		10,274		10,166
Capital expenditures, including acquisitions																	2,294		1,821		2,640
United States [Member] | Operating Segments [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total assets	14,853	[4]							14,254	[5]							14,853	[4]	14,254	[5]	13,390	[5]
Canada [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total impacted revenues																	1,060	[1]	1,552		1,031
Depreciation, depletion and amortization																	330		380		414
Interest expense																	166		12		100
Asset impairments																					2
Asset dispositions																			1		(541)
Restructuring and transaction costs																	17				19
Earnings (loss) from continuing operations before income taxes																	(374)		330		324
Income tax expense (benefit)																	(138)		6		149
Net earnings (loss) from continuing operations																	(236)		324		175
Property and equipment, net	3,909								4,310								3,909		4,310		4,110
Capital expenditures, including acquisitions																	282		348		186
Canada [Member] | Operating Segments [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total assets	$ 4,516	[4]							$ 5,498	[5]							$ 4,516	[4]	$ 5,498	[5]	$ 5,071	[5]
[1]	Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers.
[2]	(1) Additional discussion regarding asset dispositions can be found in Note 2.
[3]	(2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5
[4]	Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million.
[5]	Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively.

Segment Information (Condense_2

Segment Information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Parenthetical) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting [Abstract]
Total assets related to discontinued operations	$ 197	$ 10,489	$ 10,200

Segment Information (Schedule o

Segment Information (Schedule of Revenue from Contracts with Customers Disaggregated Based on Type of Good) (Details) - USD ($) $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

$ 4,449

$ 3,571

$ 2,772

Oil, gas and NGL derivatives

608

157

(201)

Upstream revenues

6,285

5,307

3,981

Total revenues

$ 3,708

$ 2,579

$ 2,249

$ 2,198

$ 2,380

$ 1,933

$ 2,165

$ 2,400

10,734

[1]

8,878

6,753

Operating Segments [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Oil, gas and NGL derivatives

457

Upstream revenues

5,320

Total revenues

9,674

[1]

7,326

5,722

Operating Segments [Member] | Canada [Member]

Disaggregation Of Revenue [Line Items]

Oil, gas and NGL derivatives

151

Upstream revenues

965

Total revenues

1,060

[1]

$ 1,552

$ 1,031

Oil, Gas and NGL Sales [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

5,677

Oil, Gas and NGL Sales [Member] | Oil [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

3,771

Oil, Gas and NGL Sales [Member] | Gas [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

950

Oil, Gas and NGL Sales [Member] | NGL [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

956

Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

4,863

Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Canada [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

814

Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Oil [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

2,957

Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Oil [Member] | Canada [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

814

Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Gas [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

950

Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | NGL [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

956

Marketing Revenues [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

4,449

Marketing Revenues [Member] | Oil [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

2,840

Marketing Revenues [Member] | Gas [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

738

Marketing Revenues [Member] | NGL [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

871

Marketing Revenues [Member] | Operating Segments [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

4,354

Marketing Revenues [Member] | Operating Segments [Member] | Canada [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

95

Marketing Revenues [Member] | Operating Segments [Member] | Oil [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

2,745

Marketing Revenues [Member] | Operating Segments [Member] | Oil [Member] | Canada [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

95

Marketing Revenues [Member] | Operating Segments [Member] | Gas [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

738

Marketing Revenues [Member] | Operating Segments [Member] | NGL [Member] | U.S. [Member]

Disaggregation Of Revenue [Line Items]

Total revenues from contracts with customers

$ 871

[1]

Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers.

Supplemental Information On O_3

Supplemental Information On Oil And Gas Operations (Costs Incurred) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property acquisition costs:
Proved properties	$ 2	$ 2	$ 237
Unproved properties	71	54	1,358
Exploration costs	764	677	360
Development costs	1,786	1,261	929
Costs incurred	2,623	1,994	2,884
United States [Member]
Property acquisition costs:
Proved properties	2	2	237
Unproved properties	71	50	1,356
Exploration costs	679	590	282
Development costs	1,537	1,036	875
Costs incurred	2,289	1,678	2,750
Canada [Member]
Property acquisition costs:
Unproved properties		4	2
Exploration costs	85	87	78
Development costs	249	225	54
Costs incurred	$ 334	$ 316	$ 134

Supplemental Information On O_4

Supplemental Information On Oil And Gas Operations (Narrative) (Details) $ in Millions		12 Months Ended
		Dec. 31, 2018USD ($)MBbls / dMMBoe$ / bbl$ / Mcf	Dec. 31, 2017USD ($)MMBoe	Dec. 31, 2016USD ($)MMBoe	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2015MMBoe
Reserve Quantities [Line Items]
Capitalized interest costs | $		$ 41	$ 69	$ 61
Proved undeveloped reserves increased in percentage		9.00%
Proved undeveloped reserves as a percentage of total proved reserves		23.00%
Proved undeveloped reserves due to drilling and development activities (MMBoe)		113
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)		52
Proved undeveloped reserves to proved developed reserves, conversion, percentage		26.00%
Cost incurred related to development and conversion of proved undeveloped reserves | $		$ 691
Proved undeveloped reserves	[1]	445	410	409				376
Proved developed and undeveloped reserves, revisions due to prices	[1]	51	73	(27)
Proved developed and undeveloped reserves, extensions and discoveries	[1]	243	237	126
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)		21	66	74
Average estimated future realized price per barrel of oil used to estimate future cash inflows for proved oil reserves | $ / bbl		58.64
Average estimated future realized price per barrel of bitumen used to estimate future cash inflows for proved bitumen reserves | $ / bbl		22.12
Average estimated future realized price per Mcf of gas used to estimate future cash inflows for proved gas reserves | $ / Mcf		2.45
Average estimated future realized price per barrel of natural gas liquids used to estimate future cash inflows for proved NGL reserves | $ / bbl		24.72
Future development costs | $		$ 5,002	$ 5,169	$ 4,985
Future dismantlement, abandonment and rehabilitation costs | $		$ 1,400
Scenario, Forecast [Member]
Reserve Quantities [Line Items]
Future development costs | $					$ 300	$ 600	$ 1,200
Jackfish [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves		206	209
Daily barrel facility capacity (MBbls/d) | MBbls / d		35
Year development schedule will be complete		Dec. 31, 2032
Proved undeveloped reserves, remaining undeveloped 5 years or more after initial booking (energy)		125
Proved undeveloped reserves, requiring excess of five years to develop		81
US [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves due to drilling and development activities (MMBoe)		107
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)		52
Proved undeveloped reserves	[1]	239	201	115				75
Proved developed and undeveloped reserves, revisions due to prices	[1]	40	111	(48)
Proved developed and undeveloped reserves, extensions and discoveries	[1]	232	221	124
Future development costs | $		$ 3,444	$ 3,316	$ 2,784
Canada [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves due to drilling and development activities (MMBoe)		6
Proved undeveloped reserves	[1]	206	209	294				301
Proved developed and undeveloped reserves, revisions due to prices	[1]	11	(38)	21
Proved developed and undeveloped reserves, extensions and discoveries	[1]	11	16	2
Future development costs | $		$ 1,558	$ 1,853	$ 2,201
STACK and Delaware Basin [Member]
Reserve Quantities [Line Items]
Percentage of additions to proved developed and undeveloped reserves for extensions and discoveries		72.00%	80.00%
Delaware Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries		88	79	18
STACK [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries		87	120	97
Eagle Ford [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries				7
Oil and Gas Properties [Member]
Reserve Quantities [Line Items]
Capitalized interest costs | $		$ 41	$ 69	$ 61
[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 O_5

Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)$ / Boe	Dec. 31, 2017USD ($)$ / Boe	Dec. 31, 2016USD ($)$ / Boe
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 5,677	$ 5,150	$ 4,182
Production expenses	(2,225)	(1,823)	(1,805)
Exploration expenses	(177)	(380)	(215)
Depreciation, depletion and amortization	(1,559)	(1,419)	(1,446)
Asset dispositions	262	212	947
Asset impairments	(109)		(435)
Accretion of asset retirement obligations	(59)	(62)	(75)
Income tax (expense) benefit	(409)	(104)	(13)
Results of operations	$ 1,401	$ 1,574	$ 1,140
Depreciation, depletion and amortization per Boe | $ / Boe	7.98	7.15	6.47
US [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 4,863	$ 3,746	$ 3,198
Production expenses	(1,620)	(1,232)	(1,313)
Exploration expenses	(129)	(346)	(176)
Depreciation, depletion and amortization	(1,234)	(1,050)	(1,066)
Asset dispositions	262	211	946
Asset impairments	(109)		(435)
Accretion of asset retirement obligations	(35)	(38)	(49)
Income tax (expense) benefit	(460)
Results of operations	$ 1,538	$ 1,291	$ 1,105
Depreciation, depletion and amortization per Boe | $ / Boe	8.08	6.97	6.11
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 814	$ 1,404	$ 984
Production expenses	(605)	(591)	(492)
Exploration expenses	(48)	(34)	(39)
Depreciation, depletion and amortization	(325)	(369)	(380)
Asset dispositions		1	1
Accretion of asset retirement obligations	(24)	(24)	(26)
Income tax (expense) benefit	51	(104)	(13)
Results of operations	$ (137)	$ 283	$ 35
Depreciation, depletion and amortization per Boe | $ / Boe	7.63	7.73	7.75

Supplemental Information On O_6

Supplemental Information On Oil And Gas Operations (Proved Developed and Undeveloped Reserves) (Details) MBbls in Thousands, Mcf in Millions		12 Months Ended
		Dec. 31, 2018MMBoeMBblsMcf	Dec. 31, 2017MMBoeMBblsMcf	Dec. 31, 2016MMBoeMBblsMcf	Dec. 31, 2015MMBoeMBblsMcf
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | MMBoe	[1]	2,152	2,058	2,182
Proved developed and undeveloped reserves, revisions due to prices | MMBoe	[1]	51	73	(27)
Proved developed and undeveloped reserves, revisions other than price | MMBoe	[1]	(57)	(12)	137
Proved developed and undeveloped reserves, extensions and discoveries | MMBoe	[1]	243	237	126
Proved developed and undeveloped reserves, purchase of reserves | MMBoe	[1]			20
Proved developed and undeveloped reserves, production | MMBoe	[1]	(195)	(198)	(223)
Proved developed and undeveloped reserves, sale of reserves | MMBoe	[1]	(267)	(6)	(157)
Proved developed and undeveloped reserves, ending balance | MMBoe	[1]	1,927	2,152	2,058
Proved developed reserves | MMBoe	[1]	1,482	1,742	1,649	1,806
Proved developed producing reserves | MMBoe	[1]	1,448	1,693	1,593	1,749
Proved undeveloped reserves | MMBoe	[1]	445	410	409	376
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]	1,725	1,554	1,638
Proved developed and undeveloped reserves, revisions due to prices | MMBoe	[1]	40	111	(48)
Proved developed and undeveloped reserves, revisions other than price | MMBoe	[1]	(60)	(5)	151
Proved developed and undeveloped reserves, extensions and discoveries | MMBoe	[1]	232	221	124
Proved developed and undeveloped reserves, purchase of reserves | MMBoe	[1]			20
Proved developed and undeveloped reserves, production | MMBoe	[1]	(153)	(150)	(174)
Proved developed and undeveloped reserves, sale of reserves | MMBoe	[1]	(267)	(6)	(157)
Proved developed and undeveloped reserves, ending balance | MMBoe	[1]	1,517	1,725	1,554
Proved developed reserves | MMBoe	[1]	1,278	1,524	1,439	1,563
Proved developed producing reserves | MMBoe	[1]	1,249	1,481	1,386	1,509
Proved undeveloped reserves | MMBoe	[1]	239	201	115	75
Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | MMBoe	[1]	427	504	544
Proved developed and undeveloped reserves, revisions due to prices | MMBoe	[1]	11	(38)	21
Proved developed and undeveloped reserves, revisions other than price | MMBoe	[1]	3	(7)	(14)
Proved developed and undeveloped reserves, extensions and discoveries | MMBoe	[1]	11	16	2
Proved developed and undeveloped reserves, production | MMBoe	[1]	(42)	(48)	(49)
Proved developed and undeveloped reserves, ending balance | MMBoe	[1]	410	427	504
Proved developed reserves | MMBoe	[1]	204	218	210	243
Proved developed producing reserves | MMBoe	[1]	199	212	207	240
Proved undeveloped reserves | MMBoe	[1]	206	209	294	301
Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance		272	211	264
Proved developed and undeveloped reserves, revisions due to prices		13	11	(20)
Proved developed and undeveloped reserves, revisions other than price		(8)	8	1
Proved developed and undeveloped reserves, extensions and discoveries		98	94	38
Proved developed and undeveloped reserves, purchase of reserves				8
Proved developed and undeveloped reserves, production		(54)	(49)	(55)
Proved developed and undeveloped reserves, sale of reserves		(7)	(3)	(25)
Proved developed and undeveloped reserves, ending balance		314	272	211
Proved developed reserves		214	193	177	225
Proved developed producing reserves		201	177	156	211
Proved undeveloped reserves		100	79	34	39
Oil [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance		257	194	242
Proved developed and undeveloped reserves, revisions due to prices		12	12	(18)
Proved developed and undeveloped reserves, revisions other than price		(10)	6	(2)
Proved developed and undeveloped reserves, extensions and discoveries		93	90	36
Proved developed and undeveloped reserves, purchase of reserves				8
Proved developed and undeveloped reserves, production		(47)	(42)	(47)
Proved developed and undeveloped reserves, sale of reserves		(7)	(3)	(25)
Proved developed and undeveloped reserves, ending balance		298	257	194
Proved developed reserves		198	178	160	203
Proved developed producing reserves		189	165	143	192
Proved undeveloped reserves		100	79	34	39
Oil [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance		15	17	22
Proved developed and undeveloped reserves, revisions due to prices		1	(1)	(2)
Proved developed and undeveloped reserves, revisions other than price		2	2	3
Proved developed and undeveloped reserves, extensions and discoveries		5	4	2
Proved developed and undeveloped reserves, production		(7)	(7)	(8)
Proved developed and undeveloped reserves, ending balance		16	15	17
Proved developed reserves		16	15	17	22
Proved developed producing reserves		12	12	13	19
Bitumen [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance		409	484	520
Proved developed and undeveloped reserves, revisions due to prices		10	(37)	23
Proved developed and undeveloped reserves, revisions other than price		2	(10)	(19)
Proved developed and undeveloped reserves, extensions and discoveries		7	12
Proved developed and undeveloped reserves, production		(35)	(40)	(40)
Proved developed and undeveloped reserves, ending balance		393	409	484
Proved developed reserves		187	200	190	219
Proved developed producing reserves		187	197	190	219
Proved undeveloped reserves		206	209	294	301
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | Mcf		5,987	5,631	5,821
Proved developed and undeveloped reserves, revisions due to prices | Mcf		91	399	(103)
Proved developed and undeveloped reserves, revisions other than price | Mcf		(167)	2	638
Proved developed and undeveloped reserves, extensions and discoveries | Mcf		446	403	280
Proved developed and undeveloped reserves, purchase of reserves | Mcf				33
Proved developed and undeveloped reserves, production | Mcf		(401)	(439)	(517)
Proved developed and undeveloped reserves, sale of reserves | Mcf		(1,195)	(9)	(521)
Proved developed and undeveloped reserves, ending balance | Mcf		4,761	5,987	5,631
Proved developed reserves | Mcf		4,333	5,632	5,377	5,707
Proved developed producing reserves | Mcf		4,263	5,525	5,259	5,559
Proved undeveloped reserves | Mcf		428	355	254	114
Natural Gas [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | Mcf		5,974	5,615	5,808
Proved developed and undeveloped reserves, revisions due to prices | Mcf		94	398	(103)
Proved developed and undeveloped reserves, revisions other than price | Mcf		(163)		628
Proved developed and undeveloped reserves, extensions and discoveries | Mcf		446	403	280
Proved developed and undeveloped reserves, purchase of reserves | Mcf				33
Proved developed and undeveloped reserves, production | Mcf		(397)	(433)	(510)
Proved developed and undeveloped reserves, sale of reserves | Mcf		(1,195)	(9)	(521)
Proved developed and undeveloped reserves, ending balance | Mcf		4,759	5,974	5,615
Proved developed reserves | Mcf		4,331	5,619	5,361	5,694
Proved developed producing reserves | Mcf		4,261	5,512	5,243	5,546
Proved undeveloped reserves | Mcf		428	355	254	114
Natural Gas [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | Mcf		13	16	13
Proved developed and undeveloped reserves, revisions due to prices | Mcf		(3)	1
Proved developed and undeveloped reserves, revisions other than price | Mcf		(4)	2	10
Proved developed and undeveloped reserves, production | Mcf		(4)	(6)	(7)
Proved developed and undeveloped reserves, ending balance | Mcf		2	13	16
Proved developed reserves | Mcf		2	13	16	13
Proved developed producing reserves | Mcf		2	13	16	13
Natural Gas Liquids [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance		473	425	428
Proved developed and undeveloped reserves, revisions due to prices		12	32	(13)
Proved developed and undeveloped reserves, revisions other than price		(23)	(10)	48
Proved developed and undeveloped reserves, extensions and discoveries		64	63	42
Proved developed and undeveloped reserves, purchase of reserves				7
Proved developed and undeveloped reserves, production		(39)	(36)	(42)
Proved developed and undeveloped reserves, sale of reserves		(61)	(1)	(45)
Proved developed and undeveloped reserves, ending balance		426	473	425
Proved developed reserves		359	410	387	411
Proved developed producing reserves		349	397	370	393
Proved undeveloped reserves		67	63	38	17
[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 O_7

Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2018MMBoe
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	410	[1]
Proved undeveloped reserves, extensions and discoveries	113
Proved undeveloped reserves, revisions due to prices	7
Proved undeveloped reserves, revisions other than price	(23)
Proved undeveloped reserves, sale of reserves	(10)
Proved undeveloped reserves, conversion to proved developed reserves	(52)
Proved undeveloped reserves (MMBoe) ending balance	445	[1]
United States [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	201	[1]
Proved undeveloped reserves, extensions and discoveries	107
Proved undeveloped reserves, revisions due to prices	1
Proved undeveloped reserves, revisions other than price	(8)
Proved undeveloped reserves, sale of reserves	(10)
Proved undeveloped reserves, conversion to proved developed reserves	(52)
Proved undeveloped reserves (MMBoe) ending balance	239	[1]
Canada [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	209	[1]
Proved undeveloped reserves, extensions and discoveries	6
Proved undeveloped reserves, revisions due to prices	6
Proved undeveloped reserves, revisions other than price	(15)
Proved undeveloped reserves (MMBoe) ending balance	206	[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 O_8

Supplemental Information On Oil And Gas Operations (Standardized Measure Of Discounted Future Net Cash Flows Related To Proved Reserves) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 49,329	$ 48,303	$ 32,519
Future costs:
Development	(5,002)	(5,169)	(4,985)
Production	(23,552)	(21,512)	(17,983)
Future income tax expense	(2,969)	(988)	(121)
Future net cash flow	17,806	20,634	9,430
10% discount to reflect timing of cash flows	(7,614)	(9,297)	(3,990)
Standardized measure of discounted future net cash flows	10,192	11,337	5,440	$ 7,883
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	40,183	34,701	22,847
Future costs:
Development	(3,444)	(3,316)	(2,784)
Production	(18,107)	(15,526)	(11,934)
Future income tax expense	(2,969)
Future net cash flow	15,663	15,859	8,129
10% discount to reflect timing of cash flows	(6,897)	(7,541)	(3,524)
Standardized measure of discounted future net cash flows	8,766	8,318	4,605
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	9,146	13,602	9,672
Future costs:
Development	(1,558)	(1,853)	(2,201)
Production	(5,445)	(5,986)	(6,049)
Future income tax expense		(988)	(121)
Future net cash flow	2,143	4,775	1,301
10% discount to reflect timing of cash flows	(717)	(1,756)	(466)
Standardized measure of discounted future net cash flows	$ 1,426	$ 3,019	$ 835

Supplemental Information On O_9

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Information On Oil And Gas Operations [Abstract]
Standardized measure of discounted future net cash flows, beginning balance	$ 11,337	$ 5,440	$ 7,883
Net changes in prices and production costs	(243)	5,218	(2,027)
Oil, bitumen, gas and NGL sales, net of production costs	(3,452)	(3,327)	(2,377)
Changes in estimated future development costs	(216)	789	112
Extensions and discoveries, net of future development costs	3,139	2,497	674
Purchase of reserves		2	224
Sales of reserves in place	(588)	(3)	(577)
Revisions of quantity estimates	(414)	(318)	(21)
Previously estimated development costs incurred during the period	962	559	663
Accretion of discount	960	1,034	537
Foreign exchange and other	(329)	(7)	72
Net change in income taxes	(964)	(547)	277
Standardized measure of discounted future net cash flows, ending balance	$ 10,192	$ 11,337	$ 5,440

Supplemental Quarterly Financ_3

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, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Quarterly Financial Data [Abstract]
Total revenues	$ 3,708		$ 2,579		$ 2,249		$ 2,198		$ 2,380		$ 1,933		$ 2,165		$ 2,400		$ 10,734	[1]	$ 8,878		$ 6,753
Asset dispositions	(268)	[2]	(6)	[2]	23	[2]	(12)	[2]	(17)	[2]	(170)	[2]	(22)	[2]	(8)	[2]	(263)	[2]	(217)	[2]	(1,496)
Earnings (loss) from continuing operations before income taxes	1,484	[3]	162	[3]	(481)	[3]	(245)	[3]	46		207		207		313		920	[3]	773		(433)
Net earnings (loss) from continuing operations	1,149		300		(474)		(211)		44		194		212		308		764		758		(574)
Net earnings (loss) from discontinued operations, net of income tax expense			2,263	[4]	139	[4]	58	[4]	260		18		33		9		2,460	[4]	320		(884)
Net earnings (loss) attributable to Devon	$ 1,149		$ 2,537		$ (425)		$ (197)		$ 183		$ 193		$ 219		$ 303		$ 3,064		$ 898		$ (1,056)
Basic net earnings (loss) per share attributable to Devon	$ 2.50		$ 5.17		$ (0.83)		$ (0.38)		$ 0.35		$ 0.37		$ 0.41		$ 0.58		$ 6.14		$ 1.71		$ (2.09)
Diluted net earnings (loss) per share attributable to Devon	$ 2.48		$ 5.14		$ (0.83)		$ (0.38)		$ 0.35		$ 0.37		$ 0.41		$ 0.58		$ 6.10		$ 1.70		$ (2.09)
[1]	Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers.
[2]	(1) Additional discussion regarding asset dispositions can be found in Note 2.
[3]	(2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5
[4]	(3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19

Supplemental Quarterly Financ_4

Supplemental Quarterly Financial Information (Schedule Of Unaudited Interim Results Of Operations) (Parenthetical) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2016
Quarterly Financial Data [Line Items]
Asset impairments		$ 150	$ 156	$ 437
EnLink and General Partner [Member]
Quarterly Financial Data [Line Items]
Gain on sale of aggregate ownership interests, after-tax	$ 2,200		$ 2,200