DEVON ENERGY CORP/DE, 10-K filed on 2/20/2019
Annual Report
v3.10.0.1
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 0001090012    
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 2018    
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  
v3.10.0.1
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.

 
v3.10.0.1
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.

 
v3.10.0.1
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.
v3.10.0.1
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) 1,000,000,000.0 1,000,000,000.0
Common stock, shares issued (in shares) 450,000,000 525,000,000
Treasury stock, shares 1,000,000.0  
v3.10.0.1
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          
v3.10.0.1
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, Devon sold its interests in EnLink and the General Partner on July 18, 2018. Activity relating to EnLink and the General Partner are classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows. 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.

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, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated comprehensive statements of earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are 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. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are 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), using the modified retrospective method. See revenue recognition section above for further discussion regarding Devon’s adoption of this revenue recognition standard.

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. This ASU requires entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. As a result of the adoption of this ASU, consolidated statements of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively. Upon adoption, Devon reclassified $7 million and $14 million of non-service cost components of net periodic benefit costs for 2017 and 2016, respectively, from G&A to other expenses.

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). This ASU allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. As a result of adopting this ASU, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet.

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. This ASU eliminated and added certain disclosure requirements for employers that sponsors defined benefit plans and/or other postretirement plans. Other than changes to required disclosures, this ASU did not have a material impact on Devon’s consolidated financial statements and related disclosures.

The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification, which amends various SEC disclosure requirements determined to be redundant, duplicative, overlapping, outdated or superseded as part of the SEC’s ongoing disclosure effectiveness initiative. The rule was effective November 5, 2018. The rule amended numerous SEC rules, items and forms covering a diverse group of topics. Devon has implemented these required changes to disclosures which generally reduced or eliminated disclosures. Devon will adopt the requirement of presenting a current and comparative year-to-date change in stockholder’s equity roll forward during the first quarter of 2019.

Issued Accounting Standards Not Yet Adopted

The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Short-term leases can continue being accounted for off balance sheet based on a policy election. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. Devon is adopting this ASU beginning January 1, 2019.

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. This ASU will eliminate, add and modify certain disclosure requirements for fair value measurement. The ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the entire standard or only the provisions that eliminate or modify requirements. The ASU requires the additional disclosure requirements to be adopted using a retrospective approach. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its disclosures in the notes to the consolidated financial statements.

 

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. This ASU will require a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a hosting arrangement that is a service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. This ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted. Entities have the option to adopt the ASU using either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of the adoption. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements.
v3.10.0.1
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. Additional information on these discontinued operations can be found in 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 for additional information. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 25 MMBoe, or less than 2%, of total U.S. proved reserves.

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.
v3.10.0.1
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

 
v3.10.0.1
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 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.

 

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.
v3.10.0.1
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 Impairments

 

In 2018, 2017 and 2016, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments.
v3.10.0.1
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.
v3.10.0.1
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 million, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. These losses during 2018, were partially offset by reversing $195 million of previously recognized unrealized losses on intercompany loan activity.

 

Foreign currency denominated intercompany loan activity during 2016 resulted in a realized gain of $63 million, as a result of the weakening of the U.S. dollar in relation to the Canadian dollar. These gains during 2016, were partially offset by reversing $10 million of previously recognized unrealized gains on intercompany loan activity.
v3.10.0.1
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

The 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.   

During 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. These items were not deductible for purposes of calculating income tax and, therefore, impacted the effective tax rate.

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 $784 million of U.S. state net operating loss carryforwards expiring between 2019 and 2038. In the current environment, Devon expects tax benefits from the U.S. federal, majority of U.S. state and Canadian noncapital loss carryforwards to be utilized in 2019 and beyond.

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. During 2018, Devon removed $43 million of unrecognized tax benefits, including $20 million of interest, as a result of the closure of certain tax examinations. 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

 

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.  

 
v3.10.0.1
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.

 
v3.10.0.1
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 for additional details.

 

(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 for additional details.

 
v3.10.0.1
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 for additional details. Further, in 2016, EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets included noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions.  
v3.10.0.1
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

 

 
v3.10.0.1
Property, Plant and Equipment
 12 Months Ended
Dec. 31, 2018
Extractive Industries [Abstract]  
Property, Plant and Equipment

13.Property, Plant and Equipment

 

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.

v3.10.0.1
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

 
v3.10.0.1
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% due July 1, 2018 (1)

 

$

—

 

 

$

20

 

2.25% due December 15, 2018

 

 

—

 

 

 

95

 

6.30% due January 15, 2019

 

 

162

 

 

 

162

 

4.00% due July 15, 2021

 

 

500

 

 

 

500

 

3.25% due May 15, 2022

 

 

1,000

 

 

 

1,000

 

5.85% due December 15, 2025

 

 

485

 

 

 

485

 

7.50% due September 15, 2027 (1)

 

 

73

 

 

 

73

 

7.875% due September 30, 2031 (2) (3)

 

 

675

 

 

 

1,059

 

7.95% due April 15, 2032 (2)

 

 

366

 

 

 

789

 

5.60% due July 15, 2041

 

 

1,250

 

 

 

1,250

 

4.75% due May 15, 2042

 

 

750

 

 

 

750

 

5.00% due June 15, 2045

 

 

750

 

 

 

750

 

Net discount on debentures and notes

 

 

(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. Devon recognized a loss on early retirement of debt, primarily consisting of $265 million in cash retirement costs and other fees. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.

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

 

 
v3.10.0.1
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.

 
v3.10.0.1
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 million, which was reclassified from other comprehensive earnings to other expense on the consolidated comprehensive statements of earnings in 2018.

 

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 for further discussion.

 

 

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.

v3.10.0.1
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. Additionally, in February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.

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.

v3.10.0.1
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  billion and recognized a gain of approximately $2.6  billion ($2.2  billion after-tax). Current (cash) income tax associated with the transaction was approximately $12 million. The vast majority of the tax effect relates to deferred tax expense offset by the valuation allowance adjustment explained in 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

 

 
v3.10.0.1
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.
v3.10.0.1
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, and Note 17, respectively.

 

 

 

 

 

 

 

 

 

 

 

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 derivatives– 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.

 
v3.10.0.1
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

 

 

 
v3.10.0.1
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. Additionally, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $41 million, $69 million and $61 million in 2018, 2017 and 2016, respectively.

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

 
v3.10.0.1
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.

 
v3.10.0.1
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, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated comprehensive statements of earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are 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. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are 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), using the modified retrospective method. See revenue recognition section above for further discussion regarding Devon’s adoption of this revenue recognition standard.

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. This ASU requires entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. As a result of the adoption of this ASU, consolidated statements of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively. Upon adoption, Devon reclassified $7 million and $14 million of non-service cost components of net periodic benefit costs for 2017 and 2016, respectively, from G&A to other expenses.

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). This ASU allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. As a result of adopting this ASU, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet.

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. This ASU eliminated and added certain disclosure requirements for employers that sponsors defined benefit plans and/or other postretirement plans. Other than changes to required disclosures, this ASU did not have a material impact on Devon’s consolidated financial statements and related disclosures.

The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification, which amends various SEC disclosure requirements determined to be redundant, duplicative, overlapping, outdated or superseded as part of the SEC’s ongoing disclosure effectiveness initiative. The rule was effective November 5, 2018. The rule amended numerous SEC rules, items and forms covering a diverse group of topics. Devon has implemented these required changes to disclosures which generally reduced or eliminated disclosures. Devon will adopt the requirement of presenting a current and comparative year-to-date change in stockholder’s equity roll forward during the first quarter of 2019.

Issued Accounting Standards Not Yet Adopted

The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Short-term leases can continue being accounted for off balance sheet based on a policy election. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. Devon is adopting this ASU beginning January 1, 2019.

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. This ASU will eliminate, add and modify certain disclosure requirements for fair value measurement. The ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the entire standard or only the provisions that eliminate or modify requirements. The ASU requires the additional disclosure requirements to be adopted using a retrospective approach. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its disclosures in the notes to the consolidated financial statements.

 

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. This ASU will require a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a hosting arrangement that is a service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. This ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted. Entities have the option to adopt the ASU using either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of the adoption. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements.
v3.10.0.1
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

 

 

$

—

 

 
v3.10.0.1
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

 

 
v3.10.0.1
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

 

 

$

—

 
v3.10.0.1
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

 
v3.10.0.1
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

 
v3.10.0.1
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

 
v3.10.0.1
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

 
v3.10.0.1
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.
v3.10.0.1
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 for additional details.

 

(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 for additional details.

 
v3.10.0.1
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

)
v3.10.0.1
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

 
v3.10.0.1
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

 
v3.10.0.1
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

 
v3.10.0.1
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% due July 1, 2018 (1)

 

$

—

 

 

$

20

 

2.25% due December 15, 2018

 

 

—

 

 

 

95

 

6.30% due January 15, 2019

 

 

162

 

 

 

162

 

4.00% due July 15, 2021

 

 

500

 

 

 

500

 

3.25% due May 15, 2022

 

 

1,000

 

 

 

1,000

 

5.85% due December 15, 2025

 

 

485

 

 

 

485

 

7.50% due September 15, 2027 (1)

 

 

73

 

 

 

73

 

7.875% due September 30, 2031 (2) (3)

 

 

675

 

 

 

1,059

 

7.95% due April 15, 2032 (2)

 

 

366

 

 

 

789

 

5.60% due July 15, 2041

 

 

1,250

 

 

 

1,250

 

4.75% due May 15, 2042

 

 

750

 

 

 

750

 

5.00% due June 15, 2045

 

 

750

 

 

 

750

 

Net discount on debentures and notes

 

 

(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

 
v3.10.0.1
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

 
v3.10.0.1
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 for further discussion.

 

 
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

 
v3.10.0.1
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

 

 

 

 

 
v3.10.0.1
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

 
v3.10.0.1
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

 
v3.10.0.1
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

)
v3.10.0.1
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.

v3.10.0.1
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

 
v3.10.0.1
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.

 
v3.10.0.1
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.

 
v3.10.0.1
Summary Of Significant Accounting Policies (Narrative) (Details)
 12 Months Ended
Dec. 31, 2018
USD ($)
Customer
Dec. 31, 2017
USD ($)
Customer
Dec. 31, 2016
USD ($)
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    
v3.10.0.1
Acquisitions And Divestitures (Narrative) (Details)
$ in Millions, $ in Millions
 1 Months Ended 3 Months Ended 12 Months Ended
Jan. 07, 2016
USD ($)
a
Oct. 31, 2016
USD ($)
Oct. 31, 2016
CAD ($)
Mar. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Sep. 30, 2018
USD ($)
Jun. 30, 2018
USD ($)
 [1]
Mar. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
 [1]
Sep. 30, 2017
USD ($)
 [1]
Jun. 30, 2017
USD ($)
 [1]
Mar. 31, 2017
USD ($)
 [1]
Dec. 31, 2018
USD ($)
MMBoe
Dec. 31, 2017
USD ($)
MMBoe
Dec. 31, 2016
USD ($)
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.
v3.10.0.1
Derivative Financial Instruments (Schedule Of Open Oil Derivative Positions) (Details)
 12 Months Ended
Dec. 31, 2018
$ / bbl
bbl
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 50.00
Weighted Average Floor Purchased Price 63.00
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 5.00
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)
v3.10.0.1
Derivative Financial Instruments (Schedule Of Open Natural Gas Derivative Positions) (Details)
 12 Months Ended
Dec. 31, 2018
MMBTU
$ / 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)
v3.10.0.1
Derivative Financial Instruments (Schedule Of Open NGL Derivative Positions) (Details)
 12 Months Ended
Dec. 31, 2018
$ / bbl
bbl
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
v3.10.0.1
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, 2018
USD ($)
Derivative [Line Items]  
Notional $ 100
Rate Received, percent 1.76%
Rate Paid Three Month LIBOR
Expiration Jan. 31, 2019
v3.10.0.1
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)
v3.10.0.1
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
v3.10.0.1
Share-Based Compensation (Narrative) (Details)
 12 Months Ended
Dec. 31, 2018
USD ($)
Company
shares
Dec. 31, 2017
shares
Dec. 31, 2016
shares
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  
v3.10.0.1
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
v3.10.0.1
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
$ / shares
shares
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.
v3.10.0.1
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, 2018
shares
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
v3.10.0.1
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
v3.10.0.1
Share-Based Compensation (Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2018
USD ($)
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
v3.10.0.1
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
v3.10.0.1
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
$ / shares
shares
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
v3.10.0.1
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
v3.10.0.1
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  
v3.10.0.1
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)
v3.10.0.1
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
v3.10.0.1
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
v3.10.0.1
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
v3.10.0.1
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
v3.10.0.1
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%)
v3.10.0.1
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    
v3.10.0.1
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)
v3.10.0.1
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
v3.10.0.1
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 2015
Minimum [Member] | Canada Federal [Member]  
Tax years open 2004
Maximum [Member] | United States Federal [Member]  
Tax years open 2018
Maximum [Member] | Canada Federal [Member]  
Tax years open 2018
Various U.S. States [Member] | Minimum [Member]  
Tax years open 2014
Various U.S. States [Member] | Maximum [Member]  
Tax years open 2018
Various Canadian Provinces [Member] | Minimum [Member]  
Tax years open 2004
Various Canadian Provinces [Member] | Maximum [Member]  
Tax years open 2018
v3.10.0.1
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.
v3.10.0.1
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 for additional details.

 
[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 for additional details.

 
v3.10.0.1
Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Parenthetical) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2018
USD ($)
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 for additional details.

 
v3.10.0.1
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)
v3.10.0.1
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
v3.10.0.1
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  
v3.10.0.1
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
v3.10.0.1
Property, Plant and Equipment (Schedule of Aging of Capitalized Exploratory Well Costs (Details)
$ in Millions
Dec. 31, 2018
USD ($)
Project
Dec. 31, 2017
USD ($)
Project
Dec. 31, 2016
USD ($)
Project
Dec. 31, 2015
USD ($)
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  
v3.10.0.1
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
v3.10.0.1
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. 01, 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 $169 million and 6.5%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.
[3] Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon.
[4] These senior notes were included in 2018 tender offer repurchases discussed below.
v3.10.0.1
Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Parenthetical) (Details) - USD ($)
$ 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. 01, 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.
v3.10.0.1
Debt And Related Expenses (Schedule Of Debt Maturities) (Details)
$ in Millions
Dec. 31, 2018
USD ($)
Debt Disclosure [Abstract]  
2019 $ 162
2021 500
2022 1,000
Thereafter 4,349
Total $ 6,011
v3.10.0.1
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   $ 0.0      
Redemption of senior notes   922.0 $ 2,492.0    
Loss on early retirement of debt   (312.0) (269.0)    
Loss on early retirement of debt, cash retirement costs   304.0 265.0    
Repurchase of debt securities     $ 2,100.0    
Senior Notes [Member]          
Debt Instrument [Line Items]          
Redemption of senior notes   807.0      
Loss on early retirement of debt   (312.0)      
Loss on early retirement of debt, cash retirement costs   304.0      
Loss on early retirement of debt, noncash charges   $ 8.0      
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   $ 384.0      
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   $ 423.0      
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   $ 95.0      
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 $ 162.0        
Debt interest rate, stated percentage 6.30%        
Commercial Paper [Member]          
Debt Instrument [Line Items]          
Credit Facility, borrowing capacity   $ 3,000.0      
2012 Senior Credit Facility [Member]          
Debt Instrument [Line Items]          
Credit Facility, borrowing capacity       $ 3,000.0  
2018 Senior Credit Facility [Member]          
Debt Instrument [Line Items]          
Credit Facility, borrowing capacity   $ 3,000.0      
Credit facility maturity date   Oct. 05, 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   0.0      
Outstanding letters of credit   $ 48.0      
Debt-to-capitalization ratio   0.210      
2018 Senior Credit Facility [Member] | Maximum [Member]          
Debt Instrument [Line Items]          
Debt-to-capitalization ratio   0.65      
v3.10.0.1
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
v3.10.0.1
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  
v3.10.0.1
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  
v3.10.0.1
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%    
v3.10.0.1
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)  
v3.10.0.1
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
v3.10.0.1
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 for further discussion.

 
v3.10.0.1
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%
v3.10.0.1
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)       1,000,000,000.0       1,000,000,000.0               1,000,000,000.0    
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       $ 1.00                       $ 1.00    
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                                
v3.10.0.1
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      
v3.10.0.1
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      
v3.10.0.1
Discontinued Operations and Assets Held for Sale (Narrative) (Details)
$ in Millions
 3 Months Ended 5 Months Ended 12 Months Ended
Sep. 30, 2018
USD ($)
Dec. 31, 2018
USD ($)
Dec. 31, 2018
USD ($)
MMcf
Dec. 31, 2016
USD ($)
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 2021  
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  
v3.10.0.1
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.

 
v3.10.0.1
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  
v3.10.0.1
Commitments And Contingencies (Narrative) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2018
USD ($)
Defendant
Dec. 31, 2017
USD ($)
Dec. 31, 2016
USD ($)
Loss Contingencies [Line Items]      
Obligation related to the purchase of condensate, year of expiration 2021    
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    
v3.10.0.1
Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details)
$ in Millions
Dec. 31, 2018
USD ($)
Purchase Obligations [Member]  
Long Term Purchase Commitment [Line Items]  
2019 $ 541
2020 567
2021 140
Total 1,248
Drilling And Facility Obligations [Member]  
Long Term Purchase Commitment [Line Items]  
2019 274
2020 85
2021 48
2022 14
2023 8
Thereafter 16
Total 445
Operational Agreements [Member]  
Long Term Purchase Commitment [Line Items]  
2019 587
2020 519
2021 373
2022 419
2023 354
Thereafter 3,374
Total 5,626
Office And Equipment Leases [Member]  
Long Term Purchase Commitment [Line Items]  
2019 64
2020 43
2021 31
2022 26
2023 25
Thereafter 311
Total $ 500
v3.10.0.1
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)
v3.10.0.1
Segment Information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Details)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2018
USD ($)
Sep. 30, 2018
USD ($)
Jun. 30, 2018
USD ($)
Mar. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Sep. 30, 2017
USD ($)
Jun. 30, 2017
USD ($)
Mar. 31, 2017
USD ($)
Dec. 31, 2018
USD ($)
segment
Dec. 31, 2017
USD ($)
Dec. 31, 2016
USD ($)
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 $10.2 billion in 2017 and 2016, respectively.
v3.10.0.1
Segment Information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Parenthetical) (Details) - USD ($)
$ 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
v3.10.0.1
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.
v3.10.0.1
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
v3.10.0.1
Supplemental Information On Oil And Gas Operations (Narrative) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2018
USD ($)
MBbls / d
MMBoe
$ / bbl
$ / Mcf
Dec. 31, 2017
USD ($)
MMBoe
Dec. 31, 2016
USD ($)
MMBoe
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Dec. 31, 2019
USD ($)
Dec. 31, 2015
MMBoe
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.
v3.10.0.1
Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2018
USD ($)
$ / Boe
Dec. 31, 2017
USD ($)
$ / Boe
Dec. 31, 2016
USD ($)
$ / 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
v3.10.0.1
Supplemental Information On Oil And Gas Operations (Proved Developed and Undeveloped Reserves) (Details)
MBbls in Thousands, Mcf in Millions
 12 Months Ended
Dec. 31, 2018
MMBoe
MBbls
Mcf
Dec. 31, 2017
MMBoe
MBbls
Mcf
Dec. 31, 2016
MMBoe
MBbls
Mcf
Dec. 31, 2015
MMBoe
MBbls
Mcf
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.
v3.10.0.1
Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details)
 12 Months Ended
Dec. 31, 2018
MMBoe
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.
v3.10.0.1
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  
v3.10.0.1
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
v3.10.0.1
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.

 
v3.10.0.1
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