Document And Entity Information
Document And Entity Information - USD ($) shares in Millions, $ in Billions | 12 Months Ended | ||
Dec. 31, 2018 | Feb. 06, 2019 | Jun. 29, 2018 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Amendment Flag | false | ||
Trading Symbol | DVN | ||
Entity Registrant Name | DEVON ENERGY CORP/DE | ||
Entity Central Index Key | 1,090,012 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | Yes | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2,018 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Document Fiscal Period Focus | FY | ||
Entity Public Float | $ 22.5 | ||
Entity Common Stock, Shares Outstanding | 438.3 |
Consolidated Comprehensive Stat
Consolidated Comprehensive Statements Of Earnings - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||
Income Statement [Abstract] | |||||
Upstream revenues | $ 6,285 | $ 5,307 | $ 3,981 | ||
Revenues | $ 4,449 | $ 3,571 | $ 2,772 | ||
Type of Revenue [Extensible List] | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | ||
Total revenues | $ 10,734 | [1] | $ 8,878 | $ 6,753 | |
Production expenses | 2,225 | 1,823 | 1,805 | ||
Exploration expenses | 177 | 380 | 215 | ||
Expenses | $ 4,363 | $ 3,619 | $ 2,821 | ||
Type of Cost, Good or Service [Extensible List] | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | ||
Depreciation, depletion and amortization | $ 1,658 | $ 1,529 | $ 1,592 | ||
Asset impairments | 156 | 437 | |||
Asset dispositions | (263) | [2] | (217) | [2] | (1,496) |
General and administrative expenses | 650 | 737 | 733 | ||
Financing costs, net | 594 | 317 | 717 | ||
Restructuring and transaction costs | 114 | 261 | |||
Other expenses | 140 | (83) | 101 | ||
Total expenses | 9,814 | 8,105 | 7,186 | ||
Earnings (loss) from continuing operations before income taxes | 920 | [3] | 773 | (433) | |
Income tax expense | 156 | 15 | 141 | ||
Net earnings (loss) from continuing operations | 764 | 758 | (574) | ||
Net earnings (loss) from discontinued operations, net of income tax expense | 2,460 | [4] | 320 | (884) | |
Net earnings (loss) | 3,224 | 1,078 | (1,458) | ||
Net earnings (loss) attributable to noncontrolling interests | 160 | 180 | (402) | ||
Net earnings (loss) attributable to Devon | $ 3,064 | $ 898 | $ (1,056) | ||
Basic net earnings (loss) per share: | |||||
Basic earnings (loss) from continuing operations per share | $ 1.53 | $ 1.44 | $ (1.14) | ||
Basic earnings (loss) from discontinued operations per share | 4.61 | 0.27 | (0.95) | ||
Basic net earnings (loss) per share | 6.14 | 1.71 | (2.09) | ||
Diluted net earnings (loss) per share: | |||||
Diluted earnings (loss) from continuing operations per share | 1.52 | 1.43 | (1.14) | ||
Diluted earnings (loss) from discontinued operations per share | 4.58 | 0.27 | (0.95) | ||
Diluted net earnings (loss) per share | $ 6.10 | $ 1.70 | $ (2.09) | ||
Comprehensive earnings (loss): | |||||
Net earnings (loss) | $ 3,224 | $ 1,078 | $ (1,458) | ||
Other comprehensive earnings (loss), net of tax: | |||||
Foreign currency translation | (152) | 83 | 11 | ||
Pension and postretirement plans | 44 | 29 | 22 | ||
Other comprehensive earnings (loss), net of tax | (108) | 112 | 33 | ||
Comprehensive earnings (loss) | 3,116 | 1,190 | (1,425) | ||
Comprehensive earnings (loss) attributable to noncontrolling interests | 160 | 180 | (402) | ||
Comprehensive earnings (loss) attributable to Devon | $ 2,956 | $ 1,010 | $ (1,023) | ||
[1] | Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. | ||||
[2] | (1) Additional discussion regarding asset dispositions can be found in Note 2. | ||||
[3] | (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 | ||||
[4] | (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Cash flows from operating activities: | ||||
Net earnings (loss) | $ 3,224 | $ 1,078 | $ (1,458) | |
Adjustments to reconcile net earnings to net cash from operating activities: | ||||
Net (earnings) loss from discontinued operations, net of income tax expense | (2,460) | [1] | (320) | 884 |
Depreciation, depletion and amortization | 1,658 | 1,529 | 1,592 | |
Asset impairments | 156 | 437 | ||
Leasehold impairments | 95 | 219 | 113 | |
Accretion on discounted liabilities | 61 | 63 | 75 | |
Total (gains) losses on commodity derivatives | (608) | (157) | 201 | |
Cash settlements on commodity derivatives | (84) | 53 | 1 | |
Gains on asset dispositions | (263) | (217) | (1,496) | |
Deferred income tax expense (benefit) | 226 | (97) | 43 | |
Share-based compensation | 161 | 150 | 203 | |
Early retirement of debt | 312 | 269 | ||
Total (gains) losses on foreign exchange | 139 | (132) | (121) | |
Settlements of intercompany foreign denominated assets/liabilities | (241) | 9 | 63 | |
Other | (5) | (1) | 4 | |
Changes in assets and liabilities, net | (143) | 32 | 24 | |
Net cash from operating activities - continuing operations | 2,228 | 2,209 | 834 | |
Cash flows from investing activities: | ||||
Capital expenditures | (2,451) | (1,968) | (1,384) | |
Acquisitions of property and equipment | (55) | (46) | (849) | |
Divestitures of property and equipment | 1,013 | 426 | 3,020 | |
Net cash from investing activities - continuing operations | (1,493) | (1,588) | 787 | |
Cash flows from financing activities: | ||||
Repayments of long-term debt principal | (922) | (2,492) | ||
Net short-term debt repayments | (626) | |||
Early retirement of debt | (304) | (265) | ||
Issuance of common stock | 1,469 | |||
Repurchases of common stock | (2,956) | |||
Dividends paid on common stock | (149) | (127) | (221) | |
Shares exchanged for tax withholdings | (48) | (59) | (35) | |
Other | (7) | |||
Net cash from financing activities - continuing operations | (4,386) | (186) | (2,170) | |
Effect of exchange rate changes on cash: | ||||
Settlements of intercompany foreign denominated assets/liabilities | 241 | (9) | (63) | |
Other | (35) | 15 | 2 | |
Total effect of exchange rate changes on cash - continuing operations | 206 | 6 | (61) | |
Net change in cash, cash equivalents and restricted cash of continuing operations | (3,445) | 441 | (610) | |
Cash flows from discontinued operations: | ||||
Operating activities | 476 | 700 | 666 | |
Investing activities | 2,548 | (611) | (1,381) | |
Financing activities | 183 | 195 | 974 | |
Net change in cash, cash equivalents and restricted cash of discontinued operations | 3,207 | 284 | 259 | |
Net change in cash, cash equivalents and restricted cash | (238) | 725 | (351) | |
Cash, cash equivalents and restricted cash at beginning of period | 2,684 | 1,959 | 2,310 | |
Cash, cash equivalents and restricted cash at end of period | 2,446 | 2,684 | 1,959 | |
Reconciliation of cash, cash equivalents and restricted cash: | ||||
Cash and cash equivalents | 2,414 | 2,642 | 1,947 | |
Restricted cash included in other current assets | 32 | 11 | ||
Cash and cash equivalents included in current assets held for sale | 31 | 12 | ||
Cash, cash equivalents and restricted cash at end of period | $ 2,446 | $ 2,684 | $ 1,959 | |
[1] | (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
ASSETS | |||
Cash and cash equivalents | $ 2,414 | $ 2,642 | |
Accounts receivable | 885 | 989 | |
Current assets held for sale | 197 | 760 | |
Other current assets | 941 | 400 | |
Total current assets | 4,437 | 4,791 | |
Oil and gas property and equipment, based on successful efforts accounting, net | 12,813 | 13,318 | |
Other property and equipment, net | 1,122 | 1,266 | |
Total property and equipment, net | 13,935 | 14,584 | |
Goodwill | 841 | 841 | |
Other long-term assets | 353 | 296 | |
Long-term assets held for sale | 9,729 | ||
Total assets | 19,566 | 30,241 | |
LIABILITIES AND EQUITY | |||
Accounts payable | 662 | 633 | |
Revenues and royalties payable | 898 | 748 | |
Short-term debt | [1] | 162 | 115 |
Current liabilities held for sale | 69 | 991 | |
Other current liabilities | 435 | 828 | |
Total current liabilities | 2,226 | 3,315 | |
Long-term debt | 5,785 | 6,749 | |
Asset retirement obligations | 1,030 | 1,099 | |
Other long-term liabilities | 462 | 549 | |
Long-term liabilities held for sale | 3,936 | ||
Deferred income taxes | 877 | 489 | |
Equity: | |||
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 450 million and 525 million shares in 2018 and 2017, respectively | 45 | 53 | |
Additional paid-in capital | 4,486 | 7,333 | |
Retained earnings | 3,650 | 702 | |
Accumulated other comprehensive earnings | 1,027 | 1,166 | |
Treasury stock, at cost, 1.0 million shares in 2018 | (22) | ||
Total stockholders’ equity attributable to Devon | 9,186 | 9,254 | |
Noncontrolling interests | 4,850 | ||
Total equity | 9,186 | 14,104 | |
Total liabilities and equity | $ 19,566 | $ 30,241 | |
[1] | 2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement Of Financial Position [Abstract] | ||
Common stock, par value (in dollars per share) | $ 0.10 | $ 0.10 |
Common stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued (in shares) | 450,000,000 | 525,000,000 |
Treasury stock, shares | 1,000,000 |
Consolidated Statements Of Equi
Consolidated Statements Of Equity - USD ($) shares in Millions, $ in Millions | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Retained Earnings (Accumulated Deficit) [Member] | Accumulated Other Comprehensive Earnings [Member] | Treasury Stock [Member] | Noncontrolling Interests [Member] |
Balance at Dec. 31, 2015 | $ 11,111 | $ 42 | $ 4,996 | $ 1,112 | $ 1,021 | $ 3,940 | |
Balance, shares at Dec. 31, 2015 | 418 | ||||||
Net earnings (loss) | (1,458) | (1,056) | (402) | ||||
Other comprehensive earnings (loss), net of tax | 33 | 33 | |||||
Restricted stock grants, net of cancellations, shares | 2 | ||||||
Common stock repurchased | (28) | $ (28) | |||||
Common stock retired | (28) | 28 | |||||
Common stock dividends | (221) | (96) | (125) | ||||
Common stock issued | 2,127 | $ 10 | 2,117 | ||||
Common stock issued, shares | 103 | ||||||
Share-based compensation | 168 | 168 | |||||
Subsidiary equity transactions | 1,294 | 80 | 1,214 | ||||
Distributions to noncontrolling interests | (304) | (304) | |||||
Balance at Dec. 31, 2016 | 12,722 | $ 52 | 7,237 | (69) | 1,054 | 4,448 | |
Balance, shares at Dec. 31, 2016 | 523 | ||||||
Net earnings (loss) | 1,078 | 898 | 180 | ||||
Other comprehensive earnings (loss), net of tax | 112 | 112 | |||||
Restricted stock grants, net of cancellations, value | 1 | $ 1 | |||||
Restricted stock grants, net of cancellations, shares | 1 | ||||||
Common stock repurchased | (44) | (44) | |||||
Common stock retired | (44) | 44 | |||||
Common stock dividends | (127) | (127) | |||||
Share-based compensation | 126 | 126 | |||||
Share-based compensation, shares | 1 | ||||||
Subsidiary equity transactions | 590 | 14 | 576 | ||||
Distributions to noncontrolling interests | (354) | (354) | |||||
Balance at Dec. 31, 2017 | 14,104 | $ 53 | 7,333 | 702 | 1,166 | 4,850 | |
Balance, shares at Dec. 31, 2017 | 525 | ||||||
Net earnings (loss) | 3,224 | 3,064 | 160 | ||||
Other comprehensive earnings (loss), net of tax | (108) | (108) | |||||
Restricted stock grants, net of cancellations, shares | 3 | ||||||
Common stock repurchased | (3,017) | (3,017) | |||||
Common stock retired | $ (8) | (2,987) | 2,995 | ||||
Common stock retired, shares | (79) | ||||||
Common stock dividends | (149) | (149) | |||||
Share-based compensation | 140 | 140 | |||||
Share-based compensation, shares | 1 | ||||||
Divestment of subsidiary equity investment | (4,861) | 2 | (4,863) | ||||
Subsidiary equity transactions | 72 | 72 | |||||
Distributions to noncontrolling interests | (219) | $ (219) | |||||
Other | 33 | (33) | |||||
Balance at Dec. 31, 2018 | $ 9,186 | $ 45 | $ 4,486 | $ 3,650 | $ 1,027 | $ (22) | |
Balance, shares at Dec. 31, 2018 | 450 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | 1. Summary of Significant Accounting Policies Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. As further discussed in Note 2 Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U.S. and reflect industry practices. The more significant of such policies are discussed below. Principles of Consolidation The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets. Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following: • proved reserves and related present value of future net revenues; • evaluation of suspended well costs; • the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; • derivative financial instruments; • the fair value of reporting units and related assessment of goodwill for impairment; • income taxes; • asset retirement obligations; • obligations related to employee pension and postretirement benefits; • legal and environmental risks and exposures; and • general credit risk associated with receivables and other assets. Revenue Recognition Impact of ASC 606 Adoption In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. The impact of adoption in the current period results is as follows: Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) Upstream revenues $ 6,285 $ 6,031 $ 254 Marketing revenues 4,449 4,449 — Total impacted revenues $ 10,734 $ 10,480 $ 254 Production expenses $ 2,225 $ 1,971 $ 254 Marketing expenses 4,363 4,363 — Total impacted expenses $ 6,588 $ 6,334 $ 254 Earnings from continuing operations before income taxes $ 920 $ 920 $ — Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses. Upstream Revenues Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings. Natural gas and NGL sales Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statements of earnings. In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Oil sales Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Marketing Revenues Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership. Satisfaction of Performance Obligations and Revenue Recognitions Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the natural gas, NGLs or crude oil are delivered at a fixed or determinable price. Transaction Price Allocated to Remaining Performance Obligations Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets. Disaggregation of Revenue Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. Disaggregation of revenue disclosures can be found in Note 22 Customers During 2018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue. During 2017 and 2016, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue. Derivative Financial Instruments Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes. Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes both two-way price collars and three-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty. The three-way price collars consist of a two-way collar with an additional short put option sold by Devon, and cash-settle similarly to the two-way collars unless the market price falls below the additional short put causing the company to receive the market price plus the long put to short put price differential. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of December 31, 2018, Devon did not have any open foreign exchange contracts. All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2018, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2018, Devon held no cash collateral of its counterparties nor posted collateral to its counterparties. General and Administrative Expenses G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon. Share-Based Compensation Devon grants share-based awards to members of its Board of Directors and select employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6 Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase. Income Taxes Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 8 for further discussion. Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense. Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur. Net Earnings (Loss) Per Share Attributable to Devon Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of unvested performance share units. Cash and Cash Equivalents Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. Accounts Receivable Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable, including joint interest receivables, for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance. Property and Equipment Oil and Gas Property and Equipment Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly. Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production. Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are amortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms. Proved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. generally accounted for as adjustments to capitalized costs with no gain or loss recognized. Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major development projects of oil and gas properties. Other Property and Equipment Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major corporate construction projects are also capitalized. Asset Retirement Obligations Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment. Goodwill Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of each reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. Devon performed impairment tests of goodwill in the fourth quarters of 2018, 2017 and 2016. No impairment was required as a result of the annual tests in these time periods. Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment. Fair Value Measurements Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels: • Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. • Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. • Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model. Foreign Currency Translation Adjustments The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity. Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. Recently Adopted Accounting Standards In January 2018, Devon adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash . This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon made changes to the statement of cash flows to include the required presentation and reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows. In the fourth quarter of 2018, Devon early adopted ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220) In the fourth quarter of 2018, Devon early adopted ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification Issued Accounting Standards Not Yet Adopted The FASB issued ASU 2016-02, Leases (Topic 842) Leases Devon will apply the guidance using a modified retrospective transition method at the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also has elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases. Devon will be allowed to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented with the 2019 adoption year. Devon has implemented processe |
Acquisitions And Divestitures
Acquisitions And Divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisitions And Divestitures | 2. Acquisitions and Divestitures Acquisitions In January 2016, Devon acquired approximately 80,000 net acres and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of equity. The allocation of the purchase price was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties. Divestitures EnLink and General Partner During the third quarter of 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). The proceeds from the sale were utilized to increase Devon’s share repurchase program to $4.0 billion, which is discussed further in Note 18 Note 19 Upstream Assets During 2018, Devon received proceeds of approximately $1.0 billion and recognized a net gain on asset dispositions of approximately $260 million, primarily from sales of non-core assets in the Barnett Shale and Delaware Basin. As part of the transactions, approximately $84 million of asset retirement obligations were assumed by the purchasers. In conjunction with the divestitures, Devon settled certain gas processing contracts and recognized $40 million in settlement expense, which is included in asset dispositions within the 2018 consolidated statements of earnings. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 267 MMBoe, or 18%, of total U.S. proved reserves. Additionally, in the first quarter of 2019, Devon completed two separate divestitures of non-core assets in the Permian Basin totaling $300 million. One of the divestitures related to the sale of an entire common operating field, and Devon expects to recognize a gain of approximately $35 million during the first quarter of 2019. As of December 31, 2018, these associated assets and liabilities were classified as held for sale in the accompanying consolidated balance sheet. See Note 19 During 2017, Devon received proceeds totaling approximately $420 million, and recognized a net gain on asset dispositions of $212 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves. During 2016, Devon received proceeds totaling approximately $1.9 billion and recognized a net gain on asset dispositions of $809 million, primarily from sales of non-core assets in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. Estimated proved reserves associated with these assets were approximately 157 MMBoe, or 10%, of total U.S. proved reserves. As part of the transactions, approximately $290 million of asset retirement obligations were assumed by purchasers and approximately $80 million of goodwill was allocated to these divested assets. Access Pipeline In October 2016, Devon divested its 50% interest in Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes. Canada and Barnett Shale (Subsequent Event) In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from the Company, based on authorizations provided by its Board of Directors subsequent to December 31, 2018. Devon will evaluate multiple methods of separation for these assets, including potential sales or spin-offs. Devon is in the early stages of marketing these assets and does not currently have any indications that it would recognize an impairment upon separating its Canadian business or its Barnett Shale assets. Devon anticipates reporting all financial information for its Canadian business and Barnett Shale assets as discontinued operations in 2019 when all the requisite criteria are met for such financial statement presentation. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | 3. Derivative Financial Instruments Commodity Derivatives As of December 31, 2018, Devon had the following open oil derivative positions. The first two tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The third table presents Devon’s oil derivatives that settle against the respective indices noted within the table. Price Swaps Price Collars Period Volume (Bbls/d) Weighted Average Price ($/Bbl) Volume (Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2019 51,719 $ 59.48 87,921 $ 54.48 $ 64.49 Q1-Q4 2020 1,740 $ 62.88 8,951 $ 52.85 $ 63.13 Three-Way Price Collars Period Volume (Bbls/d) Weighted Average Floor Sold Price ($/Bbl) Weighted Average Floor Purchased Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2019 5,000 $ 50.00 $ 63.00 $ 74.80 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2019 Midland Sweet 28,000 $ (0.46 ) Q1-Q4 2019 Argus LLS 17,500 $ 5.00 Q1-Q4 2019 Argus MEH 16,000 $ 2.84 Q1-Q4 2019 NYMEX Roll 38,000 $ 0.45 Q1-Q4 2019 Western Canadian Select 31,505 $ (21.73 ) Q1-Q4 2020 NYMEX Roll 38,000 $ 0.31 Q1-Q4 2020 Western Canadian Select 915 $ (20.75 ) As of December 31, 2018, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table. Price Swaps Price Collars Period Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Volume (MMBtu/d) Weighted Average Floor Price ($/MMBtu) Weighted Average Ceiling Price ($/MMBtu) Q1-Q4 2019 266,293 $ 2.86 231,474 $ 2.69 $ 3.06 Q1-Q4 2020 26,480 $ 2.92 24,490 $ 2.74 $ 3.04 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2019 Panhandle Eastern Pipe Line 84,466 $ (0.73 ) Q1-Q4 2019 El Paso Natural Gas 130,000 $ (1.46 ) Q1-Q4 2019 Houston Ship Channel 142,637 $ 0.01 Q1-Q4 2019 Transco Zone 4 7,397 $ (0.03 ) As of December 31, 2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index. Price Swaps Period Product Volume (Bbls/d) Weighted Average Price ($/Bbl) Q1-Q4 2019 Ethane 1,000 $ 11.55 Q1-Q4 2019 Natural Gasoline 4,500 $ 55.93 Q1-Q4 2019 Normal Butane 4,000 $ 33.69 Q1-Q4 2019 Propane 8,500 $ 30.01 Interest Rate Derivatives As of December 31, 2018, Devon had the following open interest rate derivative positions: Notional Rate Received Rate Paid Expiration $ 100 1.76% Three Month LIBOR January 2019 In January 2019, this interest rate derivative position settled. Financial Statement Presentation The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption. Year Ended December 31, 2018 2017 2016 Commodity derivatives: Upstream revenues $ 608 $ 157 $ (201 ) Marketing revenues (1 ) 3 (2 ) Interest rate derivatives: Other expenses 65 (22 ) (19 ) Foreign currency derivatives: Other expenses — — (153 ) Net gains (losses) recognized $ 672 $ 138 $ (375 ) The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2018 December 31, 2017 Commodity derivative assets: Other current assets $ 637 $ 203 Other long-term assets 40 2 Interest rate derivative assets: Other current assets — 1 Total derivative assets $ 677 $ 206 Commodity derivative liabilities: Other current liabilities $ 67 $ 259 Other long-term liabilities 1 27 Interest rate derivative liabilities: Other current liabilities — 64 Total derivative liabilities $ 68 $ 350 |
Share-Based Compensation
Share-Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Share-Based Compensation | 4. Share-Based Compensation In 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards that were transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares. The vesting for certain share-based awards was accelerated in 2018 and 2016 in conjunction with the reduction of workforce activities described in Note 6 The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 G&A $ 122 $ 141 $ 124 Exploration expenses 4 7 6 Restructuring and transaction costs 31 — 60 Total $ 157 $ 148 $ 190 Related income tax benefit $ 22 $ 6 $ 6 The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plans. Restricted Stock Performance-Based Performance Awards and Units Restricted Stock Awards Share Units Awards and Units Weighted Average Grant-Date Fair Value Awards Weighted Average Grant-Date Fair Value Units Weighted Average Grant-Date Fair Value (Thousands, except fair value data) Unvested at 12/31/17 6,328 $ 36.81 575 $ 38.92 2,758 $ 41.21 Granted 3,592 $ 35.98 — $ — 845 $ 37.40 Vested (3,114 ) $ 38.75 (273 ) $ 42.22 (571 ) $ 84.22 Forfeited (843 ) $ 35.58 — $ — (164 ) $ 33.92 Unvested at 12/31/18 5,963 $ 35.47 302 $ 35.93 2,868 (1 ) $ 30.14 (1) A maximum of 5.7 million common shares could be awarded based upon Devon’s final TSR ranking. The following table presents the aggregate fair value of awards and units that vested during the indicated period. 2018 2017 2016 Restricted Stock Awards and Units $ 111 $ 105 $ 73 Performance-Based Restricted Stock Awards $ 10 $ 10 $ 5 Performance Share Units $ 20 $ 38 $ 13 The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2018. Performance-Based Restricted Stock Restricted Stock Performance Awards and Units Awards Share Units Unrecognized compensation cost $ 117 $ 1 $ 23 Weighted average period for recognition (years) 2.4 1.0 1.7 Restricted Stock Awards and Units Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from one to four years. During the vesting period, recipients of restricted stock awards made under the 2015 Plan or 2009 Plan receive dividends that are not subject to restrictions or other limitations. However, dividends declared during the vesting period with respect to restricted stock awards made under the 2017 Plan and all restricted stock units will not be paid until the underlying award vests. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. Performance-Based Restricted Stock Awards Performance-based restricted stock awards were granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from one to four years. In order for awards to vest, the performance target must be met in the first year. If the performance target is met, the recipient is entitled to dividends under the same terms described above for nonperformance-based restricted stock. If the performance target and service period requirements are not met, the award does not vest. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. Performance Share Units Performance share units are granted to certain members of Devon’s management and senior employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified three-year performance period. The vesting of units may be between zero and 200% of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date. At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted. 2018 2017 2016 Grant-date fair value $36.23 — $ 37.88 $51.05 — $53.12 $9.24 — $10.61 Risk-free interest rate 2.28% 1.50% 0.94% Volatility factor 45.8% 45.8% 37.7% Contractual term (years) 2.89 2.89 2.83 Stock Options In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from one to four years. The fair value of stock options on the date of grant is expensed over the applicable vesting period. No stock options were granted in 2018, 2017 and 2016. The following table presents a summary of Devon’s outstanding stock options. Weighted Average Options Exercise Price Remaining Term Intrinsic Value (Thousands) (Years) Outstanding at December 31, 2017 1,746 $ 70.04 Expired (1,029 ) $ 72.51 Outstanding at December 31, 2018 717 $ 66.49 0.87 $ — Exercisable at December 31, 2018 717 $ 66.49 0.87 $ — As of December 31, 2018, Devon had no unrecognized compensation cost related to unvested stock options. |
Asset Impairments
Asset Impairments | 12 Months Ended |
Dec. 31, 2018 | |
Asset Impairment Charges [Abstract] | |
Asset Impairments | 5. Asset Impairments The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 Proved oil and gas assets $ 109 $ — $ 435 Other assets 47 — 2 Total asset impairments $ 156 $ — $ 437 Unproved impairments $ 95 $ 217 $ 77 Proved Oil and Gas and Other Asset Impairments In 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and approximately $47 million of non-oil and gas asset impairments. In 2016, Devon impaired a portion of its U.S. oil and gas portfolio due to lower forecasted oil, gas and NGL prices. Unproved In 2018, 2017 and 2016, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments. |
Restructuring and Transaction C
Restructuring and Transaction Costs | 12 Months Ended |
Dec. 31, 2018 | |
Restructuring And Related Activities [Abstract] | |
Restructuring and Transaction Costs | 6. Restructuring and Transaction Costs The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets. Other Other Current Long-term Liabilities Liabilities Total Balance as of December 31, 2016 $ 48 $ 62 $ 110 Changes related to prior years’ restructurings (29 ) (31 ) (60 ) Balance as of December 31, 2017 $ 19 $ 31 $ 50 Changes due to 2018 workforce reductions 30 — 30 Changes related to prior years’ restructurings (2 ) (15 ) (17 ) Balance as of December 31, 2018 $ 47 $ 16 $ 63 2018 Workforce Reductions In 2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized $114 million of restructuring expenses during 2018, primarily consisting of employee-related costs. Of these expenses, $31 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, $14 million resulted from estimated settlements of defined retirement benefits. Prior Years’ Restructurings In 2016, Devon recognized $227 million in employee-related and other costs associated with a reduction in workforce that was made in response to the depressed commodity price environment. Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $24 million resulted from estimated defined benefit settlements. As a result of the reduction of workforce, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Devon recognized $23 million in restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using. Transaction Costs In 2016, Devon recognized $11 million in transaction costs primarily associated with the closing of the STACK acquisition discussed in Note 2 |
Other Expenses
Other Expenses | 12 Months Ended |
Dec. 31, 2018 | |
Other Income And Expenses [Abstract] | |
Other Expenses | 7. Other Expenses The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 Foreign exchange (gain) loss, net $ 139 $ (132 ) $ 39 Asset retirement obligation accretion 59 62 75 Other, net (58 ) (13 ) (13 ) Total $ 140 $ (83 ) $ 101 Foreign exchange (gain) loss, net The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. The amounts in the table above include both unrealized and realized foreign exchange impacts of foreign currency denominated monetary assets and liabilities, including intercompany loans between subsidiaries with different functional currencies. Unrealized gains and losses arise from the remeasurement of these foreign currency denominated monetary assets and liabilities and intercompany loans. Realized gains and losses arise when there are settlements of these foreign currency denominated monetary assets and liabilities and intercompany loans. Foreign currency denominated intercompany loan activity during 2018 resulted in a realized loss of $ 241 195 Foreign currency denominated intercompany loan activity during 2016 resulted in a realized gain of $ 63 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 8. Income Taxes Income Tax Expense (Benefit) The following table presents Devon’s income tax components. Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit): U.S. federal $ (14 ) $ 9 $ 3 Various states (3 ) — (11 ) Canada and various provinces (53 ) 103 106 Total current tax expense (benefit) (70 ) 112 98 Deferred income tax expense (benefit): U.S. federal 248 — — Various states 63 — — Canada and various provinces (85 ) (97 ) 43 Total deferred tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141 Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following: Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit) $ (70 ) $ 112 $ 98 Deferred income tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141 U.S. statutory income tax rate 21 % 35 % 35 % U.S. Tax Reform 0 % 36 % 0 % Legal entity restructuring 2 % (94 %) 19 % State income taxes 5 % 0 % 10 % Change in unrecognized tax benefits (5 %) 2 % (16 %) Other (0 %) (13 %) 8 % Deferred tax asset valuation allowance (6 %) 36 % (89 %) Effective income tax rate 17 % 2 % (33 %) Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examinations by the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. 2018 In the second quarter of 2018, Devon’s Canadian segment utilized a portion of its capital losses as a part of an internal legal entity restructuring. A valuation allowance remains recorded against the remaining balance of the capital losses. During 2018, Devon recorded a tax benefit of $42 million related to unrecognized tax benefits, primarily as a result of a favorable Canadian court decision and the closure of prior year IRS audits. Throughout 2017 and through the first two quarters of 2018, Devon’s U.S. segment maintained a 100% valuation allowance against its U.S. deferred tax assets. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period projected net operating loss utilization, and projections of future taxable income, Devon reassessed its position and determined that its U.S. segment is no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses. As part of its reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon’s U.S. segment would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the $259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations. A partial valuation allowance continues to be held against certain Canadian segment deferred tax assets. During 2018, the Canadian segment reduced its valuation allowance by approximately $59 million. 2017 T he Tax Reform Legislation, enacted on December 22, 2017, contained several key tax provisions that affected Devon, including a one-time mandatory transition tax on accumulated foreign earnings and a reduction of the corporate income tax rate to 21% effective January 1, 2018. Devon was required to recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax, remeasuring U.S. deferred tax assets and liabilities and reassessing the net realizability of deferred tax assets and liabilities . Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings, and $108 million in deferred tax expense related to the reduction of the U.S. corporate income tax rate to 21%. In the fourth quarter of 2017, Devon’s Canadian segment generated nonrecurring capital losses from internal legal entity restructuring. A deferred tax asset of $727 million was recognized related to the capital losses, offset by a $641 million increase in the valuation allowance Devon maintained a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to asset impairments and significant net operating losses for U.S. federal and state income tax. Devon reduced its U.S. segment valuation allowance by $323 million in 2017 based primarily on the financial income recorded during the period. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets. Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in 2017 due to lower relative earnings during the period. 2016 Devon recorded a tax expense of $63 million related to unrecognized tax benefits during 2016, primarily as a result of Canadian audits and legal proceedings. During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its deferred tax assets. The allowance resulted from continued financial losses in 2016. As of December 31, 2016, the allowance continued to represent a 100% valuation against the U.S. net deferred tax assets. Additionally, the Canadian segment recognized a $71 million partial valuation allowance resulting from continued financial losses. D uring the third quarter of 2016, Devon derecognized $83 million of goodwill related to its U.S. operations in conjunction with the divestiture of certain non-core U.S. upstream oil and gas assets. Deferred Tax Assets and Liabilities The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities. December 31, 2018 2017 Deferred tax assets: Asset retirement obligations $ 300 $ 313 Accrued liabilities 50 62 Net operating loss carryforwards 287 796 Pension benefit obligations 44 54 Canadian capital loss carryforwards 609 760 Other 87 135 Total deferred tax assets before valuation allowance 1,377 2,120 Less: valuation allowance (640 ) (968 ) Net deferred tax assets 737 1,152 Deferred tax liabilities: Property and equipment (1,473 ) (1,288 ) Long-term debt — (92 ) Other (141 ) (261 ) Total deferred tax liabilities (1,614 ) (1,641 ) Net deferred tax liability $ (877 ) $ (489 ) At December 31, 2018, Devon has recognized $287 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segment has $595 million of noncapital loss carryforwards expiring between 2029 and 2038. Devon’s U.S. segment has $389 million of U.S. federal net operating loss carryforwards expiring in 2037 and . As a result of Devon’s sale of its aggregate ownership interests in EnLink and the General Partner during the third quarter of 2018, Devon’s U.S. segment reassessed its position and released its full valuation allowance position, maintaining only $31 million of valuation allowance against certain deferred tax assets, including certain tax credits and state net operating losses. Also during 2018, Devon’s Canadian segment maintained a valuation allowance of $609 million against the deferred tax asset related to the Canadian capital loss carryforward due to projected lack of future capital gain income. In the event Devon were to determine that it would be able to realize the deferred income tax assets in the future, Devon would adjust the valuation allowance, reducing the provision for income taxes in the period of such adjustment. After enactment of the Tax Reform Legislation, Devon’s Canadian segment is the sole foreign operation to be considered for the indefinitely reinvested assertion of APB 23. Devon’s Canadian operations are robust and active and requires continuing capital investment. Accordingly, as of December 31, 2018, no income taxes should be accrued by Devon relative to its investment in its Canadian operations. In view of Devon’s decision in February 2019 to dispose of the Canadian business, the indefinitely reinvested assertion of APB 23 and any required accrual of income tax will be reevaluated in 2019. Unrecognized Tax Benefits The following table presents changes in Devon’s unrecognized tax benefits. December 31, 2018 2017 Balance at beginning of year $ 115 $ 202 Tax positions taken in prior periods (43 ) (7 ) Tax positions taken in current year (2 ) (3 ) Accrual of interest related to tax positions taken 3 16 Settlements — (101 ) Foreign currency translation (3 ) 8 Balance at end of year $ 70 $ 115 Devon’s unrecognized tax benefit balance at December 31, 2018 and 2017 included $12 million and $28 million, respectively, of interest and penalties. If recognized, $70 million of Devon’s unrecognized tax benefits as of December 31, 2018 would affect Devon’s effective income tax rate. Jurisdiction Tax Years Open U.S. Federal 2015-2018 Various U.S. states 2014-2018 Canada Federal 2004-2018 Various Canadian provinces 2004-2018 Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. |
Net Earnings (Loss) Per Share f
Net Earnings (Loss) Per Share from Continuing Operations | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Net Earnings (Loss) Per Share from Continuing Operations | 9 . Net Earnings (Loss) Per Share from Continuing Operations The following table reconciles net earnings (loss) from continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share from continuing operations. Year Ended December 31, 2018 2017 2016 Net earnings (loss) from continuing operations: Net earnings (loss) from continuing operations $ 764 $ 758 $ (574 ) Attributable to participating securities (9 ) (8 ) (2 ) Basic and diluted earnings (loss) from continuing operations $ 755 $ 750 $ (576 ) Common shares: Common shares outstanding - total 499 525 513 Attributable to participating securities (5 ) (5 ) (6 ) Common shares outstanding - basic 494 520 507 Dilutive effect of potential common shares issuable 3 3 — Common shares outstanding - diluted 497 523 507 Net earnings (loss) per share from continuing operations: Basic $ 1.53 $ 1.44 $ (1.14 ) Diluted $ 1.52 $ 1.43 $ (1.14 ) Antidilutive options (1) 1 2 3 (1) Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive. |
Other Comprehensive Earnings
Other Comprehensive Earnings | 12 Months Ended |
Dec. 31, 2018 | |
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease [Abstract] | |
Other Comprehensive Earnings | 10. Other Comprehensive Earnings Components of other comprehensive earnings consist of the following: Year Ended December 31, 2018 2017 2016 Foreign currency translation: Beginning accumulated foreign currency translation $ 1,309 $ 1,226 $ 1,215 Change in cumulative translation adjustment (166 ) 113 22 Income tax benefit (expense) 14 (30 ) (11 ) Ending accumulated foreign currency translation 1,157 1,309 1,226 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (143 ) (172 ) (194 ) Net actuarial loss and prior service cost arising in current year (3 ) 10 (28 ) Recognition of net actuarial loss and prior service cost in earnings (1) 12 19 26 Curtailment and settlement of pension benefits 47 — 24 Income tax expense (12 ) — — Other (2) (33 ) — — Ending accumulated pension and postretirement benefits (132 ) (143 ) (172 ) Other 2 — — Accumulated other comprehensive earnings, net of tax $ 1,027 $ 1,166 $ 1,054 (1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 17 (2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1 |
Supplemental Information To Sta
Supplemental Information To Statements Of Cash Flows | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Information To Statements Of Cash Flows | 11. Supplemental Information to Statements of Cash Flows Year Ended December 31, 2018 2017 2016 Changes in assets and liabilities, net Accounts receivable $ 88 $ (94 ) $ (58 ) Other current assets (128 ) 20 326 Other long-term assets (28 ) (47 ) 36 Accounts payable — 113 (196 ) Revenues and royalties payable 153 106 (26 ) Other current liabilities (150 ) (53 ) (74 ) Other long-term liabilities (78 ) (13 ) 16 Total $ (143 ) $ 32 $ 24 Supplementary cash flow data - total operations: Interest paid (net of capitalized interest) $ 385 $ 481 $ 569 Income taxes paid (received) $ 40 $ 78 $ (159 ) In 2016, Devon’s acquisition of certain STACK assets included the noncash issuance of Devon common stock. See Note 2 |
Accounts Receivable
Accounts Receivable | 12 Months Ended |
Dec. 31, 2018 | |
Accounts Receivable Net [Abstract] | |
Accounts Receivable | 12. Accounts Receivable Components of accounts receivable include the following: December 31, 2018 December 31, 2017 Oil, gas and NGL sales $ 430 $ 559 Joint interest billings 155 134 Marketing revenues 285 278 Other 23 29 Gross accounts receivable 893 1,000 Allowance for doubtful accounts (8 ) (11 ) Net accounts receivable $ 885 $ 989 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Property, Plant and Equipment | 13. Capitalized Costs The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities. December 31, 2018 U.S. Canada Total Property and equipment: Proved $ 40,378 $ 6,427 $ 46,805 Unproved and properties under development 833 1,434 2,267 Total oil and gas 41,211 7,861 49,072 Less accumulated DD&A (32,229 ) (4,030 ) (36,259 ) Oil and gas property and equipment, net $ 8,982 $ 3,831 $ 12,813 Other property and equipment 1,832 Less accumulated DD&A (710 ) Other property and equipment, net 1,122 Property and equipment, net $ 13,935 December 31, 2017 U.S. Canada Total Property and equipment: Proved $ 40,491 $ 6,804 $ 47,295 Unproved and properties under development 984 1,473 2,457 Total oil and gas 41,475 8,277 49,752 Less accumulated DD&A (32,379 ) (4,055 ) (36,434 ) Oil and gas property and equipment, net $ 9,096 $ 4,222 $ 13,318 Other property and equipment 1,955 Less accumulated DD&A (689 ) Other property and equipment, net 1,266 Property and equipment, net $ 14,584 Suspended Exploratory Well Costs The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2018. Year Ended December 31, 2018 2017 2016 Beginning balance $ 313 $ 261 $ 225 Additions pending determination of proved reserves 672 504 247 Charges to exploration expense — — (29 ) Reclassifications to proved properties (662 ) (466 ) (189 ) Foreign currency translation adjustment (19 ) 14 7 Ending balance $ 304 $ 313 $ 261 The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. Year Ended December 31, 2018 2017 2016 Exploratory well costs capitalized for a period of one year or less $ 110 $ 113 $ 88 Exploratory well costs capitalized for a period greater than one year 194 200 173 Ending balance $ 304 $ 313 $ 261 Number of projects with exploratory well costs capitalized for a period greater than one year 2 2 2 Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling relate to Devon’s heavy oil operations. Management believes these projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development. Currently, Devon has not planned additional exploratory work in the near future on these assets and will continue to assess its future development timeline of these long cycle projects as it competes for capital allocation within Devon’s portfolio. Devon’s interest in this acreage does not begin to expire until 2025. |
Other Current Liabilities
Other Current Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Other Liabilities Disclosure [Abstract] | |
Other Current Liabilities | 14. Other Current Liabilities Components of other current liabilities include the following: December 31, 2018 December 31, 2017 Derivative liabilities $ 67 $ 323 Accrued interest payable 80 96 Income taxes payable 14 144 Restructuring liabilities 47 19 Other 227 246 Other current liabilities $ 435 $ 828 |
Debt And Related Expenses
Debt And Related Expenses | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt and Related Expenses | 15. Debt and Related Expenses See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon. December 31, 2018 December 31, 2017 8.25% (1) $ — $ 20 2.25% — 95 6.30% 162 162 4.00% 500 500 3.25% 1,000 1,000 5.85% 485 485 7.50% (1) 73 73 7.875% (2) (3) 675 1,059 7.95% (2) 366 789 5.60% 1,250 1,250 4.75% 750 750 5.00% 750 750 Net discount on debentures and notes (24 ) (30 ) Debt issuance costs (40 ) (39 ) Total debt 5,947 6,864 Less amount classified as short-term debt (4) 162 115 Total long-term debt $ 5,785 $ 6,749 (1) These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. (2) These senior notes were included in 2018 tender offer repurchases discussed below. (3) Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. (4) 2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019. Debt maturities as of December 31, 2018, excluding debt issuance costs, premiums and discounts, are as follows: Total 2019 $ 162 2020 — 2021 500 2022 1,000 2023 — Thereafter 4,349 Total $ 6,011 Credit Lines Under its 2012 Senior Credit Facility, Devon had $3.0 billion of available credit. On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and subsequently entered into its new $3.0 billion revolving 2018 Senior Credit Facility. The 2018 Senior Credit Facility matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods subject to lender consent. Amounts borrowed under the 2018 Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The 2018 Senior Credit Facility currently provides for an annual facility fee of $6.1 million. As of December 31, 2018, Devon had $48 million in outstanding letters of credit under the 2018 Senior Credit Facility. There were no borrowings under the Senior Credit Facility as of December 31, 2018. The 2018 Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. For example, total capitalization is adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 21.0%. Commercial Paper Devon’s 2018 Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the commercial paper market. As of December 31, 2018, Devon had no outstanding commercial paper borrowings. Retirement of Senior Notes During 2018, Devon completed tender offers to repurchase $807 million in aggregate principal amount of debt using cash on hand. This included $384 million of the 7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million loss on early retirement of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along with other charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings. In December 2018, Devon repaid the $95 million of 2.25% senior notes at maturity. Additionally, in January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity. During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 2 Financing Costs, Net The following schedule includes the components of net financing costs. Year Ended December 31, 2018 2017 2016 Interest based on debt outstanding $ 339 $ 390 $ 488 Early retirement of debt 312 — 269 Capitalized interest (41 ) (69 ) (61 ) Other (16 ) (4 ) 21 Total net financing costs $ 594 $ 317 $ 717 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 16. Asset Retirement Obligations The following table presents the changes in asset retirement obligations. Year Ended December 31, 2018 2017 Asset retirement obligations as of beginning of period $ 1,138 $ 1,258 Liabilities incurred 39 40 Liabilities settled and divested (116 ) (68 ) Revision of estimated obligation (25 ) (184 ) Accretion expense on discounted obligation 59 62 Foreign currency translation adjustment (38 ) 30 Asset retirement obligations as of end of period 1,057 1,138 Less current portion 27 39 Asset retirement obligations, long-term $ 1,030 $ 1,099 During 2018, Devon reduced its asset retirement obligation by $84 million, primarily as a result of Devon’s 2018 divestitures. For additional information, see Note 2 . During 2017, Devon reduced its asset retirement obligations by $184 million, primarily due to changes in the assumed inflation rate and retirement dates for its oil and gas assets. |
Retirement Plans
Retirement Plans | 12 Months Ended |
Dec. 31, 2018 | |
Compensation And Retirement Disclosure [Abstract] | |
Retirement Plans | 17. Retirement Plans Defined Contribution Plans Devon sponsors defined contribution plans covering its employees in the U.S. and Canada. Such plans include its 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. Devon contributed $50 million, $53 million and $57 million to these plans in 2018, 2017 and 2016, respectively. Defined Benefit Plans Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans covering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits under the defined benefit plans have been closed to new employees; however, eligible employees continue to accrue benefits based upon years of service and compensation. Benefits are primarily funded from assets held in the plans’ trusts. Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 70% fixed income, 20% equity and 10% other. See the following discussion for Devon’s pension assets by asset class. Fixed-income – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices and were $193 million and $342 million at December 31, 2018 and 2017, respectively. Also, included are commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these securities are based upon the net asset values provided by the investment managers and were $301 million and $401 million at December 31, 2018 and 2017, respectively. Equity – Devon’s equity securities include commingled global equity funds that invest in large, mid and small capitalization stocks across the world’s developed and emerging markets and international large cap equity securities. These equity securities can be sold on demand but are not actively traded. The fair values of these securities are based upon the net asset values provided by the investment managers and were $84 million and $157 million at December 31, 2018 and 2017, respectively. Other – Devon’s other securities include short-term investment funds and a hedge fund that invest both long and short using a variety of investment strategies. The fair value of these securities is based upon the net asset values provided by investment managers and were $132 million and $135 million at December 31, 2018 and 2017, respectively. Defined Postretirement Plans Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents. Benefit Obligations and Funded Status The following table summarizes the benefit obligations, assets, funded status and balance sheet impacts associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2018 and 2017. Pension Benefits Postretirement Benefits 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of year $ 1,279 $ 1,249 $ 19 $ 21 Service cost 10 15 — — Interest cost 39 42 — — Actuarial loss (gain) (83 ) 59 (3 ) — Plan amendments — — — — Plan curtailments 2 — 2 — Plan settlements (241 ) — — — Foreign exchange rate changes (3 ) 2 — — Participant contributions — — 2 1 Benefits paid (60 ) (88 ) (3 ) (3 ) Benefit obligation at end of year 943 1,279 17 19 Change in plan assets: Fair value of plan assets at beginning of year 1,035 985 — — Actual return on plan assets (36 ) 122 — — Employer contributions 14 14 1 2 Participant contributions — — 2 1 Plan settlements (241 ) — — — Benefits paid (60 ) (88 ) (3 ) (3 ) Foreign exchange rate changes (3 ) 2 — — Fair value of plan assets at end of year 709 1,035 — — Funded status at end of year $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in balance sheet: Other long-term assets $ 3 $ 4 $ — $ — Other current liabilities (14 ) (13 ) (3 ) (3 ) Other long-term liabilities (223 ) (235 ) (14 ) (16 ) Net amount $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 202 $ 257 $ (11 ) $ (11 ) Prior service cost (credit) 4 6 (2 ) (3 ) Total $ 206 $ 263 $ (13 ) $ (14 ) During the third quarter of 2018, Devon entered into a group annuity contract, under which a third party has permanently assumed certain of Devon’s defined benefit pension obligations. The purchase of this group annuity contract reduced Devon’s pension assets and liabilities and is the primary component of the $241 million of plan settlements within the preceding table. In connection with the group annuity contract transaction, Devon recorded a settlement expense of approximately $ 33 Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2018 and December 31, 2017, as presented in the table below. December 31, 2018 2017 Projected benefit obligation $ 922 $ 1,255 Accumulated benefit obligation $ 906 $ 1,226 Fair value of plan assets $ 685 $ 1,007 The following table presents the components of net periodic benefit cost and other comprehensive earnings. Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Net periodic benefit cost: Service cost $ 10 $ 15 $ 15 $ — $ — $ — Interest cost 39 42 42 — — 1 Expected return on plan assets (49 ) (54 ) (55 ) — — — Recognition of net actuarial loss (gain) (1) 13 19 25 (1 ) (1 ) (1 ) Recognition of prior service cost (1) 1 2 3 (1 ) (1 ) (1 ) Total net periodic benefit cost (2) 14 24 30 (2 ) (2 ) (1 ) Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 4 (9 ) 26 (1 ) (1 ) — Prior service cost arising in current year — — 2 — — — Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) (60 ) (19 ) (43 ) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) (2 ) (2 ) (9 ) 1 1 1 Total other comprehensive loss (earnings) (58 ) (30 ) (24 ) 1 1 2 Total recognized $ (44 ) $ (6 ) $ 6 $ (1 ) $ (1 ) $ 1 (1) These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. (2) The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings. (3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6 Assumptions Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Assumptions to determine benefit obligations: Discount rate 4.21% 3.59% 4.07% 4.01% 3.25% 3.46% Rate of compensation increase 2.50% 2.50% 4.49% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate - service cost 3.98% 4.29% 4.39% 4.13% 4.22% 3.63% Discount rate - interest cost 3.22% 2.99% 4.39% 2.67% 2.39% 3.63% Rate of compensation increase 2.50% 4.48% 4.49% N/A N/A N/A Expected return on plan assets 5.67% 5.69% 5.20% N/A N/A N/A Discount Rate - Future pension and post-retirement obligations are discounted based on the rate at which obligations could be effectively settled, considering the timing of expected future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types. Mortality rate – Devon utilized the Society of Actuaries produced mortality tables and an improvement scale derived from the updated tables for 2017 and 2018 and the actuary’s best estimate of mortality for 2016 for the population of participants in Devon’s plans. Other assumptions – For measurement of the 2018 benefit obligation for the other postretirement medical plans, a 7.1% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Expected Cash Flows Devon expects benefit plan payments to average approximately $59 million a year for the next five years and $153 million total for the five years thereafter. Of these payments to be paid in 2019, $17 million is expected to be funded from Devon’s available cash, cash equivalents and other assets. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2018 | |
Stockholders Equity Note [Abstract] | |
Stockholders' Equity | 18. Stockholders’ Equity The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. Common Stock Issued In January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition discussed in Note 2 Share Repurchase Program In March 2018, Devon announced a share repurchase program to buy up to $1.0 billion of shares of common stock. In June 2018, in conjunction with the announced divestiture of its investment in EnLink and the General Partner, Devon increased its program by an additional $3.0 billion. In February 2019, Devon’s Board of Directors authorized an expansion of the share repurchase program by an additional $1.0 billion, bringing the total to $5.0 billion. The share repurchase program expires December 31, 2019. During the third quarter of 2018, Devon entered into and completed an ASR transaction to repurchase $1.0 billion of the $4.0 billion program. The table below provides information regarding purchases of Devon’s common stock that were made during 2018 (shares in thousands). Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid per Share First quarter 2018: Open-Market 2,561 $ 82 $ 32.19 Second quarter 2018: Open-Market 11,154 439 39.35 Third quarter 2018: Open-Market 16,492 712 43.13 ASR 24,330 1,000 41.10 Total 40,822 1,712 41.92 Fourth quarter 2018: Open-Market 23,612 745 31.57 Total year-to-date 78,149 $ 2,978 $ 38.11 Dividends The table below summarizes the dividends Devon paid on its common stock. Amounts Rate Per Share Year Ended 2018: First quarter $ 32 $ 0.06 Second quarter 42 $ 0.08 Third quarter 38 $ 0.08 Fourth quarter 37 $ 0.08 Total year-to-date $ 149 Year Ended 2017: First quarter $ 32 $ 0.06 Second quarter 33 $ 0.06 Third quarter 30 $ 0.06 Fourth quarter 32 $ 0.06 Total year-to-date $ 127 Year Ended 2016: First quarter $ 125 $ 0.24 Second quarter 33 $ 0.06 Third quarter 32 $ 0.06 Fourth quarter 31 $ 0.06 Total year-to-date $ 221 In response to the depressed commodity price environment, Devon reduced the quarterly dividend rate from $0.24 to $0.06 per share in the second quarter of 2016. Devon increased the quarterly dividend by 33% to $0.08 per share in the second quarter of 2018. In February 2019, Devon announced a 12.5% increase to its quarterly dividend, to $0.09 per share, beginning in the second quarter of 2019. |
Discontinued Operations and Ass
Discontinued Operations and Assets Held for Sale | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations And Disposal Groups [Abstract] | |
Discontinued Operations and Assets Held for Sale | 19. Discontinued Operations and Assets Held For Sale On June 6, 2018, Devon announced that it had entered into an agreement to sell its aggregate ownership interests in EnLink and the General Partner for $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire midstream business ownership; 2) EnLink and the General Partner are a separate reportable segment and are a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, debt, revenues, net earnings and operating cash flows. As a result, Devon classified the results of operations and cash flows related to EnLink and the General Partner as discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was signed. On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $ 3.125 2.6 2.2 12 Note 8 As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon has minimum volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant through early 2021. From the period of July 19, 2018 through December 31, 2018, Devon had net outflows of approximately $380 million with EnLink, which primarily related to gathering and processing expenses. These net outflows represent gross cash amounts and not net working interest amounts. Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation. The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations. Year Ended December 31, 2018 2017 2016 Marketing and midstream revenues $ 3,567 $ 5,071 $ 3,551 Marketing and midstream expenses 2,912 4,111 2,712 Depreciation, depletion and amortization 244 545 504 General and administrative expenses 65 128 118 Financing costs, net 98 181 190 Asset impairments — 17 873 Asset dispositions (2,607 ) — 13 Other expenses (8 ) (34 ) 25 Total expenses 704 4,948 4,435 Earnings (loss) from discontinued operations before income taxes 2,863 123 (884 ) Income tax expense (benefit) 403 (197 ) — Net earnings (loss) from discontinued operations, net of income tax expense 2,460 320 (884 ) Net earnings (loss) attributable to noncontrolling interests 160 180 (403 ) Net earnings (loss) from discontinued operations attributable to Devon $ 2,300 $ 140 $ (481 ) The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets. The assets and liabilities classified as held for sale at December 31, 2018 are related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2 The assets and liabilities classified as held for sale at December 31, 2017 are related to the divestiture of EnLink and the General Partner. December 31, 2018 December 31, 2017 Cash and cash equivalents $ — $ 31 Accounts receivable 7 681 Other current assets — 48 Oil and gas property and equipment, based on successful efforts accounting, net 190 — Midstream and other property and equipment, net — 6,587 Goodwill — 1,542 Other long-term assets — 1,600 Total assets held for sale $ 197 $ 10,489 Accounts payable $ 3 $ 186 Revenues and royalties payable — 432 Other current liabilities 19 373 Long-term debt — 3,542 Deferred income taxes — 346 Asset retirement obligations 47 14 Other long-term liabilities — 34 Total liabilities held for sale $ 69 $ 4,927 |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments And Contingencies | 20. Commitments and Contingencies Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates. Royalty Matters Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters. Environmental Matters Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material. Beginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although we cannot predict the ultimate outcome of these matters, Devon is vigorously defending against these claims. Other Matters Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no material pending legal proceedings to which Devon is a party or to which any of its property is subject. Commitments The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2018. Year Ending December 31, Purchase Obligations Drilling and Facility Obligations Operational Agreements Office and Equipment Leases 2019 $ 541 $ 274 $ 587 $ 64 2020 567 85 519 43 2021 140 48 373 31 2022 — 14 419 26 2023 — 8 354 25 Thereafter — 16 3,374 311 Total $ 1,248 $ 445 $ 5,626 $ 500 Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices. Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. The value of the drilling obligations reported is based on gross contractual value. Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets. Devon leases certain office space and equipment under operating lease arrangements. Total rental expense recognized for operating leases, net of sublease income, was $11 million, $7 million and $11 million in 2018, 2017 and 2016, respectively. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 21. Fair Value Measurements The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at December 31, 2018 and December 31, 2017, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets and related impairments are measured as of the impairment date using Level 3 inputs. Additional information on asset impairments and the pension plan assets is provided in Note 5 Note 17 Fair Value Measurements Using: Carrying Total Fair Level 1 Level 2 Amount Value Inputs Inputs December 31, 2018 assets (liabilities): Cash equivalents $ 1,505 $ 1,505 $ 1,405 $ 100 Commodity derivatives $ 677 $ 677 $ — $ 677 Commodity derivatives $ (68 ) $ (68 ) $ — $ (68 ) Debt $ (5,947 ) $ (5,965 ) $ — $ (5,965 ) December 31, 2017 assets (liabilities): Cash equivalents $ 1,533 $ 1,533 $ 1,454 $ 79 Commodity derivatives $ 205 $ 205 $ — $ 205 Commodity derivatives $ (286 ) $ (286 ) $ — $ (286 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (64 ) $ (64 ) $ — $ (64 ) Debt $ (6,864 ) $ (8,131 ) $ — $ (8,131 ) The following methods and assumptions were used to estimate the fair values in the tables above. Level 1 Fair Value Measurements Cash equivalents – Amounts consist primarily of money market investments and the fair value approximates the carrying value. Level 2 Fair Value Measurements Cash equivalents – Amounts consist primarily of commercial paper and Canadian agency and provincial securities investments. The fair value approximates the carrying value. Commodity and interest rate – The fair values of commodity and interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements. Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Segment Information | 22. Segment Information Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian exploration and production operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas exploration and production activities, and certain information regarding such activities for each segment is included in Note 23 Devon considers EnLink, combined with the General Partner, to be a segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located in the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. However, with Devon’s closing of the divestment of EnLink and the General Partner in July 2018, activity related to EnLink and the General Partner have now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows, and the associated assets and liabilities of EnLink and the General Partner are presented as assets and liabilities held for sale on the consolidated balance sheets. Additional information can be found in Note 19 U.S. Canada Total Year Ended December 31, 2018: Revenues from external customers (1) $ 9,674 $ 1,060 $ 10,734 Depreciation, depletion and amortization $ 1,328 $ 330 $ 1,658 Interest expense $ 469 $ 166 $ 635 Asset impairments $ 156 $ — $ 156 Asset dispositions $ (263 ) $ — $ (263 ) Restructuring and transaction costs $ 97 $ 17 $ 114 Earnings (loss) from continuing operations before income taxes $ 1,294 $ (374 ) $ 920 Income tax expense (benefit) $ 294 $ (138 ) $ 156 Net earnings (loss) from continuing operations $ 1,000 $ (236 ) $ 764 Property and equipment, net $ 10,026 $ 3,909 $ 13,935 Total assets (2) $ 14,853 $ 4,516 $ 19,369 Capital expenditures, including acquisitions $ 2,294 $ 282 $ 2,576 Year Ended December 31, 2017: Revenues from external customers $ 7,326 $ 1,552 $ 8,878 Depreciation, depletion and amortization $ 1,149 $ 380 $ 1,529 Interest expense $ 324 $ 12 $ 336 Asset dispositions $ (218 ) $ 1 $ (217 ) Earnings from continuing operations before income taxes $ 443 $ 330 $ 773 Income tax expense $ 9 $ 6 $ 15 Net earnings from continuing operations $ 434 $ 324 $ 758 Property and equipment, net $ 10,274 $ 4,310 $ 14,584 Total assets (3) $ 14,254 $ 5,498 $ 19,752 Capital expenditures, including acquisitions $ 1,821 $ 348 $ 2,169 Year Ended December 31, 2016: Revenues from external customers $ 5,722 $ 1,031 $ 6,753 Depreciation, depletion and amortization $ 1,178 $ 414 $ 1,592 Interest expense $ 624 $ 100 $ 724 Asset impairments $ 435 $ 2 $ 437 Asset dispositions $ (955 ) $ (541 ) $ (1,496 ) Restructuring and transaction costs $ 242 $ 19 $ 261 Earnings (loss) from continuing operations before income taxes $ (757 ) $ 324 $ (433 ) Income tax expense (benefit) $ (8 ) $ 149 $ 141 Net earnings (loss) from continuing operations $ (749 ) $ 175 $ (574 ) Property and equipment, net $ 10,166 $ 4,110 $ 14,276 Total assets (3) $ 13,390 $ 5,071 $ 18,461 Capital expenditures, including acquisitions $ 2,640 $ 186 $ 2,826 (1) Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. (2) Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million. (3) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively. The following table presents revenue from contracts with customers that are disaggregated based on the type of good. Year Ended December 31, 2018 U.S. Canada Total Oil $ 2,957 $ 814 $ 3,771 Gas 950 — 950 NGL 956 — 956 Oil, gas and NGL revenues from contracts with customers 4,863 814 5,677 Oil, gas and NGL derivatives 457 151 608 Upstream revenues 5,320 965 6,285 Oil 2,745 95 2,840 Gas 738 — 738 NGL 871 — 871 Total marketing revenues from contracts with customers 4,354 95 4,449 Total revenues $ 9,674 $ 1,060 $ 10,734 |
Supplemental Information On Oil
Supplemental Information On Oil And Gas Operations | 12 Months Ended |
Dec. 31, 2018 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |
Supplemental Information on Oil and Gas Operations | 23. Supplemental Information on Oil and Gas Operations (Unaudited) Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country. Costs Incurred The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities. Year Ended December 31, 2018 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 71 — 71 Exploration costs 679 85 764 Development costs 1,537 249 1,786 Costs incurred $ 2,289 $ 334 $ 2,623 Year Ended December 31, 2017 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 50 4 54 Exploration costs 590 87 677 Development costs 1,036 225 1,261 Costs incurred $ 1,678 $ 316 $ 1,994 Year Ended December 31, 2016 U.S. Canada Total Property acquisition costs: Proved properties $ 237 $ — $ 237 Unproved properties 1,356 2 1,358 Exploration costs 282 78 360 Development costs 875 54 929 Costs incurred $ 2,750 $ 134 $ 2,884 Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations. Results of Operations The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including DD&A and after giving effect to permanent differences. Year Ended December 31, 2018 U.S. Canada Total Oil, gas and NGL sales $ 4,863 $ 814 $ 5,677 Production expenses (1,620 ) (605 ) (2,225 ) Exploration expenses (129 ) (48 ) (177 ) Depreciation, depletion and amortization (1,234 ) (325 ) (1,559 ) Asset dispositions 262 — 262 Asset impairments (109 ) — (109 ) Accretion of asset retirement obligations (35 ) (24 ) (59 ) Income tax (expense) benefit (460 ) 51 (409 ) Results of operations $ 1,538 $ (137 ) $ 1,401 Depreciation, depletion and amortization per Boe $ 8.08 $ 7.63 $ 7.98 Year Ended December 31, 2017 U.S. Canada Total Oil, gas and NGL sales $ 3,746 $ 1,404 $ 5,150 Production expenses (1,232 ) (591 ) (1,823 ) Exploration expenses (346 ) (34 ) (380 ) Depreciation, depletion and amortization (1,050 ) (369 ) (1,419 ) Asset dispositions 211 1 212 Accretion of asset retirement obligations (38 ) (24 ) (62 ) Income tax expense — (104 ) (104 ) Results of operations $ 1,291 $ 283 $ 1,574 Depreciation, depletion and amortization per Boe $ 6.97 $ 7.73 $ 7.15 Year Ended December 31, 2016 U.S. Canada Total Oil, gas and NGL sales $ 3,198 $ 984 $ 4,182 Production expenses (1,313 ) (492 ) (1,805 ) Exploration expenses (176 ) (39 ) (215 ) Depreciation, depletion and amortization (1,066 ) (380 ) (1,446 ) Asset dispositions 946 1 947 Asset impairments (435 ) — (435 ) Accretion of asset retirement obligations (49 ) (26 ) (75 ) Income tax expense — (13 ) (13 ) Results of operations $ 1,105 $ 35 $ 1,140 Depreciation, depletion and amortization per Boe $ 6.11 $ 7.75 $ 6.47 Proved Reserves The following table presents Devon’s estimated proved reserves by product and by country. Bitumen NGL Oil (MMBbls) (MMBbls) Gas (Bcf) (MMBbls) Combined (MMBoe) (1) U.S. Canada Total Canada U.S. Canada Total U.S. U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2015 242 22 264 520 5,808 13 5,821 428 1,638 544 2,182 Revisions due to prices (18 ) (2 ) (20 ) 23 (103 ) — (103 ) (13 ) (48 ) 21 (27 ) Revisions other than price (2 ) 3 1 (19 ) 628 10 638 48 151 (14 ) 137 Extensions and discoveries 36 2 38 — 280 — 280 42 124 2 126 Purchase of reserves 8 — 8 — 33 — 33 7 20 — 20 Production (47 ) (8 ) (55 ) (40 ) (510 ) (7 ) (517 ) (42 ) (174 ) (49 ) (223 ) Sale of reserves (25 ) — (25 ) — (521 ) — (521 ) (45 ) (157 ) — (157 ) December 31, 2016 194 17 211 484 5,615 16 5,631 425 1,554 504 2,058 Revisions due to prices 12 (1 ) 11 (37 ) 398 1 399 32 111 (38 ) 73 Revisions other than price 6 2 8 (10 ) — 2 2 (10 ) (5 ) (7 ) (12 ) Extensions and discoveries 90 4 94 12 403 — 403 63 221 16 237 Production (42 ) (7 ) (49 ) (40 ) (433 ) (6 ) (439 ) (36 ) (150 ) (48 ) (198 ) Sale of reserves (3 ) — (3 ) — (9 ) — (9 ) (1 ) (6 ) — (6 ) December 31, 2017 257 15 272 409 5,974 13 5,987 473 1,725 427 2,152 Revisions due to prices 12 1 13 10 94 (3 ) 91 12 40 11 51 Revisions other than price (10 ) 2 (8 ) 2 (163 ) (4 ) (167 ) (23 ) (60 ) 3 (57 ) Extensions and discoveries 93 5 98 7 446 — 446 64 232 11 243 Production (47 ) (7 ) (54 ) (35 ) (397 ) (4 ) (401 ) (39 ) (153 ) (42 ) (195 ) Sale of reserves (7 ) — (7 ) — (1,195 ) — (1,195 ) (61 ) (267 ) — (267 ) December 31, 2018 298 16 314 393 4,759 2 4,761 426 1,517 410 1,927 Proved developed reserves: December 31, 2015 203 22 225 219 5,694 13 5,707 411 1,563 243 1,806 December 31, 2016 160 17 177 190 5,361 16 5,377 387 1,439 210 1,649 December 31, 2017 178 15 193 200 5,619 13 5,632 410 1,524 218 1,742 December 31, 2018 198 16 214 187 4,331 2 4,333 359 1,278 204 1,482 Proved developed-producing reserves: December 31, 2015 192 19 211 219 5,546 13 5,559 393 1,509 240 1,749 December 31, 2016 143 13 156 190 5,243 16 5,259 370 1,386 207 1,593 December 31, 2017 165 12 177 197 5,512 13 5,525 397 1,481 212 1,693 December 31, 2018 189 12 201 187 4,261 2 4,263 349 1,249 199 1,448 Proved undeveloped reserves: December 31, 2015 39 — 39 301 114 — 114 17 75 301 376 December 31, 2016 34 — 34 294 254 — 254 38 115 294 409 December 31, 2017 79 — 79 209 355 — 355 63 201 209 410 December 31, 2018 100 — 100 206 428 — 428 67 239 206 445 (1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. Proved Undeveloped Reserves The following table presents the changes in Devon’s total proved undeveloped reserves during 2018 (MMBoe). U.S. Canada Total Proved undeveloped reserves as of December 31, 2017 201 209 410 Extensions and discoveries 107 6 113 Revisions due to prices 1 6 7 Revisions other than price (8 ) (15 ) (23 ) Sale of reserves (10 ) — (10 ) Conversion to proved developed reserves (52 ) — (52 ) Proved undeveloped reserves as of December 31, 2018 239 206 445 Total proved undeveloped reserves increased 9% from 2017 to 2018 with the year-end 2018 balance representing 23% of total proved reserves. Devon’s focus on drilling and development activities in the STACK and Delaware Basin was the primary driver of the 113 MMBoe in extensions and discoveries. Continued development primarily in the STACK and Delaware Basin led to the conversion of 52 MMBoe, or 26%, of the 2017 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $691 million for 2018. A significant amount of Devon’s proved undeveloped reserves at the end of 2018 related to its Jackfish operations. At December 31, 2018 and 2017, Devon’s Jackfish proved undeveloped reserves were 206 MMBoe and 209 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35 MBbl daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than five years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends through 2032. At the end of 2018, approximately 125 MMBoe of proved undeveloped reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of the reserves. Furthermore, approximately 81 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop. Price Revisions Reserves increased 40 MMBoe in the U.S. primarily due to price increases in the trailing 12 month average for oil, gas and NGLs in 2018. Reserves increased 11 MMBoe in Canada due to a decrease in the trailing 12 month average price for bitumen in 2018. The decreased price has the effect of decreasing the applicable royalties, which increases the after-royalty volumes. Reserves increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12 month average for oil, gas and NGLs in 2017. Reserves decreased 38 MMBoe in Canada due to a significant increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing the royalties, which decreases the after-royalty volumes. Reserves decreased 27 MMBoe during 2016 primarily due to lower commodity prices for oil and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes. Revisions Other Than Price Total revisions other than price in 2018 primarily related to Devon’s evaluation of certain oil and dry gas regions, with the largest revisions being made in the STACK. Total revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and NGLs, with the largest revisions being made in the Barnett Shale and STACK (Cana-Woodford Shale). Extensions and Discoveries 2018 – Approximately 72% of the additions were through our focused efforts in the STACK (87 MMBoe) and the Delaware Basin (88 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio. The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling activities, primarily relating to the STACK. 2017 – Over 80% of the additions were through our focused efforts in the STACK (120 MMBoe) and the Delaware Basin (79 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio. The 2017 extensions and discoveries included 66 MMBoe related to additions from Devon’s infill drilling activities primarily related to the STACK. 2016 – Of the 126 MMBoe of extensions and discoveries, 97 MMBoe related to STACK, 18 MMBoe related to the Delaware Basin and 7 MMBoe related to the Eagle Ford. The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling activities primarily related to the STACK. Purchase of Reserves 2016 – Primarily related to Devon’s acquisition in the STACK play. Sale of Reserves Related to Devon’s 2018, 2017 and 2016 U.S. non-core asset divestitures as discussed further in Note 2 Standardized Measure The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves. Year Ended December 31, 2018 U.S. Canada Total Future cash inflows $ 40,183 $ 9,146 $ 49,329 Future costs: Development (3,444 ) (1,558 ) (5,002 ) Production (18,107 ) (5,445 ) (23,552 ) Future income tax expense (2,969 ) — (2,969 ) Future net cash flow 15,663 2,143 17,806 10% discount to reflect timing of cash flows (6,897 ) (717 ) (7,614 ) Standardized measure of discounted future net cash flows $ 8,766 $ 1,426 $ 10,192 Year Ended December 31, 2017 U.S. Canada Total Future cash inflows $ 34,701 $ 13,602 $ 48,303 Future costs: Development (3,316 ) (1,853 ) (5,169 ) Production (15,526 ) (5,986 ) (21,512 ) Future income tax expense — (988 ) (988 ) Future net cash flow 15,859 4,775 20,634 10% discount to reflect timing of cash flows (7,541 ) (1,756 ) (9,297 ) Standardized measure of discounted future net cash flows $ 8,318 $ 3,019 $ 11,337 Year Ended December 31, 2016 U.S. Canada Total Future cash inflows $ 22,847 $ 9,672 $ 32,519 Future costs: Development (2,784 ) (2,201 ) (4,985 ) Production (11,934 ) (6,049 ) (17,983 ) Future income tax expense — (121 ) (121 ) Future net cash flow 8,129 1,301 9,430 10% discount to reflect timing of cash flows (3,524 ) (466 ) (3,990 ) Standardized measure of discounted future net cash flows $ 4,605 $ 835 $ 5,440 Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2018 estimates, Devon’s future realized prices were assumed to be $58.64 per Bbl of oil, $22.12 per Bbl of bitumen, $2.45 per Mcf of gas and $24.72 per Bbl of NGLs. Of the $5.0 billion of future development costs as of the end of 2018, $1.2 billion, $0.6 billion and $0.3 billion are estimated to be spent in 2019, 2020 and 2021, respectively. Future development costs include not only development costs but also future asset retirement costs. Included as part of the $5.0 billion of future development costs are $1.4 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws. The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows: Year Ended December 31, 2018 2017 2016 Beginning balance $ 11,337 $ 5,440 $ 7,883 Net changes in prices and production costs (243 ) 5,218 (2,027 ) Oil, bitumen, gas and NGL sales, net of production costs (3,452 ) (3,327 ) (2,377 ) Changes in estimated future development costs (216 ) 789 112 Extensions and discoveries, net of future development costs 3,139 2,497 674 Purchase of reserves — 2 224 Sales of reserves in place (588 ) (3 ) (577 ) Revisions of quantity estimates (414 ) (318 ) (21 ) Previously estimated development costs incurred during the period 962 559 663 Accretion of discount 960 1,034 537 Foreign exchange and other (329 ) (7 ) 72 Net change in income taxes (964 ) (547 ) 277 Ending balance $ 10,192 $ 11,337 $ 5,440 |
Supplemental Quarterly Financia
Supplemental Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Data [Abstract] | |
Supplemental Quarterly Financial Information | 24. Supplemental Quarterly Financial Information (Unaudited) The following tables present a summary of Devon’s unaudited interim results of operations. 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,198 $ 2,249 $ 2,579 $ 3,708 $ 10,734 Asset dispositions (1) $ (12 ) $ 23 $ (6 ) $ (268 ) $ (263 ) Earnings (loss) from continuing operations before income taxes (2) $ (245 ) $ (481 ) $ 162 $ 1,484 $ 920 Net earnings (loss) from continuing operations $ (211 ) $ (474 ) $ 300 $ 1,149 $ 764 Net earnings from discontinued operations, net of income tax expense (3) $ 58 $ 139 $ 2,263 $ — $ 2,460 Net earnings (loss) attributable to Devon $ (197 ) $ (425 ) $ 2,537 $ 1,149 $ 3,064 Basic net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.17 $ 2.50 $ 6.14 Diluted net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.14 $ 2.48 $ 6.10 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,400 $ 2,165 $ 1,933 $ 2,380 $ 8,878 Asset dispositions (1) $ (8 ) $ (22 ) $ (170 ) $ (17 ) $ (217 ) Earnings from continuing operations before income taxes $ 313 $ 207 $ 207 $ 46 $ 773 Net earnings from continuing operations $ 308 $ 212 $ 194 $ 44 $ 758 Net earnings from discontinued operations, net of income tax expense $ 9 $ 33 $ 18 $ 260 $ 320 Net earnings attributable to Devon $ 303 $ 219 $ 193 $ 183 $ 898 Basic net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.71 Diluted net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.70 (1) Additional discussion regarding asset dispositions can be found in Note 2. (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19 |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Principles Of Consolidation | Principles of Consolidation The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets. |
Use Of Estimates | Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following: • proved reserves and related present value of future net revenues; • evaluation of suspended well costs; • the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; • derivative financial instruments; • the fair value of reporting units and related assessment of goodwill for impairment; • income taxes; • asset retirement obligations; • obligations related to employee pension and postretirement benefits; • legal and environmental risks and exposures; and • general credit risk associated with receivables and other assets. |
Revenue Recognition | Revenue Recognition Impact of ASC 606 Adoption In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. The impact of adoption in the current period results is as follows: Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) Upstream revenues $ 6,285 $ 6,031 $ 254 Marketing revenues 4,449 4,449 — Total impacted revenues $ 10,734 $ 10,480 $ 254 Production expenses $ 2,225 $ 1,971 $ 254 Marketing expenses 4,363 4,363 — Total impacted expenses $ 6,588 $ 6,334 $ 254 Earnings from continuing operations before income taxes $ 920 $ 920 $ — Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses. Upstream Revenues Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings. Natural gas and NGL sales Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statements of earnings. In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Oil sales Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Marketing Revenues Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership. Satisfaction of Performance Obligations and Revenue Recognitions Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the natural gas, NGLs or crude oil are delivered at a fixed or determinable price. Transaction Price Allocated to Remaining Performance Obligations Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets. Disaggregation of Revenue Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. Disaggregation of revenue disclosures can be found in Note 22 Customers During 2018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue. During 2017 and 2016, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue. |
Derivative Financial Instruments | Derivative Financial Instruments Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes. Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes both two-way price collars and three-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty. The three-way price collars consist of a two-way collar with an additional short put option sold by Devon, and cash-settle similarly to the two-way collars unless the market price falls below the additional short put causing the company to receive the market price plus the long put to short put price differential. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of December 31, 2018, Devon did not have any open foreign exchange contracts. All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2018, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2018, Devon held no cash collateral of its counterparties nor posted collateral to its counterparties. |
General And Administrative Expenses | General and Administrative Expenses G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon. |
Share-Based Compensation | Share-Based Compensation Devon grants share-based awards to members of its Board of Directors and select employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6 Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase. |
Income Taxes | Income Taxes Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 8 for further discussion. Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense. Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur. |
Net Earnings (Loss) Per Share Attributable To Devon | Net Earnings (Loss) Per Share Attributable to Devon Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of unvested performance share units. |
Cash And Cash Equivalents | Cash and Cash Equivalents Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. |
Accounts Receivable | Accounts Receivable Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable, including joint interest receivables, for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance. |
Property And Equipment | Property and Equipment Oil and Gas Property and Equipment Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly. Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production. Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are amortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms. Proved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. generally accounted for as adjustments to capitalized costs with no gain or loss recognized. Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major development projects of oil and gas properties. Other Property and Equipment Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major corporate construction projects are also capitalized. Asset Retirement Obligations Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment. |
Goodwill | Goodwill Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of each reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. Devon performed impairment tests of goodwill in the fourth quarters of 2018, 2017 and 2016. No impairment was required as a result of the annual tests in these time periods. |
Commitments And Contingencies | Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment. Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates. |
Fair Value Measurements | Fair Value Measurements Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels: • Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. • Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. • Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model. |
Foreign Currency Translation Adjustments | Foreign Currency Translation Adjustments The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity. |
Noncontrolling Interests | Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. |
Recent Accounting Standards | Recently Adopted Accounting Standards In January 2018, Devon adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash . This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon made changes to the statement of cash flows to include the required presentation and reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows. In the fourth quarter of 2018, Devon early adopted ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220) In the fourth quarter of 2018, Devon early adopted ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification Issued Accounting Standards Not Yet Adopted The FASB issued ASU 2016-02, Leases (Topic 842) Leases Devon will apply the guidance using a modified retrospective transition method at the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also has elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases. Devon will be allowed to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented with the 2019 adoption year. Devon has implemented processes, controls, and a technology solution needed to comply with the requirements of this ASU. To adopt Topic 842, Devon expects to recognize right-of-use assets of approximately $400 million with a corresponding lease liability based on the present value of the remaining term minimum lease payments. Devon’s right-of-use assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Additionally, Devon will recognize a $24 million before tax, $19 million net of tax cumulative-effect adjustment to reduce retained earnings. The FASB issued ASU 2018-04, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement The FASB issued ASU 2018-05-15, Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of Impact of Adoption for Revenue Recognition | The impact of adoption in the current period results is as follows: Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) Upstream revenues $ 6,285 $ 6,031 $ 254 Marketing revenues 4,449 4,449 — Total impacted revenues $ 10,734 $ 10,480 $ 254 Production expenses $ 2,225 $ 1,971 $ 254 Marketing expenses 4,363 4,363 — Total impacted expenses $ 6,588 $ 6,334 $ 254 Earnings from continuing operations before income taxes $ 920 $ 920 $ — |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative [Line Items] | |
Schedule Of Derivative Financial Instruments Included In Consolidated Comprehensive Statements Of Earnings And Consolidated Balance Sheets | The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption. Year Ended December 31, 2018 2017 2016 Commodity derivatives: Upstream revenues $ 608 $ 157 $ (201 ) Marketing revenues (1 ) 3 (2 ) Interest rate derivatives: Other expenses 65 (22 ) (19 ) Foreign currency derivatives: Other expenses — — (153 ) Net gains (losses) recognized $ 672 $ 138 $ (375 ) The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. December 31, 2018 December 31, 2017 Commodity derivative assets: Other current assets $ 637 $ 203 Other long-term assets 40 2 Interest rate derivative assets: Other current assets — 1 Total derivative assets $ 677 $ 206 Commodity derivative liabilities: Other current liabilities $ 67 $ 259 Other long-term liabilities 1 27 Interest rate derivative liabilities: Other current liabilities — 64 Total derivative liabilities $ 68 $ 350 |
Interest Rate Derivatives [Member] | |
Derivative [Line Items] | |
Schedule Of Open Derivative Positions | Notional Rate Received Rate Paid Expiration $ 100 1.76% Three Month LIBOR January 2019 |
Open Oil Derivative Positions [Member] | |
Derivative [Line Items] | |
Schedule Of Open Derivative Positions | Price Swaps Price Collars Period Volume (Bbls/d) Weighted Average Price ($/Bbl) Volume (Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2019 51,719 $ 59.48 87,921 $ 54.48 $ 64.49 Q1-Q4 2020 1,740 $ 62.88 8,951 $ 52.85 $ 63.13 Three-Way Price Collars Period Volume (Bbls/d) Weighted Average Floor Sold Price ($/Bbl) Weighted Average Floor Purchased Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Q1-Q4 2019 5,000 $ 50.00 $ 63.00 $ 74.80 Oil Basis Swaps Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Q1-Q4 2019 Midland Sweet 28,000 $ (0.46 ) Q1-Q4 2019 Argus LLS 17,500 $ 5.00 Q1-Q4 2019 Argus MEH 16,000 $ 2.84 Q1-Q4 2019 NYMEX Roll 38,000 $ 0.45 Q1-Q4 2019 Western Canadian Select 31,505 $ (21.73 ) Q1-Q4 2020 NYMEX Roll 38,000 $ 0.31 Q1-Q4 2020 Western Canadian Select 915 $ (20.75 ) |
Open Natural Gas Derivative Positions [Member] | |
Derivative [Line Items] | |
Schedule Of Open Derivative Positions | Price Swaps Price Collars Period Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Volume (MMBtu/d) Weighted Average Floor Price ($/MMBtu) Weighted Average Ceiling Price ($/MMBtu) Q1-Q4 2019 266,293 $ 2.86 231,474 $ 2.69 $ 3.06 Q1-Q4 2020 26,480 $ 2.92 24,490 $ 2.74 $ 3.04 Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2019 Panhandle Eastern Pipe Line 84,466 $ (0.73 ) Q1-Q4 2019 El Paso Natural Gas 130,000 $ (1.46 ) Q1-Q4 2019 Houston Ship Channel 142,637 $ 0.01 Q1-Q4 2019 Transco Zone 4 7,397 $ (0.03 ) |
Open NGL Derivative Positions [Member] | |
Derivative [Line Items] | |
Schedule Of Open Derivative Positions | Price Swaps Period Product Volume (Bbls/d) Weighted Average Price ($/Bbl) Q1-Q4 2019 Ethane 1,000 $ 11.55 Q1-Q4 2019 Natural Gasoline 4,500 $ 55.93 Q1-Q4 2019 Normal Butane 4,000 $ 33.69 Q1-Q4 2019 Propane 8,500 $ 30.01 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Schedule Of Share-Based Compensation Expense Included In The Consolidated Comprehensive Statements Of Earnings | Year Ended December 31, 2018 2017 2016 G&A $ 122 $ 141 $ 124 Exploration expenses 4 7 6 Restructuring and transaction costs 31 — 60 Total $ 157 $ 148 $ 190 Related income tax benefit $ 22 $ 6 $ 6 |
Summary Of Unvested Restricted Stock Awards and Units, Performance-Based Restricted Stock Awards And Performance Share Units | Restricted Stock Performance-Based Performance Awards and Units Restricted Stock Awards Share Units Awards and Units Weighted Average Grant-Date Fair Value Awards Weighted Average Grant-Date Fair Value Units Weighted Average Grant-Date Fair Value (Thousands, except fair value data) Unvested at 12/31/17 6,328 $ 36.81 575 $ 38.92 2,758 $ 41.21 Granted 3,592 $ 35.98 — $ — 845 $ 37.40 Vested (3,114 ) $ 38.75 (273 ) $ 42.22 (571 ) $ 84.22 Forfeited (843 ) $ 35.58 — $ — (164 ) $ 33.92 Unvested at 12/31/18 5,963 $ 35.47 302 $ 35.93 2,868 (1 ) $ 30.14 (1) A maximum of 5.7 million common shares could be awarded based upon Devon’s final TSR ranking. |
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Aggregate Fair Value Of Awards And Units Table Text Block | 2018 2017 2016 Restricted Stock Awards and Units $ 111 $ 105 $ 73 Performance-Based Restricted Stock Awards $ 10 $ 10 $ 5 Performance Share Units $ 20 $ 38 $ 13 |
Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition | Performance-Based Restricted Stock Restricted Stock Performance Awards and Units Awards Share Units Unrecognized compensation cost $ 117 $ 1 $ 23 Weighted average period for recognition (years) 2.4 1.0 1.7 |
Summary Of Performance Share Units Grant-Date Fair Values And Their Related Assumptions | 2018 2017 2016 Grant-date fair value $36.23 — $ 37.88 $51.05 — $53.12 $9.24 — $10.61 Risk-free interest rate 2.28% 1.50% 0.94% Volatility factor 45.8% 45.8% 37.7% Contractual term (years) 2.89 2.89 2.83 |
Summary Of Outstanding Stock Options, Including Changes During The Year | Weighted Average Options Exercise Price Remaining Term Intrinsic Value (Thousands) (Years) Outstanding at December 31, 2017 1,746 $ 70.04 Expired (1,029 ) $ 72.51 Outstanding at December 31, 2018 717 $ 66.49 0.87 $ — Exercisable at December 31, 2018 717 $ 66.49 0.87 $ — |
Asset Impairments (Tables)
Asset Impairments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Impairment Charges [Abstract] | |
Summary of Asset Impairments | Year Ended December 31, 2018 2017 2016 Proved oil and gas assets $ 109 $ — $ 435 Other assets 47 — 2 Total asset impairments $ 156 $ — $ 437 Unproved impairments $ 95 $ 217 $ 77 |
Restructuring and Transaction_2
Restructuring and Transaction Costs (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Restructuring And Related Activities [Abstract] | |
Schedule Of The Activity And Balances Associated With Restructuring Liabilities | The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets. Other Other Current Long-term Liabilities Liabilities Total Balance as of December 31, 2016 $ 48 $ 62 $ 110 Changes related to prior years’ restructurings (29 ) (31 ) (60 ) Balance as of December 31, 2017 $ 19 $ 31 $ 50 Changes due to 2018 workforce reductions 30 — 30 Changes related to prior years’ restructurings (2 ) (15 ) (17 ) Balance as of December 31, 2018 $ 47 $ 16 $ 63 |
Other Expenses (Tables)
Other Expenses (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Income And Expenses [Abstract] | |
Schedule Of Other Expenses Presented In The Accompanying Consolidated Comprehensive Statements of Earnings | The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings. Year Ended December 31, 2018 2017 2016 Foreign exchange (gain) loss, net $ 139 $ (132 ) $ 39 Asset retirement obligation accretion 59 62 75 Other, net (58 ) (13 ) (13 ) Total $ 140 $ (83 ) $ 101 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule Of Income Tax Expense (Benefit) | The following table presents Devon’s income tax components. Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit): U.S. federal $ (14 ) $ 9 $ 3 Various states (3 ) — (11 ) Canada and various provinces (53 ) 103 106 Total current tax expense (benefit) (70 ) 112 98 Deferred income tax expense (benefit): U.S. federal 248 — — Various states 63 — — Canada and various provinces (85 ) (97 ) 43 Total deferred tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141 |
Schedule Of Effective Income Tax Rate Reconciliation | Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following: Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit) $ (70 ) $ 112 $ 98 Deferred income tax expense (benefit) 226 (97 ) 43 Total income tax expense $ 156 $ 15 $ 141 U.S. statutory income tax rate 21 % 35 % 35 % U.S. Tax Reform 0 % 36 % 0 % Legal entity restructuring 2 % (94 %) 19 % State income taxes 5 % 0 % 10 % Change in unrecognized tax benefits (5 %) 2 % (16 %) Other (0 %) (13 %) 8 % Deferred tax asset valuation allowance (6 %) 36 % (89 %) Effective income tax rate 17 % 2 % (33 %) |
Schedule Of Deferred Tax Assets And Liabilities | The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities. December 31, 2018 2017 Deferred tax assets: Asset retirement obligations $ 300 $ 313 Accrued liabilities 50 62 Net operating loss carryforwards 287 796 Pension benefit obligations 44 54 Canadian capital loss carryforwards 609 760 Other 87 135 Total deferred tax assets before valuation allowance 1,377 2,120 Less: valuation allowance (640 ) (968 ) Net deferred tax assets 737 1,152 Deferred tax liabilities: Property and equipment (1,473 ) (1,288 ) Long-term debt — (92 ) Other (141 ) (261 ) Total deferred tax liabilities (1,614 ) (1,641 ) Net deferred tax liability $ (877 ) $ (489 ) |
Schedule Of Changes In Unrecognized Tax Benefits | The following table presents changes in Devon’s unrecognized tax benefits. December 31, 2018 2017 Balance at beginning of year $ 115 $ 202 Tax positions taken in prior periods (43 ) (7 ) Tax positions taken in current year (2 ) (3 ) Accrual of interest related to tax positions taken 3 16 Settlements — (101 ) Foreign currency translation (3 ) 8 Balance at end of year $ 70 $ 115 |
Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities | Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities. Jurisdiction Tax Years Open U.S. Federal 2015-2018 Various U.S. states 2014-2018 Canada Federal 2004-2018 Various Canadian provinces 2004-2018 |
Net Earnings (Loss) Per Share_2
Net Earnings (Loss) Per Share from Continuing Operations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Net Earnings (Loss) Per Share Computations from Continuing Operations | Year Ended December 31, 2018 2017 2016 Net earnings (loss) from continuing operations: Net earnings (loss) from continuing operations $ 764 $ 758 $ (574 ) Attributable to participating securities (9 ) (8 ) (2 ) Basic and diluted earnings (loss) from continuing operations $ 755 $ 750 $ (576 ) Common shares: Common shares outstanding - total 499 525 513 Attributable to participating securities (5 ) (5 ) (6 ) Common shares outstanding - basic 494 520 507 Dilutive effect of potential common shares issuable 3 3 — Common shares outstanding - diluted 497 523 507 Net earnings (loss) per share from continuing operations: Basic $ 1.53 $ 1.44 $ (1.14 ) Diluted $ 1.52 $ 1.43 $ (1.14 ) Antidilutive options (1) 1 2 3 (1) Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive. |
Other Comprehensive Earnings (T
Other Comprehensive Earnings (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease [Abstract] | |
Components Of Other Comprehensive Earnings | Components of other comprehensive earnings consist of the following: Year Ended December 31, 2018 2017 2016 Foreign currency translation: Beginning accumulated foreign currency translation $ 1,309 $ 1,226 $ 1,215 Change in cumulative translation adjustment (166 ) 113 22 Income tax benefit (expense) 14 (30 ) (11 ) Ending accumulated foreign currency translation 1,157 1,309 1,226 Pension and postretirement benefit plans: Beginning accumulated pension and postretirement benefits (143 ) (172 ) (194 ) Net actuarial loss and prior service cost arising in current year (3 ) 10 (28 ) Recognition of net actuarial loss and prior service cost in earnings (1) 12 19 26 Curtailment and settlement of pension benefits 47 — 24 Income tax expense (12 ) — — Other (2) (33 ) — — Ending accumulated pension and postretirement benefits (132 ) (143 ) (172 ) Other 2 — — Accumulated other comprehensive earnings, net of tax $ 1,027 $ 1,166 $ 1,054 (1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 17 (2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1 |
Supplemental Information To S_2
Supplemental Information To Statements Of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule Of Supplemental Information To Statements Of Cash Flows | Year Ended December 31, 2018 2017 2016 Changes in assets and liabilities, net Accounts receivable $ 88 $ (94 ) $ (58 ) Other current assets (128 ) 20 326 Other long-term assets (28 ) (47 ) 36 Accounts payable — 113 (196 ) Revenues and royalties payable 153 106 (26 ) Other current liabilities (150 ) (53 ) (74 ) Other long-term liabilities (78 ) (13 ) 16 Total $ (143 ) $ 32 $ 24 Supplementary cash flow data - total operations: Interest paid (net of capitalized interest) $ 385 $ 481 $ 569 Income taxes paid (received) $ 40 $ 78 $ (159 ) |
Accounts Receivable (Tables)
Accounts Receivable (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounts Receivable Net [Abstract] | |
Schedule Of Components Of Accounts Receivable | Components of accounts receivable include the following: December 31, 2018 December 31, 2017 Oil, gas and NGL sales $ 430 $ 559 Joint interest billings 155 134 Marketing revenues 285 278 Other 23 29 Gross accounts receivable 893 1,000 Allowance for doubtful accounts (8 ) (11 ) Net accounts receivable $ 885 $ 989 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Table of Property and Equipment, net | The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities. December 31, 2018 U.S. Canada Total Property and equipment: Proved $ 40,378 $ 6,427 $ 46,805 Unproved and properties under development 833 1,434 2,267 Total oil and gas 41,211 7,861 49,072 Less accumulated DD&A (32,229 ) (4,030 ) (36,259 ) Oil and gas property and equipment, net $ 8,982 $ 3,831 $ 12,813 Other property and equipment 1,832 Less accumulated DD&A (710 ) Other property and equipment, net 1,122 Property and equipment, net $ 13,935 December 31, 2017 U.S. Canada Total Property and equipment: Proved $ 40,491 $ 6,804 $ 47,295 Unproved and properties under development 984 1,473 2,457 Total oil and gas 41,475 8,277 49,752 Less accumulated DD&A (32,379 ) (4,055 ) (36,434 ) Oil and gas property and equipment, net $ 9,096 $ 4,222 $ 13,318 Other property and equipment 1,955 Less accumulated DD&A (689 ) Other property and equipment, net 1,266 Property and equipment, net $ 14,584 |
Summary of Changes in Suspended Exploratory Well Costs | The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2018. Year Ended December 31, 2018 2017 2016 Beginning balance $ 313 $ 261 $ 225 Additions pending determination of proved reserves 672 504 247 Charges to exploration expense — — (29 ) Reclassifications to proved properties (662 ) (466 ) (189 ) Foreign currency translation adjustment (19 ) 14 7 Ending balance $ 304 $ 313 $ 261 |
Schedule of Aging of Capitalized Exploratory Well Costs | The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. Year Ended December 31, 2018 2017 2016 Exploratory well costs capitalized for a period of one year or less $ 110 $ 113 $ 88 Exploratory well costs capitalized for a period greater than one year 194 200 173 Ending balance $ 304 $ 313 $ 261 Number of projects with exploratory well costs capitalized for a period greater than one year 2 2 2 |
Other Current Liabilities (Tabl
Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Liabilities Disclosure [Abstract] | |
Schedule Of Other Current Liabilities | December 31, 2018 December 31, 2017 Derivative liabilities $ 67 $ 323 Accrued interest payable 80 96 Income taxes payable 14 144 Restructuring liabilities 47 19 Other 227 246 Other current liabilities $ 435 $ 828 |
Debt And Related Expenses (Tabl
Debt And Related Expenses (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule Of Debt Instruments and Balances | See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon. December 31, 2018 December 31, 2017 8.25% (1) $ — $ 20 2.25% — 95 6.30% 162 162 4.00% 500 500 3.25% 1,000 1,000 5.85% 485 485 7.50% (1) 73 73 7.875% (2) (3) 675 1,059 7.95% (2) 366 789 5.60% 1,250 1,250 4.75% 750 750 5.00% 750 750 Net discount on debentures and notes (24 ) (30 ) Debt issuance costs (40 ) (39 ) Total debt 5,947 6,864 Less amount classified as short-term debt (4) 162 115 Total long-term debt $ 5,785 $ 6,749 (1) These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. (2) These senior notes were included in 2018 tender offer repurchases discussed below. (3) Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. (4) 2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019. |
Schedule of Debt Maturities | Total 2019 $ 162 2020 — 2021 500 2022 1,000 2023 — Thereafter 4,349 Total $ 6,011 |
Schedule Of Net Financing Cost Components | Year Ended December 31, 2018 2017 2016 Interest based on debt outstanding $ 339 $ 390 $ 488 Early retirement of debt 312 — 269 Capitalized interest (41 ) (69 ) (61 ) Other (16 ) (4 ) 21 Total net financing costs $ 594 $ 317 $ 717 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Summary Of Changes In Asset Retirement Obligations | Year Ended December 31, 2018 2017 Asset retirement obligations as of beginning of period $ 1,138 $ 1,258 Liabilities incurred 39 40 Liabilities settled and divested (116 ) (68 ) Revision of estimated obligation (25 ) (184 ) Accretion expense on discounted obligation 59 62 Foreign currency translation adjustment (38 ) 30 Asset retirement obligations as of end of period 1,057 1,138 Less current portion 27 39 Asset retirement obligations, long-term $ 1,030 $ 1,099 |
Retirement Plans (Tables)
Retirement Plans (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Compensation And Retirement Disclosure [Abstract] | |
Schedule Of Changes In Defined Benefit Plan Obligations | Pension Benefits Postretirement Benefits 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of year $ 1,279 $ 1,249 $ 19 $ 21 Service cost 10 15 — — Interest cost 39 42 — — Actuarial loss (gain) (83 ) 59 (3 ) — Plan amendments — — — — Plan curtailments 2 — 2 — Plan settlements (241 ) — — — Foreign exchange rate changes (3 ) 2 — — Participant contributions — — 2 1 Benefits paid (60 ) (88 ) (3 ) (3 ) Benefit obligation at end of year 943 1,279 17 19 Change in plan assets: Fair value of plan assets at beginning of year 1,035 985 — — Actual return on plan assets (36 ) 122 — — Employer contributions 14 14 1 2 Participant contributions — — 2 1 Plan settlements (241 ) — — — Benefits paid (60 ) (88 ) (3 ) (3 ) Foreign exchange rate changes (3 ) 2 — — Fair value of plan assets at end of year 709 1,035 — — Funded status at end of year $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in balance sheet: Other long-term assets $ 3 $ 4 $ — $ — Other current liabilities (14 ) (13 ) (3 ) (3 ) Other long-term liabilities (223 ) (235 ) (14 ) (16 ) Net amount $ (234 ) $ (244 ) $ (17 ) $ (19 ) Amounts recognized in accumulated other comprehensive earnings: Net actuarial loss (gain) $ 202 $ 257 $ (11 ) $ (11 ) Prior service cost (credit) 4 6 (2 ) (3 ) Total $ 206 $ 263 $ (13 ) $ (14 ) |
Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets | Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2018 and December 31, 2017, as presented in the table below. December 31, 2018 2017 Projected benefit obligation $ 922 $ 1,255 Accumulated benefit obligation $ 906 $ 1,226 Fair value of plan assets $ 685 $ 1,007 |
Schedule Of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Postretirement Benefit Plans | Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Net periodic benefit cost: Service cost $ 10 $ 15 $ 15 $ — $ — $ — Interest cost 39 42 42 — — 1 Expected return on plan assets (49 ) (54 ) (55 ) — — — Recognition of net actuarial loss (gain) (1) 13 19 25 (1 ) (1 ) (1 ) Recognition of prior service cost (1) 1 2 3 (1 ) (1 ) (1 ) Total net periodic benefit cost (2) 14 24 30 (2 ) (2 ) (1 ) Other comprehensive loss (earnings): Actuarial loss (gain) arising in current year 4 (9 ) 26 (1 ) (1 ) — Prior service cost arising in current year — — 2 — — — Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) (60 ) (19 ) (43 ) 1 1 1 Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) (2 ) (2 ) (9 ) 1 1 1 Total other comprehensive loss (earnings) (58 ) (30 ) (24 ) 1 1 2 Total recognized $ (44 ) $ (6 ) $ 6 $ (1 ) $ (1 ) $ 1 (1) These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. (2) The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings. (3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6 |
Schedule Of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost | Pension Benefits Postretirement Benefits 2018 2017 2016 2018 2017 2016 Assumptions to determine benefit obligations: Discount rate 4.21% 3.59% 4.07% 4.01% 3.25% 3.46% Rate of compensation increase 2.50% 2.50% 4.49% N/A N/A N/A Assumptions to determine net periodic benefit cost: Discount rate - service cost 3.98% 4.29% 4.39% 4.13% 4.22% 3.63% Discount rate - interest cost 3.22% 2.99% 4.39% 2.67% 2.39% 3.63% Rate of compensation increase 2.50% 4.48% 4.49% N/A N/A N/A Expected return on plan assets 5.67% 5.69% 5.20% N/A N/A N/A |
Stockholders' Equity (Tables)
Stockholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Stockholders Equity Note [Abstract] | |
Summary of Purchases of Common Stock | The table below provides information regarding purchases of Devon’s common stock that were made during 2018 (shares in thousands). Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid per Share First quarter 2018: Open-Market 2,561 $ 82 $ 32.19 Second quarter 2018: Open-Market 11,154 439 39.35 Third quarter 2018: Open-Market 16,492 712 43.13 ASR 24,330 1,000 41.10 Total 40,822 1,712 41.92 Fourth quarter 2018: Open-Market 23,612 745 31.57 Total year-to-date 78,149 $ 2,978 $ 38.11 |
Summary Of Dividends Paid On Common Stock | The table below summarizes the dividends Devon paid on its common stock. Amounts Rate Per Share Year Ended 2018: First quarter $ 32 $ 0.06 Second quarter 42 $ 0.08 Third quarter 38 $ 0.08 Fourth quarter 37 $ 0.08 Total year-to-date $ 149 Year Ended 2017: First quarter $ 32 $ 0.06 Second quarter 33 $ 0.06 Third quarter 30 $ 0.06 Fourth quarter 32 $ 0.06 Total year-to-date $ 127 Year Ended 2016: First quarter $ 125 $ 0.24 Second quarter 33 $ 0.06 Third quarter 32 $ 0.06 Fourth quarter 31 $ 0.06 Total year-to-date $ 221 |
Discontinued Operations and A_2
Discontinued Operations and Assets Held for Sale (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations And Disposal Groups [Abstract] | |
Summary of Amounts Reported as Discontinued Operations in the Consolidated Comprehensive Statements of Earnings and Carrying Amounts of Assets and Liabilities Classified as Held for Sale on the Consolidated Balance Sheets | The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations. Year Ended December 31, 2018 2017 2016 Marketing and midstream revenues $ 3,567 $ 5,071 $ 3,551 Marketing and midstream expenses 2,912 4,111 2,712 Depreciation, depletion and amortization 244 545 504 General and administrative expenses 65 128 118 Financing costs, net 98 181 190 Asset impairments — 17 873 Asset dispositions (2,607 ) — 13 Other expenses (8 ) (34 ) 25 Total expenses 704 4,948 4,435 Earnings (loss) from discontinued operations before income taxes 2,863 123 (884 ) Income tax expense (benefit) 403 (197 ) — Net earnings (loss) from discontinued operations, net of income tax expense 2,460 320 (884 ) Net earnings (loss) attributable to noncontrolling interests 160 180 (403 ) Net earnings (loss) from discontinued operations attributable to Devon $ 2,300 $ 140 $ (481 ) The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets. The assets and liabilities classified as held for sale at December 31, 2018 are related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2 The assets and liabilities classified as held for sale at December 31, 2017 are related to the divestiture of EnLink and the General Partner. December 31, 2018 December 31, 2017 Cash and cash equivalents $ — $ 31 Accounts receivable 7 681 Other current assets — 48 Oil and gas property and equipment, based on successful efforts accounting, net 190 — Midstream and other property and equipment, net — 6,587 Goodwill — 1,542 Other long-term assets — 1,600 Total assets held for sale $ 197 $ 10,489 Accounts payable $ 3 $ 186 Revenues and royalties payable — 432 Other current liabilities 19 373 Long-term debt — 3,542 Deferred income taxes — 346 Asset retirement obligations 47 14 Other long-term liabilities — 34 Total liabilities held for sale $ 69 $ 4,927 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Schedule Of Commitments And Contingencies | Year Ending December 31, Purchase Obligations Drilling and Facility Obligations Operational Agreements Office and Equipment Leases 2019 $ 541 $ 274 $ 587 $ 64 2020 567 85 519 43 2021 140 48 373 31 2022 — 14 419 26 2023 — 8 354 25 Thereafter — 16 3,374 311 Total $ 1,248 $ 445 $ 5,626 $ 500 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities | Fair Value Measurements Using: Carrying Total Fair Level 1 Level 2 Amount Value Inputs Inputs December 31, 2018 assets (liabilities): Cash equivalents $ 1,505 $ 1,505 $ 1,405 $ 100 Commodity derivatives $ 677 $ 677 $ — $ 677 Commodity derivatives $ (68 ) $ (68 ) $ — $ (68 ) Debt $ (5,947 ) $ (5,965 ) $ — $ (5,965 ) December 31, 2017 assets (liabilities): Cash equivalents $ 1,533 $ 1,533 $ 1,454 $ 79 Commodity derivatives $ 205 $ 205 $ — $ 205 Commodity derivatives $ (286 ) $ (286 ) $ — $ (286 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (64 ) $ (64 ) $ — $ (64 ) Debt $ (6,864 ) $ (8,131 ) $ — $ (8,131 ) |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments | U.S. Canada Total Year Ended December 31, 2018: Revenues from external customers (1) $ 9,674 $ 1,060 $ 10,734 Depreciation, depletion and amortization $ 1,328 $ 330 $ 1,658 Interest expense $ 469 $ 166 $ 635 Asset impairments $ 156 $ — $ 156 Asset dispositions $ (263 ) $ — $ (263 ) Restructuring and transaction costs $ 97 $ 17 $ 114 Earnings (loss) from continuing operations before income taxes $ 1,294 $ (374 ) $ 920 Income tax expense (benefit) $ 294 $ (138 ) $ 156 Net earnings (loss) from continuing operations $ 1,000 $ (236 ) $ 764 Property and equipment, net $ 10,026 $ 3,909 $ 13,935 Total assets (2) $ 14,853 $ 4,516 $ 19,369 Capital expenditures, including acquisitions $ 2,294 $ 282 $ 2,576 Year Ended December 31, 2017: Revenues from external customers $ 7,326 $ 1,552 $ 8,878 Depreciation, depletion and amortization $ 1,149 $ 380 $ 1,529 Interest expense $ 324 $ 12 $ 336 Asset dispositions $ (218 ) $ 1 $ (217 ) Earnings from continuing operations before income taxes $ 443 $ 330 $ 773 Income tax expense $ 9 $ 6 $ 15 Net earnings from continuing operations $ 434 $ 324 $ 758 Property and equipment, net $ 10,274 $ 4,310 $ 14,584 Total assets (3) $ 14,254 $ 5,498 $ 19,752 Capital expenditures, including acquisitions $ 1,821 $ 348 $ 2,169 Year Ended December 31, 2016: Revenues from external customers $ 5,722 $ 1,031 $ 6,753 Depreciation, depletion and amortization $ 1,178 $ 414 $ 1,592 Interest expense $ 624 $ 100 $ 724 Asset impairments $ 435 $ 2 $ 437 Asset dispositions $ (955 ) $ (541 ) $ (1,496 ) Restructuring and transaction costs $ 242 $ 19 $ 261 Earnings (loss) from continuing operations before income taxes $ (757 ) $ 324 $ (433 ) Income tax expense (benefit) $ (8 ) $ 149 $ 141 Net earnings (loss) from continuing operations $ (749 ) $ 175 $ (574 ) Property and equipment, net $ 10,166 $ 4,110 $ 14,276 Total assets (3) $ 13,390 $ 5,071 $ 18,461 Capital expenditures, including acquisitions $ 2,640 $ 186 $ 2,826 (1) Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. (2) Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million. (3) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively. |
Schedule of Revenue from Contracts with Customers Disaggregated Based on Type of Good | Year Ended December 31, 2018 U.S. Canada Total Oil $ 2,957 $ 814 $ 3,771 Gas 950 — 950 NGL 956 — 956 Oil, gas and NGL revenues from contracts with customers 4,863 814 5,677 Oil, gas and NGL derivatives 457 151 608 Upstream revenues 5,320 965 6,285 Oil 2,745 95 2,840 Gas 738 — 738 NGL 871 — 871 Total marketing revenues from contracts with customers 4,354 95 4,449 Total revenues $ 9,674 $ 1,060 $ 10,734 The following table presents revenue from contracts with customers that are disaggregated based on the type of good. |
Supplemental Information On O_2
Supplemental Information On Oil And Gas Operations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |
Costs Incurred | Year Ended December 31, 2018 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 71 — 71 Exploration costs 679 85 764 Development costs 1,537 249 1,786 Costs incurred $ 2,289 $ 334 $ 2,623 Year Ended December 31, 2017 U.S. Canada Total Property acquisition costs: Proved properties $ 2 $ — $ 2 Unproved properties 50 4 54 Exploration costs 590 87 677 Development costs 1,036 225 1,261 Costs incurred $ 1,678 $ 316 $ 1,994 Year Ended December 31, 2016 U.S. Canada Total Property acquisition costs: Proved properties $ 237 $ — $ 237 Unproved properties 1,356 2 1,358 Exploration costs 282 78 360 Development costs 875 54 929 Costs incurred $ 2,750 $ 134 $ 2,884 |
Results Of Operations | Year Ended December 31, 2018 U.S. Canada Total Oil, gas and NGL sales $ 4,863 $ 814 $ 5,677 Production expenses (1,620 ) (605 ) (2,225 ) Exploration expenses (129 ) (48 ) (177 ) Depreciation, depletion and amortization (1,234 ) (325 ) (1,559 ) Asset dispositions 262 — 262 Asset impairments (109 ) — (109 ) Accretion of asset retirement obligations (35 ) (24 ) (59 ) Income tax (expense) benefit (460 ) 51 (409 ) Results of operations $ 1,538 $ (137 ) $ 1,401 Depreciation, depletion and amortization per Boe $ 8.08 $ 7.63 $ 7.98 Year Ended December 31, 2017 U.S. Canada Total Oil, gas and NGL sales $ 3,746 $ 1,404 $ 5,150 Production expenses (1,232 ) (591 ) (1,823 ) Exploration expenses (346 ) (34 ) (380 ) Depreciation, depletion and amortization (1,050 ) (369 ) (1,419 ) Asset dispositions 211 1 212 Accretion of asset retirement obligations (38 ) (24 ) (62 ) Income tax expense — (104 ) (104 ) Results of operations $ 1,291 $ 283 $ 1,574 Depreciation, depletion and amortization per Boe $ 6.97 $ 7.73 $ 7.15 Year Ended December 31, 2016 U.S. Canada Total Oil, gas and NGL sales $ 3,198 $ 984 $ 4,182 Production expenses (1,313 ) (492 ) (1,805 ) Exploration expenses (176 ) (39 ) (215 ) Depreciation, depletion and amortization (1,066 ) (380 ) (1,446 ) Asset dispositions 946 1 947 Asset impairments (435 ) — (435 ) Accretion of asset retirement obligations (49 ) (26 ) (75 ) Income tax expense — (13 ) (13 ) Results of operations $ 1,105 $ 35 $ 1,140 Depreciation, depletion and amortization per Boe $ 6.11 $ 7.75 $ 6.47 |
Proved Reserves | Bitumen NGL Oil (MMBbls) (MMBbls) Gas (Bcf) (MMBbls) Combined (MMBoe) (1) U.S. Canada Total Canada U.S. Canada Total U.S. U.S. Canada Total Proved developed and undeveloped reserves: December 31, 2015 242 22 264 520 5,808 13 5,821 428 1,638 544 2,182 Revisions due to prices (18 ) (2 ) (20 ) 23 (103 ) — (103 ) (13 ) (48 ) 21 (27 ) Revisions other than price (2 ) 3 1 (19 ) 628 10 638 48 151 (14 ) 137 Extensions and discoveries 36 2 38 — 280 — 280 42 124 2 126 Purchase of reserves 8 — 8 — 33 — 33 7 20 — 20 Production (47 ) (8 ) (55 ) (40 ) (510 ) (7 ) (517 ) (42 ) (174 ) (49 ) (223 ) Sale of reserves (25 ) — (25 ) — (521 ) — (521 ) (45 ) (157 ) — (157 ) December 31, 2016 194 17 211 484 5,615 16 5,631 425 1,554 504 2,058 Revisions due to prices 12 (1 ) 11 (37 ) 398 1 399 32 111 (38 ) 73 Revisions other than price 6 2 8 (10 ) — 2 2 (10 ) (5 ) (7 ) (12 ) Extensions and discoveries 90 4 94 12 403 — 403 63 221 16 237 Production (42 ) (7 ) (49 ) (40 ) (433 ) (6 ) (439 ) (36 ) (150 ) (48 ) (198 ) Sale of reserves (3 ) — (3 ) — (9 ) — (9 ) (1 ) (6 ) — (6 ) December 31, 2017 257 15 272 409 5,974 13 5,987 473 1,725 427 2,152 Revisions due to prices 12 1 13 10 94 (3 ) 91 12 40 11 51 Revisions other than price (10 ) 2 (8 ) 2 (163 ) (4 ) (167 ) (23 ) (60 ) 3 (57 ) Extensions and discoveries 93 5 98 7 446 — 446 64 232 11 243 Production (47 ) (7 ) (54 ) (35 ) (397 ) (4 ) (401 ) (39 ) (153 ) (42 ) (195 ) Sale of reserves (7 ) — (7 ) — (1,195 ) — (1,195 ) (61 ) (267 ) — (267 ) December 31, 2018 298 16 314 393 4,759 2 4,761 426 1,517 410 1,927 Proved developed reserves: December 31, 2015 203 22 225 219 5,694 13 5,707 411 1,563 243 1,806 December 31, 2016 160 17 177 190 5,361 16 5,377 387 1,439 210 1,649 December 31, 2017 178 15 193 200 5,619 13 5,632 410 1,524 218 1,742 December 31, 2018 198 16 214 187 4,331 2 4,333 359 1,278 204 1,482 Proved developed-producing reserves: December 31, 2015 192 19 211 219 5,546 13 5,559 393 1,509 240 1,749 December 31, 2016 143 13 156 190 5,243 16 5,259 370 1,386 207 1,593 December 31, 2017 165 12 177 197 5,512 13 5,525 397 1,481 212 1,693 December 31, 2018 189 12 201 187 4,261 2 4,263 349 1,249 199 1,448 Proved undeveloped reserves: December 31, 2015 39 — 39 301 114 — 114 17 75 301 376 December 31, 2016 34 — 34 294 254 — 254 38 115 294 409 December 31, 2017 79 — 79 209 355 — 355 63 201 209 410 December 31, 2018 100 — 100 206 428 — 428 67 239 206 445 (1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. |
Proved Undeveloped Reserves | U.S. Canada Total Proved undeveloped reserves as of December 31, 2017 201 209 410 Extensions and discoveries 107 6 113 Revisions due to prices 1 6 7 Revisions other than price (8 ) (15 ) (23 ) Sale of reserves (10 ) — (10 ) Conversion to proved developed reserves (52 ) — (52 ) Proved undeveloped reserves as of December 31, 2018 239 206 445 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves | Year Ended December 31, 2018 U.S. Canada Total Future cash inflows $ 40,183 $ 9,146 $ 49,329 Future costs: Development (3,444 ) (1,558 ) (5,002 ) Production (18,107 ) (5,445 ) (23,552 ) Future income tax expense (2,969 ) — (2,969 ) Future net cash flow 15,663 2,143 17,806 10% discount to reflect timing of cash flows (6,897 ) (717 ) (7,614 ) Standardized measure of discounted future net cash flows $ 8,766 $ 1,426 $ 10,192 Year Ended December 31, 2017 U.S. Canada Total Future cash inflows $ 34,701 $ 13,602 $ 48,303 Future costs: Development (3,316 ) (1,853 ) (5,169 ) Production (15,526 ) (5,986 ) (21,512 ) Future income tax expense — (988 ) (988 ) Future net cash flow 15,859 4,775 20,634 10% discount to reflect timing of cash flows (7,541 ) (1,756 ) (9,297 ) Standardized measure of discounted future net cash flows $ 8,318 $ 3,019 $ 11,337 Year Ended December 31, 2016 U.S. Canada Total Future cash inflows $ 22,847 $ 9,672 $ 32,519 Future costs: Development (2,784 ) (2,201 ) (4,985 ) Production (11,934 ) (6,049 ) (17,983 ) Future income tax expense — (121 ) (121 ) Future net cash flow 8,129 1,301 9,430 10% discount to reflect timing of cash flows (3,524 ) (466 ) (3,990 ) Standardized measure of discounted future net cash flows $ 4,605 $ 835 $ 5,440 |
Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves | Year Ended December 31, 2018 2017 2016 Beginning balance $ 11,337 $ 5,440 $ 7,883 Net changes in prices and production costs (243 ) 5,218 (2,027 ) Oil, bitumen, gas and NGL sales, net of production costs (3,452 ) (3,327 ) (2,377 ) Changes in estimated future development costs (216 ) 789 112 Extensions and discoveries, net of future development costs 3,139 2,497 674 Purchase of reserves — 2 224 Sales of reserves in place (588 ) (3 ) (577 ) Revisions of quantity estimates (414 ) (318 ) (21 ) Previously estimated development costs incurred during the period 962 559 663 Accretion of discount 960 1,034 537 Foreign exchange and other (329 ) (7 ) 72 Net change in income taxes (964 ) (547 ) 277 Ending balance $ 10,192 $ 11,337 $ 5,440 |
Supplemental Quarterly Financ_2
Supplemental Quarterly Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Data [Abstract] | |
Schedule Of Quarterly Financial Information | The following tables present a summary of Devon’s unaudited interim results of operations. 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,198 $ 2,249 $ 2,579 $ 3,708 $ 10,734 Asset dispositions (1) $ (12 ) $ 23 $ (6 ) $ (268 ) $ (263 ) Earnings (loss) from continuing operations before income taxes (2) $ (245 ) $ (481 ) $ 162 $ 1,484 $ 920 Net earnings (loss) from continuing operations $ (211 ) $ (474 ) $ 300 $ 1,149 $ 764 Net earnings from discontinued operations, net of income tax expense (3) $ 58 $ 139 $ 2,263 $ — $ 2,460 Net earnings (loss) attributable to Devon $ (197 ) $ (425 ) $ 2,537 $ 1,149 $ 3,064 Basic net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.17 $ 2.50 $ 6.14 Diluted net earnings (loss) per share attributable to Devon $ (0.38 ) $ (0.83 ) $ 5.14 $ 2.48 $ 6.10 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Full Year Total revenues $ 2,400 $ 2,165 $ 1,933 $ 2,380 $ 8,878 Asset dispositions (1) $ (8 ) $ (22 ) $ (170 ) $ (17 ) $ (217 ) Earnings from continuing operations before income taxes $ 313 $ 207 $ 207 $ 46 $ 773 Net earnings from continuing operations $ 308 $ 212 $ 194 $ 44 $ 758 Net earnings from discontinued operations, net of income tax expense $ 9 $ 33 $ 18 $ 260 $ 320 Net earnings attributable to Devon $ 303 $ 219 $ 193 $ 183 $ 898 Basic net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.71 Diluted net earnings per share attributable to Devon $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.70 (1) Additional discussion regarding asset dispositions can be found in Note 2. (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Schedule of Impact of Adoption for Revenue Recognition) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||||||
Revenue Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||
Upstream revenues | $ 6,285 | $ 5,307 | $ 3,981 | |||||||||||||
Revenues | $ 4,449 | $ 3,571 | $ 2,772 | |||||||||||||
Type of Revenue [Extensible List] | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | |||||||||||||
Total impacted revenues | $ 3,708 | $ 2,579 | $ 2,249 | $ 2,198 | $ 2,380 | $ 1,933 | $ 2,165 | $ 2,400 | $ 10,734 | [1] | $ 8,878 | $ 6,753 | ||||
Production expenses | 2,225 | 1,823 | 1,805 | |||||||||||||
Expenses | $ 4,363 | $ 3,619 | $ 2,821 | |||||||||||||
Type of Cost, Good or Service [Extensible List] | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | |||||||||||||
Total impacted expenses | $ 6,588 | |||||||||||||||
Earnings from continuing operations before income taxes | $ 1,484 | [2] | $ 162 | [2] | $ (481) | [2] | $ (245) | [2] | $ 46 | $ 207 | $ 207 | $ 313 | 920 | [2] | $ 773 | $ (433) |
Under ASC 605 [Member] | Accounting Standards Update 2014-09 | ||||||||||||||||
Revenue Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||
Upstream revenues | 6,031 | |||||||||||||||
Revenues | $ 4,449 | |||||||||||||||
Type of Revenue [Extensible List] | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | |||||||||||||||
Total impacted revenues | $ 10,480 | |||||||||||||||
Production expenses | 1,971 | |||||||||||||||
Expenses | $ 4,363 | |||||||||||||||
Type of Cost, Good or Service [Extensible List] | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | |||||||||||||||
Total impacted expenses | $ 6,334 | |||||||||||||||
Earnings from continuing operations before income taxes | 920 | |||||||||||||||
Increase/(Decrease) of Under ASC 606 and Under ASC 605 [Member] | Accounting Standards Update 2014-09 | ||||||||||||||||
Revenue Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||
Upstream revenues | 254 | |||||||||||||||
Total impacted revenues | 254 | |||||||||||||||
Production expenses | 254 | |||||||||||||||
Total impacted expenses | $ 254 | |||||||||||||||
[1] | Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. | |||||||||||||||
[2] | (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)Customer | Dec. 31, 2017USD ($)Customer | Dec. 31, 2016USD ($)Customer | |
Summary Of Significant Accounting Policies [Line Items] | |||
Concentration risk percentage | Customer | 1 | 0 | 0 |
Derivative collateral held | $ 0 | ||
Cash collateral posted | 0 | ||
ASU 2017-07 [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Reclassification of non-service cost components of net periodic benefit costs | $ 7,000,000 | $ 14,000,000 | |
ASU 2018-02 [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Cumulative effect on retained earnings | 33,000,000 | ||
ASU 2016-02 [Member] | Scenario Plan [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Cumulative effect on retained earnings | (19,000,000) | ||
Right-of-use assets expects to recognize | 400,000,000 | ||
Cumulative effect on retained earnings, before tax | $ (24,000,000) | ||
Minimum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Other property and equipment, useful life | 3 years | ||
Maximum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Other property and equipment, useful life | 60 years | ||
Customer Concentration Risk [Member] | One Customer [Member] | Consolidated Sales Revenue [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Concentration risk percentage | 11.00% | ||
Upstream Revenues [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Number of days allowed for payment from end of production month | 30 days | ||
Marketing Revenues [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Number of days allowed for payment of invoiced amount | 30 days |
Acquisitions And Divestitures (
Acquisitions And Divestitures (Narrative) (Details) $ in Millions, $ in Millions | Jan. 07, 2016USD ($)a | Oct. 31, 2016USD ($) | Oct. 31, 2016CAD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | [1] | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | [1] | Sep. 30, 2017USD ($) | [1] | Jun. 30, 2017USD ($) | [1] | Mar. 31, 2017USD ($) | [1] | Dec. 31, 2018USD ($)MMBoe | Dec. 31, 2017USD ($)MMBoe | Dec. 31, 2016USD ($)MMBoe | ||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Gain on sale of aggregate ownership interests, before-tax | $ 2,607 | $ (13) | ||||||||||||||||||||||||
Gain on asset dispositions | $ 268 | [1] | $ 6 | [1] | $ (23) | $ 12 | [1] | $ 17 | $ 170 | $ 22 | $ 8 | 263 | [1] | $ 217 | [1] | $ 1,496 | ||||||||||
Asset retirement obligations assumed by purchasers | $ 116 | $ 68 | ||||||||||||||||||||||||
Total estimated proved reserves | MMBoe | [2] | 267 | 6 | 157 | ||||||||||||||||||||||
US [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Total estimated proved reserves | MMBoe | [2] | 267 | 6 | 157 | ||||||||||||||||||||||
Non Core Assets [Member] | US [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Divestitures of property and equipment | $ 1,000 | $ 420 | $ 1,900 | |||||||||||||||||||||||
Gain on asset dispositions | 260 | $ 212 | 809 | |||||||||||||||||||||||
Asset retirement obligations assumed by purchasers | 84 | $ 290 | ||||||||||||||||||||||||
Settlement expenses relating to gas processing contracts | $ 40 | |||||||||||||||||||||||||
Total estimated proved reserves | MMBoe | 267 | 157 | ||||||||||||||||||||||||
Percentage of Estimated proved reserves associated with divestiture assets | 18.00% | 10.00% | ||||||||||||||||||||||||
Goodwill allocated to divested assets | $ 80 | |||||||||||||||||||||||||
Non Core Assets [Member] | Permian Basin [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Total estimated proved reserves | MMBoe | 25 | |||||||||||||||||||||||||
Non Core Assets [Member] | Permian Basin [Member] | Scenario, Forecast [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Divestitures of property and equipment | $ 300 | |||||||||||||||||||||||||
Gain on asset dispositions | $ 35 | |||||||||||||||||||||||||
Access Pipeline [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Divestitures of property and equipment | $ 1,100 | $ 1,400 | ||||||||||||||||||||||||
Gain on asset dispositions | $ 540 | |||||||||||||||||||||||||
Ownership interest | 50.00% | 50.00% | ||||||||||||||||||||||||
Divestiture agreement dedication initial term | 25 years | 25 years | ||||||||||||||||||||||||
Access Pipeline [Member] | Scenario Plan [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Divestitures of property and equipment | $ 150 | |||||||||||||||||||||||||
EnLink and General Partner [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Proceeds from sale of aggregate ownership interest | 3,125 | $ 3,125 | ||||||||||||||||||||||||
Gain on sale of aggregate ownership interests, after-tax | 2,200 | 2,200 | ||||||||||||||||||||||||
Gain on sale of aggregate ownership interests, before-tax | 2,600 | $ 2,600 | ||||||||||||||||||||||||
Maximum [Member] | Non Core Assets [Member] | US [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Percentage of Estimated proved reserves associated with divestiture assets | 1.00% | |||||||||||||||||||||||||
Maximum [Member] | Non Core Assets [Member] | Permian Basin [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Percentage of Estimated proved reserves associated with divestiture assets | 2.00% | |||||||||||||||||||||||||
Maximum [Member] | Access Pipeline [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Potential pipeline capacity committed, percentage | 90.00% | 90.00% | ||||||||||||||||||||||||
Maximum [Member] | Share Repurchase Program [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Share repurchase program, maximum authorized amount | $ 4,000 | $ 1,000 | ||||||||||||||||||||||||
STACK [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Number of net acres acquired | a | 80,000 | |||||||||||||||||||||||||
Aggregate purchase price | $ 1,500 | |||||||||||||||||||||||||
Cash payment to acquire interest | 849 | |||||||||||||||||||||||||
Unproved properties | 1,300 | $ 1,300 | ||||||||||||||||||||||||
Proved properties | $ 200 | $ 200 | ||||||||||||||||||||||||
STACK [Member] | Common Stock [Member] | Equity Issued in Business Combination [Member] | ||||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||||
Equity units value | $ 659 | |||||||||||||||||||||||||
[1] | (1) Additional discussion regarding asset dispositions can be found in Note 2. | |||||||||||||||||||||||||
[2] | Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. |
Derivative Financial Instrume_3
Derivative Financial Instruments (Schedule Of Open Oil Derivative Positions) (Details) | 12 Months Ended |
Dec. 31, 2018$ / bblbbl | |
NYMEX West Texas Intermediate Price Swaps Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 51,719 |
Weighted Average Price Swap | 59.48 |
NYMEX West Texas Intermediate Price Swaps Oil Q1-Q4 2020 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 1,740 |
Weighted Average Price Swap | 62.88 |
NYMEX West Texas Intermediate Price Collars Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 87,921 |
Weighted Average Floor Price | 54.48 |
Weighted Average Ceiling Price | 64.49 |
NYMEX West Texas Intermediate Price Collars Oil Q1-Q4 2020 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 8,951 |
Weighted Average Floor Price | 52.85 |
Weighted Average Ceiling Price | 63.13 |
NYMEX West Texas Intermediate Three-Way Price Collars Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 5,000 |
Weighted Average Ceiling Price | 74.80 |
Weighted Average Floor Sold Price | 50 |
Weighted Average Floor Purchased Price | 63 |
Midland Sweet Basis Swaps Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 28,000 |
Weighted Average Differential To WTI | (0.46) |
Argus LLS Basis Swaps Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 17,500 |
Weighted Average Differential To WTI | 5 |
Argus MEH Basis Swaps Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 16,000 |
Weighted Average Differential To WTI | 2.84 |
NYMEX Roll Basis Swaps Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 38,000 |
Weighted Average Differential To WTI | 0.45 |
Western Canadian Select Basis Swaps Oil Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 31,505 |
Weighted Average Differential To WTI | (21.73) |
NYMEX Roll Basis Swaps Oil Q1-Q4 2020 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 38,000 |
Weighted Average Differential To WTI | 0.31 |
Western Canadian Select Basis Swaps Oil Q1-Q4 2020 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 915 |
Weighted Average Differential To WTI | (20.75) |
Derivative Financial Instrume_4
Derivative Financial Instruments (Schedule Of Open Natural Gas Derivative Positions) (Details) | 12 Months Ended |
Dec. 31, 2018MMBTU$ / MMBTU | |
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 266,293 |
Weighted Average Price Swap | 2.86 |
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2020 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 26,480 |
Weighted Average Price Swap | 2.92 |
FERC Henry Hub Price Collars Natural Gas Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 231,474 |
Weighted Average Floor Price | 2.69 |
Weighted Average Ceiling Price | 3.06 |
FERC Henry Hub Price Collars Natural Gas Q1-Q4 2020 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 24,490 |
Weighted Average Floor Price | 2.74 |
Weighted Average Ceiling Price | 3.04 |
PEPL Basis Swaps Natural Gas Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 84,466 |
Weighted Average Differential To Henry Hub | (0.73) |
El Paso Natural Gas Basis Swaps Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 130,000 |
Weighted Average Differential To Henry Hub | (1.46) |
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 142,637 |
Weighted Average Differential To Henry Hub | 0.01 |
Transco Zone 4 Natural Gas Basis Swaps Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (MMBtu/d) | MMBTU | 7,397 |
Weighted Average Differential To Henry Hub | (0.03) |
Derivative Financial Instrume_5
Derivative Financial Instruments (Schedule Of Open NGL Derivative Positions) (Details) | 12 Months Ended |
Dec. 31, 2018$ / bblbbl | |
OPIS Mont Belvieu Texas Ethane Price Swaps NGL Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 1,000 |
Weighted Average Price Swap | $ / bbl | 11.55 |
OPIS Mont Belvieu Texas Natural Gasoline Price Swaps NGL Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 4,500 |
Weighted Average Price Swap | $ / bbl | 55.93 |
OPIS Mont Belvieu Texas Normal Butane Price Swaps NGL Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 4,000 |
Weighted Average Price Swap | $ / bbl | 33.69 |
OPIS Mont Belvieu Texas Propane Price Swaps NGL Q1-Q4 2019 [Member] | |
Derivative [Line Items] | |
Volume Per Day (Bbls/d) | bbl | 8,500 |
Weighted Average Price Swap | $ / bbl | 30.01 |
Derivative Financial Instrume_6
Derivative Financial Instruments (Schedule Of Open Interest Rate Swap Derivative Positions) (Details) - Interest Rate Contract 1.76% Expiration January 2019 [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Derivative [Line Items] | |
Notional | $ 100 |
Rate Received, percent | 1.76% |
Rate Paid | Three Month LIBOR |
Expiration | Jan. 31, 2019 |
Derivative Financial Instrume_7
Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Comprehensive Statements Of Earnings) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative [Line Items] | |||
Net gains (losses) recognized in consolidated comprehensive statements of earnings | $ 672 | $ 138 | $ (375) |
Commodity Derivatives [Member] | Upstream Revenues [Member] | |||
Derivative [Line Items] | |||
Net gains (losses) recognized in consolidated comprehensive statements of earnings | 608 | 157 | (201) |
Commodity Derivatives [Member] | Marketing Revenues [Member] | |||
Derivative [Line Items] | |||
Net gains (losses) recognized in consolidated comprehensive statements of earnings | (1) | 3 | (2) |
Interest Rate Derivatives [Member] | Other Expenses [Member] | |||
Derivative [Line Items] | |||
Net gains (losses) recognized in consolidated comprehensive statements of earnings | $ 65 | $ (22) | (19) |
Foreign Currency Derivatives [Member] | Other Expenses [Member] | |||
Derivative [Line Items] | |||
Net gains (losses) recognized in consolidated comprehensive statements of earnings | $ (153) |
Derivative Financial Instrume_8
Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivatives Fair Value [Line Items] | ||
Fair value of derivative assets | $ 677 | $ 206 |
Fair value of derivative liabilities | 68 | 350 |
Other Current Liabilities [Member] | ||
Derivatives Fair Value [Line Items] | ||
Fair value of derivative liabilities | 67 | 323 |
Commodity Derivatives [Member] | Other Current Assets [Member] | ||
Derivatives Fair Value [Line Items] | ||
Fair value of derivative assets | 637 | 203 |
Commodity Derivatives [Member] | Other Long-Term Assets [Member] | ||
Derivatives Fair Value [Line Items] | ||
Fair value of derivative assets | 40 | 2 |
Commodity Derivatives [Member] | Other Current Liabilities [Member] | ||
Derivatives Fair Value [Line Items] | ||
Fair value of derivative liabilities | 67 | 259 |
Commodity Derivatives [Member] | Other Long-Term Liabilities [Member] | ||
Derivatives Fair Value [Line Items] | ||
Fair value of derivative liabilities | $ 1 | 27 |
Interest Rate Derivatives [Member] | Other Current Assets [Member] | ||
Derivatives Fair Value [Line Items] | ||
Fair value of derivative assets | 1 | |
Interest Rate Derivatives [Member] | Other Current Liabilities [Member] | ||
Derivatives Fair Value [Line Items] | ||
Fair value of derivative liabilities | $ 64 |
Share-Based Compensation (Narra
Share-Based Compensation (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)Companyshares | Dec. 31, 2017shares | Dec. 31, 2016shares | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock options granted | 0 | 0 | 0 |
Performance Share Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Number of predetermined peer companies to compare against Devon's total shareholder's return for Performance awards | Company | 14 | ||
Comparison period of peer companies for performance awards | 3 years | ||
Stock Options [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Expiration duration of options | 8 years | ||
Unrecognized compensation cost | $ | $ 0 | ||
Minimum [Member] | Restricted Stock Awards And Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 1 year | ||
Minimum [Member] | Performance-Based Restricted Stock Awards [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 1 year | ||
Minimum [Member] | Performance Share Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Percentage of vesting units to units granted | 0.00% | ||
Minimum [Member] | Stock Options [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 1 year | ||
Maximum [Member] | Restricted Stock Awards And Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 4 years | ||
Maximum [Member] | Performance-Based Restricted Stock Awards [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 4 years | ||
Maximum [Member] | Performance Share Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Percentage of vesting units to units granted | 200.00% | ||
Maximum [Member] | Stock Options [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 4 years | ||
2017 Plan [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Shares authorized for issuance | 33,500,000 | ||
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, options and stock appreciation rights | 1 | ||
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, other awards | 2.3 |
Share-Based Compensation (Sched
Share-Based Compensation (Schedule Of Share-Based Compensation Expense Included In The Consolidated Comprehensive Statements Of Earnings) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation expense | $ 157 | $ 148 | $ 190 |
Related income tax benefit | 22 | 6 | 6 |
G&A [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation expense | 122 | 141 | 124 |
Exploration Expenses [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation expense | 4 | $ 7 | 6 |
Restructuring and Transaction Costs [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Accelerated share-based compensation expense | $ 31 | $ 60 |
Share-Based Compensation (Summa
Share-Based Compensation (Summary Of Unvested Restricted Stock Awards and Units, Performance-Based Restricted Stock Awards And Performance Share Units) (Details) shares in Thousands | 12 Months Ended | |
Dec. 31, 2018$ / sharesshares | ||
Restricted Stock Awards And Units [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Unvested at December 31, 2017 | shares | 6,328 | |
Granted, awards and units | shares | 3,592 | |
Vested, awards and units | shares | (3,114) | |
Forfeited, awards and units | shares | (843) | |
Unvested at December 31, 2018 | shares | 5,963 | |
Unvested weighted average grant-date fair value at December 31, 2017 | $ / shares | $ 36.81 | |
Granted, weighted average grant-date fair value | $ / shares | 35.98 | |
Vested, weighted average grant-date fair value | $ / shares | 38.75 | |
Forfeited, weighted average grant-date fair value | $ / shares | 35.58 | |
Unvested weighted average grant-date fair value at December 31, 2018 | $ / shares | $ 35.47 | |
Performance-Based Restricted Stock Awards [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Unvested at December 31, 2017 | shares | 575 | |
Vested, awards and units | shares | (273) | |
Unvested at December 31, 2018 | shares | 302 | |
Unvested weighted average grant-date fair value at December 31, 2017 | $ / shares | $ 38.92 | |
Vested, weighted average grant-date fair value | $ / shares | 42.22 | |
Unvested weighted average grant-date fair value at December 31, 2018 | $ / shares | $ 35.93 | |
Performance Share Units [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Unvested at December 31, 2017 | shares | 2,758 | |
Granted, awards and units | shares | 845 | |
Vested, awards and units | shares | (571) | |
Forfeited, awards and units | shares | (164) | |
Unvested at December 31, 2018 | shares | 2,868 | [1] |
Unvested weighted average grant-date fair value at December 31, 2017 | $ / shares | $ 41.21 | |
Granted, weighted average grant-date fair value | $ / shares | 37.40 | |
Vested, weighted average grant-date fair value | $ / shares | 84.22 | |
Forfeited, weighted average grant-date fair value | $ / shares | 33.92 | |
Unvested weighted average grant-date fair value at December 31, 2018 | $ / shares | $ 30.14 | |
[1] | A maximum of 5.7 million common shares could be awarded based upon Devon’s final TSR ranking. |
Share-Based Compensation (Sum_2
Share-Based Compensation (Summary Of Unvested Restricted Stock Awards and Units, Performance-Based Restricted Stock Awards And Performance Share Units) (Parenthetical) (Details) shares in Millions | 12 Months Ended |
Dec. 31, 2018shares | |
Performance Share Units [Member] | Maximum [Member] | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Maximum common shares that could be awarded based upon total shareholder return | 5.7 |
Share-Based Compensation (Sch_2
Share-Based Compensation (Schedule Of Aggregate Fair Value Of Restricted Stock, Performance-Based Restricted Stock And Performance Shares, Awards And Units, That Vested During The Period) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Restricted Stock Awards And Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate fair value of awards and units, vested | $ 111 | $ 105 | $ 73 |
Performance-Based Restricted Stock Awards [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate fair value of awards and units, vested | 10 | 10 | 5 |
Performance Share Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate fair value of awards and units, vested | $ 20 | $ 38 | $ 13 |
Share-Based Compensation (Sum_3
Share-Based Compensation (Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Restricted Stock Awards And Units [Member] | |
Unrecognized Compensation And Weighted Average Recognition [Line Items] | |
Unrecognized compensation cost | $ 117 |
Weighted average period for recognition (years) | 2 years 4 months 24 days |
Performance-Based Restricted Stock Awards [Member] | |
Unrecognized Compensation And Weighted Average Recognition [Line Items] | |
Unrecognized compensation cost | $ 1 |
Weighted average period for recognition (years) | 1 year |
Performance Share Units [Member] | |
Unrecognized Compensation And Weighted Average Recognition [Line Items] | |
Unrecognized compensation cost | $ 23 |
Weighted average period for recognition (years) | 1 year 8 months 12 days |
Share-Based Compensation (Sum_4
Share-Based Compensation (Summary Of Performance Share Units Grant-Date Fair Values And Their Related Assumptions) (Details) - Performance Share Units [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Grant-date fair value | $ 37.40 | ||
Risk-free interest rate | 2.28% | 1.50% | 0.94% |
Volatility factor | 45.80% | 45.80% | 37.70% |
Contractual term (years) | 2 years 10 months 20 days | 2 years 10 months 20 days | 2 years 9 months 29 days |
Minimum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Grant-date fair value | $ 36.23 | $ 51.05 | $ 9.24 |
Maximum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Grant-date fair value | $ 37.88 | $ 53.12 | $ 10.61 |
Share-Based Compensation (Sum_5
Share-Based Compensation (Summary Of Outstanding Stock Options, Including Changes During The Year) (Details) - Stock Options [Member] shares in Thousands | 12 Months Ended |
Dec. 31, 2018$ / sharesshares | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Outstanding at December 31, 2017 | shares | 1,746 |
Options, Expired | shares | (1,029) |
Outstanding at December 31, 2018 | shares | 717 |
Exercisable at December 31, 2018 | shares | 717 |
Weighted average exercise price, Outstanding, December 31, 2017 | $ / shares | $ 70.04 |
Expired, weighted average exercise price | $ / shares | 72.51 |
Weighted average exercise price, Outstanding, December 31, 2018 | $ / shares | 66.49 |
Exercisable at December 31, 2018 | $ / shares | $ 66.49 |
Outstanding, weighted average remaining term | 10 months 13 days |
Excercisable, weighted average remaining term | 10 months 13 days |
Asset Impairments (Summary of A
Asset Impairments (Summary of Asset Impairments) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Impaired Long Lived Assets Held And Used [Line Items] | ||||
Asset impairment charges | $ 150 | $ 156 | $ 437 | |
Proved Oil and Gas Assets [Member] | ||||
Impaired Long Lived Assets Held And Used [Line Items] | ||||
Asset impairment charges | 109 | 435 | ||
Unproved Impairments [Member] | ||||
Impaired Long Lived Assets Held And Used [Line Items] | ||||
Asset impairment charges | 95 | $ 217 | 77 | |
Other Assets [Member] | ||||
Impaired Long Lived Assets Held And Used [Line Items] | ||||
Asset impairment charges | $ 47 | $ 2 |
Asset Impairments (Narrative) (
Asset Impairments (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2016 | |
Impaired Long Lived Assets Held And Used [Line Items] | |||
Asset impairments | $ 150 | $ 156 | $ 437 |
Proved Asset Impairments [Member] | |||
Impaired Long Lived Assets Held And Used [Line Items] | |||
Asset impairments | 109 | ||
Non-oil and Gas Asset Impairments [Member] | |||
Impaired Long Lived Assets Held And Used [Line Items] | |||
Asset impairments | $ 47 |
Restructuring and Transaction_3
Restructuring and Transaction Costs (Schedule Of The Activity And Balances Associated With Restructuring Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Restructuring Cost And Reserve [Line Items] | ||
Beginning balance | $ 50 | $ 110 |
Ending balance | 63 | 50 |
Reduction of workforce [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring reserve activity | 30 | |
Prior years' restructurings [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring reserve activity | (17) | (60) |
Other Current Liabilities [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Beginning balance | 19 | 48 |
Ending balance | 47 | 19 |
Other Current Liabilities [Member] | Reduction of workforce [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring reserve activity | 30 | |
Other Current Liabilities [Member] | Prior years' restructurings [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring reserve activity | (2) | (29) |
Other Long-Term Liabilities [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Beginning balance | 31 | 62 |
Ending balance | 16 | 31 |
Other Long-Term Liabilities [Member] | Prior years' restructurings [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring reserve activity | $ (15) | $ (31) |
Restructuring and Transaction_4
Restructuring and Transaction Costs (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2016 | |
Restructuring Cost And Reserve [Line Items] | ||
Restructuring and transaction costs | $ 114 | $ 261 |
Transaction Costs [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring and transaction costs | 11 | |
Reduction of workforce [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring and transaction costs | 114 | |
Expense associated with accelerated awards | 31 | 60 |
Reduction of workforce [Member] | Estimated Defined Benefit Settlements [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring and transaction costs | $ 14 | 24 |
Reduction of workforce [Member] | Employee Related Costs [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring and transaction costs | 227 | |
Reduction of workforce [Member] | Lease Obligations [Member] | ||
Restructuring Cost And Reserve [Line Items] | ||
Restructuring and transaction costs | $ 23 |
Other Expenses (Schedule Of Oth
Other Expenses (Schedule Of Other Expenses Presented In The Accompanying Consolidated Comprehensive Statements of Earnings) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other Income And Expenses [Abstract] | |||
Foreign exchange (gain) loss, net | $ 139 | $ (132) | $ 39 |
Asset retirement obligation accretion | 59 | 62 | 75 |
Other, net | (58) | (13) | (13) |
Total | $ 140 | $ (83) | $ 101 |
Other Expenses (Narrative) (Det
Other Expenses (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2016 | |
Other Income And Expenses [Abstract] | ||
Foreign currency realized gain (loss) | $ (241) | $ 63 |
Foreign currency unrealized gain (losses) | $ (195) | $ 10 |
Income Taxes (Schedule Of Incom
Income Taxes (Schedule Of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current income tax expense (benefit): | |||
United States federal, current income tax expense (benefit) | $ (14) | $ 9 | $ 3 |
Various states, current income tax expense (benefit) | (3) | (11) | |
Canada and various provinces, current income tax expense (benefit) | (53) | 103 | 106 |
Total current tax expense (benefit) | (70) | 112 | 98 |
Deferred income tax expense (benefit): | |||
United States federal, deferred income tax expense (benefit) | 248 | ||
Various states, deferred income tax expense (benefit) | 63 | ||
Canada and various provinces, deferred income tax expense (benefit) | (85) | (97) | 43 |
Total deferred tax expense (benefit) | 226 | (97) | 43 |
Total income tax expense | $ 156 | $ 15 | $ 141 |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Current income tax expense (benefit) | $ (70) | $ 112 | $ 98 |
Deferred income tax expense (benefit) | 226 | (97) | 43 |
Total income tax expense | $ 156 | $ 15 | $ 141 |
U.S. statutory income tax rate | 21.00% | 35.00% | 35.00% |
U.S. Tax Reform | 0.00% | 36.00% | 0.00% |
Legal entity restructuring | 2.00% | (94.00%) | 19.00% |
State income taxes | 5.00% | 0.00% | 10.00% |
Change in unrecognized tax benefits | (5.00%) | 2.00% | (16.00%) |
Other | 0.00% | (13.00%) | 8.00% |
Deferred tax asset valuation allowance | (6.00%) | 36.00% | (89.00%) |
Effective income tax rate | 17.00% | 2.00% | (33.00%) |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2016 | Jun. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax [Line Items] | |||||||
Tax benefit related to unrecognized tax benefits | $ 42 | ||||||
Valuation allowance against U.S. deferred tax assets, percent | 100.00% | 100.00% | 100.00% | ||||
Gain on sale of aggregate ownership interests, before-tax | 2,607 | $ (13) | |||||
Deferred tax benefit resulting from release of valuation allowance position; allocated to discontinued operations | $ 259 | ||||||
U.S. statutory income tax rate | 21.00% | 35.00% | 35.00% | ||||
Deferred income tax expense (benefit) | $ 226 | $ (97) | $ 43 | ||||
Capital loss carryforward, deferred tax asset | $ 760 | 609 | 760 | ||||
Tax expense related to unrecognized tax benefits | 63 | ||||||
Deferred tax assets, valuation allowance | 968 | 640 | 968 | ||||
Net operating loss carryforwards, deferred tax assets | 796 | 287 | 796 | ||||
Unrecognized tax benefits, interest and penalties | 28 | 12 | 28 | ||||
Unrecognized tax benefit that would impact effective tax rate | 70 | ||||||
Unrecognized tax benefits removed | 43 | 7 | |||||
Interest associated with tax examinations | $ 20 | ||||||
United States Federal [Member] | |||||||
Income Tax [Line Items] | |||||||
Net operating loss carryforward, expiration date | Dec. 31, 2037 | ||||||
Net operating loss carryforwards | $ 389 | ||||||
Various U.S. States [Member] | |||||||
Income Tax [Line Items] | |||||||
Net operating loss carryforwards | $ 784 | ||||||
Minimum [Member] | United States Federal [Member] | |||||||
Income Tax [Line Items] | |||||||
Operating loss carryforward, utilization period | Dec. 31, 2019 | ||||||
Minimum [Member] | Various U.S. States [Member] | |||||||
Income Tax [Line Items] | |||||||
Net operating loss carryforward, expiration date | Dec. 31, 2019 | ||||||
Operating loss carryforward, utilization period | Dec. 31, 2019 | ||||||
Minimum [Member] | Canada Federal [Member] | |||||||
Income Tax [Line Items] | |||||||
Net operating loss carryforward, expiration date | Dec. 31, 2029 | ||||||
Operating loss carryforward, utilization period | Dec. 31, 2019 | ||||||
Maximum [Member] | Various U.S. States [Member] | |||||||
Income Tax [Line Items] | |||||||
Net operating loss carryforward, expiration date | Dec. 31, 2038 | ||||||
Maximum [Member] | Canada Federal [Member] | |||||||
Income Tax [Line Items] | |||||||
Net operating loss carryforward, expiration date | Dec. 31, 2038 | ||||||
Canada [Member] | |||||||
Income Tax [Line Items] | |||||||
Change in deferred tax valuation allowance | 641 | $ (59) | |||||
Capital loss carryforward, deferred tax asset | 727 | 727 | |||||
Deferred tax assets, valuation allowance | 609 | 71 | |||||
Net operating loss carryforwards | 595 | ||||||
U.S. [Member] | |||||||
Income Tax [Line Items] | |||||||
Change in deferred tax valuation allowance | $ (323) | $ 313 | |||||
Deferred tax assets, valuation allowance | 31 | ||||||
Allocated goodwill | $ 83 | ||||||
U.S. [Member] | Transition Tax [Member] | |||||||
Income Tax [Line Items] | |||||||
Deferred income tax expense (benefit) | 167 | ||||||
U.S. [Member] | Change in Income Tax Rate [Member] | |||||||
Income Tax [Line Items] | |||||||
Deferred income tax expense (benefit) | $ 108 | ||||||
EnLink and General Partner [Member] | |||||||
Income Tax [Line Items] | |||||||
Gain on sale of aggregate ownership interests, before-tax | $ 2,600 | $ 2,600 |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Income Tax Disclosure [Abstract] | ||
Deferred tax assets, asset retirement obligations | $ 300 | $ 313 |
Deferred tax assets, accrued liabilities | 50 | 62 |
Deferred tax assets, net operating loss carryforwards | 287 | 796 |
Deferred tax assets, pension benefit obligations | 44 | 54 |
Deferred tax assets, Canadian capital loss carryforwards | 609 | 760 |
Deferred tax assets, other | 87 | 135 |
Total deferred tax assets before valuation allowance | 1,377 | 2,120 |
Less: valuation allowance | (640) | (968) |
Net deferred tax assets | 737 | 1,152 |
Deferred tax liabilities, property and equipment | (1,473) | (1,288) |
Deferred tax liabilities, long-term debt | (92) | |
Deferred tax liabilities, other | (141) | (261) |
Total deferred tax liabilities | (1,614) | (1,641) |
Net deferred tax liability | $ (877) | $ (489) |
Income Taxes (Schedule Of Chang
Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | ||
Unrecognized tax benefits, Balance at beginning of year | $ 115 | $ 202 |
Unrecognized tax benefits, Tax positions taken in prior periods | (43) | (7) |
Unrecognized tax benefits, Tax positions taken in current year | (2) | (3) |
Unrecognized tax benefits, Accrual of interest related to tax positions taken | 3 | 16 |
Unrecognized tax benefits, Settlements | (101) | |
Unrecognized tax benefits, Foreign currency translation | (3) | 8 |
Unrecognized tax benefits, Balance at end of year | $ 70 | $ 115 |
Income Taxes (Summary Of The Ta
Income Taxes (Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities) (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Minimum [Member] | United States Federal [Member] | |
Tax years open | 2,015 |
Minimum [Member] | Canada Federal [Member] | |
Tax years open | 2,004 |
Maximum [Member] | United States Federal [Member] | |
Tax years open | 2,018 |
Maximum [Member] | Canada Federal [Member] | |
Tax years open | 2,018 |
Various U.S. States [Member] | Minimum [Member] | |
Tax years open | 2,014 |
Various U.S. States [Member] | Maximum [Member] | |
Tax years open | 2,018 |
Various Canadian Provinces [Member] | Minimum [Member] | |
Tax years open | 2,004 |
Various Canadian Provinces [Member] | Maximum [Member] | |
Tax years open | 2,018 |
Net Earnings (Loss) Per Share_3
Net Earnings (Loss) Per Share from Continuing Operations (Earnings Per Share Computations from Continuing Operations) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Net earnings (loss) from continuing operations: | ||||||||||||
Net earnings (loss) from continuing operations | $ 1,149 | $ 300 | $ (474) | $ (211) | $ 44 | $ 194 | $ 212 | $ 308 | $ 764 | $ 758 | $ (574) | |
Attributable to participating securities | (9) | (8) | (2) | |||||||||
Basic and diluted earnings (loss) from continuing operations | $ 755 | $ 750 | $ (576) | |||||||||
Common shares: | ||||||||||||
Common shares outstanding - total | 499 | 525 | 513 | |||||||||
Attributable to participating securities | (5) | (5) | (6) | |||||||||
Common shares outstanding - basic | 494 | 520 | 507 | |||||||||
Dilutive effect of potential common shares issuable | 3 | 3 | ||||||||||
Common shares outstanding - diluted | 497 | 523 | 507 | |||||||||
Net earnings (loss) per share from continuing operations: | ||||||||||||
Basic | $ 1.53 | $ 1.44 | $ (1.14) | |||||||||
Diluted | $ 1.52 | $ 1.43 | $ (1.14) | |||||||||
Antidilutive options | [1] | 1 | 2 | 3 | ||||||||
[1] | Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive. |
Other Comprehensive Earnings (C
Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Foreign currency translation: | ||||
Beginning accumulated foreign currency translation | $ 1,309 | $ 1,226 | $ 1,215 | |
Change in cumulative translation adjustment | (166) | 113 | 22 | |
Income tax benefit (expense) | 14 | (30) | (11) | |
Ending accumulated foreign currency translation | 1,157 | 1,309 | 1,226 | |
Pension and postretirement benefit plans: | ||||
Beginning accumulated pension and postretirement benefits | (143) | (172) | (194) | |
Net actuarial loss and prior service cost arising in current year | (3) | 10 | (28) | |
Recognition of net actuarial loss and prior service cost in earnings | [1] | 12 | 19 | 26 |
Curtailment and settlement of pension benefits | 47 | 24 | ||
Income tax expense | (12) | |||
Other | [2] | (33) | ||
Ending accumulated pension and postretirement benefits | (132) | (143) | (172) | |
Other | 2 | |||
Accumulated other comprehensive earnings, net of tax | $ 1,027 | $ 1,166 | $ 1,054 | |
[1] | (1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 17 | |||
[2] | (2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1 |
Other Comprehensive Earnings _2
Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Parenthetical) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018USD ($) | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Effect of new accounting pronouncement | $ (33) | [1] |
ASU 2018-02 [Member] | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Effect of new accounting pronouncement | $ (33) | |
[1] | (2) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1 |
Supplemental Information To S_3
Supplemental Information To Statements Of Cash Flows (Schedule Of Supplemental Information To Statements Of Cash Flows) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in assets and liabilities, net | |||
Accounts receivable | $ 88 | $ (94) | $ (58) |
Other current assets | (128) | 20 | 326 |
Other long-term assets | (28) | (47) | 36 |
Accounts payable | 113 | (196) | |
Revenues and royalties payable | 153 | 106 | (26) |
Other current liabilities | (150) | (53) | (74) |
Other long-term liabilities | (78) | (13) | 16 |
Total | (143) | 32 | 24 |
Supplementary cash flow data - total operations: | |||
Interest paid (net of capitalized interest) | 385 | 481 | 569 |
Income taxes paid (received) | $ 40 | $ 78 | $ (159) |
Accounts Receivable (Schedule O
Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Joint interest billings | $ 155 | $ 134 |
Other | 23 | 29 |
Gross accounts receivable | 893 | 1,000 |
Allowance for doubtful accounts | (8) | (11) |
Net accounts receivable | 885 | 989 |
Oil, Gas and NGL Sales [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Gross accounts receivable | 430 | 559 |
Marketing Revenues [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Gross accounts receivable | $ 285 | $ 278 |
Property, Plant and Equipment_2
Property, Plant and Equipment (Table of Property and Equipment, net) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Property and equipment: | |||
Proved | $ 46,805 | $ 47,295 | |
Unproved and properties under development | 2,267 | 2,457 | |
Total oil and gas | 49,072 | 49,752 | |
Less accumulated DD&A | (36,259) | (36,434) | |
Oil and gas property and equipment, net | 12,813 | 13,318 | |
Other property and equipment | 1,832 | 1,955 | |
Less accumulated DD&A | (710) | (689) | |
Other property and equipment, net | 1,122 | 1,266 | |
Total property and equipment, net | 13,935 | 14,584 | $ 14,276 |
US [Member] | |||
Property and equipment: | |||
Proved | 40,378 | 40,491 | |
Unproved and properties under development | 833 | 984 | |
Total oil and gas | 41,211 | 41,475 | |
Less accumulated DD&A | (32,229) | (32,379) | |
Oil and gas property and equipment, net | 8,982 | 9,096 | |
Canada [Member] | |||
Property and equipment: | |||
Proved | 6,427 | 6,804 | |
Unproved and properties under development | 1,434 | 1,473 | |
Total oil and gas | 7,861 | 8,277 | |
Less accumulated DD&A | (4,030) | (4,055) | |
Oil and gas property and equipment, net | $ 3,831 | $ 4,222 |
Property, Plant and Equipment_3
Property, Plant and Equipment (Summary of Changes in Suspended Exploratory Well Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Increase Decrease In Capitalized Exploratory Well Costs That Are Pending Determination Of Proved Reserves Roll Forward | |||
Beginning balance | $ 313 | $ 261 | $ 225 |
Additions pending determination of proved reserves | 672 | 504 | 247 |
Charges to exploration expense | (29) | ||
Reclassifications to proved properties | (662) | (466) | (189) |
Foreign currency translation adjustment | (19) | 14 | 7 |
Ending balance | $ 304 | $ 313 | $ 261 |
Property, Plant and Equipment_4
Property, Plant and Equipment (Schedule of Aging of Capitalized Exploratory Well Costs (Details) $ in Millions | Dec. 31, 2018USD ($)Project | Dec. 31, 2017USD ($)Project | Dec. 31, 2016USD ($)Project | Dec. 31, 2015USD ($) |
Schedule Of Aging Of Capitalized Exploratory Well Costs [Abstract] | ||||
Exploratory well costs capitalized for a period of one year or less | $ 110 | $ 113 | $ 88 | |
Exploratory well costs capitalized for a period greater than one year | 194 | 200 | 173 | |
Ending balance | $ 304 | $ 313 | $ 261 | $ 225 |
Number of projects with exploratory well costs capitalized for a period greater than one year | Project | 2 | 2 | 2 |
Other Current Liabilities (Sche
Other Current Liabilities (Schedule Of Other Current Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Other Liabilities, Current [Abstract] | ||
Derivative liabilities | $ 68 | $ 350 |
Accrued interest payable | 80 | 96 |
Income taxes payable | 14 | 144 |
Restructuring liabilities | 47 | 19 |
Other | 227 | 246 |
Other current liabilities | 435 | 828 |
Other Current Liabilities [Member] | ||
Other Liabilities, Current [Abstract] | ||
Derivative liabilities | $ 67 | $ 323 |
Debt And Related Expenses (Sche
Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | ||
Debt Instrument [Line Items] | |||
Short-term debt | [1] | $ 162 | $ 115 |
Long-term debt, gross | 6,011 | ||
Net discount on debentures and notes | (24) | (30) | |
Debt issuance costs | (40) | (39) | |
Total debt | 5,947 | 6,864 | |
Total long-term debt | $ 5,785 | 6,749 | |
8.25% Due July 1, 2018 [Member] | |||
Debt Instrument [Line Items] | |||
Short-term debt | [2] | $ 20 | |
Debt, maturity date | Jul. 1, 2018 | ||
Debt interest rate, stated percentage | 8.25% | 8.25% | |
2.25% Due December 15, 2018 [Member] | |||
Debt Instrument [Line Items] | |||
Short-term debt | $ 95 | ||
Debt, maturity date | Dec. 15, 2018 | ||
Debt interest rate, stated percentage | 2.25% | 2.25% | |
6.30% Due January 15, 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Short-term debt | $ 162 | ||
Long-term debt, gross | $ 162 | ||
Debt, maturity date | Jan. 15, 2019 | ||
Debt interest rate, stated percentage | 6.30% | 6.30% | |
4.00% Due July 15, 2021 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | $ 500 | $ 500 | |
Debt, maturity date | Jul. 15, 2021 | ||
Debt interest rate, stated percentage | 4.00% | 4.00% | |
3.25% due May 15, 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | $ 1,000 | $ 1,000 | |
Debt, maturity date | May 15, 2022 | ||
Debt interest rate, stated percentage | 3.25% | 3.25% | |
5.85% due December 15, 2025 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | $ 485 | $ 485 | |
Debt, maturity date | Dec. 15, 2025 | ||
Debt interest rate, stated percentage | 5.85% | 5.85% | |
7.50% due September 15, 2027 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | [2] | $ 73 | $ 73 |
Debt, maturity date | Sep. 15, 2027 | ||
Debt interest rate, stated percentage | 7.50% | 7.50% | |
7.875% due September 30, 2031 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | [3],[4] | $ 675 | $ 1,059 |
Debt, maturity date | Sep. 30, 2031 | ||
Debt interest rate, stated percentage | 7.875% | 7.875% | |
7.95% due April 15, 2032 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | [4] | $ 366 | $ 789 |
Debt, maturity date | Apr. 15, 2032 | ||
Debt interest rate, stated percentage | 7.95% | 7.95% | |
5.60% due July 15, 2041 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | $ 1,250 | $ 1,250 | |
Debt, maturity date | Jul. 15, 2041 | ||
Debt interest rate, stated percentage | 5.60% | 5.60% | |
4.75% due May 15, 2042 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | $ 750 | $ 750 | |
Debt, maturity date | May 15, 2042 | ||
Debt interest rate, stated percentage | 4.75% | 4.75% | |
5.00% due June 15, 2045 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, gross | $ 750 | $ 750 | |
Debt, maturity date | Jun. 15, 2045 | ||
Debt interest rate, stated percentage | 5.00% | 5.00% | |
[1] | 2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019. | ||
[2] | These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. | ||
[3] | Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. | ||
[4] | These senior notes were included in 2018 tender offer repurchases discussed below. |
Debt And Related Expenses (Sc_2
Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Parenthetical) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Apr. 30, 2003 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Debt Instrument [Line Items] | ||||
Short-term debt | [1] | $ 162 | $ 115 | |
8.25% Due July 1, 2018 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt interest rate, stated percentage | 8.25% | 8.25% | ||
Short-term debt | [2] | $ 20 | ||
Debt, maturity date | Jul. 1, 2018 | |||
8.25% Due July 1, 2018 [Member] | Ocean Energy [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt interest rate, stated percentage | 8.25% | |||
Fair value of notes assumed | $ 147 | |||
Effective interest rate of notes | 5.50% | |||
7.50% due September 15, 2027 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt interest rate, stated percentage | 7.50% | 7.50% | ||
Debt, maturity date | Sep. 15, 2027 | |||
7.50% due September 15, 2027 [Member] | Ocean Energy [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt interest rate, stated percentage | 7.50% | |||
Fair value of notes assumed | $ 169 | |||
Effective interest rate of notes | 6.50% | |||
6.30% Due January 15, 2019 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt interest rate, stated percentage | 6.30% | 6.30% | ||
Short-term debt | $ 162 | |||
Debt, maturity date | Jan. 15, 2019 | |||
[1] | 2018 short-term debt consists of $162 million of 6.30% senior notes due January 15, 2019. | |||
[2] | These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. |
Debt And Related Expenses (Sc_3
Debt And Related Expenses (Schedule Of Debt Maturities) (Details) $ in Millions | Dec. 31, 2018USD ($) |
Debt Disclosure [Abstract] | |
2,019 | $ 162 |
2,021 | 500 |
2,022 | 1,000 |
Thereafter | 4,349 |
Total | $ 6,011 |
Debt And Related Expenses (Narr
Debt And Related Expenses (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2016 | Oct. 05, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | |||||
Commercial paper | $ 0 | ||||
Redemption of senior notes | 922 | $ 2,492 | |||
Loss on early retirement of debt | (312) | (269) | |||
Loss on early retirement of debt, cash retirement costs | 304 | 265 | |||
Repurchase of debt securities | $ 2,100 | ||||
Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption of senior notes | 807 | ||||
Loss on early retirement of debt | (312) | ||||
Loss on early retirement of debt, cash retirement costs | 304 | ||||
Loss on early retirement of debt, noncash charges | $ 8 | ||||
7.875% due September 30, 2031 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt interest rate, stated percentage | 7.875% | 7.875% | |||
Debt, maturity date | Sep. 30, 2031 | ||||
7.875% due September 30, 2031 [Member] | Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption of senior notes | $ 384 | ||||
Debt interest rate, stated percentage | 7.875% | ||||
Debt, maturity date | Sep. 30, 2031 | ||||
7.95% due April 15, 2032 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt interest rate, stated percentage | 7.95% | 7.95% | |||
Debt, maturity date | Apr. 15, 2032 | ||||
7.95% due April 15, 2032 [Member] | Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption of senior notes | $ 423 | ||||
Debt interest rate, stated percentage | 7.95% | ||||
Debt, maturity date | Apr. 15, 2032 | ||||
2.25% Due December 15, 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt interest rate, stated percentage | 2.25% | 2.25% | |||
Debt, maturity date | Dec. 15, 2018 | ||||
2.25% Due December 15, 2018 [Member] | Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption of senior notes | $ 95 | ||||
Debt interest rate, stated percentage | 2.25% | ||||
6.30% Due January 15, 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt interest rate, stated percentage | 6.30% | 6.30% | |||
Debt, maturity date | Jan. 15, 2019 | ||||
6.30% Due January 15, 2019 [Member] | Senior Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption of senior notes | $ 162 | ||||
Debt interest rate, stated percentage | 6.30% | ||||
Commercial Paper [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit Facility, borrowing capacity | $ 3,000 | ||||
2012 Senior Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit Facility, borrowing capacity | $ 3,000 | ||||
2018 Senior Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Credit Facility, borrowing capacity | $ 3,000 | ||||
Credit facility maturity date | Oct. 5, 2023 | ||||
Credit facility extension period description | The 2018 Senior Credit Facility matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods subject to lender consent. | ||||
Frequency of payment | annual | ||||
Commitment fee amount | $ 6.1 | ||||
Outstanding credit facility borrowings | 0 | ||||
Outstanding letters of credit | $ 48 | ||||
Debt-to-capitalization ratio | 0.210 | ||||
2018 Senior Credit Facility [Member] | Maximum [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt-to-capitalization ratio | 0.65 |
Debt And Related Expenses (Sc_4
Debt And Related Expenses (Schedule of Net Financing Cost Components) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |||
Interest based on debt outstanding | $ 339 | $ 390 | $ 488 |
Early retirement of debt | 312 | 269 | |
Capitalized interest | (41) | (69) | (61) |
Other | (16) | (4) | 21 |
Total net financing costs | $ 594 | $ 317 | $ 717 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |||
Asset retirement obligations as of beginning of period | $ 1,138 | $ 1,258 | |
Liabilities incurred | 39 | 40 | |
Liabilities settled and divested | (116) | (68) | |
Revision of estimated obligation | (25) | (184) | |
Accretion expense on discounted obligation | 59 | 62 | $ 75 |
Foreign currency translation adjustment | (38) | 30 | |
Asset retirement obligations as of end of period | 1,057 | 1,138 | $ 1,258 |
Less current portion | 27 | 39 | |
Asset retirement obligations, long-term | $ 1,030 | $ 1,099 |
Asset Retirement Obligations (N
Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligations [Line Items] | ||
Decrease in asset retirement obligation | $ 116 | $ 68 |
Revision of estimated obligation | (25) | $ (184) |
Asset Divestitures [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Decrease in asset retirement obligation | $ 84 |
Retirement Plans (Narrative) (D
Retirement Plans (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Contributions to defined contribution plans | $ 50 | $ 53 | $ 57 | |
Settlement expense | $ 33 | |||
Expected benefit plan payments for each of the next five years | 59 | |||
Benefit plan payments expected to be funded from cash and cash equivalents and other assets for next fiscal year | 17 | |||
Expected total benefit plan payments for five years after the next five years | 153 | |||
Pension Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 709 | 1,035 | $ 985 | |
Settlement expense | $ 241 | $ 241 | ||
Pension Benefits [Member] | Fixed Income Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Target plan asset allocations | 70.00% | |||
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 1 Inputs [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 193 | 342 | ||
Pension Benefits [Member] | Fixed Income Securities [Member] | Level 2 Inputs [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 301 | 401 | ||
Pension Benefits [Member] | Equity Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Target plan asset allocations | 20.00% | |||
Fair value of plan assets | $ 84 | 157 | ||
Pension Benefits [Member] | Other Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Target plan asset allocations | 10.00% | |||
Fair value of plan assets | $ 132 | $ 135 | ||
Postretirement Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined benefit plan health care cost trend rate assumed for next fiscal year | 7.10% | |||
Defined benefit plan ultimate health care cost trend rate | 5.00% |
Retirement Plans (Schedule Of C
Retirement Plans (Schedule Of Changes In Defined Benefit Plan Obligations) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Change in benefit obligation: | ||||
Plan settlements | $ (33) | |||
Pension Benefits [Member] | ||||
Change in benefit obligation: | ||||
Benefit obligation at beginning of year | $ 1,279 | $ 1,249 | ||
Service cost | 10 | 15 | $ 15 | |
Interest cost | 39 | 42 | 42 | |
Actuarial loss (gain) | (83) | 59 | ||
Plan curtailments | 2 | |||
Plan settlements | $ (241) | (241) | ||
Foreign exchange rate changes | (3) | 2 | ||
Benefits paid | (60) | (88) | ||
Benefit obligation at end of year | 943 | 1,279 | 1,249 | |
Change in plan assets: | ||||
Fair value of plan assets at beginning of year | 1,035 | 985 | ||
Actual return on plan assets | (36) | 122 | ||
Employer contributions | 14 | 14 | ||
Plan settlements | (241) | |||
Benefits paid | (60) | (88) | ||
Foreign exchange rate changes | (3) | 2 | ||
Fair value of plan assets at end of year | 709 | 1,035 | 985 | |
Funded status at end of year | (234) | (244) | ||
Amounts recognized in balance sheet: | ||||
Other long-term assets | 3 | 4 | ||
Other current liabilities | (14) | (13) | ||
Other long-term liabilities | (223) | (235) | ||
Net amount | (234) | (244) | ||
Amounts recognized in accumulated other comprehensive earnings: | ||||
Net actuarial loss (gain) | 202 | 257 | ||
Prior service cost (credit) | 4 | 6 | ||
Total | 206 | 263 | ||
Postretirement Benefits [Member] | ||||
Change in benefit obligation: | ||||
Benefit obligation at beginning of year | 19 | 21 | ||
Interest cost | 1 | |||
Actuarial loss (gain) | (3) | |||
Plan curtailments | 2 | |||
Participant contributions | 2 | 1 | ||
Benefits paid | (3) | (3) | ||
Benefit obligation at end of year | 17 | 19 | $ 21 | |
Change in plan assets: | ||||
Employer contributions | 1 | 2 | ||
Participant contributions | 2 | 1 | ||
Benefits paid | (3) | (3) | ||
Funded status at end of year | (17) | (19) | ||
Amounts recognized in balance sheet: | ||||
Other current liabilities | (3) | (3) | ||
Other long-term liabilities | (14) | (16) | ||
Net amount | (17) | (19) | ||
Amounts recognized in accumulated other comprehensive earnings: | ||||
Net actuarial loss (gain) | (11) | (11) | ||
Prior service cost (credit) | (2) | (3) | ||
Total | $ (13) | $ (14) |
Retirement Plans (Schedule Of P
Retirement Plans (Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Retirement Plans[Abstract] | ||
Projected benefit obligation | $ 922 | $ 1,255 |
Accumulated benefit obligation | 906 | 1,226 |
Fair value of plan assets | $ 685 | $ 1,007 |
Retirement Plans (Schedule Of N
Retirement Plans (Schedule Of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Other Postretirement Benefit Plans) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Pension Benefits [Member] | ||||
Net periodic benefit cost: | ||||
Service cost | $ 10 | $ 15 | $ 15 | |
Interest cost | 39 | 42 | 42 | |
Expected return on plan assets | (49) | (54) | (55) | |
Recognition of net actuarial loss (gain) | [1] | 13 | 19 | 25 |
Recognition of prior service cost | [1] | 1 | 2 | 3 |
Total net periodic benefit cost | [2] | 14 | 24 | 30 |
Other comprehensive loss (earnings): | ||||
Actuarial loss (gain) arising in current year | 4 | (9) | 26 | |
Prior service cost arising in current year | 2 | |||
Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost | [3] | (60) | (19) | (43) |
Recognition of prior service cost, including curtailment, in net periodic benefit cost | [3] | (2) | (2) | (9) |
Total other comprehensive loss (earnings) | (58) | (30) | (24) | |
Total recognized | (44) | (6) | 6 | |
Postretirement Benefits [Member] | ||||
Net periodic benefit cost: | ||||
Interest cost | 1 | |||
Recognition of net actuarial loss (gain) | [1] | (1) | (1) | (1) |
Recognition of prior service cost | [1] | (1) | (1) | (1) |
Total net periodic benefit cost | [2] | (2) | (2) | (1) |
Other comprehensive loss (earnings): | ||||
Actuarial loss (gain) arising in current year | (1) | (1) | ||
Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost | [3] | 1 | 1 | 1 |
Recognition of prior service cost, including curtailment, in net periodic benefit cost | [3] | 1 | 1 | 1 |
Total other comprehensive loss (earnings) | 1 | 1 | 2 | |
Total recognized | $ (1) | $ (1) | $ 1 | |
[1] | These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. | |||
[2] | The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings. | |||
[3] | (3) These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6 |
Retirement Plans (Schedule Of A
Retirement Plans (Schedule Of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost) (Details) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Benefits [Member] | |||
Assumptions to determine benefit obligations: | |||
Discount rate | 4.21% | 3.59% | 4.07% |
Rate of compensation increase | 2.50% | 2.50% | 4.49% |
Assumptions to determine net periodic benefit cost: | |||
Discount rate - service cost | 3.98% | 4.29% | 4.39% |
Discount rate - interest cost | 3.22% | 2.99% | 4.39% |
Rate of compensation increase | 2.50% | 4.48% | 4.49% |
Expected return on plan assets | 5.67% | 5.69% | 5.20% |
Postretirement Benefits [Member] | |||
Assumptions to determine benefit obligations: | |||
Discount rate | 4.01% | 3.25% | 3.46% |
Assumptions to determine net periodic benefit cost: | |||
Discount rate - service cost | 4.13% | 4.22% | 3.63% |
Discount rate - interest cost | 2.67% | 2.39% | 3.63% |
Stockholders' Equity (Narrative
Stockholders' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||||
Feb. 29, 2016 | Jan. 31, 2016 | Jun. 30, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2016 | Feb. 28, 2019 | |
Stockholders Equity [Abstract] | ||||||||||||||||||
Common stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 | 1,000,000,000 | |||||||||||||||
Common stock, par value (in dollars per share) | $ 0.10 | $ 0.10 | $ 0.10 | |||||||||||||||
Preferred Stock, Shares Authorized | 4,500,000 | 4,500,000 | ||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ 1 | $ 1 | ||||||||||||||||
Net proceeds from offering | $ 1,469 | |||||||||||||||||
Shares repurchased, value | $ 1,712 | $ 2,978 | ||||||||||||||||
Percentage of increase to quarterly dividend | 33.00% | |||||||||||||||||
Common stock dividends, rate per share | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.24 | ||||||
Subsequent Event [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Percentage of additional increase in quarterly dividend | 12.50% | |||||||||||||||||
Common stock dividends, rate per share, declared | $ 0.09 | |||||||||||||||||
Share Repurchase Program [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Share-repurchase program, additional authorized amount | $ 3,000 | |||||||||||||||||
Share-repurchase program expiration date | Dec. 31, 2019 | |||||||||||||||||
Share Repurchase Program [Member] | Subsequent Event [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Share-repurchase program, additional authorized amount | $ 1,000 | |||||||||||||||||
Share Repurchase Program [Member] | Maximum [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Share-repurchase program, authorized amount | $ 4,000 | $ 1,000 | ||||||||||||||||
Share Repurchase Program [Member] | Maximum [Member] | Subsequent Event [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Share-repurchase program, authorized amount | $ 5,000 | |||||||||||||||||
ASR Transaction [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Shares repurchased, value | $ 1,000 | |||||||||||||||||
Common Stock [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Common stock, shares issued | 103,000,000 | |||||||||||||||||
Common Stock Offering [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Common stock, shares issued | 79,000,000 | |||||||||||||||||
Net proceeds from offering | $ 1,500 | |||||||||||||||||
Common Stock Offering [Member] | Underwriters [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Common stock, shares issued | 10,000,000 | |||||||||||||||||
Equity Issued in Business Combination [Member] | Common Stock [Member] | STACK [Member] | ||||||||||||||||||
Stockholders Equity [Abstract] | ||||||||||||||||||
Equity issued for acquisition | 23,000,000 |
Stockholders' Equity (Summary o
Stockholders' Equity (Summary of Purchases of Common Stock) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2018 | |
Stockholders Equity [Line Items] | |||||
Total Number of Shares Purchased | 40,822 | 78,149 | |||
Dollar Value of Shares Purchased | $ 1,712 | $ 2,978 | |||
Average Price Paid per Share | $ 41.92 | $ 38.11 | |||
Open-Market [Member] | |||||
Stockholders Equity [Line Items] | |||||
Total Number of Shares Purchased | 23,612 | 16,492 | 11,154 | 2,561 | |
Dollar Value of Shares Purchased | $ 745 | $ 712 | $ 439 | $ 82 | |
Average Price Paid per Share | $ 31.57 | $ 43.13 | $ 39.35 | $ 32.19 | |
ASR [Member] | |||||
Stockholders Equity [Line Items] | |||||
Total Number of Shares Purchased | 24,330 | ||||
Dollar Value of Shares Purchased | $ 1,000 | ||||
Average Price Paid per Share | $ 41.10 |
Stockholders' Equity (Summary_2
Stockholders' Equity (Summary Of Dividends Paid On Common Stock) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Stockholders Equity Note [Abstract] | |||||||||||||||
Common stock dividends paid, Amount | $ 37 | $ 38 | $ 42 | $ 32 | $ 32 | $ 30 | $ 33 | $ 32 | $ 31 | $ 32 | $ 33 | $ 125 | $ 149 | $ 127 | $ 221 |
Common stock dividends, rate per share | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.06 | $ 0.24 |
Discontinued Operations and A_3
Discontinued Operations and Assets Held for Sale (Narrative) (Details) $ in Millions | 3 Months Ended | 5 Months Ended | 12 Months Ended | |
Sep. 30, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018USD ($)MMcf | Dec. 31, 2016USD ($) | |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||
Gain on sale of aggregate ownership interests, before-tax | $ 2,607 | $ (13) | ||
EnLink and General Partner [Member] | ||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of aggregate ownership interests | $ 3,125 | $ 3,125 | ||
Effective close date of divestiture | Jul. 18, 2018 | |||
Gain on sale of aggregate ownership interests, before-tax | 2,600 | $ 2,600 | ||
Gain on sale of aggregate ownership interests, after-tax | $ 2,200 | 2,200 | ||
Cash income taxes | $ 12 | |||
Net cash outflows | $ 380 | |||
EnLink and General Partner [Member] | Chisholm Gathering and Processing Contract [Member] | ||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||
Gathering and processing minimum volume commitments period end | early 2,021 | |||
EnLink and General Partner [Member] | Bridgeport and Cana Gathering and Processing Contracts [Member] | ||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||
Commitment Termination Date | Dec. 31, 2029 | |||
EnLink and General Partner [Member] | Minimum [Member] | Chisholm Gathering and Processing Contract [Member] | ||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||
Minimum gathering volume commitment | MMcf | 77 | |||
Minimum processing volume commitment | MMcf | 77 | |||
EnLink and General Partner [Member] | Maximum [Member] | Chisholm Gathering and Processing Contract [Member] | ||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||
Minimum gathering volume commitment | MMcf | 128 | |||
Minimum processing volume commitment | MMcf | 128 |
Discontinued Operations and A_4
Discontinued Operations and Assets Held for Sale (Amounts Reported as Discontinued Operations in the Consolidated Comprehensive Statements of Earnings) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Sep. 30, 2018 | [1] | Jun. 30, 2018 | [1] | Mar. 31, 2018 | [1] | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Discontinued Operations And Disposal Groups [Abstract] | ||||||||||||||
Marketing and midstream revenues | $ 3,567 | $ 5,071 | $ 3,551 | |||||||||||
Marketing and midstream expenses | 2,912 | 4,111 | 2,712 | |||||||||||
Depreciation, depletion and amortization | 244 | 545 | 504 | |||||||||||
General and administrative expenses | 65 | 128 | 118 | |||||||||||
Financing costs, net | 98 | 181 | 190 | |||||||||||
Asset impairments | 17 | 873 | ||||||||||||
Asset dispositions | (2,607) | 13 | ||||||||||||
Other expenses | (8) | (34) | 25 | |||||||||||
Total expenses | 704 | 4,948 | 4,435 | |||||||||||
Earnings (loss) from discontinued operations before income taxes | 2,863 | 123 | (884) | |||||||||||
Income tax expense (benefit) | 403 | (197) | ||||||||||||
Net earnings (loss) from discontinued operations, net of income tax expense | $ 2,263 | $ 139 | $ 58 | $ 260 | $ 18 | $ 33 | $ 9 | 2,460 | [1] | 320 | (884) | |||
Net earnings (loss) attributable to noncontrolling interests | 160 | 180 | (403) | |||||||||||
Net earnings (loss) from discontinued operations attributable to Devon | $ 2,300 | $ 140 | $ (481) | |||||||||||
[1] | (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19 |
Discontinued Operations and A_5
Discontinued Operations and Assets Held for Sale (Carrying Amounts of Assets and Liabilities Classified as Held for Sale on Consolidated Balance Sheets) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Disposal Group Including Discontinued Operation Balance Sheet Disclosures [Abstract] | |||
Cash and cash equivalents | $ 31 | $ 12 | |
Accounts receivable | $ 7 | 681 | |
Other current assets | 48 | ||
Oil and gas property and equipment, based on successful efforts accounting, net | 190 | ||
Midstream and other property and equipment, net | 6,587 | ||
Goodwill | 1,542 | ||
Other long-term assets | 1,600 | ||
Total assets held for sale | 197 | 10,489 | $ 10,200 |
Accounts payable | 3 | 186 | |
Revenues and royalties payable | 432 | ||
Other current liabilities | 19 | 373 | |
Long-term debt | 3,542 | ||
Deferred income taxes | 346 | ||
Asset retirement obligations | 47 | 14 | |
Other long-term liabilities | 34 | ||
Total liabilities held for sale | $ 69 | $ 4,927 |
Commitments And Contingencies_2
Commitments And Contingencies (Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)Defendant | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Loss Contingencies [Line Items] | |||
Obligation related to the purchase of condensate, year of expiration | 2,021 | ||
Total rental expense recognized, including certain office space and equipment under operating lease agreements, net of sub-lease income | $ | $ 11 | $ 7 | $ 11 |
Parishes in Louisiana [Member] | Minimum [Member] | |||
Loss Contingencies [Line Items] | |||
Number of defendants | Defendant | 100 |
Commitments And Contingencies_3
Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details) $ in Millions | Dec. 31, 2018USD ($) |
Purchase Obligations [Member] | |
Long Term Purchase Commitment [Line Items] | |
2,019 | $ 541 |
2,020 | 567 |
2,021 | 140 |
Total | 1,248 |
Drilling And Facility Obligations [Member] | |
Long Term Purchase Commitment [Line Items] | |
2,019 | 274 |
2,020 | 85 |
2,021 | 48 |
2,022 | 14 |
2,023 | 8 |
Thereafter | 16 |
Total | 445 |
Operational Agreements [Member] | |
Long Term Purchase Commitment [Line Items] | |
2,019 | 587 |
2,020 | 519 |
2,021 | 373 |
2,022 | 419 |
2,023 | 354 |
Thereafter | 3,374 |
Total | 5,626 |
Office And Equipment Leases [Member] | |
Long Term Purchase Commitment [Line Items] | |
2,019 | 64 |
2,020 | 43 |
2,021 | 31 |
2,022 | 26 |
2,023 | 25 |
Thereafter | 311 |
Total | $ 500 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, assets | $ 677 | $ 206 |
Derivatives, liabilities | (68) | (350) |
Carrying Amount [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash equivalents | 1,505 | 1,533 |
Debt | (5,947) | (6,864) |
Carrying Amount [Member] | Commodity Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, assets | 677 | 205 |
Derivatives, liabilities | (68) | (286) |
Carrying Amount [Member] | Interest Rate Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, assets | 1 | |
Derivatives, liabilities | (64) | |
Total Fair Value [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash equivalents | 1,505 | 1,533 |
Debt | (5,965) | (8,131) |
Total Fair Value [Member] | Commodity Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, assets | 677 | 205 |
Derivatives, liabilities | (68) | (286) |
Total Fair Value [Member] | Interest Rate Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, assets | 1 | |
Derivatives, liabilities | (64) | |
Level 1 Inputs [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash equivalents | 1,405 | 1,454 |
Level 2 Inputs [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash equivalents | 100 | 79 |
Debt | (5,965) | (8,131) |
Level 2 Inputs [Member] | Commodity Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, assets | 677 | 205 |
Derivatives, liabilities | $ (68) | (286) |
Level 2 Inputs [Member] | Interest Rate Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, assets | 1 | |
Derivatives, liabilities | $ (64) |
Segment Information (Condensed
Segment Information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Details) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($)segment | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||
Total impacted revenues | $ 3,708 | $ 2,579 | $ 2,249 | $ 2,198 | $ 2,380 | $ 1,933 | $ 2,165 | $ 2,400 | $ 10,734 | [1] | $ 8,878 | $ 6,753 | ||||||||||
Depreciation, depletion and amortization | 1,658 | 1,529 | 1,592 | |||||||||||||||||||
Interest expense | 635 | 336 | 724 | |||||||||||||||||||
Asset impairments | 150 | 156 | 437 | |||||||||||||||||||
Asset dispositions | (268) | [2] | (6) | [2] | 23 | [2] | (12) | [2] | (17) | [2] | (170) | [2] | (22) | [2] | (8) | [2] | (263) | [2] | (217) | [2] | (1,496) | |
Restructuring and transaction costs | 114 | 261 | ||||||||||||||||||||
Earnings (loss) from continuing operations before income taxes | 1,484 | [3] | 162 | [3] | (481) | [3] | (245) | [3] | 46 | 207 | 207 | 313 | 920 | [3] | 773 | (433) | ||||||
Income tax expense (benefit) | 156 | 15 | 141 | |||||||||||||||||||
Net earnings (loss) from continuing operations | 1,149 | $ 300 | $ (474) | $ (211) | 44 | $ 194 | $ 212 | $ 308 | 764 | 758 | (574) | |||||||||||
Property and equipment, net | 13,935 | 14,584 | 13,935 | 14,584 | 14,276 | |||||||||||||||||
Total assets | 19,566 | 30,241 | 19,566 | 30,241 | ||||||||||||||||||
Capital expenditures, including acquisitions | 2,576 | 2,169 | 2,826 | |||||||||||||||||||
Continuing Operations [Member] | ||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||
Total assets | 19,369 | [4] | 19,752 | [5] | $ 19,369 | [4] | 19,752 | [5] | 18,461 | [5] | ||||||||||||
United States [Member] | ||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||
Number of reportable segments | segment | 1 | |||||||||||||||||||||
United States [Member] | Operating Segments [Member] | ||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||
Total impacted revenues | $ 9,674 | [1] | 7,326 | 5,722 | ||||||||||||||||||
Depreciation, depletion and amortization | 1,328 | 1,149 | 1,178 | |||||||||||||||||||
Interest expense | 469 | 324 | 624 | |||||||||||||||||||
Asset impairments | 156 | 435 | ||||||||||||||||||||
Asset dispositions | (263) | (218) | (955) | |||||||||||||||||||
Restructuring and transaction costs | 97 | 242 | ||||||||||||||||||||
Earnings (loss) from continuing operations before income taxes | 1,294 | 443 | (757) | |||||||||||||||||||
Income tax expense (benefit) | 294 | 9 | (8) | |||||||||||||||||||
Net earnings (loss) from continuing operations | 1,000 | 434 | (749) | |||||||||||||||||||
Property and equipment, net | 10,026 | 10,274 | 10,026 | 10,274 | 10,166 | |||||||||||||||||
Capital expenditures, including acquisitions | 2,294 | 1,821 | 2,640 | |||||||||||||||||||
United States [Member] | Operating Segments [Member] | Continuing Operations [Member] | ||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||
Total assets | 14,853 | [4] | 14,254 | [5] | 14,853 | [4] | 14,254 | [5] | 13,390 | [5] | ||||||||||||
Canada [Member] | Operating Segments [Member] | ||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||
Total impacted revenues | 1,060 | [1] | 1,552 | 1,031 | ||||||||||||||||||
Depreciation, depletion and amortization | 330 | 380 | 414 | |||||||||||||||||||
Interest expense | 166 | 12 | 100 | |||||||||||||||||||
Asset impairments | 2 | |||||||||||||||||||||
Asset dispositions | 1 | (541) | ||||||||||||||||||||
Restructuring and transaction costs | 17 | 19 | ||||||||||||||||||||
Earnings (loss) from continuing operations before income taxes | (374) | 330 | 324 | |||||||||||||||||||
Income tax expense (benefit) | (138) | 6 | 149 | |||||||||||||||||||
Net earnings (loss) from continuing operations | (236) | 324 | 175 | |||||||||||||||||||
Property and equipment, net | 3,909 | 4,310 | 3,909 | 4,310 | 4,110 | |||||||||||||||||
Capital expenditures, including acquisitions | 282 | 348 | 186 | |||||||||||||||||||
Canada [Member] | Operating Segments [Member] | Continuing Operations [Member] | ||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||
Total assets | $ 4,516 | [4] | $ 5,498 | [5] | $ 4,516 | [4] | $ 5,498 | [5] | $ 5,071 | [5] | ||||||||||||
[1] | Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. | |||||||||||||||||||||
[2] | (1) Additional discussion regarding asset dispositions can be found in Note 2. | |||||||||||||||||||||
[3] | (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 | |||||||||||||||||||||
[4] | Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million. | |||||||||||||||||||||
[5] | Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively. |
Segment Information (Condense_2
Segment Information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Parenthetical) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Segment Reporting [Abstract] | |||
Total assets related to discontinued operations | $ 197 | $ 10,489 | $ 10,200 |
Segment Information (Schedule o
Segment Information (Schedule of Revenue from Contracts with Customers Disaggregated Based on Type of Good) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | $ 4,449 | $ 3,571 | $ 2,772 | |||||||||
Oil, gas and NGL derivatives | 608 | 157 | (201) | |||||||||
Upstream revenues | 6,285 | 5,307 | 3,981 | |||||||||
Total revenues | $ 3,708 | $ 2,579 | $ 2,249 | $ 2,198 | $ 2,380 | $ 1,933 | $ 2,165 | $ 2,400 | 10,734 | [1] | 8,878 | 6,753 |
Operating Segments [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Oil, gas and NGL derivatives | 457 | |||||||||||
Upstream revenues | 5,320 | |||||||||||
Total revenues | 9,674 | [1] | 7,326 | 5,722 | ||||||||
Operating Segments [Member] | Canada [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Oil, gas and NGL derivatives | 151 | |||||||||||
Upstream revenues | 965 | |||||||||||
Total revenues | 1,060 | [1] | $ 1,552 | $ 1,031 | ||||||||
Oil, Gas and NGL Sales [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 5,677 | |||||||||||
Oil, Gas and NGL Sales [Member] | Oil [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 3,771 | |||||||||||
Oil, Gas and NGL Sales [Member] | Gas [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 950 | |||||||||||
Oil, Gas and NGL Sales [Member] | NGL [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 956 | |||||||||||
Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 4,863 | |||||||||||
Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Canada [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 814 | |||||||||||
Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Oil [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 2,957 | |||||||||||
Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Oil [Member] | Canada [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 814 | |||||||||||
Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | Gas [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 950 | |||||||||||
Oil, Gas and NGL Sales [Member] | Operating Segments [Member] | NGL [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 956 | |||||||||||
Marketing Revenues [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 4,449 | |||||||||||
Marketing Revenues [Member] | Oil [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 2,840 | |||||||||||
Marketing Revenues [Member] | Gas [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 738 | |||||||||||
Marketing Revenues [Member] | NGL [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 871 | |||||||||||
Marketing Revenues [Member] | Operating Segments [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 4,354 | |||||||||||
Marketing Revenues [Member] | Operating Segments [Member] | Canada [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 95 | |||||||||||
Marketing Revenues [Member] | Operating Segments [Member] | Oil [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 2,745 | |||||||||||
Marketing Revenues [Member] | Operating Segments [Member] | Oil [Member] | Canada [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 95 | |||||||||||
Marketing Revenues [Member] | Operating Segments [Member] | Gas [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | 738 | |||||||||||
Marketing Revenues [Member] | Operating Segments [Member] | NGL [Member] | U.S. [Member] | ||||||||||||
Disaggregation Of Revenue [Line Items] | ||||||||||||
Total revenues from contracts with customers | $ 871 | |||||||||||
[1] | Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. |
Supplemental Information On O_3
Supplemental Information On Oil And Gas Operations (Costs Incurred) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property acquisition costs: | |||
Proved properties | $ 2 | $ 2 | $ 237 |
Unproved properties | 71 | 54 | 1,358 |
Exploration costs | 764 | 677 | 360 |
Development costs | 1,786 | 1,261 | 929 |
Costs incurred | 2,623 | 1,994 | 2,884 |
United States [Member] | |||
Property acquisition costs: | |||
Proved properties | 2 | 2 | 237 |
Unproved properties | 71 | 50 | 1,356 |
Exploration costs | 679 | 590 | 282 |
Development costs | 1,537 | 1,036 | 875 |
Costs incurred | 2,289 | 1,678 | 2,750 |
Canada [Member] | |||
Property acquisition costs: | |||
Unproved properties | 4 | 2 | |
Exploration costs | 85 | 87 | 78 |
Development costs | 249 | 225 | 54 |
Costs incurred | $ 334 | $ 316 | $ 134 |
Supplemental Information On O_4
Supplemental Information On Oil And Gas Operations (Narrative) (Details) $ in Millions | 12 Months Ended | |||||||
Dec. 31, 2018USD ($)MBbls / dMMBoe$ / bbl$ / Mcf | Dec. 31, 2017USD ($)MMBoe | Dec. 31, 2016USD ($)MMBoe | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2015MMBoe | ||
Reserve Quantities [Line Items] | ||||||||
Capitalized interest costs | $ | $ 41 | $ 69 | $ 61 | |||||
Proved undeveloped reserves increased in percentage | 9.00% | |||||||
Proved undeveloped reserves as a percentage of total proved reserves | 23.00% | |||||||
Proved undeveloped reserves due to drilling and development activities (MMBoe) | 113 | |||||||
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe) | 52 | |||||||
Proved undeveloped reserves to proved developed reserves, conversion, percentage | 26.00% | |||||||
Cost incurred related to development and conversion of proved undeveloped reserves | $ | $ 691 | |||||||
Proved undeveloped reserves | [1] | 445 | 410 | 409 | 376 | |||
Proved developed and undeveloped reserves, revisions due to prices | [1] | 51 | 73 | (27) | ||||
Proved developed and undeveloped reserves, extensions and discoveries | [1] | 243 | 237 | 126 | ||||
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe) | 21 | 66 | 74 | |||||
Average estimated future realized price per barrel of oil used to estimate future cash inflows for proved oil reserves | $ / bbl | 58.64 | |||||||
Average estimated future realized price per barrel of bitumen used to estimate future cash inflows for proved bitumen reserves | $ / bbl | 22.12 | |||||||
Average estimated future realized price per Mcf of gas used to estimate future cash inflows for proved gas reserves | $ / Mcf | 2.45 | |||||||
Average estimated future realized price per barrel of natural gas liquids used to estimate future cash inflows for proved NGL reserves | $ / bbl | 24.72 | |||||||
Future development costs | $ | $ 5,002 | $ 5,169 | $ 4,985 | |||||
Future dismantlement, abandonment and rehabilitation costs | $ | $ 1,400 | |||||||
Scenario, Forecast [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Future development costs | $ | $ 300 | $ 600 | $ 1,200 | |||||
Jackfish [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved undeveloped reserves | 206 | 209 | ||||||
Daily barrel facility capacity (MBbls/d) | MBbls / d | 35 | |||||||
Year development schedule will be complete | Dec. 31, 2032 | |||||||
Proved undeveloped reserves, remaining undeveloped 5 years or more after initial booking (energy) | 125 | |||||||
Proved undeveloped reserves, requiring excess of five years to develop | 81 | |||||||
US [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved undeveloped reserves due to drilling and development activities (MMBoe) | 107 | |||||||
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe) | 52 | |||||||
Proved undeveloped reserves | [1] | 239 | 201 | 115 | 75 | |||
Proved developed and undeveloped reserves, revisions due to prices | [1] | 40 | 111 | (48) | ||||
Proved developed and undeveloped reserves, extensions and discoveries | [1] | 232 | 221 | 124 | ||||
Future development costs | $ | $ 3,444 | $ 3,316 | $ 2,784 | |||||
Canada [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved undeveloped reserves due to drilling and development activities (MMBoe) | 6 | |||||||
Proved undeveloped reserves | [1] | 206 | 209 | 294 | 301 | |||
Proved developed and undeveloped reserves, revisions due to prices | [1] | 11 | (38) | 21 | ||||
Proved developed and undeveloped reserves, extensions and discoveries | [1] | 11 | 16 | 2 | ||||
Future development costs | $ | $ 1,558 | $ 1,853 | $ 2,201 | |||||
STACK and Delaware Basin [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Percentage of additions to proved developed and undeveloped reserves for extensions and discoveries | 72.00% | 80.00% | ||||||
Delaware Basin [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved developed and undeveloped reserves, extensions and discoveries | 88 | 79 | 18 | |||||
STACK [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved developed and undeveloped reserves, extensions and discoveries | 87 | 120 | 97 | |||||
Eagle Ford [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved developed and undeveloped reserves, extensions and discoveries | 7 | |||||||
Oil and Gas Properties [Member] | ||||||||
Reserve Quantities [Line Items] | ||||||||
Capitalized interest costs | $ | $ 41 | $ 69 | $ 61 | |||||
[1] | Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. |
Supplemental Information On O_5
Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)$ / Boe | Dec. 31, 2017USD ($)$ / Boe | Dec. 31, 2016USD ($)$ / Boe | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil, gas and NGL sales | $ 5,677 | $ 5,150 | $ 4,182 |
Production expenses | (2,225) | (1,823) | (1,805) |
Exploration expenses | (177) | (380) | (215) |
Depreciation, depletion and amortization | (1,559) | (1,419) | (1,446) |
Asset dispositions | 262 | 212 | 947 |
Asset impairments | (109) | (435) | |
Accretion of asset retirement obligations | (59) | (62) | (75) |
Income tax (expense) benefit | (409) | (104) | (13) |
Results of operations | $ 1,401 | $ 1,574 | $ 1,140 |
Depreciation, depletion and amortization per Boe | $ / Boe | 7.98 | 7.15 | 6.47 |
US [Member] | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil, gas and NGL sales | $ 4,863 | $ 3,746 | $ 3,198 |
Production expenses | (1,620) | (1,232) | (1,313) |
Exploration expenses | (129) | (346) | (176) |
Depreciation, depletion and amortization | (1,234) | (1,050) | (1,066) |
Asset dispositions | 262 | 211 | 946 |
Asset impairments | (109) | (435) | |
Accretion of asset retirement obligations | (35) | (38) | (49) |
Income tax (expense) benefit | (460) | ||
Results of operations | $ 1,538 | $ 1,291 | $ 1,105 |
Depreciation, depletion and amortization per Boe | $ / Boe | 8.08 | 6.97 | 6.11 |
Canada [Member] | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil, gas and NGL sales | $ 814 | $ 1,404 | $ 984 |
Production expenses | (605) | (591) | (492) |
Exploration expenses | (48) | (34) | (39) |
Depreciation, depletion and amortization | (325) | (369) | (380) |
Asset dispositions | 1 | 1 | |
Accretion of asset retirement obligations | (24) | (24) | (26) |
Income tax (expense) benefit | 51 | (104) | (13) |
Results of operations | $ (137) | $ 283 | $ 35 |
Depreciation, depletion and amortization per Boe | $ / Boe | 7.63 | 7.73 | 7.75 |
Supplemental Information On O_6
Supplemental Information On Oil And Gas Operations (Proved Developed and Undeveloped Reserves) (Details) MBbls in Thousands, Mcf in Millions | 12 Months Ended | ||||
Dec. 31, 2018MMBoeMBblsMcf | Dec. 31, 2017MMBoeMBblsMcf | Dec. 31, 2016MMBoeMBblsMcf | Dec. 31, 2015MMBoeMBblsMcf | ||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | MMBoe | [1] | 2,152 | 2,058 | 2,182 | |
Proved developed and undeveloped reserves, revisions due to prices | MMBoe | [1] | 51 | 73 | (27) | |
Proved developed and undeveloped reserves, revisions other than price | MMBoe | [1] | (57) | (12) | 137 | |
Proved developed and undeveloped reserves, extensions and discoveries | MMBoe | [1] | 243 | 237 | 126 | |
Proved developed and undeveloped reserves, purchase of reserves | MMBoe | [1] | 20 | |||
Proved developed and undeveloped reserves, production | MMBoe | [1] | (195) | (198) | (223) | |
Proved developed and undeveloped reserves, sale of reserves | MMBoe | [1] | (267) | (6) | (157) | |
Proved developed and undeveloped reserves, ending balance | MMBoe | [1] | 1,927 | 2,152 | 2,058 | |
Proved developed reserves | MMBoe | [1] | 1,482 | 1,742 | 1,649 | 1,806 |
Proved developed producing reserves | MMBoe | [1] | 1,448 | 1,693 | 1,593 | 1,749 |
Proved undeveloped reserves | MMBoe | [1] | 445 | 410 | 409 | 376 |
Conversion rate of gas reserves from barrels of oil to Boe | 6 | ||||
United States [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | MMBoe | [1] | 1,725 | 1,554 | 1,638 | |
Proved developed and undeveloped reserves, revisions due to prices | MMBoe | [1] | 40 | 111 | (48) | |
Proved developed and undeveloped reserves, revisions other than price | MMBoe | [1] | (60) | (5) | 151 | |
Proved developed and undeveloped reserves, extensions and discoveries | MMBoe | [1] | 232 | 221 | 124 | |
Proved developed and undeveloped reserves, purchase of reserves | MMBoe | [1] | 20 | |||
Proved developed and undeveloped reserves, production | MMBoe | [1] | (153) | (150) | (174) | |
Proved developed and undeveloped reserves, sale of reserves | MMBoe | [1] | (267) | (6) | (157) | |
Proved developed and undeveloped reserves, ending balance | MMBoe | [1] | 1,517 | 1,725 | 1,554 | |
Proved developed reserves | MMBoe | [1] | 1,278 | 1,524 | 1,439 | 1,563 |
Proved developed producing reserves | MMBoe | [1] | 1,249 | 1,481 | 1,386 | 1,509 |
Proved undeveloped reserves | MMBoe | [1] | 239 | 201 | 115 | 75 |
Canada [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | MMBoe | [1] | 427 | 504 | 544 | |
Proved developed and undeveloped reserves, revisions due to prices | MMBoe | [1] | 11 | (38) | 21 | |
Proved developed and undeveloped reserves, revisions other than price | MMBoe | [1] | 3 | (7) | (14) | |
Proved developed and undeveloped reserves, extensions and discoveries | MMBoe | [1] | 11 | 16 | 2 | |
Proved developed and undeveloped reserves, production | MMBoe | [1] | (42) | (48) | (49) | |
Proved developed and undeveloped reserves, ending balance | MMBoe | [1] | 410 | 427 | 504 | |
Proved developed reserves | MMBoe | [1] | 204 | 218 | 210 | 243 |
Proved developed producing reserves | MMBoe | [1] | 199 | 212 | 207 | 240 |
Proved undeveloped reserves | MMBoe | [1] | 206 | 209 | 294 | 301 |
Oil [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | 272 | 211 | 264 | ||
Proved developed and undeveloped reserves, revisions due to prices | 13 | 11 | (20) | ||
Proved developed and undeveloped reserves, revisions other than price | (8) | 8 | 1 | ||
Proved developed and undeveloped reserves, extensions and discoveries | 98 | 94 | 38 | ||
Proved developed and undeveloped reserves, purchase of reserves | 8 | ||||
Proved developed and undeveloped reserves, production | (54) | (49) | (55) | ||
Proved developed and undeveloped reserves, sale of reserves | (7) | (3) | (25) | ||
Proved developed and undeveloped reserves, ending balance | 314 | 272 | 211 | ||
Proved developed reserves | 214 | 193 | 177 | 225 | |
Proved developed producing reserves | 201 | 177 | 156 | 211 | |
Proved undeveloped reserves | 100 | 79 | 34 | 39 | |
Oil [Member] | United States [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | 257 | 194 | 242 | ||
Proved developed and undeveloped reserves, revisions due to prices | 12 | 12 | (18) | ||
Proved developed and undeveloped reserves, revisions other than price | (10) | 6 | (2) | ||
Proved developed and undeveloped reserves, extensions and discoveries | 93 | 90 | 36 | ||
Proved developed and undeveloped reserves, purchase of reserves | 8 | ||||
Proved developed and undeveloped reserves, production | (47) | (42) | (47) | ||
Proved developed and undeveloped reserves, sale of reserves | (7) | (3) | (25) | ||
Proved developed and undeveloped reserves, ending balance | 298 | 257 | 194 | ||
Proved developed reserves | 198 | 178 | 160 | 203 | |
Proved developed producing reserves | 189 | 165 | 143 | 192 | |
Proved undeveloped reserves | 100 | 79 | 34 | 39 | |
Oil [Member] | Canada [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | 15 | 17 | 22 | ||
Proved developed and undeveloped reserves, revisions due to prices | 1 | (1) | (2) | ||
Proved developed and undeveloped reserves, revisions other than price | 2 | 2 | 3 | ||
Proved developed and undeveloped reserves, extensions and discoveries | 5 | 4 | 2 | ||
Proved developed and undeveloped reserves, production | (7) | (7) | (8) | ||
Proved developed and undeveloped reserves, ending balance | 16 | 15 | 17 | ||
Proved developed reserves | 16 | 15 | 17 | 22 | |
Proved developed producing reserves | 12 | 12 | 13 | 19 | |
Bitumen [Member] | Canada [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | 409 | 484 | 520 | ||
Proved developed and undeveloped reserves, revisions due to prices | 10 | (37) | 23 | ||
Proved developed and undeveloped reserves, revisions other than price | 2 | (10) | (19) | ||
Proved developed and undeveloped reserves, extensions and discoveries | 7 | 12 | |||
Proved developed and undeveloped reserves, production | (35) | (40) | (40) | ||
Proved developed and undeveloped reserves, ending balance | 393 | 409 | 484 | ||
Proved developed reserves | 187 | 200 | 190 | 219 | |
Proved developed producing reserves | 187 | 197 | 190 | 219 | |
Proved undeveloped reserves | 206 | 209 | 294 | 301 | |
Natural Gas [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | Mcf | 5,987 | 5,631 | 5,821 | ||
Proved developed and undeveloped reserves, revisions due to prices | Mcf | 91 | 399 | (103) | ||
Proved developed and undeveloped reserves, revisions other than price | Mcf | (167) | 2 | 638 | ||
Proved developed and undeveloped reserves, extensions and discoveries | Mcf | 446 | 403 | 280 | ||
Proved developed and undeveloped reserves, purchase of reserves | Mcf | 33 | ||||
Proved developed and undeveloped reserves, production | Mcf | (401) | (439) | (517) | ||
Proved developed and undeveloped reserves, sale of reserves | Mcf | (1,195) | (9) | (521) | ||
Proved developed and undeveloped reserves, ending balance | Mcf | 4,761 | 5,987 | 5,631 | ||
Proved developed reserves | Mcf | 4,333 | 5,632 | 5,377 | 5,707 | |
Proved developed producing reserves | Mcf | 4,263 | 5,525 | 5,259 | 5,559 | |
Proved undeveloped reserves | Mcf | 428 | 355 | 254 | 114 | |
Natural Gas [Member] | United States [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | Mcf | 5,974 | 5,615 | 5,808 | ||
Proved developed and undeveloped reserves, revisions due to prices | Mcf | 94 | 398 | (103) | ||
Proved developed and undeveloped reserves, revisions other than price | Mcf | (163) | 628 | |||
Proved developed and undeveloped reserves, extensions and discoveries | Mcf | 446 | 403 | 280 | ||
Proved developed and undeveloped reserves, purchase of reserves | Mcf | 33 | ||||
Proved developed and undeveloped reserves, production | Mcf | (397) | (433) | (510) | ||
Proved developed and undeveloped reserves, sale of reserves | Mcf | (1,195) | (9) | (521) | ||
Proved developed and undeveloped reserves, ending balance | Mcf | 4,759 | 5,974 | 5,615 | ||
Proved developed reserves | Mcf | 4,331 | 5,619 | 5,361 | 5,694 | |
Proved developed producing reserves | Mcf | 4,261 | 5,512 | 5,243 | 5,546 | |
Proved undeveloped reserves | Mcf | 428 | 355 | 254 | 114 | |
Natural Gas [Member] | Canada [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | Mcf | 13 | 16 | 13 | ||
Proved developed and undeveloped reserves, revisions due to prices | Mcf | (3) | 1 | |||
Proved developed and undeveloped reserves, revisions other than price | Mcf | (4) | 2 | 10 | ||
Proved developed and undeveloped reserves, production | Mcf | (4) | (6) | (7) | ||
Proved developed and undeveloped reserves, ending balance | Mcf | 2 | 13 | 16 | ||
Proved developed reserves | Mcf | 2 | 13 | 16 | 13 | |
Proved developed producing reserves | Mcf | 2 | 13 | 16 | 13 | |
Natural Gas Liquids [Member] | United States [Member] | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves, beginning balance | 473 | 425 | 428 | ||
Proved developed and undeveloped reserves, revisions due to prices | 12 | 32 | (13) | ||
Proved developed and undeveloped reserves, revisions other than price | (23) | (10) | 48 | ||
Proved developed and undeveloped reserves, extensions and discoveries | 64 | 63 | 42 | ||
Proved developed and undeveloped reserves, purchase of reserves | 7 | ||||
Proved developed and undeveloped reserves, production | (39) | (36) | (42) | ||
Proved developed and undeveloped reserves, sale of reserves | (61) | (1) | (45) | ||
Proved developed and undeveloped reserves, ending balance | 426 | 473 | 425 | ||
Proved developed reserves | 359 | 410 | 387 | 411 | |
Proved developed producing reserves | 349 | 397 | 370 | 393 | |
Proved undeveloped reserves | 67 | 63 | 38 | 17 | |
[1] | Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. |
Supplemental Information On O_7
Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details) | 12 Months Ended | |
Dec. 31, 2018MMBoe | ||
Reserve Quantities [Line Items] | ||
Proved undeveloped reserves (MMBoe) beginning balance | 410 | [1] |
Proved undeveloped reserves, extensions and discoveries | 113 | |
Proved undeveloped reserves, revisions due to prices | 7 | |
Proved undeveloped reserves, revisions other than price | (23) | |
Proved undeveloped reserves, sale of reserves | (10) | |
Proved undeveloped reserves, conversion to proved developed reserves | (52) | |
Proved undeveloped reserves (MMBoe) ending balance | 445 | [1] |
United States [Member] | ||
Reserve Quantities [Line Items] | ||
Proved undeveloped reserves (MMBoe) beginning balance | 201 | [1] |
Proved undeveloped reserves, extensions and discoveries | 107 | |
Proved undeveloped reserves, revisions due to prices | 1 | |
Proved undeveloped reserves, revisions other than price | (8) | |
Proved undeveloped reserves, sale of reserves | (10) | |
Proved undeveloped reserves, conversion to proved developed reserves | (52) | |
Proved undeveloped reserves (MMBoe) ending balance | 239 | [1] |
Canada [Member] | ||
Reserve Quantities [Line Items] | ||
Proved undeveloped reserves (MMBoe) beginning balance | 209 | [1] |
Proved undeveloped reserves, extensions and discoveries | 6 | |
Proved undeveloped reserves, revisions due to prices | 6 | |
Proved undeveloped reserves, revisions other than price | (15) | |
Proved undeveloped reserves (MMBoe) ending balance | 206 | [1] |
[1] | Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. |
Supplemental Information On O_8
Supplemental Information On Oil And Gas Operations (Standardized Measure Of Discounted Future Net Cash Flows Related To Proved Reserves) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 49,329 | $ 48,303 | $ 32,519 | |
Future costs: | ||||
Development | (5,002) | (5,169) | (4,985) | |
Production | (23,552) | (21,512) | (17,983) | |
Future income tax expense | (2,969) | (988) | (121) | |
Future net cash flow | 17,806 | 20,634 | 9,430 | |
10% discount to reflect timing of cash flows | (7,614) | (9,297) | (3,990) | |
Standardized measure of discounted future net cash flows | 10,192 | 11,337 | 5,440 | $ 7,883 |
United States [Member] | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 40,183 | 34,701 | 22,847 | |
Future costs: | ||||
Development | (3,444) | (3,316) | (2,784) | |
Production | (18,107) | (15,526) | (11,934) | |
Future income tax expense | (2,969) | |||
Future net cash flow | 15,663 | 15,859 | 8,129 | |
10% discount to reflect timing of cash flows | (6,897) | (7,541) | (3,524) | |
Standardized measure of discounted future net cash flows | 8,766 | 8,318 | 4,605 | |
Canada [Member] | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 9,146 | 13,602 | 9,672 | |
Future costs: | ||||
Development | (1,558) | (1,853) | (2,201) | |
Production | (5,445) | (5,986) | (6,049) | |
Future income tax expense | (988) | (121) | ||
Future net cash flow | 2,143 | 4,775 | 1,301 | |
10% discount to reflect timing of cash flows | (717) | (1,756) | (466) | |
Standardized measure of discounted future net cash flows | $ 1,426 | $ 3,019 | $ 835 |
Supplemental Information On O_9
Supplemental Information On Oil And Gas Operations (Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Information On Oil And Gas Operations [Abstract] | |||
Standardized measure of discounted future net cash flows, beginning balance | $ 11,337 | $ 5,440 | $ 7,883 |
Net changes in prices and production costs | (243) | 5,218 | (2,027) |
Oil, bitumen, gas and NGL sales, net of production costs | (3,452) | (3,327) | (2,377) |
Changes in estimated future development costs | (216) | 789 | 112 |
Extensions and discoveries, net of future development costs | 3,139 | 2,497 | 674 |
Purchase of reserves | 2 | 224 | |
Sales of reserves in place | (588) | (3) | (577) |
Revisions of quantity estimates | (414) | (318) | (21) |
Previously estimated development costs incurred during the period | 962 | 559 | 663 |
Accretion of discount | 960 | 1,034 | 537 |
Foreign exchange and other | (329) | (7) | 72 |
Net change in income taxes | (964) | (547) | 277 |
Standardized measure of discounted future net cash flows, ending balance | $ 10,192 | $ 11,337 | $ 5,440 |
Supplemental Quarterly Financ_3
Supplemental Quarterly Financial Information (Schedule Of Unaudited Interim Results Of Operations) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||||||||
Quarterly Financial Data [Abstract] | |||||||||||||||||||||
Total revenues | $ 3,708 | $ 2,579 | $ 2,249 | $ 2,198 | $ 2,380 | $ 1,933 | $ 2,165 | $ 2,400 | $ 10,734 | [1] | $ 8,878 | $ 6,753 | |||||||||
Asset dispositions | (268) | [2] | (6) | [2] | 23 | [2] | (12) | [2] | (17) | [2] | (170) | [2] | (22) | [2] | (8) | [2] | (263) | [2] | (217) | [2] | (1,496) |
Earnings (loss) from continuing operations before income taxes | 1,484 | [3] | 162 | [3] | (481) | [3] | (245) | [3] | 46 | 207 | 207 | 313 | 920 | [3] | 773 | (433) | |||||
Net earnings (loss) from continuing operations | 1,149 | 300 | (474) | (211) | 44 | 194 | 212 | 308 | 764 | 758 | (574) | ||||||||||
Net earnings (loss) from discontinued operations, net of income tax expense | 2,263 | [4] | 139 | [4] | 58 | [4] | 260 | 18 | 33 | 9 | 2,460 | [4] | 320 | (884) | |||||||
Net earnings (loss) attributable to Devon | $ 1,149 | $ 2,537 | $ (425) | $ (197) | $ 183 | $ 193 | $ 219 | $ 303 | $ 3,064 | $ 898 | $ (1,056) | ||||||||||
Basic net earnings (loss) per share attributable to Devon | $ 2.50 | $ 5.17 | $ (0.83) | $ (0.38) | $ 0.35 | $ 0.37 | $ 0.41 | $ 0.58 | $ 6.14 | $ 1.71 | $ (2.09) | ||||||||||
Diluted net earnings (loss) per share attributable to Devon | $ 2.48 | $ 5.14 | $ (0.83) | $ (0.38) | $ 0.35 | $ 0.37 | $ 0.41 | $ 0.58 | $ 6.10 | $ 1.70 | $ (2.09) | ||||||||||
[1] | Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. | ||||||||||||||||||||
[2] | (1) Additional discussion regarding asset dispositions can be found in Note 2. | ||||||||||||||||||||
[3] | (2) Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5 | ||||||||||||||||||||
[4] | (3) Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19 |
Supplemental Quarterly Financ_4
Supplemental Quarterly Financial Information (Schedule Of Unaudited Interim Results Of Operations) (Parenthetical) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2016 | |
Quarterly Financial Data [Line Items] | ||||
Asset impairments | $ 150 | $ 156 | $ 437 | |
EnLink and General Partner [Member] | ||||
Quarterly Financial Data [Line Items] | ||||
Gain on sale of aggregate ownership interests, after-tax | $ 2,200 | $ 2,200 |