Former name, address and former fiscal year, if changed from last report: Not applicable

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

On April ~~17, 2019, 415.2~~22, 2020, 382.7 million shares of common stock were outstanding.

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” ~~“Devon”~~“Devon,” the “Company” and ~~the “Company”~~“Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within ~~this~~this Quarterly Report on Form 10-Q:

“ASR” means an accelerated share-repurchase transaction with a financial institution to repurchase Devon’s common stock.

“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. ~~Bitumen and~~ NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.

“Canada” means the division of Devon encompassing oil and gas properties located in Canada. On June 27, 2019, all of Devon’s Canadian operating assets and operations were divested. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.

“~~EnLink” means EnLink Midstream Partners, LP, a master limited partnership.~~

“General Partner” means EnLink Midstream, LLC, the indirect general partner of EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.

“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 5, 2018.

“~~Upstream operations” means upstream revenues minus production expenses.~~

This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited ~~to:~~to those, identified below.

The COVID-19 pandemic and its related repercussions have created significant volatility, uncertainty and turmoil in the global economy and our industry. This turmoil has included an unprecedented supply-and-demand imbalance for oil and other commodities, resulting in a swift and material decline in commodity prices in early 2020. Our future actual results could differ materially from the forward-looking statements in this report due to the COVID-19 pandemic and related impacts, including, among other things: contributing to a sustained or further deterioration in commodity prices; causing takeaway capacity constraints for production, resulting in production shut-ins and additional downward pressure on impacted regional pricing differentials; limiting our ability to access sources of capital due to disruptions in financial markets; increasing the risk of a downgrade from credit rating agencies; exacerbating counterparty credit risks and the risk of supply chain interruptions; and increasing the risk of operational disruptions due to social distancing measures and other changes to business practices.

In addition to the risks associated with the COVID-19 pandemic and its related impacts, our actual future results could differ materially from our expectations due to other factors, including, among other things:

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
	(Unaudited)						(Unaudited)
Upstream revenues	$	710		$	1,319		$	1,527		$	314
Marketing revenues		791			879
Marketing and midstream revenues								560			765
Total revenues		1,501			2,198			2,087			1,079
Production expenses		506			543			318			283
Exploration expenses		13			33			112			4
Marketing expenses		759			873
Marketing and midstream expenses								578			750
Depreciation, depletion and amortization		459			399			401			360
Asset impairments								2,666			—
Asset dispositions		(44	)		(12	)		—			(45	)
General and administrative expenses		153			199			102			135
Financing costs, net		73			387			65			60
Restructuring and transaction costs		54			—			—			51
Other expenses		(45	)		21			(48	)		(22	)
Total expenses		1,928			2,443			4,194			1,576
Loss from continuing operations before income taxes		(427	)		(245	)		(2,107	)		(497	)
Income tax benefit		(110	)		(34	)		(417	)		(119	)
Net loss from continuing operations		(317	)		(211	)		(1,690	)		(378	)
Net earnings from discontinued operations, net of income tax expense		—			58
Net earnings (loss) from discontinued operations, net of income taxes								(125	)		61
Net loss		(317	)		(153	)		(1,815	)		(317	)
Net earnings attributable to noncontrolling interests		—			44			1			—
Net loss attributable to Devon	$	(317	)	$	(197	)	$	(1,816	)	$	(317	)
Basic net loss per share:
Basic net earnings (loss) per share:
Basic loss from continuing operations per share	$	(0.74	)	$	(0.41	)	$	(4.48	)	$	(0.89	)
Basic earnings from discontinued operations per share		—			0.03
Basic earnings (loss) from discontinued operations per share								(0.34	)		0.15
Basic net loss per share	$	(0.74	)	$	(0.38	)	$	(4.82	)	$	(0.74	)
Diluted net loss per share:
Diluted net earnings (loss) per share:
Diluted loss from continuing operations per share	$	(0.74	)	$	(0.41	)	$	(4.48	)	$	(0.89	)
Diluted earnings from discontinued operations per share		—			0.03
Diluted earnings (loss) from discontinued operations per share								(0.34	)		0.15
Diluted net loss per share	$	(0.74	)	$	(0.38	)	$	(4.82	)	$	(0.74	)
Comprehensive earnings (loss):
Net loss							$	(1,815	)	$	(317	)
Other comprehensive earnings, net of tax:
Foreign currency translation, discontinued operations								—			35
Pension and postretirement plans								1			2
Other comprehensive earnings, net of tax								1			37
Comprehensive loss:								(1,814	)		(280	)
Net loss	$	(317	)	$	(153	)
Other comprehensive earnings (loss), net of tax:
Foreign currency translation		35			(48	)
Pension and postretirement plans		2			4
Other comprehensive earnings (loss), net of tax		37			(44	)
Comprehensive loss		(280	)		(197	)
Comprehensive earnings attributable to noncontrolling interests		—			44			1			—
Comprehensive loss attributable to Devon	$	(280	)	$	(241	)	$	(1,815	)	$	(280	)

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
	(Unaudited)						(Unaudited)
Cash flows from operating activities:
Net loss	$	(317	)	$	(153	)	$	(1,815	)	$	(317	)
Adjustments to reconcile net loss to net cash from operating activities:
Net earnings from discontinued operations, net of income tax expense		—			(58	)
Net (earnings) loss from discontinued operations, net of income taxes								125			(61	)
Depreciation, depletion and amortization		459			399			401			360
Asset impairments								2,666			—
Leasehold impairments		1			8			110			1
Accretion on discounted liabilities		17			16			8			9
Total losses on commodity derivatives		709			41
Total (gains) losses on commodity derivatives								(720	)		605
Cash settlements on commodity derivatives		(43	)		11			101			31
Gains on asset dispositions		(44	)		(12	)		—			(45	)
Deferred income tax benefit		(107	)		(38	)		(311	)		(115	)
Share-based compensation		48			38			20			44
Early retirement of debt		—			312
Total (gains) losses on foreign exchange		(34	)		50
Other		(10	)		(29	)		—			(14	)
Changes in assets and liabilities, net		(302	)		25			(56	)		(61	)
Net cash from operating activities - continuing operations		377			610			529			437
Cash flows from investing activities:
Capital expenditures		(548	)		(651	)		(425	)		(490	)
Acquisitions of property and equipment		(11	)		(6	)		(4	)		(10	)
Divestitures of property and equipment		311			47			25			310
Net cash from investing activities - continuing operations		(248	)		(610	)		(404	)		(190	)
Cash flows from financing activities:
Repayments of long-term debt principal		(162	)		(807	)
Early retirement of debt		—			(304	)
Repayments of long-term debt								—			(162	)
Repurchases of common stock		(999	)		(71	)		(38	)		(999	)
Dividends paid on common stock		(34	)		(32	)		(34	)		(34	)
Contributions from noncontrolling interests								5			—
Distributions to noncontrolling interests								(3	)		—
Shares exchanged for tax withholdings		(26	)		(38	)		(17	)		(19	)
Net cash from financing activities - continuing operations		(1,221	)		(1,252	)		(87	)		(1,214	)
Effect of exchange rate changes on cash - continuing operations		1			(15	)
Net change in cash, cash equivalents and restricted cash of continuing operations		(1,091	)		(1,267	)		38			(967	)
Cash flows from discontinued operations:
Operating activities		—			194			(131	)		(59	)
Investing activities		—			(180	)		(1	)		(59	)
Financing activities		—			39			—			(7	)
Effect of exchange rate changes on cash								(23	)		1
Net change in cash, cash equivalents and restricted cash of discontinued operations		—			53			(155	)		(124	)
Net change in cash, cash equivalents and restricted cash		(1,091	)		(1,214	)		(117	)		(1,091	)
Cash, cash equivalents and restricted cash at beginning of period		2,446			2,684			1,844			2,446
Cash, cash equivalents and restricted cash at end of period	$	1,355		$	1,470		$	1,727		$	1,355

Reconciliation of cash, cash equivalents and restricted cash:
Cash and cash equivalents	$	1,327		$	1,407		$	1,527		$	1,327
Cash restricted for discontinued operations								200			—
Restricted cash included in other current assets		28			46			—			28
Cash and cash equivalents included in current assets held for sale		—			17
Total cash, cash equivalents and restricted cash	$	1,355		$	1,470		$	1,727		$	1,355

	March 31, 2019			December 31, 2018			March 31, 2020			December 31, 2019
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,327		$	2,414		$	1,527		$	1,464
Cash restricted for discontinued operations								200			380
Accounts receivable		1,038			885			594			832
Current assets held for sale		—			197
Current assets associated with discontinued operations								736			896
Other current assets		338			941			998			279
Total current assets		2,703			4,437			4,055			3,851
Oil and gas property and equipment, based on successful efforts accounting, net		12,766			12,813			4,756			7,558
Other property and equipment, net		1,098			1,122
Other property and equipment, net ($89 and $80 million related to CDM in 2020 and 2019, respectively)								1,024			1,035
Total property and equipment, net		13,864			13,935			5,780			8,593
Goodwill		841			841			753			753
Right-of-use assets		365			—			237			243
Other long-term assets		304			353			245			196
Long-term assets associated with discontinued operations								74			81
Total assets	$	18,077		$	19,566		$	11,144		$	13,717
LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	603		$	662		$	444		$	428
Revenues and royalties payable		850			898			617			730
Short-term debt		—			162
Current liabilities held for sale		—			69
Current liabilities associated with discontinued operations								294			459
Other current liabilities		515			435			199			310
Total current liabilities		1,968			2,226			1,554			1,927
Long-term debt		5,786			5,785			4,295			4,294
Lease liabilities		298			—			245			244
Asset retirement obligations		938			1,030			386			380
Other long-term liabilities		458			462			461			426
Long-term liabilities associated with discontinued operations								163			185
Deferred income taxes		772			877			—			341
Stockholders' equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 417 million and 450 million shares in 2019 and 2018, respectively		42			45
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 383 million and 382 million shares in 2020 and 2019, respectively								38			38
Additional paid-in capital		3,518			4,486			2,701			2,735
Retained earnings		3,280			3,650			1,298			3,148
Accumulated other comprehensive earnings		1,064			1,027
Treasury stock, at cost, 1.5 million and 1.0 million shares in 2019 and 2018, respectively		(47	)		(22	)
Total stockholders’ equity		7,857			9,186
Total liabilities and stockholders' equity	$	18,077		$	19,566
Accumulated other comprehensive loss								(118	)		(119	)
Total stockholders’ equity attributable to Devon								3,919			5,802
Noncontrolling interests								121			118
Total equity								4,040			5,920
Total liabilities and equity							$	11,144		$	13,717

													Accumulated																					Retained			Other
							Additional						Other																		Additional			Earnings			Comprehensive
	Common Stock						Paid-In			Retained			Comprehensive			Treasury			Noncontrolling			Total			Common Stock						Paid-In			(Accumulated			Earnings			Treasury			Noncontrolling			Total
	Shares			Amount			Capital			Earnings			Earnings			Stock			Interests			Equity			Shares			Amount			Capital			Deficit)			(Loss)			Stock			Interests			Equity
	(Unaudited)																								(Unaudited)
Three Months Ended March 31, 2020
Balance as of December 31, 2019																										382		$	38		$	2,735		$	3,148		$	(119	)	$	—		$	118		$	5,920
Net earnings (loss)																										—			—			—			(1,816	)		—			—			1			(1,815	)
Other comprehensive earnings, net of tax																										—			—			—			—			1			—			—			1
Restricted stock grants, net of cancellations																										3			—			—			—			—			—			—			—
Common stock repurchased																										—			—			—			—			—			(54	)		—			(54	)
Common stock retired																										(3	)		—			(54	)		—			—			54			—			—
Common stock dividends																										—			—			—			(34	)		—			—			—			(34	)
Share-based compensation																										1			—			20			—			—			—			—			20
Contributions from noncontrolling interests																										—			—			—			—			—			—			5			5
Distributions to noncontrolling interests																										—			—			—			—			—			—			(3	)		(3	)
Balance as of March 31, 2020																										383		$	38		$	2,701		$	1,298		$	(118	)	$	—		$	121		$	4,040
Three Months Ended March 31, 2019
Balance as of December 31, 2018		450		$	45		$	4,486		$	3,650		$	1,027		$	(22	)	$	—		$	9,186			450		$	45		$	4,486		$	3,650		$	1,027		$	(22	)	$	—		$	9,186
Effect of adoption of lease accounting		—			—			—			(19	)		—			—			—			(19	)		—			—			—			(19	)		—			—			—			(19	)
Net loss		—			—			—			(317	)		—			—			—			(317	)		—			—			—			(317	)		—			—			—			(317	)
Other comprehensive earnings, net of tax		—			—			—			—			37			—			—			37			—			—			—			—			37			—			—			37
Restricted stock grants, net of cancellations		3			—			—			—			—			—			—			—			3			—			—			—			—			—			—			—
Common stock repurchased		—			—			—			—			—			(1,042	)		—			(1,042	)		—			—			—			—			—			(1,042	)		—			(1,042	)
Common stock retired		(36	)		(3	)		(1,014	)		—			—			1,017			—			—			(36	)		(3	)		(1,014	)		—			—			1,017			—			—
Common stock dividends		—			—			—			(34	)		—			—			—			(34	)		—			—			—			(34	)		—			—			—			(34	)
Share-based compensation		—			—			46			—			—			—			—			46			—			—			46			—			—			—			—			46
Balance as of March 31, 2019		417		$	42		$	3,518		$	3,280		$	1,064		$	(47	)	$	—		$	7,857			417		$	42		$	3,518		$	3,280		$	1,064		$	(47	)	$	—		$	7,857
Three Months Ended March 31, 2018
Balance as of December 31, 2017		525		$	53		$	7,333		$	702		$	1,166		$	—		$	4,850		$	14,104
Net earnings (loss)		—			—			—			(197	)		—			—			44			(153	)
Other comprehensive loss, net of tax		—			—			—			—			(44	)		—			—			(44	)
Restricted stock grants, net of cancellations		3			—			—			—			—			—			—			—
Common stock repurchased		—			—			—			—			—			(111	)		—			(111	)
Common stock retired		(3	)		—			(99	)		—			—			99			—			—
Common stock dividends		—			—			—			(32	)		—			—			—			(32	)
Share-based compensation		1			—			36			—			—			—			—			36
Subsidiary equity transactions		—			—			(1	)		—			—			—			28			27
Distributions to noncontrolling interests		—			—			—			—			—			—			(102	)		(102	)
Balance as of March 31, 2018		526		$	53		$	7,269		$	473		$	1,122		$	(12	)	$	4,820		$	13,725

The accompanying unaudited interim financial statements and notes of Devon have been prepared pursuant to the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted. The accompanying unaudited interim financial statements and notes should be read in conjunction with the financial statements and notes included in Devon’s ~~2018~~2019 Annual Report on Form 10-K.

The accompanying unaudited interim financial statements in this report reflect all adjustments that are, in the opinion of management, necessary for a fair statement of Devon’s results of operations and cash flows for the three-month periods ended March 31, ~~2019~~2020 and ~~2018~~2019 and Devon’s financial position as of March 31, ~~2019.~~2020. As further discussed in Note 1917, Devon reached an agreement to sell its Barnett Shale assets in December 2019, which was amended in April 2020, and sold its ~~interests in EnLink and the General Partner~~Canadian operations on ~~July 18, 2018.~~ June 27, 2019. Activity relating to ~~EnLink~~Devon’s Barnett Shale assets, inclusive of properties divested as partial sales of the Barnett Shale common operating field in previous reporting periods located primarily in Johnson and ~~the General Partner~~Wise counties, Texas, and its Canadian operations are classified as discontinued operations within Devon’s consolidated ~~comprehensive~~ statements of comprehensive earnings and consolidated statements of cash flows. The associated assets and liabilities of Devon’s Barnett Shale assets and Canadian operations are presented as assets and liabilities associated with discontinued operations on the consolidated balance sheets.

~~Recently Adopted Accounting Standards~~During the fourth quarter of 2019, Devon entered into an agreement to form Cotton Draw Midstream, L.L.C. (“CDM”), a joint-venture entity in the Delaware Basin with an affiliate of QL Capital Partners, LP (“QLCP”). Devon holds a controlling interest in CDM and the portions of CDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon. The assets of CDM cannot be used by Devon for general corporate purposes and are included in and disclosed parenthetically on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which the creditors do not have recourse to Devon's assets are also included in, and disclosed parenthetically, on Devon's consolidated balance sheets if material.

~~In January 2019, Devon adopted ASU 2016-02,~~ ~~Leases (Topic 842), using the modified retrospective method. See~~ ~~Note 15for further discussion regarding Devon’s adoption~~Disaggregation of ~~the leases standard.~~

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

The ~~FASB issued ASU 2018-13,~~ ~~Fair Value Measurement (Topic 820): Changes to~~following table presents revenue from contracts with customers that are disaggregated based on the ~~Disclosure Requirements for Fair Value Measurement~~. This ASU will eliminate, add and modify certain disclosure requirements for fair value measurement. The ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the entire standardtype of good or only the provisions that eliminate or modify requirements. The ASU requires the additional disclosure requirements to be adopted using a retrospective approach. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its disclosures in the notes to the consolidated financial statements.service.

~~The FASB issued ASU 2018-15,~~ ~~Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract~~. This ASU will require a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a hosting arrangement that is a service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. This ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted. Entities have the option to adopt the ASU using either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of the adoption. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements.

~~The SEC released Final Rule Release No. 33-10618, FAST Act Modernization and Simplification of Regulation S-K~~, which amends Regulation S-K to modernize and simplify certain disclosure requirements in a manner that reduces costs and burdens on registrants while continuing to provide all material information to investors. The rule is effective May 2, 2019. The rule amends numerous SEC rules, items and forms covering a diverse group of topics. As the changes are generally expected to reduce or eliminate disclosures, Devon is currently evaluating and assessing the impact it may have on its disclosures.

In 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses. This ASU changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans and other financial assets measured at amortized cost from the current “incurred loss” model to a new forward-looking “expected loss” model. Devon adopted this ASU in the first quarter of 2020 using the modified retrospective approach. Devon assesses credit risk by class of account type which includes cash equivalents and oil and gas, marketing and midstream, joint interest and other accounts receivable. These classes are then further evaluated using a probability weighted scenario assessment based on historical losses and a probability of future default. This evaluation is supported by an assessment of risk factors such as the age of receivable, current macro-economic conditions, credit rating of the counterparty and our historical loss rate. This adoption did not have a material impact on Devon’s consolidated financial statements.

In June 2019, ~~Asset Divestitures~~Devon completed the sale of substantially all of its oil and gas assets and operations in Canada to Canadian Natural Resources Limited for proceeds, net of purchase price adjustments, of $2.6 billion ($3.4 billion Canadian dollars), and recognized a pre-tax gain of $223 million ($425 million, net of tax, primarily due to a significant deferred tax benefit). Additional information can be found in Note 17.

Devon announced the sale of its Barnett Shale assets to BKV in December 2019 and subsequently amended the agreement in April 2020. Under the amended terms, Devon has agreed to sell its Barnett Shale assets for $570 million in cash, before purchase price adjustments, at closing, which was extended to December 31, 2020. Devon recognized a $748 million asset impairment related to these assets in the fourth quarter of 2019 and an incremental $179 million asset impairment during the first quarter of 2020. Additional information can be found in Note 17.

During the first quarter of 2020, Devon entered into a farmout agreement in which the third-party to the agreement can participate in the development of certain Devon-owned non-operated interests in the Delaware Basin. Under the agreement, Devon will periodically transfer working interests to the third party, who will then fund its share of operating and development costs. Once certain investment hurdles are met, a portion of the working interest held by the third party will revert back to Devon. No material activity occurred during the first quarter of 2020.

In the first quarter of 2019, Devon received proceeds of approximately $300 million and recognized a $45 million net gain on asset dispositions, ~~of approximately $44 million,~~ primarily from sales of non-core assets in the Permian Basin. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 25 MMBoe, or less than 2% of total U.S. proved reserves. As of December 31, 2018, assets and liabilities associated with these divested assets were classified as held for sale in the accompanying consolidated balance sheet.

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. Devon is evaluating multiple methods of separation for these assets, including potential sales or spin-offs. As of March 31, 2019, Devon 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.MMBoe.

Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL marketing activities. These commodity derivative financial instruments include financial price swaps, basis swaps and costless price collars. 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.~~volatility. As of March 31, ~~2019,~~2020, Devon did not have any open interest rate swap ~~or foreign exchange~~ contracts.

Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

By using derivative financial instruments, 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 contain provisions that provide for collateral payments if Devon’s or its counterparty’s credit rating falls below certain credit rating levels. As of March 31, 2020, Devon neither held cash collateral of its counterparties 0r posted collateral to its counterparties.

As of March 31, ~~2019,~~2020, Devon had the following open oil derivative positions. The first ~~two tables present~~table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The ~~third~~second table presents Devon’s oil derivatives that settle against the respective indices noted within the ~~table.~~table.

As of March 31, ~~2019,~~2020, 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.

~~As of March 31, 2019, 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.~~

As of March 31, 2020, 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.

The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated ~~comprehensive~~ statements of comprehensive earnings caption.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020		2019
Commodity derivatives:
Upstream revenues	$	(709	)	$	(41	)	$	720	$	(605	)
Marketing revenues		1			—
Interest rate derivatives:
Other expenses		—			46
Marketing and midstream revenues								—		1
Net gains (losses) recognized	$	(708	)	$	5		$	720	$	(604	)

The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance ~~sheet~~sheets caption.

	March 31, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Commodity derivative assets:
Other current assets	$	30	$	637	$	616	$	49
Other long-term assets		6		40		27		1
Total derivative assets	$	36	$	677	$	643	$	50
Commodity derivative liabilities:
Other current liabilities	$	91	$	67	$	—	$	30
Other long-term liabilities		6		1		5		1
Total derivative liabilities	$	97	$	68	$	5	$	31

The table below presents the share-based compensation expense included in Devon’s accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings. The vesting for certain share-based awards was accelerated in conjunction with the reduction of workforce described in Note 56 and is included in restructuring and transaction costs in the accompanying consolidated ~~comprehensive~~ statements of ~~earnings.~~comprehensive earnings.

	Three Months Ended March 31,				Three Months Ended March 31st,
	2019		2018		2020		2019
G&A	$	26	$	37	$	20	$	23
Exploration expenses		1		2
Restructuring and transaction costs		22		—		—		22
Total	$	49	$	39	$	20	$	45
Related income tax benefit	$	10	$	1	$	—	$	9

Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first three months of ~~2019.~~2020. 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 plan.

	Restricted Stock					Performance-Based					Performance												Performance-Based					Performance
	Awards and Units					Restricted Stock Awards					Share Units							Restricted Stock Awards					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		Awards			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)																	(Thousands, except fair value data)
Unvested at 12/31/18		5,963		$	35.47		302		$	35.93		2,868				$	30.14
Unvested at 12/31/19																			4,984		$	29.65		153		$	33.88		2,155				$	40.35
Granted		4,271		$	25.47		—		$	—		741				$	28.97		2,865		$	22.54		—		$	—		688				$	27.89
Vested		(2,505	)	$	35.05		(137	)	$	37.44		—				$	—		(1,733	)	$	29.42		(105	)	$	29.12		(455	)			$	52.56
Forfeited		(442	)	$	26.83		—		$	—		(1,267	)			$	11.15		(29	)	$	28.05		—		$	—		(304	)			$	52.56
Unvested at 3/31/19		7,287		$	30.27		165		$	34.67		2,342		⁽¹	⁾	$	40.05
Unvested at 3/31/20																			6,087		$	26.37		48		$	44.12		2,084		⁽¹	⁾	$	31.79

The following table presents the assumptions related to the performance share units granted in ~~2019,~~2020, as indicated in the previous summary table.

	2019					2020
Grant-date fair value	$	28.43	—	$	29.53	$	27.89
Risk-free interest rate	2.48%					1.36%
Volatility factor	39.1%					38.4%
Contractual term (years)	2.89					2.89

The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of March 31, ~~2019.~~2020.

			Performance-Based						Performance-Based
	Restricted Stock		Restricted Stock		Performance		Restricted Stock		Restricted Stock		Performance
	Awards and Units		Awards		Share Units		Awards		Awards		Share Units
Unrecognized compensation cost	$	162	$	—	$	33	$	120	$	—	$	25
Weighted average period for recognition (years)		2.8		2.2		1.9		2.9		1.2		1.8

The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the consolidated statements of comprehensive earnings.

Reduced demand from the COVID-19 pandemic caused an unprecedented downturn in the price of oil. As a result, Devon reduced planned 2020 capital investment by 45%. With materially lower commodity prices and reduced near-term investment, Devon assessed all of its oil and gas fields for impairment as of March 31, 2020. For impairment determinations, Devon historically utilized NYMEX forward strip prices for the first five years and applied internally generated price forecasts for subsequent years. In response to the COVID-19 pandemic, the NYMEX forward market became highly illiquid as evidenced by materially reduced trading volumes for periods beyond 2021. Therefore, Devon supplemented the NYMEX forward strip prices with price forecasts published by reputable investment banks and reservoir engineering firms to estimate future revenues as of March 31, 2020. To measure indicated impairments, Devon used a market-based weighted-average cost of capital to discount the future net cash flows.

Devon recognized approximately $2.7 billion of proved asset impairments during the first three months of 2020. These impairments related to the Anadarko Basin and Rockies fields in which the cost basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher than they are today. In the first quarter of 2020, Devon recognized $2 million of product line fill impairments.

Due to the recent downturn in the commodity price environment and reduced near-term investment as discussed above, Devon also recognized $110 million of unproved impairments during the first three months of 2020, primarily in the Rockies field. During the first three months of 2019, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments of $1 million.

During the first quarter of 2019, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure in conjunction with the portfolio transformation announcement further discussed in Note 2.2. As a result, Devon recognized ~~$54~~$51 million of restructuring expenses during the first three months of 2019. Of these expenses, $22 million resulted from accelerated vesting of share-based grants, which are noncash charges. ~~Devon anticipates recognizing additional restructuring charges in 2019 primarily when the separation of the Canadian and Barnett Shale assets are completed.~~

~~The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings.~~

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.

The following table presents Devon’s total income tax expense (benefit) and a reconciliation of its effective income tax rate to the U.S. statutory income tax rate.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Current income tax expense (benefit)	$	(3	)	$	4
Loss from continuing operations before income taxes							$	(2,107	)	$	(497	)

Current income tax benefit							$	(106	)	$	(4	)
Deferred income tax benefit		(107	)		(38	)		(311	)		(115	)
Total income tax benefit	$	(110	)	$	(34	)	$	(417	)	$	(119	)

U.S. statutory income tax rate		21	%		21	%		21	%		21	%
State income taxes		7	%		1	%		1	%		6	%
Change in tax legislation								5	%		0	%
Other		(2	%)		(8	%)		(3	%)		(3	%)
Deferred tax asset valuation allowance								(4	%)		0	%
Effective income tax rate		26	%		14	%		20	%		24	%

Devon estimates its annual effective income tax rate to record its quarterly 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 quarter in which they occur.

~~In the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease~~The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) became law on March 27, 2020. The CARES Act allows net operating losses generated in ~~relation~~taxable years beginning after December 31, 2017 and before January 1, 2021 to ~~the change~~be carried back five years to offset taxable income and generate a refund. Devon intends to carry net operating losses generated in ~~pre-tax earnings. Generally, such items have an insignificant impact on Devon’s effective~~2019 and 2020 back to 2014 and 2015, respectively. As a result, Devon recorded a $96 million income tax ~~rate. However, these items had a more noticeable impact~~benefit in Q1 2020, and expects to record an additional $9 million income tax benefit by the ~~rate in~~end of the ~~first three months of 2018 due to the low relative net loss during the period.~~year.

~~In the first quarter of~~Throughout 2019, ~~the deferred tax asset representing Devon’s U.S. state net operating loss subject to~~Devon maintained a valuation allowance decreased by $13 million. The corresponding decrease in the valuation allowance against the state net operating loss resulted in a deferred tax benefit, which is included within state income taxes in the table above.

As of the first quarter of 2018, Devon’s U.S. segment maintained a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses, oil and gas impairments, and significant net operating losses for U.S. federal and state income tax. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon reassessed its position and determined that its U.S. segment was 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. ~~Devon’s Canadian segment maintains~~Since then, reduced demand from the COVID-19 pandemic has caused an unprecedented downturn in the commodity price environment. As a ~~valuation allowance against certain capital loss carryforwards.~~

~~During~~result, Devon recorded significant impairments during the first quarter of ~~2019,~~ 2020 and is now in a net deferred tax asset position. Devon ~~announced~~reassessed its ~~intent to separate~~position and recorded a 100% valuation allowance against all ~~Canadian assets. As a result, Devon’s foreign earnings were no longer considered indefinitely reinvested~~net deferred tax assets as of March 31, ~~2019. However,~~2020, increasing its valuation allowance by $108 million.

Included in “other” in the ~~deferred~~table above is the impact of increasing Devon’s unrecognized tax ~~asset~~benefits by approximately $34 million during the first quarter of ~~its Canadian investment will not be recorded until the form of the separation is certain.~~

The following table reconciles net ~~loss~~earnings (loss) from continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net ~~loss~~earnings (loss) per share from continuing operations.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Net loss from continuing operations:
Net loss from continuing operations	$	(317	)	$	(211	)	$	(1,691	)	$	(378	)
Attributable to participating securities		—			—			(1	)		—
Basic and diluted loss from continuing operations	$	(317	)	$	(211	)	$	(1,692	)	$	(378	)
Common shares:
Common shares outstanding - total		434			527			383			434
Attributable to participating securities		(6	)		(7	)		(6	)		(6	)
Common shares outstanding - basic and diluted		428			520			377			428
Net loss per share from continuing operations:
Basic	$	(0.74	)	$	(0.41	)	$	(4.48	)	$	(0.89	)
Diluted	$	(0.74	)	$	(0.41	)	$	(4.48	)	$	(0.89	)
Antidilutive options ⁽¹⁾		1			2			—			1

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Foreign currency translation:
Beginning accumulated foreign currency translation and other	$	1,159		$	1,309		$	—		$	1,159
Change in cumulative translation adjustment		35			(61	)		—			35
Income tax benefit		—			13
Ending accumulated foreign currency translation		1,194			1,261
Ending accumulated foreign currency translation and other								—			1,194
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(132	)		(143	)		(119	)		(132	)
Recognition of net actuarial loss and prior service cost in earnings ⁽¹⁾		3			4			2			3
Income tax expense		(1	)		—			(1	)		(1	)
Ending accumulated pension and postretirement benefits		(130	)		(139	)		(118	)		(130	)
Accumulated other comprehensive earnings, net of tax	$	1,064		$	1,122
Accumulated other comprehensive earnings (loss), net of tax							$	(118	)	$	1,064

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Changes in assets and liabilities, net
Changes in assets and liabilities, net:
Accounts receivable	$	(152	)	$	37		$	238		$	(29	)
Income tax receivable								(113	)		—
Other current assets		(7	)		(88	)		(38	)		9
Other long-term assets		(19	)		(53	)		(24	)		(8	)
Accounts payable		(37	)		4			42			(51	)
Revenues and royalties payable		(49	)		66			(113	)		46
Other current liabilities		(30	)		64			(81	)		(23	)
Other long-term liabilities		(8	)		(5	)		33			(5	)
Total	$	(302	)	$	25		$	(56	)	$	(61	)
Supplementary cash flow data - total operations:
Interest paid (net of capitalized interest)	$	53		$	76		$	64		$	53
Income taxes paid	$	6		$	1		$	151		$	6

	March 31, 2019			December 31, 2018			March 31, 2020			December 31, 2019
Oil, gas and NGL sales	$	608		$	430		$	235		$	452
Joint interest billings		155			155			147			168
Marketing revenues		269			285
Marketing and midstream revenues								149			207
Other		14			23			74			13
Gross accounts receivable		1,046			893			605			840
Allowance for doubtful accounts		(8	)		(8	)		(11	)		(8	)
Net accounts receivable	$	1,038		$	885		$	594		$	832

The following table presents the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.

	March 31, 2019			December 31, 2018			March 31, 2020			December 31, 2019
Property and equipment:
Proved	$	47,325		$	46,805		$	27,986		$	27,668
Unproved and properties under development		2,215			2,267			504			583
Total oil and gas		49,540			49,072			28,490			28,251
Less accumulated DD&A		(36,774	)		(36,259	)		(23,734	)		(20,693	)
Oil and gas property and equipment, net		12,766			12,813			4,756			7,558
Other property and equipment		1,819			1,832			1,732			1,725
Less accumulated DD&A		(721	)		(710	)		(708	)		(690	)
Other property and equipment, net(1)		1,098			1,122			1,024			1,035
Property and equipment, net	$	13,864		$	13,935		$	5,780		$	8,593

During the first quarter of 2020, Devon recognized asset impairments of $2.7 billion primarily related to proved oil and gas assets and $110 million of unproved impairments, which significantly reduced the carrying value of its property and equipment, net. See Note 5 for additional details.

See below for a summary of debt ~~is as follows:~~instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.

Devon has a $3.0 billion Senior Credit Facility. As of March 31, ~~2019,~~2020, Devon had no0 outstanding borrowings under the Senior Credit Facility and had issued ~~$52~~$2 million in outstanding letters of credit under this facility. The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. Under the terms of the credit agreement, total capitalization is adjusted to add back noncash financial write-downs such as impairments. As of March 31, ~~2019,~~2020, Devon was in compliance with this covenant with a debt-to-capitalization ratio of ~~21.6%~~18.8%.

In January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity.

In the first quarter of 2018, Devon completed tender offers to repurchase $807 million in aggregate principal amount of debt securities, 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.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Interest based on debt outstanding	$	78		$	96		$	65		$	65
Early retirement of debt		—			312
Capitalized interest		—			(18	)
Interest income								(5	)		(11	)
Other		(5	)		(3	)		5			6
Total net financing costs	$	73		$	387		$	65		$	60

~~Devon adopted ASU No. 2016-02,~~ ~~Leases (Topic 842)~~, as of January 1, 2019, using the modified retrospective transition approach. ASC 842 supersedes the previous lease accounting requirements in ASC 840 and requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 establishes a right-of-use model that requires a lessee to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term longer than 12 months. At adoption, using the modified retrospective transition approach, Devon recorded right-of-use lease assets of $394 million and lease liabilities of $380 million. Additionally, Devon recorded a $24 million before tax, $19 million net of tax, cumulative-effect adjustment to reduce retained earnings. Comparative periods have been presented in accordance with ASC Topic 840 and do not include any retrospective adjustments to reflect the adoption of Topic 842. Excluding land easements and rights-of-way, all leases that existed at January 1, 2019 or were entered into or modified thereafter, are accounted for under Topic 842. Devon 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 elected a policy not to recognizeThe following table presents Devon’s right-of-use assets and lease liabilities ~~related to short-term leases with terms~~as of ~~12 months or less. Additionally, Devon elected to account for lease components separately from the nonlease components.~~March 31, 2020 and December 31, 2019.

Devon made certain significant assumptions and judgments in determining its right-of-use asset and lease liability balances. First is the determination of whether a contract contains a lease. Devon considered the presence of an identified asset that is physically distinct, and for which the supplier does not have substantive substitution rights and whether Devon has the right to control the underlying asset. Second, Devon assessed lease terms and considered whether Devon is reasonably certain to extend leases or exercise purchase options. Certain of Devon’s leases include one or more options to renew, with renewal terms that can extend the lease term for additional years. Certain leases also include options to purchase the leased property. For options to renew or purchase that Devon is reasonably certain to exercise, these costs are recognized as part of the right-of-use assets and lease liabilities. Third, significant judgments have been made in determining discount rates. Devon estimates discount rates using market rates that approximate collateralized borrowings over the remaining term of Devon’s lease payments.

Devon’s right-of-use operating lease 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. Devon’s right-of-use financing lease assets are related to real estate. ~~Certain~~

The following table presents the changes in Devon’s ~~right-of-use assets~~asset retirement obligations.

During the first three months of 2019, Devon reduced its asset retirement obligations by $62 million, primarily due to changes in the future cost estimates and ~~lease liabilities~~retirement dates for its oil and gas assets. Additionally, during the first three months of 2019, Devon reduced its asset retirement obligations by $29 million as a result of ~~March 31, 2019.~~the non-core asset divestitures. For additional information, see Note 2.

In March 2018, Devon announced a $1.0 billion share repurchase program. In June 2018, Devon announced the expansion of this program to $4.0 billion. In February 2019, Devon announced a further expansion to $5.0 billion with a December 31, 2019 expiration date. In December 2019, Devon announced a new $1.0 billion share repurchase program with a December 31, 2020 expiration date. Under the new program, $800 million of the $1.0 billion authorization is conditioned upon the closing of the Barnett Shale divestiture for cash proceeds of at least $725 million. Due to the amended terms of the Barnett Shale divestiture with BKV, which reduced the closing payment to $570 million and extended the closing date to December 31, 2020, Devon does not anticipate being able to repurchase more than $200 million of the $1.0 billion authorization before the program expiration date. As the pricing and economic environment has changed due to the COVID-19 pandemic and demand challenges for commodities, Devon has temporarily suspended its share repurchase program to preserve liquidity.

The table below provides information regarding purchases of Devon’s common stock that were made under the respective share repurchase programs (shares in thousands).

Devon paid common stock dividends of $34 million ($0.09 per share) and $34 million ($0.08 per share) during the first three months of 2020 and 2019, respectively. In February 2020, Devon announced a 22% increase to its quarterly dividend, to $0.11 per

share, beginning in the second quarter of 2020. In the second quarter of 2019, Devon raised its quarterly dividend from $0.08 to $0.09 per share.

In 2019, Devon announced that it had entered into an agreement to sell its Barnett Shale assets to BKV and subsequently amended the agreement in April 2020. Under the amended terms, Devon has agreed to sell its Barnett Shale assets for $570 million in cash, before purchase price adjustments, at closing, which was extended to December 31, 2020. Additionally, the agreement provides for contingent earnout payments to Devon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The ~~following table presents~~contingent payment period commences on January 1, 2021 and has a term of four years. Under the terms of the agreement, Devon received the deposit funds of $170 million in April 2020. The deposit is being held by Devon pursuant to the terms of the sale agreement, which only requires Devon to return such funds to BKV in the event the transaction does not close as a result of Devon’s ~~additional lease information~~breach of its closing obligations.

In connection with the announced sale of its Barnett Shale assets, approximately $88 million of the U.S. reporting unit goodwill was allocated to the Barnett Shale assets. Additionally, Devon ceased depreciation for all property, plant and equipment classified as assets held for sale on the ~~three months ended~~date the sales agreement was approved by the Board of Directors. Devon also recognized a $748 million asset impairment in the fourth quarter of 2019 related to these assets, primarily due to the difference between the net carrying value and the purchase price, net of estimated customary purchase price adjustments. During the first quarter of 2020, Devon adjusted the estimated impairment $179 million, primarily due to the amended agreement terms. The valuation of the future contingent earnout payments included in the March 31, ~~2019.~~2020 Barnett Shale impairment computation was $41 million. The value was derived utilizing a Monte Carlo valuation model and qualifies as a level 3 fair value measurement.

~~The following table presents Devon’s maturity analysis as~~As of March 31, 2020, Devon has restricted approximately $25 million to fund obligations in connection with the abandonment of certain gas processing contracts related to the 2018 divestitures. Cash payments for these charges total approximately $2 million per quarter.

On June 27, 2019, Devon completed the sale of its Canadian business for ~~leases expiring~~$2.6 billion ($3.4 billion Canadian dollars), net of purchase price adjustments, and recognized a pre-tax gain of $223 million ($425 million net of tax, primarily due to a significant deferred tax benefit). Current (cash) income tax associated with the sale was approximately $150 million and was paid in ~~each~~the first quarter of 2020.The disposition of substantially all of Devon’s Canadian oil and gas assets resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings to be included within the gain computation. The historical cumulative foreign currency translation portion of the ~~next 5 years~~gain is not taxable.

During the third quarter of 2019, Devon utilized a portion of the sales proceeds to early retire its $500 million of the 4.00% senior notes due July 15, 2021 and ~~thereafter.~~$1.0 billion of the 3.25% senior notes due May 15, 2022. Devon recognized a charge on the early retirement of these notes consisting of $52 million in cash retirement costs and $6 million of noncash charges.

~~Devon rents or subleases certain real estate to third parties.~~ The following table presents ~~Devon’s expected lease income~~the amounts reported in the consolidated statements of comprehensive earnings as ~~of March 31, 2019 for each of the next 5 years and thereafter.~~

~~16.~~

~~Asset Retirement Obligations~~

Three Months Ended March 31,	Barnett Shale			Canada			Total
2020
Upstream revenues	$	92		$	—		$	92
Total revenues		92			—			92
Production expenses		74			—			74
Asset impairments		179			—			179
General and administrative expenses		—			1			1
Financing costs, net		—			(2	)		(2	)
Other expenses		(13	)		10			(3	)
Total expenses		240			9			249
Loss from discontinued operations before income taxes		(148	)		(9	)		(157	)
Income tax benefit		(32	)		—			(32	)
Net loss from discontinued operations, net of tax	$	(116	)	$	(9	)	$	(125	)
2019
Upstream revenues	$	149		$	247		$	396
Marketing and midstream revenues		—			26			26
Total revenues		149			273			422
Production expenses		81			141			222
Exploration expenses		—			9			9
Marketing and midstream expenses		—			9			9
Depreciation, depletion and amortization		20			79			99
Asset dispositions		1			—			1
General and administrative expenses		—			18			18
Financing costs, net		—			13			13
Restructuring and transaction costs		—			3			3
Other expenses		6			(28	)		(22	)
Total expenses		108			244			352
Earnings from discontinued operations before income taxes		41			29			70
Income tax expense		9			—			9
Net earnings from discontinued operations, net of tax	$	32		$	29		$	61

The following table presents the ~~changes in Devon’s asset retirement obligations.~~carrying amounts of the assets and liabilities associated with discontinued operations on the consolidated balance sheets.

Three Months Ended March 31,

2019

2018

Asset retirement obligations as of beginning of period

$
1,057

$
1,138

Liabilities incurred

7

15

Liabilities settled and divested

(37
)

(20
)
Revision of estimated obligation

(87
)

23

Accretion expense on discounted obligation

14

16

Foreign currency translation adjustment

9

(13
)
Asset retirement obligations as of end of period

963

1,159

Less current portion

25

32

Asset retirement obligations, long-term

$
938

$
1,127

	As of March 31, 2020						As of December 31, 2019
	Barnett Shale		Canada		Total		Barnett Shale		Canada		Total
Cash restricted for discontinued operations	$	25	$	175	$	200	$	25	$	355	$	380

Accounts receivable	$	36	$	1	$	37	$	38	$	1	$	39
Other current assets		5		2		7		5		2		7
Oil and gas property and equipment, based on successful efforts accounting, net		593		—		593		751		—		751
Other property and equipment, net		11		—		11		11		—		11
Goodwill		88		—		88		88		—		88
Other long-term assets		—		74		74		—		81		81
Total assets associated with discontinued operations	$	733	$	77	$	810	$	893	$	84	$	977

Accounts payable	$	14	$	6	$	20	$	15	$	4	$	19
Revenues and royalties payable		36		3		39		44		3		47
Other current liabilities		21		73		94		19		233		252
Asset retirement obligations		141		—		141		141		—		141
Other long-term liabilities		15		148		163		16		169		185
Total liabilities associated with discontinued operations	$	227	$	230	$	457	$	235	$	409	$	644

~~During the first three months of 2019, Devon reduced its asset retirement obligations by $87 million,~~ ~~primarily due to changes in the future cost estimates and retirement dates for its oil and gas assets~~.

The following table presents the components of net periodic benefit cost for Devon’s pension benefits plan. There were no net periodic benefit costs for postretirement benefit plans for all periods presented below.

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.

~~The table below provides information regarding purchases of Devon’s common stock that were made during 2018 and the first three months of 2019 (shares in thousands).~~

Devon paid common stock dividends of $34 million ($0.08 per share) and $32 million ($0.06 per share) during the first three months of 2019 and 2018, respectively. 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. In the second quarter of 2018, Devon increased the quarterly dividend rate from $0.06 to $0.08 per share.

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 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.

On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). Current (cash) income tax associated with the transaction was approximately $12 million. The vast majority of the tax effect relates to deferred tax expense offset by the valuation allowance adjustment.

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.

During the first quarter of 2019, Devon had net outflows of approximately $150 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.~~

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~~.

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of an 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.

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.

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’ claims against Devon relate primarily to the operations of several of Devon’s corporate predecessors. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon is vigorously defending against these claims.

~~Devon is involved~~Various municipalities and other governmental and private parties in ~~other various~~California have filed legal proceedings ~~incidental~~against certain oil and gas companies, including Devon, seeking relief to ~~its business. However,~~abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctions against the production of all fossil fuels. Although Devon cannot predict the ultimate outcome of these matters,Devon believes these claims to ~~Devon’s knowledge, there were no material pending legal proceedings~~be baseless and intends to ~~which Devon is a party or to which any~~vigorously defend against the proceedings.

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, cash restricted for discontinued operations, accounts receivable, other current receivables, accounts payable, other current payables, accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at March 31, ~~2019~~2020 and December 31, ~~2018,~~2019, as applicable. Therefore, such financial assets and liabilities are not presented in the following ~~table.~~table.

							Fair Value Measurements Using:											Fair Value Measurements Using:
	Carrying			Total Fair			Level 1		Level 2			Carrying			Total Fair			Level 1		Level 2
	Amount			Value			Inputs		Inputs			Amount			Value			Inputs		Inputs
March 31, 2019 assets (liabilities):
March 31, 2020 assets (liabilities):
Cash equivalents	$	432		$	432		$	432	$	—		$	890		$	890		$	890	$	—
Commodity derivatives	$	36		$	36		$	—	$	36		$	643		$	643		$	—	$	643
Commodity derivatives	$	(97	)	$	(97	)	$	—	$	(97	)	$	(5	)	$	(5	)	$	—	$	(5	)
Debt	$	(5,786	)	$	(6,448	)	$	—	$	(6,448	)	$	(4,295	)	$	(3,118	)	$	—	$	(3,118	)
December 31, 2018 assets (liabilities):
December 31, 2019 assets (liabilities):
Cash equivalents	$	1,505		$	1,505		$	1,405	$	100		$	702		$	702		$	702	$	—
Commodity derivatives	$	677		$	677		$	—	$	677		$	50		$	50		$	—	$	50
Commodity derivatives	$	(68	)	$	(68	)	$	—	$	(68	)	$	(31	)	$	(31	)	$	—	$	(31	)
Debt	$	(5,947	)	$	(5,965	)	$	—	$	(5,965	)	$	(4,294	)	$	(5,376	)	$	—	$	(5,376	)

The following methods and assumptions were used to estimate the fair values in the table above.

Cash equivalents – Amounts consist primarily of money market investments and the fair value approximates the carrying value.

~~Cash equivalents~~ ~~– Amounts primarily consist of Canadian agency and provincial securities investments. The fair value approximates the carrying value.~~

Commodity ~~and interest rate~~ derivatives – The fair value of commodity derivatives is 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.

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 E&P 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 E&P activities.

~~The following table presents revenue from contracts with customers that are disaggregated based on the type of good.~~

Three Months Ended March 31, 2019

Three Months Ended March 31, 2018

U.S.

Canada

Total

U.S.

Canada

Total

Oil

$
661

$
351

$
1,012

$
677

$
230

$
907

Gas

233

—

233

255

—

255

NGL

174

—

174

198

—

198

Oil, gas and NGL revenues from
contracts with customers

1,068

351

1,419

1,130

230

1,360

Oil, gas and NGL derivatives

(605
)

(104
)

(709
)

(113
)

72

(41
)
Upstream revenues

463

247

710

1,017

302

1,319

Oil

356

26

382

531

17

548

Gas

218

—

218

155

—

155

NGL

191

—

191

176

—

176

Total marketing revenues from
contracts with customers

765

26

791

862

17

879

Total revenues

$
1,228

$
273

$
1,501

$
1,879

$
319

$
2,198

~~The following table presents selected financial information for Devon’s reporting segments.~~

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis addresses material changes in our results of operations for the three-month period ended March 31, ~~2019~~2020 compared to previous periods and in our financial condition and liquidity since December 31, ~~2018.~~2019. For information regarding our critical accounting policies and estimates, see our ~~2018~~2019 Annual Report on Form 10-Kunder “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

A novel strain of coronavirus, SARS-CoV-2, causing a disease referred to as COVID-19, was reported to have surfaced in China in late 2019 ~~Results~~

~~Key components~~and has subsequently spread to multiple countries worldwide, resulting in a global pandemic and health crisis. Devon began actively monitoring COVID-19 in January 2020 and formally established a COVID-19 cross-functional planning team at the beginning of March. The COVID-19 team is focused on two key priorities: the health and safety of our ~~sequential quarter financial performance are summarized below.~~

~~During~~ the ~~first three months~~uninterrupted operation of ~~2019, we made significant progress in~~ our transition to “New Devon” - a U.S. oil growth company. We announced our intention to separate our Canadian business and our Barnett Shale assets from the Company. We anticipate using the proceeds from the separation of these assets to maintain target debt levels. As we continue to execute on our strategic objectives of funding high-return projects, generating free cash flow, maintaining financial strength and returning cash to shareholders, we have already achieved the following accomplishments in 2019.business.

This outbreak and the related responses of governmental authorities and others to limit the spread of the virus have significantly reduced global economic activity, resulting in an unprecedented decline in the demand for oil and other commodities. This supply-and-demand imbalance has been exacerbated by uncertainty regarding the future global supply of oil due to disputes between Russia and the members of OPEC, particularly Saudi Arabia, in March 2020. These factors caused a swift and material deterioration in commodity prices in early 2020, with NYMEX WTI oil prices falling from over $60/Bbl at the beginning of year to below $20/Bbl in April 2020. The current supply-and-demand imbalance has also imposed constraints on Devon’s and other operators’ ability to store and move production to downstream markets, which has resulted in the delay or curtailment of development activity, as well as the shutting-in of producing wells.

In response to the current macro-economic environment, we are protecting our financial strength and liquidity as evidenced by the following items:

We operate under a disciplined returns-driven strategy focused on delivering strong operational results, financial strength and value to our shareholders and continuing our commitment to environmental, social and governance excellence, which provides us with

a strong foundation to grow returns, margin and profitability. We continue to execute on our strategy and navigate through the challenged economic environment by protecting our financial strength, tailoring our capital investment to market conditions, improving our cash cost structure and preserving operational continuity.

Trends of our quarterly earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The quarterly earnings chart presents amounts pertaining to both Devon’s continuing and discontinuing operations. The quarterly cash flow chart presents amounts pertaining to Devon’s continuing operations. “Core earnings” and “EBITDAX” are financial measures not prepared in accordance with GAAP. For a description of these measures, including reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.

Our net earnings in recent quarters have been significantly impacted by divestiture transactions, asset impairments and temporary, noncash adjustments to the value of our commodity hedges. Net earnings in the first quarter of 2020 included $2.3 billion of asset impairments on our proved and unproved properties and a $0.5 billion hedge valuation gain, both net of taxes. Net earnings in the fourth quarter of 2019 included $0.6 billion of asset impairments and a $0.1 billion hedge valuation loss, both net of taxes. Net earnings in the second quarter of 2019 included $0.3 billion for net after-tax gains and charges related to our Canadian disposition. Net earnings in the first quarter of 2019 included a $0.5 billion after-tax hedge valuation loss. Excluding these amounts, our core earnings have been more stable over recent quarters but continue to be heavily influenced by commodity prices.

Despite our portfolio enhancements, aggressive cost reductions and operational advancements, our financial results continue to be challenged by commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic. Our earnings declined from the fourth quarter of 2019 to the first quarter of 2020 due to a decrease in overall commodity prices. Led by a 19% decrease in the WTI from the fourth quarter of 2019 to the first quarter of 2020, our unhedged combined realized price dropped 23%. Despite these price drops, we were able to maintain production volumes while simultaneously reducing production and administrative costs 4% compared to 2019.

Like earnings, our operating cash flow is sensitive to volatile commodity prices. EBITDAX, which excludes financial amounts related to discontinued operations, has been more stable over the past five quarters as our production growth and cost reductions

countered price declines experienced over the same time period. Regardless of cash flow fluctuations, we remain focused on managing our capital investment to generate free cash flow. As operating cash flow has declined, we have adjusted our capital development plans accordingly.

We exited the first quarter of ~~2019~~2020 with $4.7 billion of liquidity comprised of ~~$1.3~~$1.7 billion of cash, inclusive of $200 million of cash restricted for discontinued operations, and ~~$2.9~~$3.0 billion of available credit under our Senior Credit Facility. We have $4.3 billion of debt outstanding with no ~~debt~~ maturities until ~~2021.~~the end of 2025. We currently have approximately ~~60%~~90% of our expected oil production and approximately 45% of our expected gas production protected with hedges for the remainder of ~~2019.~~2020. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub natural gas index. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our ~~portfolio in the U.S. and Canada.~~portfolio.

The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. ~~Specifically,~~To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Analysis of the change in net earnings from continuing operations is shown below and analysis of the change in net earnings from discontinued operations is shown on page 33.

Our first quarter 2020 net loss from continuing operations was $1.7 billion. The graph below shows the change in net earnings (loss) from the ~~three months ended December 31, 2018~~fourth quarter of 2019 to the ~~three months ended March 31, 2019.~~first quarter of 2020. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

* Other includes asset dispositions, restructuring and transaction costs and other expenses.Production Volumes

	Q1 2020		% of Total			Q4 2019		Change
Oil (MBbls/d)
Delaware Basin		84		51	%		84		+0	%
Anadarko Basin		24		15	%		27		- 14	%
Powder River Basin		21		13	%		20		+7	%
Eagle Ford		26		16	%		23		+13	%
Other		8		5	%		9		- 6	%
Total		163		100	%		163		+0	%

	Q1 2020		% of Total			Q4 2019		Change
Gas (MMcf/d)
Delaware Basin		244		38	%		234		+4	%
Anadarko Basin		272		43	%		295		- 8	%
Powder River Basin		29		4	%		28		+1	%
Eagle Ford		86		14	%		76		+12	%
Other		3		1	%		4		- 15	%
Total		634		100	%		637		- 1	%

~~The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.~~

	Q1 2020		% of Total			Q4 2019		Change
NGLs (MBbls/d)
Delaware Basin		37		47	%		32		+18	%
Anadarko Basin		30		37	%		30		- 2	%
Powder River Basin		3		4	%		2		+13	%
Eagle Ford		9		11	%		9		+3	%
Other		1		1	%		1		- 17	%
Total		80		100	%		74		+8	%

	Q1 2020		% of Total			Q4 2019		Change
Combined (MBoe/d)
Delaware Basin		162		47	%		154		+5	%
Anadarko Basin		98		28	%		107		- 8	%
Powder River Basin		29		8	%		27		+6	%
Eagle Ford		50		14	%		45		+11	%
Other		9		3	%		10		- 7	%
Total		348		100	%		343		+2	%

~~Upstream Operations~~

~~Production Volumes~~

��

Q1 2019

% of Total

Q4 2018

Change

Oil and bitumen (MBbls/d)

Delaware Basin

60

23
%

45

+32
%
STACK

32

13
%

31

+3
%
Powder River Basin

15

6
%

13

+22
%
Eagle Ford

25

10
%

30

- 18
%
Other

6

2
%

6

+5
%
New Devon

138

54
%

125

+10
%
Canada divest assets

112

44
%

120

- 7
%
U.S. divest assets

4

2
%

8

- 49
%
Total Oil and bitumen

254

100
%

253

+1
%

Q1 2019

% of Total

Q4 2018

Change

Gas (MMcf/d)

Delaware Basin

146

15
%

127

+14
%
STACK

333

32
%

343

- 3
%
Powder River Basin

18

2
%

20

- 8
%
Eagle Ford

83

8
%

95

- 12
%
Other

1

0
%

2

- 56
%
New Devon

581

57
%

587

- 1
%
Canada divest assets

4

0
%

6

- 31
%
U.S. divest assets

439

43
%

457

- 4
%
Total

1,024

100
%

1,050

- 3
%

Q1 2019

% of Total

Q4 2018

Change

NGLs (MBbls/d)

Delaware Basin

23

22
%

18

+29
%
STACK

35

34
%

37

- 5
%
Powder River Basin

2

2
%

2

+9
%
Eagle Ford

12

11
%

15

- 22
%
Other

1

1
%

1

- 8
%
New Devon

73

70
%

73

+0
%
Divest assets

31

30
%

32

- 5
%
Total

104

100
%

105

- 1
%

Q1 2019

% of Total

Q4 2018

Change

Combined (MBoe/d)

Delaware Basin

107

20
%

84

+27
%
STACK

123

23
%

126

- 2
%
Powder River Basin

21

4
%

18

+15
%
Eagle Ford

50

10
%

61

- 18
%
Other

7

2
%

6

+8
%
New Devon

308

59
%

295

+4
%
Canada divest assets

113

21
%

121

- 7
%
U.S. divest assets

108

20
%

116

- 7
%
Total

529

100
%

532

- 1
%

Continued ~~growth~~development in the Delaware Basin and Powder River Basin drove production ~~increases for New Devon for~~increases. Additionally, a well-control event curtailed production volumes in the ~~first quarter of 2019 compared to~~Eagle Ford during the fourth quarter of ~~2018.~~2019. These ~~production gains~~ were partially offset by lower ~~production volumes associated with the Eagle Ford and U.S. divest assets. Canada production was lower due to higher royalties~~activity in the ~~first~~Anadarko Basin.

In response to the current macro-economic environment, we have reduced planned 2020 capital expenditures by 45% and shut in certain marginal wells. As a result, we anticipate total production to decrease in the second quarter of ~~2019.~~

2020 to a range of 302 to 328 MBoe/d and continue to decrease for the second half of 2020.

Field Prices

	Q1 2019			Realization		Q4 2018			Change			Q1 2020		Realization		Q4 2019		Change
Oil and bitumen (per Bbl)
Oil (per Bbl)
WTI index	$	54.88				$	58.80			- 7	%	$	46.44			$	57.02		- 19	%
Access Western Blend index	$	40.37				$	14.06			+187	%
U.S.	$	51.83			94%	$	55.78			- 7	%
Canada	$	34.60			63%	$	(2.49	)		+1489	%
Realized price, unhedged	$	44.20			81%	$	27.99			+58	%	$	44.59		96%	$	55.41		- 20	%
Cash settlements	$	(1.18	)			$	6.59					$	5.14			$	1.48
Realized price, with hedges	$	43.02			78%	$	34.58			+24	%	$	49.73		107%	$	56.89		- 13	%

	Q1 2019			Realization		Q4 2018			Change			Q1 2020		Realization		Q4 2019		Change
Gas (per Mcf)
Henry Hub index	$	3.15				$	3.65			- 14	%	$	1.95			$	2.50		- 22	%
Realized price, unhedged	$	2.53			80%	$	2.88			- 12	%	$	1.21		62%	$	1.70		- 29	%
Cash settlements	$	(0.17	)			$	(0.28	)				$	0.36			$	0.13
Realized price, with hedges	$	2.36			75%	$	2.60			- 9	%	$	1.57		81%	$	1.83		- 14	%

	Q1 2019		Realization		Q4 2018		Change			Q1 2020		Realization		Q4 2019		Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	22.94			$	26.30		- 13	%	$	14.39			$	18.69		- 23	%
Realized price, unhedged	$	18.64		81%	$	22.15		- 16	%	$	10.40		72%	$	15.79		- 34	%
Cash settlements	$	0.48			$	0.18				$	0.61			$	1.75
Realized price, with hedges	$	19.12		83%	$	22.33		- 14	%	$	11.01		77%	$	17.54		- 37	%

Q1 2019

Q4 2018

Change

Combined (per Boe)

U.S.

$
28.58

$
30.94

- 8
%
Canada

$
34.42

$
(2.46
)

+1498
%
Realized price, unhedged

$
29.83

$
23.32

+28
%
Cash settlements

$
(0.82
)

$
2.61

Realized price, with hedges

$
29.01

$
25.93

+12
%

InFrom the fourth quarter of 2018, market forces widened Canadian heavy oil differentials beyond historical norms and negatively impacted the price we realized on our Canadian production. We had basis swaps for approximately half of our fourth quarter production2019 to mitigate the effect of the lower market price. To further mitigate the effects of the lower price, we reduced our Jackfish production beginning in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d. Our Canadian heavy oil unhedged realized price for the fourth quarter of 2018 was near zero. During the first quarter of ~~2019, heavy~~2020, field prices contributed to a $227 million decrease in earnings. Unhedged realized oil, ~~differentials significantly improved~~gas and NGL prices decreased primarily due to ~~provincially mandated~~lower WTI, Henry Hub and Mont Belvieu index prices. These decreases were partially offset by favorable hedge cash settlements across each of our products.

As prices further deteriorated towards the end of the first quarter from the COVID-19 pandemic, we added additional oil and gas hedges for the remaining quarters of 2020 and the year 2021. We currently have approximately 90% of our remaining 2020 oil production ~~cuts.~~hedged with an average floor price of $42/Bbl and approximately 45% of our remaining 2020 gas production hedged with an average floor price of $2.15/Mcf. Additionally, we are currently building our 2021 hedge positions at market prices.

~~Hedging~~Hedge Settlements

	Q1 2019			Q4 2018			Change			Q1 2020		Q4 2019		Change
	Q									Q
Oil	$	(27	)	$	153			- 118	%	$	76	$	22		+245	%
Natural gas		(16	)		(27	)		+41	%		21		8		+163	%
NGL		4			1			+300	%		4		12		- 67	%
Total cash settlements		(39	)		127			- 131	%	$	101	$	42		+140	%
Valuation changes		(670	)		1,295			- 152	%
Total	$	(709	)	$	1,422			- 150	%

Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Production Expenses

	Q1 2020			Q4 2019			Change
LOE	$	126		$	120			+5	%
Gathering, processing & transportation		130			131			- 1	%
Production taxes		56			69			- 19	%
Property taxes		6			4			+50	%
Total	$	318		$	324			- 2	%
Per Boe:
LOE	$	3.96		$	3.79			+5	%
Gathering, processing & transportation	$	4.11		$	4.16			- 1	%
Percent of oil, gas and NGL sales:
Production taxes		6.9	%		6.7	%		+3	%

In ~~addition~~response to the current macro-economic environment, reduced planned 2020 capital expenditures and shutting in certain marginal wells, we anticipate decreases in LOE and gathering, processing and transportation of approximately 10% during the remainder of 2020. Additionally, we expect lower production taxes as a result of lower oil, gas and NGL revenues.

Field-Level Cash Margin

The table below presents the field-level cash ~~settlements, we also~~margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL revenues less production expenses and is not prepared in accordance with GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, field prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.

	Q1 2020		$ per BOE		Q4 2019		$ per BOE
Field-level cash margin (non-GAAP)
Delaware Basin	$	260	$	17.72	$	372	$	26.30
Anadarko Basin		74	$	8.22		147	$	15.06
Powder River Basin		54	$	20.48		73	$	28.86
Eagle Ford		87	$	19.20		98	$	23.72
Other		14	$	15.55		21	$	22.33
Total	$	489	$	15.41	$	711	$	22.55

DD&A and Asset Impairments

	Q1 2020		Q4 2019		Change
Oil and gas per Boe	$	11.90	$	11.71		+2	%

Oil and gas	$	377	$	370		+2	%
Other property and equipment		24		12		+93	%
Total	$	401	$	382		+5	%

Asset impairments	$	2,666	$	—	N/M

Asset impairments were $2.7 billion in the first quarter of 2020 due to significant decreases in commodity prices since the end of 2019 resulting primarily from the COVID-19 pandemic. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

As a result of the asset impairments of $2.7 billion during the first quarter of 2020 and the lower production resulting from decreased capital expenditures, DD&A will decrease approximately 25% for the remainder of 2020.

General and Administrative Expenses

	Q1 2020		Q4 2019		Change
Labor and benefits (net of reimbursements)	$	66	$	80		- 18	%
Non-labor		36		39		- 8	%
Total Devon	$	102	$	119		- 14	%

G&A decreased primarily as a result of lower employee costs and benefits.

Other Items

	Q1 2020			Q4 2019			Change in earnings
Commodity hedge valuation changes ⁽¹⁾	$	619		$	(158	)	$	777
Marketing and midstream operations		(18	)		5			(23	)
Exploration expenses		112			29			(83	)
Net financing costs		65			64			(1	)
Restructuring and transaction costs		—			11			11
Other expenses		(48	)		16			64
							$	745

(1)

Included as a component of upstream revenues on the consolidated statements of comprehensive earnings.

~~Production Expenses~~

Q1 2019

Q4 2018

Change

LOE

$
220

$
251

- 12
%
Gathering, processing & transportation

203

220

- 8
%
Production taxes

68

70

- 3
%
Property taxes

15

15

+0
%
Total

$
506

$
556

- 9
%
Per Boe:

LOE

$
4.63

$
5.12

- 10
%
Gathering, processing &
transportation

$
4.26

$
4.50

- 5
%
Percent of oil, gas and NGL sales:

Production taxes

4.8
%

6.1
%

- 21
%

~~LOE decreased primarily due to a Canadian product inventory impairment in the fourth quarter of 2018 and our U.S. non-core divestitures.~~

~~Gathering, processing and transportation decreased approximately $20 million due to the expiration of the EnLink Bridgeport minimum volume commitment at the end of 2018.~~

Production taxes as a percent of oil, gas and NGL sales decreased in the first quarter of 2019 compared to the fourth quarter of 2018 as improved Canadian heavy oil differentials resulted in a higher percentage of our oil, gas and NGL revenues being in Canada whereas the majority of our production taxes are assessed related to our U.S. upstream revenues.

~~Exploration Expenses~~

Q1 2019

Q4 2018

Change

Unproved impairments

$
1

$
19

- 95
%
Geological and geophysical

3

3

+0
%
Exploration overhead and other

9

22

- 59
%
Total

$
13

$
44

- 70
%

~~In the fourth quarter of 2018, we had unproved impairments primarily related to a portion of our U.S. non-core operations upon which we do not intend to pursue further exploration and development.~~

~~Other~~

Q1 2019

Q4 2018

Change

Asset dispositions

$
(44
)

$
(268
)

+84
%
Restructuring

54

9

+488
%
Other

(45
)

126

- 136
%
Total

$
(35
)

$
(133
)

+74
%

~~We recognized gains in conjunction with certain of our U.S. asset dispositions in 2019 and 2018.~~ For ~~further discussion,~~additional information, see Note 23 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

~~During~~

Marketing operations decreased approximately $23 million primarily from downstream product inventory impairments of $17 million recognized in the first quarter of ~~2019, we recognized restructuring and transaction costs primarily as a result of our workforce reductions. See~~2020.

Exploration expenses increased in 2020 due to $110 million in unproved asset impairments. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this ~~report for additional information.~~report.

~~The remaining change~~

Other expenses decreased due to a severance tax refund received in ~~other expense was driven primarily by changes in foreign currency exchange instruments as further discussed in~~2020 related to prior periods.

Income Taxes

	Q1 2020			Q4 2019
Current benefit	$	(106	)	$	(5	)
Deferred benefit		(311	)		(28	)
Total benefit	$	(417	)	$	(33	)
Effective income tax rate		20	%		155	%

For discussion on income taxes, see Note 67, in “Part I. Financial Information – Item 1. Financial Statements” in this report.

~~Income Taxes~~

Q1 2019

Q4 2018

Current benefit

$
(3
)

$
(23
)
Deferred expense (benefit)

(107
)

358

Total expense (benefit)

$
(110
)

$
335

Effective income tax rate

26
%

23
%

~~For discussion on income taxes, see~~ ~~Note 7in “Part I. Financial Information – Item 1. Financial Statements” in this report.~~

~~The following graphs, discussion and analysis are intended to provide an understanding of our results of~~Our first quarter 2020 net loss from continuing operations ~~and current financial condition. Specifically, the~~was $1.7 billion. The graph below shows the change in net ~~earnings~~loss from the ~~three months ended March 31, 2018~~first quarter of 2019 to the ~~three months ended March 31, 2019.~~first quarter of 2020. The material changes are further discussed ~~by category~~ on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

* Other includes asset dispositions, restructuring and transaction costs and other expenses.

Net earnings decreased $164 million during the first quarter of 2019 compared to the first quarter of 2018. The decrease primarily related to a $572 million decrease in upstream operations, driven by $668 million loss on valuation changes and cash settlements of commodity derivatives and a $60 million increase in depreciation, depletion and amortization. These changes were partially offset by lower financing costs primarily due to $312 million of early retirement of debt costs associated with our $800 million debt retirement in the first quarter of 2018.

~~The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.~~

Production Volumes

~~Upstream Operations~~

~~Production Volumes~~

Q1 2019

% of Total

Q1 2018

Change

Oil and bitumen (MBbls/d)

Delaware Basin

60

23
%

34

+74
%
STACK

32

13
%

34

- 4
%
Powder River Basin

15

6
%

15

+6
%
Eagle Ford

25

10
%

23

+8
%
Other

6

2
%

5

+7
%
New Devon

138

54
%

111

+24
%
Canada divest assets

112

44
%

129

- 13
%
U.S. divest assets

4

2
%

11

- 64
%
Total Oil and bitumen

254

100
%

251

+1
%

	Q1 2020		% of Total			Q1 2019		Change
Oil (MBbls/d)
Delaware Basin		84		51	%		60		+40	%
Anadarko Basin		24		15	%		32		- 27	%
Powder River Basin		21		13	%		15		+39	%
Eagle Ford		26		16	%		25		+6	%
Other		8		5	%		9		- 13	%
Total		163		100	%		141		+15	%

	Q1 2019		% of Total			Q1 2018		Change			Q1 2020		% of Total			Q1 2019		Change
Gas (MMcf/d)
Delaware Basin		146		15	%		93		+57	%		244		38	%		146		+68	%
STACK		333		32	%		324		+3	%
Anadarko Basin												272		43	%		333		- 18	%
Powder River Basin		18		2	%		12		+56	%		29		4	%		18		+56	%
Eagle Ford		83		8	%		63		+31	%		86		14	%		83		+3	%
Other		1		0	%		1		- 24	%		3		1	%		8		- 58	%
New Devon		581		57	%		493		+18	%
Canada divest assets		4		0	%		12		- 68	%
U.S. divest assets		439		43	%		672		- 35	%
Total		1,024		100	%		1,177		- 13	%		634		100	%		588		+8	%

	Q1 2019		% of Total			Q1 2018		Change			Q1 2020		% of Total			Q1 2019		Change
NGLs (MBbls/d)
Delaware Basin		23		22	%		11		+108	%		37		47	%		23		+62	%
STACK		35		34	%		35		+1	%
Anadarko Basin												30		37	%		35		- 17	%
Powder River Basin		2		2	%		1		+45	%		3		4	%		2		+44	%
Eagle Ford		12		11	%		8		+47	%		9		11	%		12		- 21	%
Other		1		1	%		1		+22	%		1		1	%		2		- 32	%
New Devon		73		70	%		56		+30	%
Divest assets		31		30	%		41		- 25	%
Total		104		100	%		97		+6	%		80		100	%		74		+9	%

	Q1 2019		% of Total			Q1 2018		Change			Q1 2020		% of Total			Q1 2019		Change
Combined (MBoe/d)
Delaware Basin		107		20	%		61		+76	%		162		47	%		107		+51	%
STACK		123		23	%		123		+0	%
Anadarko Basin												98		28	%		123		- 20	%
Powder River Basin		21		4	%		18		+15	%		29		8	%		21		+41	%
Eagle Ford		50		10	%		41		+22	%		50		14	%		50		- 1	%
Other		7		2	%		6		+8	%		9		3	%		12		- 22	%
New Devon		308		59	%		249		+23	%
Canada divest assets		113		21	%		131		- 14	%
U.S. divest assets		108		20	%		164		- 34	%
Total		529		100	%		544		- 3	%		348		100	%		313		+11	%

~~Strong performance~~An increase in production volumes from the first quarter of 2019 to the first quarter of 2020 contributed to a $133 million increase in earnings. Continued development in the Delaware Basin and ~~Eagle Ford~~Powder River Basin drove production ~~growth for New Devon during~~increases, which were slightly offset by decreased activity in the Anadarko Basin.

Field Prices

	Q1 2020		Realization		Q1 2019		Change
Oil (per Bbl)
WTI index	$	46.44			$	54.88		- 15	%
Realized price, unhedged	$	44.59		96%	$	51.83		- 14	%
Cash settlements	$	5.14			$	3.65
Realized price, with hedges	$	49.73		107%	$	55.48		- 10	%

	Q1 2020		Realization		Q1 2019			Change
Gas (per Mcf)
Henry Hub index	$	1.95			$	3.15			- 38	%
Realized price, unhedged	$	1.21		62%	$	2.62			- 54	%
Cash settlements	$	0.36			$	(0.31	)
Realized price, with hedges	$	1.57		81%	$	2.31			- 32	%

	Q1 2020		Realization		Q1 2019		Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	14.39			$	22.94		- 37	%
Realized price, unhedged	$	10.40		72%	$	18.36		- 43	%
Cash settlements	$	0.61			$	0.67
Realized price, with hedges	$	11.01		77%	$	19.03		- 42	%

(1)

Based upon composition of our NGL barrel.

	Q1 2020		Q1 2019		Change
Combined (per Boe)
Realized price, unhedged	$	25.43	$	32.65		- 22	%
Cash settlements	$	3.20	$	1.22
Realized price, with hedges	$	28.63	$	33.87		- 15	%

From the first quarter of 2019 ~~compared~~ to the first quarter of ~~2018.~~2020, field prices contributed to a $245 million decrease in earnings. Unhedged realized oil, gas and NGL prices decreased primarily due to lower WTI, Henry Hub and Mont Belvieu index prices. These ~~production gains~~decreases were partially offset by ~~lower production volumes associated with divest assets.~~

~~Field Prices~~

Q1 2019

Realization

Q1 2018

Change

Oil and bitumen (per Bbl)

WTI index

$
54.88

$
62.93

- 13
%
Access Western Blend index

$
40.37

$
35.44

+14
%
U.S.

$
51.83

94%

$
61.79

- 16
%
Canada

$
34.60

63%

$
19.74

+75
%
Realized price, unhedged

$
44.20

81%

$
40.15

+10
%
Cash settlements

$
(1.18
)

$
(0.10
)

Realized price, with hedges

$
43.02

78%

$
40.05

+7
%

Q1 2019

Realization

Q1 2018

Change

Gas (per Mcf)

Henry Hub index

$
3.15

$
3.01

+5
%
Realized price, unhedged

$
2.53

80%

$
2.41

+5
%
Cash settlements

$
(0.17
)

$
0.17

Realized price, with hedges

$
2.36

75%

$
2.58

- 9
%

Q1 2019

Realization

Q1 2018

Change

NGLs (per Bbl)

Mont Belvieu blended index ⁽¹⁾

$
22.94

$
25.88

- 11
%
Realized price, unhedged

$
18.64

81%

$
22.56

- 17
%
Cash settlements

$
0.48

$
(0.53
)

Realized price, with hedges

$
19.12

83%

$
22.03

- 13
%

~~(1)Based upon composition~~favorable hedge cash settlements across each of our ~~NGL barrel.~~

Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

LOE and gathering, processing and transportation increased primarily due to continued development and increased activity in the Delaware Basin.

Field-Level Cash Margin

The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL revenues less production expenses and is not prepared in accordance with GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, field prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.

Q1 2019

Q1 2018

Change

Combined (per Boe)

U.S.

$
28.58

$
30.39

- 6
%
Canada

$
34.42

$
19.45

+77
%
Realized price, unhedged

$
29.83

$
27.75

+8
%
Cash settlements

$
(0.82
)

$
0.23

Realized price, with hedges

$
29.01

$
27.98

+4
%

	Q1 2020		$ per BOE		Q1 2019		$ per BOE
Field-level cash margin (non-GAAP)
Delaware Basin	$	260	$	17.72	$	235	$	24.39
Anadarko Basin		74	$	8.22		203	$	18.27
Powder River Basin		54	$	20.48		50	$	27.02
Eagle Ford		87	$	19.20		128	$	28.53
Other		14	$	15.55		19	$	17.57
Total	$	489	$	15.41	$	635	$	22.54

DD&A and Asset Impairments

	Q1 2020		Q1 2019		Change
Oil and gas per Boe	$	11.90	$	11.73		+1	%

Oil and gas	$	377	$	331		+14	%
Other property and equipment		24		29		- 19	%
Total	$	401	$	360		+11	%

Asset impairments	$	2,666	$	—	N/M

Our oil and gas DD&A increased primarily due to continued development in the Delaware Basin and Powder River Basin properties.

~~Commodity prices realizations improved~~

Asset impairments were $2.7 billion in the first quarter of 2020 due to significant decreases in commodity prices since the end of 2019 ~~compared~~resulting primarily from the COVID-19 pandemic. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

General and Administrative Expenses

	Q1 2020		Q1 2019		Change
Labor and benefits (net of reimbursements)	$	66	$	86		- 23	%
Non-labor		36		49		- 27	%
Total Devon	$	102	$	135		- 24	%

Labor and benefits and non-labor expenses decreased primarily as a result of continued workforce reduction and cost savings initiatives.

Other Items

	Q1 2020			Q1 2019			Change in earnings
Commodity hedge valuation changes ⁽¹⁾	$	619		$	(639	)	$	1,258
Marketing and midstream operations		(18	)		15			(33	)
Exploration expenses		112			4			(108	)
Asset dispositions		—			(45	)		(45	)
Net financing costs		65			60			(5	)
Restructuring and transaction costs		—			51			51
Other expenses		(48	)		(22	)		26
							$	1,144

(1)

Included as a component of upstream revenues on the consolidated statements of comprehensive earnings.

We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Marketing operations decreased approximately $33 million primarily from downstream product inventory impairments of $17 million recognized in the first quarter of 2020.

Income Taxes

	Q1 2020			Q1 2019
Current benefit	$	(106	)	$	(4	)
Deferred benefit		(311	)		(115	)
Total benefit	$	(417	)	$	(119	)
Effective income tax rate		20	%		24	%

For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Table of Contents

Discontinued Operations

Results of Operations – Discontinued Operations

The table below presents key components from discontinued operations for the time periods presented. Discontinued operations include the Canadian business that Devon sold in June 2019 and the Barnett Shale assets that Devon has contracted to sell and which is expected to close on December 31, 2020. For additional information on discontinued operations, see Note 17 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

	Q1 2020			Q4 2019			Q1 2019
Upstream revenues	$	92		$	121		$	396
Production expenses	$	74		$	75		$	222
Marketing margin	$	—		$	—		$	17
Asset impairments	$	179		$	748		$	—
Restructuring and transaction costs	$	—		$	4		$	3
Earnings (loss) from discontinued operations before income taxes	$	(157	)	$	(724	)	$	70
Income tax expense (benefit)	$	(32	)	$	(72	)	$	9
Net earnings (loss) from discontinued operations, net of tax	$	(125	)	$	(652	)	$	61

Production (MMBoe):
Barnett Shale		9			9			9
Canada		—			—			10
Total production		9			9			19
Realized price, unhedged (per Boe) - Barnett Shale	$	10.16		$	13.45		$	16.18
Realized price, unhedged (per Boe) - Canada	N/A			N/A			$	34.42

Q1 2020 vs. Q4 2019

Net loss from discontinued operations, net of tax decreased $527 million due to a decrease in asset impairments from the fourth quarter of 2019 to the first quarter of ~~2018, primarily driven by a near 80% increase~~2020. During the first quarter of 2020, we recognized $179 million in asset impairments on our ~~realized Canadian oil and bitumen price.~~

~~Hedging~~

Q1 2019

Q1 2018

Change

Q

Oil

$
(27
)

$
(2
)

- 1250
%
Natural gas

(16
)

18

- 189
%
NGL

4

(5
)

+180
%
Total cash settlements

(39
)

11

- 455
%
Valuation changes

(670
)

(52
)

- 1188
%
Total

$
(709
)

$
(41
)

- 1629
%

~~Production Expenses~~

Q1 2019

Q1 2018

Change

LOE

$
220

$
241

- 9
%
Gathering, processing & transportation

203

228

- 11
%
Production taxes

68

59

+15
%
Property taxes

15

15

+0
%
Total

$
506

$
543

- 7
%
Per Boe:

LOE

$
4.63

$
4.91

- 6
%
Gathering, processing &
transportation

$
4.26

$
4.65

- 8
%
Percent of oil, gas and NGL sales:

Production taxes

4.8
%

4.4
%

+11
%

~~LOE decreased primarily~~Barnett Shale assets due to the ~~impact~~amended terms of the Barnett sales agreement. During the fourth quarter of 2019, we recognized a $748 million asset impairment to our ~~U.S. non-core asset divestitures.~~Barnett Shale assets.

~~Gathering, processing and transportation~~

Q1 2020 vs. Q1 2019

Net earnings (loss) from discontinued operations, net of tax decreased ~~approximately $20~~$186 million due to $179 million in incremental asset impairments to our Barnett Shale assets related to the ~~expiration~~amended terms of the ~~EnLink Bridgeport minimum volume commitment at~~Barnett sales agreement during the ~~end~~first quarter of ~~2018.~~

~~Production taxes increased, on an absolute dollar basis~~2020. Upstream revenues and ~~as a percentage~~production expenses decreased from the first quarter of ~~oil, gas and NGL sales, primarily~~2019 to the first quarter of 2020 due to Devon’s divestment of its Canadian business in the ~~increase in Oklahoma severance tax rates that became effective during the third~~second quarter of ~~2018.~~2019.

The following table presents the major changes in cash and cash equivalents for the three months ended March 31, ~~2019~~2020 and ~~2018.~~2019.

	Three months ended March 31,						Three Months Ended March 31st,
	2019			2018			2020			2019
Operating cash flow from continuing operations	$	377		$	610		$	529		$	437
Divestitures of property and equipment		311			47			25			310
Capital expenditures		(548	)		(651	)		(425	)		(490	)
Acquisitions of property and equipment		(11	)		(6	)		(4	)		(10	)
Debt activity, net		(162	)		(1,111	)		—			(162	)
Repurchases of common stock		(999	)		(71	)		(38	)		(999	)
Common stock dividends		(34	)		(32	)		(34	)		(34	)
Effect of exchange rate and other		(25	)		(53	)
Contributions from noncontrolling interests								5			—
Distributions to noncontrolling interests								(3	)		—
Other								(17	)		(19	)
Net change in cash, cash equivalents and restricted cash from discontinued operations		—			53			(155	)		(124	)
Net change in cash, cash equivalents and restricted cash	$	(1,091	)	$	(1,214	)	$	(117	)	$	(1,091	)
Cash, cash equivalents and restricted cash at end of period	$	1,355		$	1,470		$	1,727		$	1,355

As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. ~~However, changes in assets and liabilities, net, negatively impacted~~During the three months ended March 31, 2020, our operating cash flow by $302 million in the first quarter of 2019 primarily due to realizing impacts associated with the Canadian widening differentials in the fourth quarter of 2018. Excluding this short-term timing impact, operating cash flow before changes in assets and liabilities, net fully funded all our capital expenditures ~~during the first three months of 2019. We utilize~~and dividends, allowing us to use available cash balances ~~and divestiture proceeds~~ to ~~supplement our operating cash flows.~~fund other capital uses.

During the first three months of 2019, we sold non-core U.S. assets for approximately $300 million, net of customary purchase price adjustments. For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report. ~~During the first three months of 2018, we sold non-core U.S. assets for $47 million, net of customary purchase price adjustments.~~

The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.

	Q1 2019		Q1 2018		Three Months Ended March 31st,
Oil and gas	$	541	$	626
Corporate and other		7		25
					2020		2019
Delaware Basin					$	221	$	225
Powder River Basin						85		56
Eagle Ford						94		55
Anadarko Basin						8		136
Other						3		11
Total oil and gas						411		483
Midstream						8		—
Other						6		7
Total capital expenditures	$	548	$	651	$	425	$	490
Acquisitions	$	11	$	6	$	4	$	10

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Our capital program is designed to operate within or near operating cash flow. This is evidenced by our operating cash flow fully funding capital expenditures for the three months ended March 31, 2020 and ~~maintain significant flexibility.~~89% of

capital expenditures for the three months ended March 31, 2019. Our capital investment program is driven by a disciplined allocation process focused on returns. Our capital expenditures are lower in ~~2019~~2020 primarily due to our decreased spending in the ~~STACK.~~Anadarko Basin, partially offset by increased capital investment in the Powder River Basin and Eagle Ford. In response to the current macro-economic environment, we reduced our 2020 capital expenditures outlook by approximately $800 million, or 45% compared to the original capital budget, and expect to fund our 2020 capital program within operating cash flows even at current depressed commodity prices.

During the first quarter of 2019, our debt decreased $162 million due to the repayment of our 6.30% senior notes at maturity.

During the first quarter of 2018, our debt decreased $807 million due to completed tender offers of certain long-term debt. In conjunction with the tender offers, we recognized a $312 million loss on the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see ~~Note 14~~ ~~in “Part I. Financial Information – Item 1. Financial Statements” in this report.~~

~~Devon~~We paid common stock dividends of $34 million ($0.09 per share) and $34 million ($0.08 per share) ~~and $32 million ($0.06 per share) in common stock dividends~~ during the first three months of ~~2019~~2020 and ~~2018,~~2019, respectively. In February ~~2019,~~2020, we announced ana 22% increase to our quarterly dividend, to ~~$0.09~~$0.11 per share, beginning in the second quarter of ~~2019.~~2020. Beginning with the second quarter of 2019, we increased our quarterly dividend to $0.09 per share.

We repurchased 2.2 million shares of common stock for $38 million in the first three months of 2020 and 36.1 million shares of common stock for $1.0 billion in the first ~~quarter~~three months of 2019 ~~and 2.6 million shares of common stock for $82 million in the first quarter of 2018~~ under a share repurchase ~~program~~programs authorized by our Board of Directors. For additional information, see Note 1816 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

During the first quarter of 2020, we received $5 million in contributions from our noncontrolling interests in CDM and distributed $3 million to our noncontrolling interests in CDM.

All cash flows in the following table relate to activities of ~~EnLink~~our Canadian business that Devon sold in June 2019 and the ~~General Partner,~~Barnett Shale assets that Devon has contracted to sell and is expected to close in ~~which all our aggregate ownership was divested in July 2018.~~the fourth quarter of 2020.

	Three months ended			Three Months Ended March 31st,
	March 31, 2018			2020			2019
Cash flows from discontinued operations:
Canadian tax payments				$	(153	)	$	—
Other					22			(59	)
Operating activities	$	194			(131	)		(59	)
Investing activities		(180	)		(1	)		(59	)
Debt activity, net		122
Distributions to noncontrolling interests		(102	)
Other		19
Financing activities		39			—			(7	)
Effect of exchange rate changes on cash					(23	)		1
Net change in cash, cash equivalents and restricted cash of discontinued operations	$	53		$	(155	)	$	(124	)

~~Devon received $67 million~~Operating cash flows in ~~distributions from EnLink and the General Partner during~~ the first ~~three months~~quarter of 2020 include $153 million of cash income tax payments in Canada related to divestitures. Additionally, operating cash flow was negatively affected in the first quarter of 2019 primarily due to realization impacts associated with the widening Canadian differentials in the fourth quarter of 2018. ~~Distributions to noncontrolling interests~~See Note 2and Note 17 in ~~the table above exclude the distributions EnLink and the General Partner paid to Devon, which have been eliminated~~“Part I. Financial Information – Item 1. Financial Statements” in ~~consolidation.~~this report for additional details on these divestitures.

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be

accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. In February 2019, we announced plans to separate our Canadian and Barnett Shale assets and operations. We expect to complete these asset separations in 2019. We plan to use the proceeds from these transactions for debt repayments. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements as discussed in this section.

Beginning in the first quarter of 2020, the macro-economic environment has deteriorated significantly and has created extreme volatility primarily due to concerns arising from the COVID-19 pandemic. In response to this environment, we will continue to maintain flexibility within our capital program as we continue to focus on protecting our financial strength and maintaining operational continuity.

Key inputs into determining our planned capital investment isare the ~~amount~~amounts of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of the first quarter of ~~2019,~~2020, we held approximately ~~$1.3~~$1.7 billion of ~~cash.~~cash, inclusive of $200 million of cash restricted for discontinued operations. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as the actual results of these variables may differ from our expectations.

Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, ~~bitumen,~~ gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.

Actions taken by governments around the world in response to the COVID-19 pandemic have led to an unprecedented decline in global oil demand. Oil prices, which had already been trending down on concerns about oversupply, subsequently collapsed in March. Benchmark WTI spot oil prices fell from over $60/Bbl in early January to less than $20/Bbl in April.

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. We ~~target hedging approximately 50% of~~hedge our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. For the remainder of 2020, we have approximately 90% of our oil production hedged with an average floor price of $42/Bbl and approximately 45% of our gas production hedged with an average floor price of $2.15/Mcf. Additionally, we are currently building our 2021 hedge positions at market prices. The key terms to our oil, gas and NGL derivative financial instruments as of March 31, ~~2019~~2020 are presented in Note 3 in ~~“Item 8.~~“Part I. Financial ~~Statements and Supplementary Data”~~Information – Item 1. Financial Statements” of this report.

Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.

For 2019, we expect to aggressively optimize our cost structure in conjunction with our planned Canadian and Barnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with the retained business and reduce outstanding debt. We anticipate the planned $780 million reduction of annualized costs will occur over three years, with roughly 70% of the savings delivered by the end of 2019. Approximately 40% of the reduced costs relate to our capital programs and the remainder relates to our operating expenses, including G&A, interest expense and production expenses. As of March 31, 2019, we have completed workforce reduction and cost reduction initiatives expected to generate $110 million of annualized savings and are targeting $200 million of G&A savings by the end of 2019.

Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral ~~postings.~~postings and other protections allowed per our agreements.

~~We announced~~In April 2020, we amended the ~~separation~~terms on the sale of our ~~Canadian and~~ Barnett Shale ~~businesses,~~assets with an expected close date of December 31, 2020. Under the terms of the agreement, we received the deposit funds of $170 million in April 2020. The deposit is being held by us pursuant to the terms of the sale agreement, which ~~we intend~~only requires us to ~~complete by~~return such funds to BKV in the ~~end~~event the transaction does not close as a result of ~~2019,~~ ~~as discussed further in~~ our breach of our closing obligations.~~Note 2~~ ~~in “Part I. Financial Information – Item 1. Financial Statements” in this report.~~

In response to the current macro-economic environment, we reduced our 2020 capital expenditures outlook by approximately $800 million, or 45% compared to the original capital budget, and expect to fund our 2020 capital program within operating cash flows, even at current depressed commodity prices. Our exploration and development budget for the remainder of ~~2019~~2020 is expected to range from ~~$1.3~~$0.6 billion to ~~$1.5 billion, excluding capital associated~~$0.7 billion. As economic factors change, we will continue to be flexible with our ~~Canadian and Barnett Shale upstream assets.~~capital program.

As of March 31, ~~2019,~~2020, we had approximately ~~$2.9~~$3.0 billion of available ~~borrowings~~borrowing capacity under our Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At March 31, ~~2019,~~2020, there were no borrowings under our commercial paper program, and we were in compliance with the ~~facility’s~~Senior Credit Facility’s financial covenant.

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and

Poor’s Financial Services is ~~BBB~~BBB- with a negative outlook. Our credit rating from Fitch is ~~BBB+~~BBB with a ~~negative~~stable outlook. Our credit rating from Moody’s Investor Service is Ba1 with a ~~positive~~stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

In ~~February~~December 2019, our Board of Directors ~~authorized an expansion of our pre-existing~~approved a $1.0 billion share repurchase program ~~by an additional $1.0 billion~~that expires on December 31, 2020. Through March 31, 2020, we had executed $38 million of the authorized program. However, as the pricing and economic environment has deteriorated due to ~~$5.0 billion. The~~the COVID-19 pandemic and demand challenges for commodities, we have temporarily suspended our share repurchase program ~~expires December 31, 2019. Through March 31, 2019,~~to preserve liquidity. Additionally, due to the amended terms of our Barnett Shale divestiture, we ~~had executed $4.0 billion~~do not anticipate being able to purchase more than $200 million of the ~~authorized program.~~$1.0 billion authorization by the program expiration date. We will monitor economic conditions as they develop and may resume share repurchases of the remaining $162 million, subject to the commodity price environment, the Company’s liquidity and capital resources and other factors.

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We ~~regularly~~recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess ~~factors relative~~potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Due to ~~whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions~~an unprecedented downturn in the ~~U.S.~~commodity price environment and ~~existing U.S. income~~the resulting asset impairments, Devon had significant deferred tax ~~laws.~~assets at March 31, 2020. Accordingly, we have reassessed the realizability of our deferred tax assets in future periods and have recorded a 100% valuation allowance against our net deferred tax assets.

Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level (“common operating field”) for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is 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. 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. The expected future cash flows used for impairment reviews include future production volumes associated with proved producing and risk-adjusted proved undeveloped, probable and possible reserves.

Besides the risk-adjusted estimates of reserves and future production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we historically have utilized NYMEX forward

strip prices for the first five years and applied internally generated price forecasts for subsequent years. In response to the COVID-19 pandemic, the NYMEX forward market became highly illiquid as evidenced by materially reduced trading volumes for periods beyond 2021. Therefore, we altered our price forecast assumptions to perform our March 31, 2020 impairment computations. Specifically, we supplemented the NYMEX forward strip prices with price forecasts published by reputable investment banks and reservoir engineering firms to estimate our future revenues as of March 31, 2020.

We also estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost movements to price movements similar to recent history. To measure indicated impairments, we use a market-based weighted-average cost of capital to discount the future net cash flows. Changes into any of ~~these factors could require~~the reserves or market-based assumptions can significantly effect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of ~~additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when~~impairments.

Reduced demand from the ~~factors indicate that these earnings are no longer considered indefinitely reinvested.~~

~~During~~COVID-19 pandemic and management of production levels from Saudi Arabia and Russia caused WTI to decrease more than 60% during the first quarter of ~~2019, we announced our intent to separate all Canadian assets.~~2020. As a result, we reduced our ~~foreign earnings were no longer considered indefinitely reinvested~~planned 2020 capital investment 45%. With materially lower commodity prices and reduced near-term investment, we assessed all our oil and gas fields for impairment as of March 31, ~~2019. However,~~2020 and recognized proved and unproved impairments totaling $2.8 billion. The impairments relate to our Anadarko Basin and Rockies fields in which our basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher than they are today.

Based on our March 31, 2020 impairment evaluations, our Eagle Ford asset’s sum of undiscounted pre-tax cash flows exceeds the ~~deferred tax~~carrying value by less than 10%. This cushion narrowed significantly since the end of 2019 due to lower benchmark pricing and wider differentials used to estimate future commodity pricing. If prices deteriorate further and/or management significantly reduces planned capital investment in the Eagle Ford field, our Eagle Ford asset could be subject to a material impairment of capitalized costs.

We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. We perform a qualitative assessment to determine whether it is more likely than not that the fair value of goodwill is less than its carrying amount. As part of our ~~Canadian investment~~qualitative assessment, we considered the general macro-economic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers and stock performance. If the qualitative assessment determines that a quantitative goodwill impairment test is required, then the fair value is compared to the carrying value. If the fair value 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 ~~be recorded until~~available, the ~~form~~fair value is estimated based upon a valuation analyses including comparable companies and transactions and premiums paid.

Because the trading price of our common stock decreased 73% during the first quarter of 2020 in response to the COVID-19 pandemic, we performed a goodwill impairment test as of March 31, 2020. While the cushion narrowed significantly since our last impairment evaluation, we concluded an impairment was not required as of March 31, 2020. The two most critical judgements included in the March 31, 2020, test were the period utilized to determine Devon’s market capitalization and the control premium. For the test performed as of March 31, 2020, we derived our market capitalization by using our average common stock price from the latter two thirds of March 2020, to align with the time in the quarter subsequent to a key OPEC+ meeting and the date COVID-19 was officially classified as a pandemic. We applied a control premium based on recent comparable market transactions.

Subsequent to the end of the ~~separation is certain.~~first quarter of 2020, Devon’s common stock price increased approximately 80% during the month of April but remains significantly less than our average trading price before the events experienced in the first quarter of 2020. Although our common stock price and commodity prices are in a period of high volatility, a sustained period of depressed commodity prices would adversely affect our estimates of future operating results, which could result in future goodwill impairments due to the potential impact on the cash flows of our operations. The impairment of goodwill has no effect on liquidity or capital resources. However, it would adversely affect our results of operations in the period recognized.

For additional information regarding our critical accounting policies and estimates, see our 2019 Annual Report on Form 10-K.

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of ~~2019~~2020 Results” in this Item 2 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our financial results. ~~Additionally, we’ve presented our discontinued operations associated with the sale of our aggregate interests in EnLink and the General Partner separately.~~ For more information on the results of discontinued operations for ~~EnLink~~our Barnett Shale asset and ~~the General Partner,~~Canadian operations, see Note 1917 in “Part I. Financial Information – Item 1. Financial Statements” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded relate to asset dispositions, noncash asset impairments (including noncash unproved asset impairments), deferred tax asset valuation allowance, ~~costs associated with early retirement of debt,~~ fair value changes in derivative financial instruments and foreign currency, changes in tax legislation and restructuring and transaction costs associated with the workforce reductions ~~during~~in 2019.

We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

Below are reconciliations of our core earnings and core earnings per share attributable to Devon to their comparable GAAP measures.

	Before tax			After tax			After Noncontrolling Interests			Per Diluted Share			Three Months Ended March 31,
													Before tax			After tax			After Noncontrolling Interests			Per Diluted Share
2020
Continuing Operations
Loss attributable to Devon (GAAP)													$	(2,107	)	$	(1,690	)	$	(1,691	)	$	(4.48	)
Adjustments:
Asset and exploration impairments														2,776			2,146			2,146			5.66
Deferred tax asset valuation allowance														—			108			108			0.28
Fair value changes in financial instruments														(619	)		(479	)		(479	)		(1.24	)
Change in tax legislation														—			(62	)		(62	)		(0.16	)
Core earnings attributable to Devon (Non-GAAP)													$	50		$	23		$	22		$	0.06
Discontinued Operations
Loss attributable to Devon (GAAP)													$	(157	)	$	(125	)	$	(125	)	$	(0.34	)
Adjustments:
Asset impairments														179			141			141			0.38
Fair value changes in foreign currency and other														10			10			10			0.03
Core earnings attributable to Devon (Non-GAAP)													$	32		$	26		$	26		$	0.07
Total
Loss attributable to Devon (GAAP)													$	(2,264	)	$	(1,815	)	$	(1,816	)	$	(4.82	)
Adjustments:
Continuing Operations														2,157			1,713			1,713			4.54
Discontinued Operations														189			151			151			0.41
Core earnings attributable to Devon (Non-GAAP)													$	82		$	49		$	48		$	0.13
2019
Net loss (GAAP)	$	(427	)	$	(317	)	$	(317	)	$	(0.74	)
Continuing Operations
Loss attributable to Devon (GAAP)													$	(497	)	$	(378	)	$	(378	)	$	(0.89	)
Adjustments:
Asset dispositions		(44	)		(34	)		(34	)		(0.08	)		(45	)		(35	)		(35	)		(0.08	)
Asset and exploration impairments		1			1			1			0.00			1			1			1			0.00
Deferred tax asset valuation allowance		—			(18	)		(18	)		(0.04	)		—			(13	)		(13	)		(0.03	)
Fair value changes in financial instruments and foreign currency		635			484			484			1.12
Fair value changes in financial instruments														638			492			492			1.15
Restructuring and transaction costs		54			42			42			0.10			51			39			39			0.09
Core earnings (Non-GAAP)	$	219		$	158		$	158		$	0.36
2018
Continuing Operations
Net loss (GAAP)	$	(245	)	$	(211	)	$	(211	)	$	(0.41	)
Core earnings attributable to Devon (Non-GAAP)													$	148		$	106		$	106		$	0.24
Discontinued Operations
Loss attributable to Devon (GAAP)													$	70		$	61		$	61		$	0.15
Adjustments:
Asset dispositions		(12	)		(9	)		(9	)		(0.02	)		1			1			1			0.00
Asset and exploration impairments		10			7			7			0.01
Deferred tax asset valuation allowance		—			6			6			0.01			—			(5	)		(5	)		(0.01	)
Early retirement of debt		312			240			240			0.46
Fair value changes in financial instruments and foreign currency		61			60			60			0.12
Core earnings (Non-GAAP)	$	126		$	93		$	93		$	0.17
Discontinued Operations
Net earnings (GAAP)	$	64		$	58		$	14		$	0.03
Adjustments:
Fair value changes in financial instruments		2			2			1			0.00
Core earnings (Non-GAAP)	$	66		$	60		$	15		$	0.03
Fair value changes in financial instruments and foreign currency and other														(3	)		(8	)		(8	)		(0.03	)
Restructuring and transaction costs														3			3			3			0.01
Core earnings attributable to Devon (Non-GAAP)													$	71		$	52		$	52		$	0.12
Total
Net loss (GAAP)	$	(181	)	$	(153	)	$	(197	)	$	(0.38	)
Loss attributable to Devon (GAAP)													$	(427	)	$	(317	)	$	(317	)	$	(0.74	)
Adjustments:
Continuing Operations		371			304			304			0.58			645			484			484			1.13
Discontinued Operations		2			2			1			0.00			1			(9	)		(9	)		(0.03	)
Core earnings (Non-GAAP)	$	192		$	153		$	108		$	0.20
Core earnings attributable to Devon (Non-GAAP)													$	219		$	158		$	158		$	0.36

To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; ~~depreciation, depletion and amortization;~~DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL revenues less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.

We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.

We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.

Below are reconciliations of net earnings ~~from continuing operations~~ to EBITDAX and a further reconciliation to Field-Level Cash Margin. We have excluded the EBITDAX and Field-Level Cash Margin for our divested assets, Canada and the Barnett Shale to compute Adjusted EBITDAX and Adjusted Field-Level Cash Margin for New Devon. We use Adjusted EBITDAX and Adjusted Field-Level Cash Margin to assess the performance of our portfolio of upstream assets on a “same-store” basis across periods.

	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Net loss from continuing operations (GAAP)	$	(317	)	$	(211	)
Net loss (GAAP)							$	(1,815	)	$	(317	)
Net (earnings) loss from discontinued operations, net of tax								125			(61	)
Financing costs, net		73			387			65			60
Income tax benefit		(110	)		(34	)		(417	)		(119	)
Exploration expenses		13			33			112			4
Depreciation, depletion and amortization		459			399			401			360
Asset disposition gains		(44	)		(12	)
Asset impairments								2,666			—
Asset dispositions								—			(45	)
Share-based compensation		26			37			20			23
Derivative and financial instrument non-cash valuation changes		635			61			(619	)		638
Restructuring and transaction costs		54			—			—			51
Accretion on discounted liabilities and other		(10	)		12			(48	)		(22	)
EBITDAX (non-GAAP)		779			672			490			572
Marketing revenues and expenses, net		(32	)		(6	)
Marketing and midstream revenues and expenses, net								18			(15	)
Commodity derivative cash settlements		39			(11	)		(101	)		(34	)
General and administration expenses, cash-based		127			162			82			112
Field-level cash margin (non-GAAP)	$	913		$	817		$	489		$	635

EBITDAX (non-GAAP)	$	779		$	672
EBITDAX, Divested assets		(6	)		(39	)
EBITDAX, Canada		(154	)		(189	)
EBITDAX, Barnett Shale		(68	)		(85	)
Adjusted EBITDAX (non-GAAP)	$	551		$	359

Field-level cash margin (non-GAAP)	$	913		$	817
Field-level cash margin, Divested assets		(6	)		(39	)
Field-level cash margin, Canada		(210	)		(82	)
Field-level cash margin, Barnett Shale		(68	)		(85	)
Adjusted field-level cash margin (non-GAAP)	$	629		$	611

As of March 31, ~~2019,~~2020, we have commodity derivatives that pertain to a portion of our estimated production for the last nine months of ~~2019 and~~2020, as well as for ~~2020.~~2021. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At March 31, ~~2019,~~2020, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately ~~$230~~$140 million.

As of March 31, ~~2019,~~2020, we had total debt of ~~$5.8~~$4.3 billion. All of ~~this~~our debt ~~was~~is based on fixed interest rates averaging ~~5.4%~~6.0%.

~~Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the~~Devon has certain Canadian dollar ~~functional currency. Assets and liabilities of~~obligations associated with its divested Canadian operations which are to be paid with the ~~Canadian subsidiaries~~cash restricted for discontinued operations. These balances are ~~translated to U.S. dollars~~remeasured using the applicable exchange rate as of the end of ~~a reporting period. Revenues, expenses and cash flows are translated using an average exchange rate during~~ the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our March 31, ~~2019~~2020 balance ~~sheet.~~

~~Devon engages~~sheet for these items. See Note 17 in intercompany loan activity between subsidiaries with different functional currencies. The value of these foreign currency denominated intercompany loans increases or decreases from the remeasurement into the subsidiaries’ functional currency. Based on the amount of the intercompany loans as of March 31, 2019, a 10% change“Part I. Financial Information – Item 1. Financial Statements” in ~~the foreign currency exchange rates would not have materially impacted our balance sheet.~~this report for additional information.

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of March 31, ~~2019~~2020 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

We implemented internal controls to ensure we adequately evaluated our contracts and properly assessed the impact of the new lease accounting standard on our financial statements to facilitate its adoption in the first quarter of 2019. There were no ~~significant changes to our internal control over financial reporting due to the adoption of the new lease accounting standard. There were no other~~ changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.

On April 4, 2019, Devon Energy Production Company, L.P., a wholly-owned subsidiary of the Company (“DEPCO”), agreed to settle its previously disclosed negotiations with the EPA relating to certain alleged Clean Air Act violations at its Beaver Creek Gas Plant located near Riverton, Wyoming by executing an agreed order with the EPA. The order includes a penalty of $150,000 and is subject to the issuance of a final order from the regional EPA judicial officer. Moreover, in connection with the resolution of this matter with EPA, DEPCO expects to enter into consent decree with respect to the same matter with the Wyoming Department of Environmental Quality, which will also include a separate penalty of $150,000. Any such consent decree would be subject to court approval.

~~There~~Except for the addition of the pandemic risk factor discussed below, there have been no material changes to the information included in Item 1A. “Risk Factors” in our ~~2018~~2019 Annual Report on Form 10-K.

Our Business Has Been Adversely Impacted by the COVID-19 Pandemic, and We May Experience Continuing or Worsening Adverse Effects From This or Other Pandemics

Commodity Price Impacts – The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty and turmoil in the oil and gas industry. This outbreak and the related responses of governmental authorities and others to limit the spread of the virus have significantly reduced global economic activity, resulting in an unprecedented decline in the demand for oil and other commodities. This supply-and-demand imbalance has been exacerbated by uncertainty regarding the future global supply of oil due to disputes between Russia and the members of OPEC, particularly Saudi Arabia. These factors caused a swift and material deterioration in commodity prices in early 2020, with NYMEX WTI oil prices falling from over $60/Bbl at the beginning of the year to lower than $20/Bbl as of April 2020. While OPEC and other oil producing nations agreed in April 2020 to cut production, downward pressure on commodity prices has remained and could continue for the foreseeable future. This decline in commodity prices has already adversely impacted our results of operations for the first quarter of 2020 and contributed to our recognition of a material asset impairment to our oil and gas assets during the same period. As further described in the “Risk Factors” section of our 2019 Annual Report on Form 10-K, any sustained weakness or further deterioration in commodity prices could further adversely impact our results of operations, the value of our properties and our financial condition.

The current supply-and-demand imbalance has also imposed constraints on Devon’s and other operators’ ability to store and move production to downstream markets, which has resulted in the delay or curtailment of development activity, as well as the shutting-in of producing wells. Moreover, certain regional prices have disproportionally declined relative to broader market indices in areas that have experienced acute takeaway capacity constraints, thereby potentially further reducing our realized pricing in such impacted areas. If we are forced to shut in additional production, we will likely incur greater costs to bring the associated production back online, and such costs may be significant enough that such wells may become non-economic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut in.

General Financial and Economic Impacts - The negative effects of COVID-19 on economic prospects across the world have contributed to concerns for the potential of a prolonged economic slowdown and recession. Any such downturn, or a protracted period of depressed commodity prices, could have significant adverse consequences for our financial condition and liquidity, by, among other things: (i) limiting our ability to access sources of capital due to disruptions in financial markets or otherwise; and (ii) increasing the risk of a downgrade from credit rating agencies, which could trigger new credit support obligations and further adversely affect our ability to access financing or trade credit. Moreover, any such downturn could also result in similar financial constraints for our non-operating partners, purchasers of our production and other counterparties, thereby increasing the risk that such counterparties default on their obligations to us. Such defaults or more general supply chain disruptions due to the pandemic may also jeopardize the supply of materials, equipment or services for our operations. For additional information regarding liquidity and counterparty credit risks, please see the “Risk Factors” section of the 2019 Annual Report on Form 10-K.

Other Impacts - The COVID-19 pandemic and related restrictions aimed at mitigating its spread have caused us to modify certain of our business practices, including limiting employee travel, encouraging work-from-home practices and other social distancing measures. Such measures may cause disruptions to our business and operational plans, which may include shortages of employees, contractors and subcontractors. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the disease, including the risk of infection of key employees, and our ability to perform certain functions could be impaired by these new business practices. For example, our reliance on technology has necessarily increased due to our encouragement of remote communications and other work-from-home practices, which could make us more vulnerable to cyber attacks. See the “Risk Factors” section of the 2019 Annual Report on Form 10-K for additional information regarding cyber attack risks.

The COVID-19 pandemic and its related effects continue to rapidly evolve. The ultimate extent of the impact of the COVID-19 pandemic and any other future pandemic on our business will depend on future developments, including, but not limited to, the nature, duration and spread of the disease, the responsive actions to contain its spread or address its effects and the duration, timing and severity of the related consequences on commodity prices and the economy more generally, including any recession resulting from the pandemic. Any extended period of depressed commodity prices or general economic disruption as a result of the pandemic would adversely affect our business, financial condition and results of operations. In addition, the COVID-19 pandemic has heightened, and any future pandemic could heighten, the other risks and uncertainties discussed in the “Risk Factors” section of the 2019 Annual Report on Form 10-K.

The following table provides information regarding purchases of our common stock that were made by us during the first quarter of ~~2019~~2020 (shares in thousands).

Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs ⁽²⁾		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾		Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs ⁽²⁾		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
January 1 - January 31		9,888	$	26.05		9,836	$	1,766		18	$	24.99		—	$	1,000
February 1 - February 28		10,962	$	28.09		10,577	$	1,468
February 1 - February 29										2,175	$	18.71		1,568	$	973
March 1 - March 31		15,984	$	29.86		15,728	$	998		830	$	16.01		675	$	962
Total		36,834	$	28.31		36,141				3,023	$	18.00		2,243

Under the Devon Plan, eligible employees ~~may purchase~~made purchases of shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately ~~13,500~~5,800 shares of our common stock in the first quarter of ~~2019,~~2020, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Devon Plan through open-market purchases.

Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In the first quarter of 2019, there were 8,300 shares purchased by Canadian employees.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Delaware		73-1567067
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer identification No.)

333 West Sheridan Avenue, Oklahoma City, Oklahoma		73102-5015
(Address of principal executive offices)		(Zip code)


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, par value $0.10 per share	DVN	The New York Stock Exchange

Part I. Financial Information
Item 1.	Financial Statements	6
	Consolidated ~~Comprehensive~~ Statements of Comprehensive Earnings	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Equity	9
	Notes to Consolidated Financial Statements	10
	Note 1 – Summary of Significant Accounting Policies	10
	Note 2 – Divestitures	11
	Note 3 – Derivative Financial Instruments	11
	Note 4 – Share-Based Compensation	14
	Note 5 – ~~Restructuring and Transaction Costs~~Asset Impairments	15
	Note 6 – ~~Other Expenses~~Restructuring and Transaction Costs	15
	Note 7 – Income Taxes	16
	Note 8 – Net ~~Loss~~Earnings (Loss) Per Share From Continuing Operations	17
	Note 9 – Other Comprehensive Earnings (Loss)	17
	Note 10 – Supplemental Information to Statements of Cash Flows	18
	Note 11 – Accounts Receivable	18
	Note 12 – Property, Plant and Equipment	18
	Note 13 – ~~Other Current Liabilities~~	19
	~~Note 14 –~~ Debt and Related Expenses	19
	Note 14 – Leases	19
	Note 15 – ~~Leases~~Asset Retirement Obligations	20
	Note 16 – ~~Asset Retirement Obligations~~Stockholders’ Equity	2220
	Note 17 – ~~Retirement Plans~~Discontinued Operations and Assets Held For Sale	2221
	Note 18 – ~~Stockholders’ Equity~~Commitments and Contingencies	23
	Note 19 – ~~Discontinued Operations and Assets Held For Sale~~	23
	~~Note 20 – Commitments and Contingencies~~	24
	~~Note 21 –~~ Fair Value Measurements	25
	~~Note 22 – Segment Information~~	2624
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2725
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4042
Item 4.	Controls and Procedures	4042

Part II. Other Information
Item 1.	Legal Proceedings	4143
Item 1A.	Risk Factors	4143
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4144
Item 3.	Defaults Upon Senior Securities	4144
Item 4.	Mine Safety Disclosures	4144
Item 5.	Other Information	4144
Item 6.	Exhibits	4245

Signatures		4346

	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)
Q2-Q4 2019		46,891	$	59.97		87,484	$	54.60	$	64.62
Q1-Q4 2020		3,238	$	60.13		17,186	$	51.97	$	62.12

	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)
Q2-Q4 2020		82,207	$	36.87		50,449	$	51.11	$	61.14
Q1-Q4 2021		11,649	$	36.77		15,964	$	41.24	$	51.24


Large accelerated filer	☑	Accelerated filer	☐	Non-accelerated filer	☐
Smaller reporting company	☐	Emerging growth company	☐

	Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q2-Q4 2019	Midland Sweet		24,945	$	(0.46	)
Q2-Q4 2019	Argus LLS		8,900	$	5.10
Q2-Q4 2019	Argus MEH		20,945	$	3.24
Q2-Q4 2019	NYMEX Roll		38,000	$	0.45
Q2-Q4 2019	Western Canadian Select		62,762	$	(19.21	)
Q1-Q4 2020	NYMEX Roll		38,000	$	0.31
Q1-Q4 2020	Western Canadian Select		4,577	$	(20.80	)

	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q2-Q4 2019	Panhandle Eastern Pipe Line		63,018	$	(0.71	)
Q2-Q4 2019	El Paso Natural Gas		130,000	$	(1.46	)
Q2-Q4 2019	Houston Ship Channel		162,500	$	0.01
Q1-Q4 2020	Panhandle Eastern Pipe Line		30,000	$	(0.47	)
Q1-Q4 2020	El Paso Natural Gas		40,000	$	(0.67	)
Q1-Q4 2020	Houston Ship Channel		10,000	$	0.02

		Price Swaps
Period	Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q2-Q4 2019	Ethane		1,000	$	11.55
Q2-Q4 2019	Natural Gasoline		4,500	$	55.93
Q2-Q4 2019	Normal Butane		4,000	$	33.69
Q2-Q4 2019	Propane		8,500	$	30.01

	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
Balance as of December 31, 2018	$	47		$	16		$	63
Changes related to 2019 workforce reductions		30			—			30
Changes related to prior years' restructurings		(18	)		(3	)		(21	)
Balance as of March 31, 2019	$	59		$	13		$	72

Balance as of December 31, 2017	$	19		$	31		$	50
Changes related to prior years' restructurings		(1	)		(4	)		(5	)
Balance as of March 31, 2018	$	18		$	27		$	45

	March 31, 2019		December 31, 2018
Derivative liabilities	$	91	$	67
Accrued interest payable		106		80
Lease liabilities		67		—
Restructuring liabilities		59		47
Other		192		241
Other current liabilities	$	515	$	435

	March 31, 2019			December 31, 2018
6.30% due January 15, 2019	$	—		$	162
4.00% due July 15, 2021		500			500
3.25% due May 15, 2022		1,000			1,000
5.85% due December 15, 2025		485			485
7.50% due September 15, 2027		73			73
7.875% due September 30, 2031 ⁽¹⁾		675			675
7.95% due April 15, 2032 ⁽¹⁾		366			366
5.60% due July 15, 2041		1,250			1,250
4.75% due May 15, 2042		750			750
5.00% due June 15, 2045		750			750
Net discount on debentures and notes		(24	)		(24	)
Debt issuance costs		(39	)		(40	)
Total debt		5,786			5,947
Less amount classified as short-term debt		—			162
Total long-term debt	$	5,786		$	5,785

	March 31, 2020						December 31, 2019
	Finance		Operating		Total		Finance		Operating		Total
Right-of-use assets	$	227	$	10	$	237	$	229	$	14	$	243
Lease liabilities:
Current lease liabilities ⁽¹⁾	$	7	$	7	$	14	$	7	$	10	$	17
Long-term lease liabilities		242		3		245		240		4		244
Total lease liabilities	$	249	$	10	$	259	$	247	$	14	$	261

	Total Number of Shares Purchased		Dollar Value of Shares Purchased		Average Price Paid per Share
$5.0 Billion Plan
Full year 2018		78,149	$	2,978	$	38.11
First quarter 2019		36,141		1,024		28.33
Second quarter 2019		5,911		159		27.01
Third quarter 2019		22,137		550		24.80
Fourth quarter 2019		4,436		94		21.32
Total inception-to-date		146,774	$	4,805	$	32.74

$1.0 Billion Plan
First quarter 2020		2,243	$	38	$	16.85
Total inception-to-date		2,243	$	38	$	16.85

	Three Months Ended
	March 31, 2019
Operating lease cost ⁽¹⁾⁽²⁾	$	15
Short-term lease cost ⁽¹⁾⁽³⁾		26
Financing lease cost:
Amortization of right-of-use assets ⁽⁴⁾		6
Interest on lease liabilities ⁽⁵⁾		3
Variable lease cost ⁽¹⁾		1
Lease income ⁽¹⁾		(1	)
Net lease cost	$	50

	Finance			Operating
Cash outflows for lease liabilities:
Operating cash flows	$	2		$	3
Investing cash flows	$	—		$	15
Weighted average remaining lease term (years)		8.8			2.6
Weighted average discount rate		4.2	%		3.4	%

	Finance			Operating			Total ⁽¹⁾
2019	$	5		$	48		$	53
2020		7			47			54
2021		7			16			23
2022		8			7			15
2023		8			7			15
Thereafter		306			1			307
Total lease payments		341			126			467
Less: interest		(96	)		(6	)		(102	)
Present value of lease liabilities	$	245		$	120		$	365

	Pension Benefits
	Three Months Ended March 31,
	2019			2018
Service cost	$	2		$	3
Interest cost		9			10
Expected return on plan assets		(10	)		(14	)
Net actuarial loss ⁽¹⁾		3			4
Net periodic benefit cost ⁽²⁾	$	4		$	3

	Three Months Ended March 31, 2018
Marketing and midstream revenues	$	1,612
Marketing and midstream expenses		1,341
Depreciation, depletion and amortization		138
General and administrative expenses		27
Financing costs, net		44
Other expenses		(2	)
Total expenses		1,548
Earnings from discontinued operations before income taxes		64
Income tax expense		6
Net earnings from discontinued operations, net of income tax expense		58
Net earnings attributable to noncontrolling interests		44
Net earnings from discontinued operations attributable to Devon	$	14

	Q1 2019 ⁽⁴⁾			Q4 2018 ⁽⁴⁾		Change
Net earnings (loss)	$	(317	)	$	1,149		- 128	%
Net earnings (loss) per diluted share	$	(0.74	)	$	2.48		- 130	%
Core earnings⁽¹⁾	$	158		$	46		+243	%
Core earnings per diluted share ⁽¹⁾	$	0.36		$	0.10		+256	%
Total production (MBoe/d)		529			532		- 1	%
New Devon production (MBoe/d) ⁽²⁾		308			295		+4	%
Realized price per Boe ⁽³⁾	$	29.83		$	23.32		+28	%
Operating cash flow from continuing operations	$	377		$	542		- 30	%
Capitalized expenditures, including acquisitions	$	530		$	672		- 21	%
Cash and cash equivalents	$	1,327		$	2,414		- 45	%
Total debt	$	5,786		$	5,947		- 3	%

��	Q1 2019		% of Total			Q4 2018		Change
Oil and bitumen (MBbls/d)
Delaware Basin		60		23	%		45		+32	%
STACK		32		13	%		31		+3	%
Powder River Basin		15		6	%		13		+22	%
Eagle Ford		25		10	%		30		- 18	%
Other		6		2	%		6		+5	%
New Devon		138		54	%		125		+10	%
Canada divest assets		112		44	%		120		- 7	%
U.S. divest assets		4		2	%		8		- 49	%
Total Oil and bitumen		254		100	%		253		+1	%

Exhibit Number		Description


~~10.1~~10.1*		~~2019~~2020 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon Energy Corporation and ~~executive~~certain officers for restricted stock awarded.*awarded (CEO and EVP form).

~~10.2~~10.2*		~~2019~~2020 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon Energy Corporation and ~~executive~~certain officers for performance based restricted share units awarded.*awarded (CEO and EVP form).

10.3*		2020 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon Energy Corporation and certain officers for restricted stock awarded (SVP form).

10.4*		2020 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon Energy Corporation and certain officers for performance based restricted share units awarded (SVP form).

31.1		Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		Inline XBRL Instance Document – the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH		Inline XBRL Taxonomy Extension Schema Document.

101.CAL		Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		Inline XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

				DEVON ENERGY CORPORATION

Date: May ~~1, 2019~~6, 2020				/s/ Jeremy D. Humphers
				Jeremy D. Humphers
				Senior Vice President and Chief Accounting Officer