DEVON ENERGY CORP/DE - Quarter Report: 2018 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-32318

DEVON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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)

Registrant’s telephone number, including area code: (405) 235-3611

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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.


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

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 18, 2018, 523.4 million shares of common stock were outstanding.

Table of Contents

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS

Part I. Financial Information
Item 1.	Financial Statements	6
	Consolidated Comprehensive Statements of 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 – Revenue Recognition	11
	Note 3 – Acquisitions and Divestitures	14
	Note 4 – Derivative Financial Instruments	15
	Note 5 – Share-Based Compensation	18
	Note 6 – Asset Impairments	19
	Note 7 – Other Expenses	19
	Note 8 – Income Taxes	20
	Note 9 – Net Earnings (Loss) Per Share Attributable to Devon	21
	Note 10 – Other Comprehensive Earnings	22
	Note 11 – Supplemental Information to Statements of Cash Flows	22
	Note 12 – Accounts Receivable	22
	Note 13 – Property, Plant and Equipment	23
	Note 14 – Other Intangible Assets	23
	Note 15 – Other Current Liabilities	23
	Note 16 – Debt and Related Expenses	24
	Note 17 – Asset Retirement Obligations	25
	Note 18 – Retirement Plans	26
	Note 19 – Stockholders’ Equity	26
	Note 20 – Noncontrolling Interests	26
	Note 21 – Commitments and Contingencies	26
	Note 22 – Fair Value Measurements	27
	Note 23 – Segment Information	28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43

Part II. Other Information
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	45

Signatures		46

Table of Contents

DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” 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 Quarterly Report on Form 10-Q:

“ASC” means Accounting Standards Codification.

“ASU” means Accounting Standards Update.

“Bbl” or “Bbls” means barrel or barrels.

“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.

“Btu” means British thermal units, a measure of heating value.

“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.

“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.

“DD&A” means depreciation, depletion and amortization expenses.

“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.

“E&P” means exploration and production activities.

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

“FASB” means Financial Accounting Standards Board.

“G&A” means general and administrative expenses.

“GAAP” means U.S. generally accepted accounting principles.

“General Partner” means EnLink Midstream, LLC, the indirect general partner of EnLink.

“Inside FERC” refers to the publication Inside FERC’s Gas Market Report.

“LIBOR” means London Interbank Offered Rate.

“LOE” means lease operating expenses.

“MBbls” means thousand barrels.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet.

“MMBoe” means million Boe.

“MMBtu” means million Btu.

Table of Contents

“MMcf” means million cubic feet.

“M&M operations” means marketing and midstream revenues minus marketing and midstream expenses.

“N/M” means not meaningful.

“NGL” or “NGLs” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“OPIS” means Oil Price Information Service.

“SEC” means United States Securities and Exchange Commission.

“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.

“Tax Reform Legislation” means Tax Cuts and Jobs Act.

“TSR” means total shareholder return.

“Upstream operations” means upstream revenues minus production expenses.

“U.S.” means United States of America.

“WTI” means West Texas Intermediate.

“/Bbl” means per barrel.

“/d” means per day.

“/gal” means per gallon.

“/MMBtu” means per MMBtu.

Table of Contents

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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 “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2017 reserve reports and other data in our possession or available from third parties. 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:

•

the volatility of oil, gas and NGL prices;

•

uncertainties inherent in estimating oil, gas and NGL reserves;

•

the extent to which we are successful in acquiring and discovering additional reserves;

•

the uncertainties, costs and risks involved in oil and gas operations;

•

regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;

•

risks related to our hedging activities;

•

counterparty credit risks;

•

risks relating to our indebtedness;

•

cyberattack risks;

•

our limited control over third parties who operate some of our oil and gas properties;

•

midstream capacity constraints and potential interruptions in production;

•

the extent to which insurance covers any losses we may experience;

•

competition for leases, materials, people and capital;

•

our ability to successfully complete mergers, acquisitions and divestitures; and

•

any of the other risks and uncertainties discussed in this report, our 2017 Annual Report on Form 10-K and our other filings with the SEC.

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.

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

	Three Months Ended March 31,
	2018			2017
	(Unaudited)
Upstream revenues	$	1,319		$	1,541
Marketing and midstream revenues		2,491			2,010
Total revenues		3,810			3,551
Production expenses		543			457
Exploration expenses		33			95
Marketing and midstream expenses		2,214			1,814
Depreciation, depletion and amortization		537			528
Asset impairments		—			7
Asset dispositions		(12	)		(3	)
General and administrative expenses		226			231
Financing costs, net		431			128
Other expenses		19			(31	)
Total expenses		3,991			3,226
Earnings (loss) before income taxes		(181	)		325
Income tax expense (benefit)		(28	)		8
Net earnings (loss)		(153	)		317
Net earnings attributable to noncontrolling interests		44			14
Net earnings (loss) attributable to Devon	$	(197	)	$	303
Net earnings (loss) per share attributable to Devon:
Basic	$	(0.38	)	$	0.58
Diluted	$	(0.38	)	$	0.58
Comprehensive earnings (loss):
Net earnings (loss)	$	(153	)	$	317
Other comprehensive earnings, net of tax:
Foreign currency translation and other		(48	)		8
Pension and postretirement plans		4			5
Other comprehensive earnings, net of tax		(44	)		13
Comprehensive earnings (loss)		(197	)		330
Comprehensive earnings attributable to noncontrolling interests		44			14
Comprehensive earnings (loss) attributable to Devon	$	(241	)	$	316

See accompanying notes to consolidated financial statements

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
	2018			2017
	(Unaudited)
Cash flows from operating activities:
Net earnings (loss)	$	(153	)	$	317
Adjustments to reconcile net earnings to net cash from operating activities:
Depreciation, depletion and amortization		537			528
Asset impairments		—			7
Leasehold impairments		8			42
Accretion on discounted liabilities		16			24
Total (gains) losses on commodity derivatives		41			(232	)
Cash settlements on commodity derivatives		11			8
Gain on asset dispositions		(12	)		(3	)
Deferred income taxes		(32	)		(12	)
Share-based compensation		44			55
Early retirement of debt		312			—
Other		26			(24	)
Changes in assets and liabilities, net		6			36
Net cash from operating activities		804			746
Cash flows from investing activities:
Capital expenditures		(832	)		(653	)
Acquisitions of property and equipment		(6	)		(20	)
Divestitures of property and equipment		48			32
Proceeds from sale of investment		—			190
Other		—			(3	)
Net cash from investing activities		(790	)		(454	)
Cash flows from financing activities:
Borrowings of long-term debt, net of issuance costs		801			813
Repayments of long-term debt principal		(1,236	)		(587	)
Payment of installment payable		(250	)		(250	)
Early retirement of debt		(304	)		—
Issuance of subsidiary units		1			55
Repurchases of common stock		(71	)		—
Dividends paid on common stock		(32	)		(32	)
Contributions from noncontrolling interests		23			21
Distributions to noncontrolling interests		(102	)		(81	)
Shares exchanged for tax withholdings		(43	)		(61	)
Other		—			(2	)
Net cash from financing activities		(1,213	)		(124	)
Effect of exchange rate changes on cash		(15	)		(8	)
Net change in cash, cash equivalents and restricted cash		(1,214	)		160
Cash, cash equivalents and restricted cash at beginning of period		2,684			1,959
Cash, cash equivalents and restricted cash at end of period	$	1,470		$	2,119

Reconciliation of cash, cash equivalents and restricted cash:
Cash and cash equivalents	$	1,424		$	2,119
Restricted cash included in other current assets		46			—
Total cash, cash equivalents and restricted cash	$	1,470		$	2,119

See accompanying notes to consolidated financial statements

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	March 31, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,424		$	2,673
Accounts receivable		1,695			1,670
Other current assets		516			448
Total current assets		3,635			4,791
Oil and gas property and equipment, based on successful efforts accounting, net		13,475			13,318
Midstream and other property and equipment, net		7,908			7,853
Total property and equipment, net		21,383			21,171
Goodwill		2,383			2,383
Other long-term assets		1,915			1,896
Total assets	$	29,316		$	30,241
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	862		$	819
Revenues and royalties payable		1,269			1,180
Short-term debt		354			115
Other current liabilities		997			1,201
Total current liabilities		3,482			3,315
Long-term debt		9,628			10,291
Asset retirement obligations		1,141			1,113
Other long-term liabilities		567			583
Deferred income taxes		773			835
Equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 526 million and 525 million shares in 2018 and 2017, respectively		53			53
Treasury stock, at cost, 0.4 million shares in 2018		(12	)		—
Additional paid-in capital		7,269			7,333
Retained earnings		473			702
Accumulated other comprehensive earnings		1,122			1,166
Total stockholders’ equity attributable to Devon		8,905			9,254
Noncontrolling interests		4,820			4,850
Total equity		13,725			14,104
Total liabilities and equity	$	29,316		$	30,241

See accompanying notes to consolidated financial statements

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

									Retained			Accumulated
						Additional			Earnings			Other
	Common Stock					Paid-In			(Accumulated			Comprehensive			Treasury			Noncontrolling			Total
	Shares			Amount		Capital			Deficit)			Earnings			Stock			Interests			Equity
	(Unaudited)
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
Three Months Ended March 31, 2017
Balance as of December 31, 2016		523		$	52	$	7,237		$	(69	)	$	1,054		$	—		$	4,448		$	12,722
Net earnings		—			—		—			303			—			—			14			317
Other comprehensive earnings, net of tax		—			—		—			—			13			—			—			13
Restricted stock grants, net of cancellations		2			1		—			—			—			—			—			1
Common stock repurchased		—			—		—			—			—			(38	)		—			(38	)
Common stock retired		—			—		(38	)		—			—			38			—			—
Common stock dividends		—			—		—			(32	)		—			—			—			(32	)
Share-based compensation		1			—		30			—			—			—			—			30
Subsidiary equity transactions		—			—		10			—			—			—			75			85
Distributions to noncontrolling interests		—			—		—			—			—			—			(81	)		(81	)
Balance as of March 31, 2017		526		$	53	$	7,239		$	202		$	1,067		$	—		$	4,456		$	13,017

See accompanying notes to consolidated financial statement

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.Summary of Significant Accounting Policies

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 2017 Annual Report on Form 10-K.

The accompanying unaudited interim financial statements furnished 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, 2018 and 2017 and Devon’s financial position as of March 31, 2018.

Recently Adopted Accounting Standards

In January 2018, Devon adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606), using the modified retrospective method. See Note 2 for further discussion regarding Devon’s adoption of the revenue recognition standard.

In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU requires entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. As a result of adoption of this ASU, consolidated statement of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively.

In January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of adoption, Devon made changes to the statement of cash flows to include the required presentation and reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statement of cash flows.

Issued Accounting Standards Not Yet Adopted

The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019. Early adoption is permitted, but Devon does not plan to early adopt. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. However, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842), Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The proposed ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. Recently, the FASB issued ASU No. 2018-01, Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842. This ASU would permit an entity not to apply Topic 842 to land easements and rights-of-way that exist or expired before the effective date of Topic 842 and that were not previously assessed under Topic 840. An entity would continue to apply its current accounting policy for accounting for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements and rights-of-way to determine whether the arrangement should be accounted for as a lease. For Devon, these easement and right-of-way

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.

Devon has preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact the adoption will have on its consolidated financial statements and related disclosures. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls. Devon is in the process of designing processes and controls and implementing a technology solution needed to comply with the requirements of this ASU. While Devon cannot currently estimate the quantitative effect that ASU 2016-02 will have on its consolidated financial statements, the adoption will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities.

The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This ASU will expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company's risk management activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This ASU only applies to entities that elect hedge accounting, which Devon has not for derivative financial instruments. This ASU is effective for annual and interim periods beginning January 1, 2019, with early adoption permitted in 2018. The ASU is required to be adopted using a cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements if hedge accounting were elected by Devon in the future.

The FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220). This ASU allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and allows for early adoption in any interim period after issuance of the update. Devon is currently assessing the impact this ASU will have on its consolidated financial statements.

2.	Revenue Recognition

Impact of ASC 606 Adoption

Devon adopted ASC 606 - Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.

The impact of adoption in the current period results is as follows:

	Three Months Ended March 31, 2018
	Under ASC 606			Under ASC 605			Increase/(Decrease)
Upstream revenues	$	1,319		$	1,257		$	62
Marketing and midstream revenues		2,491			2,629			(138	)
Total impacted revenues	$	3,810		$	3,886		$	(76	)

Production expenses	$	543		$	481		$	62
Marketing and midstream expenses		2,214			2,352			(138	)
Total impacted expenses	$	2,757		$	2,833		$	(76	)

Loss before income taxes	$	(181	)	$	(181	)	$	—

Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses.

Changes to marketing and midstream revenues and expenses are due to the determination of when control is transferred. As a result, Devon has changed the classification of certain transactions from marketing and midstream revenues to expenses or from marketing and midstream expenses to revenues.

Upstream Revenues

Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings.

Natural gas and NGL Sales

Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statement of earnings.

In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statement of earnings.

Oil sales

Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statement of earnings.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Marketing and Midstream Revenues

Marketing and midstream revenues are generated as a result of performing gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services and marketing, through various contractual arrangements, which include fee-based arrangements or arrangements where Devon purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. Marketing and midstream revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold or services are provided to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. Control is transferred from the producer when the midstream processor has discretion on the sale or further processing of the liquids. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing and midstream revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership.

For contracts where control of commodities is transferred before the service is performed, Devon generally has no performance obligation for its services, and accordingly, does not consider these revenue-generating service contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities is transferred after the service is performed, Devon considers these contracts to contain performance obligations for its services. Accordingly, Devon considers the satisfaction of these performance obligations as revenue-generating and recognizes these fees as midstream services revenue at the time its performance obligations are satisfied. For contracts where control of commodities is never transferred, Devon simply earns a fee for its services and recognizes these fees as midstream services revenue at the time its performance obligations are satisfied.

Satisfaction of Performance Obligations and Revenue Recognitions

Since Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon applies the practical expedient in ASC 606 that allows recognition of revenue in the amount to which there is a right to invoice and prevents the need to estimate a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. Devon recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered at a fixed or determinable price.

Transaction Price Allocated to Remaining Performance Obligations

Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Cash received relating to future performance obligations are deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of March 31, 2018. Devon’s product sales and marketing and midstream contracts do not give rise to contract assets under ASC 606.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Disaggregation of Revenue

Revenue from both upstream revenues and marketing and midstream revenues represent revenue from contracts with customers and these revenue line items are reflected in the consolidated comprehensive statements of earnings. The following table presents revenue from contracts with customers that are disaggregated based on the type of good or service. During the quarter ended March 31, 2018, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue.

	Three Months Ended March 31, 2018
	U.S.			Canada		EnLink ⁽¹⁾		Total
Revenues from contracts with customers:
Oil	$	677		$	230	$	—	$	907
Gas		255			—		—		255
NGL		198			—		—		198
Oil, gas and NGL sales		1,130			230		—		1,360
Oil, gas and NGL derivatives		(113	)		72		—		(41	)
Total upstream revenues		1,017			302		—		1,319

Gathering and transportation		—			—		56		56
Processing		—			—		15		15
NGL services		—			—		16		16
Oil services		—			—		6		6
Total midstream services revenue		—			—		93		93
Oil and condensate		531			17		632		1,180
Gas		155			—		286		441
NGL		176			—		601		777
Total product sales		862			17		1,519		2,398
Total marketing and midstream revenues		862			17		1,612		2,491

Total revenues from contracts with customers	$	1,879		$	319	$	1,612	$	3,810

(1) Amounts presented net of eliminations

3.	Acquisitions and Divestitures

Devon Divestitures

In March 2018, Devon entered into a definitive agreement to sell a portion of its Barnett Shale assets, primarily located in Johnson County for $553 million, before purchase price adjustments. The transaction is expected to close in the second quarter of 2018. Estimated proved reserves associated with these assets are approximately 10% of total proved reserves. Devon anticipates the impact of the Johnson County divestiture will result in an adjustment to its capitalized costs with no gain recognition in the consolidated statement of earnings. In conjunction with the divestiture, Devon will settle certain gas processing contracts and expects to recognize an approximate $40 million settlement expense.

EnLink Divestitures

During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4.	Derivative Financial Instruments

Objectives and Strategies

Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These 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. As of March 31, 2018, Devon did not have any open 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.

Counterparty Credit Risk

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.

Commodity Derivatives

As of March 31, 2018, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

	Price Swaps				Price Collars
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q2-Q4 2018		58,855	$	53.74		83,167	$	50.28	$	60.28
Q1-Q4 2019		17,030	$	55.37		43,290	$	50.94	$	60.94

	Oil Basis Swaps						Oil Basis Collars
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)				Volume (Bbls/d)		Weighted Average Floor Differential to WTI ($/Bbl)			Weighted Average Ceiling Differential to WTI ($/Bbl)
Q2-Q4 2018	Midland Sweet		23,000	$	(1.02	)			—	$	—		$	—
Q2-Q4 2018	Argus LLS		12,000	$	3.95				—	$	—		$	—
Q2-Q4 2018	Western Canadian Select		69,018	$	(14.91	)			1,775	$	(15.50	)	$	(13.93	)
Q1-Q4 2019	Midland Sweet		28,000	$	(0.46	)			—	$	—		$	—

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of March 31, 2018, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas swaps that settle against the NYMEX last day settle natural gas index. The third table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.

	Price Swaps				Price Collars
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q2-Q4 2018		378,033	$	2.97		201,867	$	2.79	$	3.10
Q1-Q4 2019		52,622	$	2.90		52,844	$	2.77	$	3.07


	Price Swaps
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Q1-Q4 2019		128,164	$	2.78
Q1-Q4 2020		116,364	$	2.73

	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q2-Q4 2018	Panhandle Eastern Pipe Line		90,000	$	(0.43)
Q2-Q4 2018	El Paso Natural Gas		30,000	$	(0.85)
Q2-Q4 2018	Houston Ship Channel		60,000	$	(0.01)
Q2-Q4 2018	Transco Zone 4		10,036	$	(0.03)
Q1-Q4 2019	Houston Ship Channel		32,500	$	(0.02)
Q1-Q4 2019	Transco Zone 4		7,397	$	(0.03)

As of March 31, 2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.

		Price Swaps
Period	Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q2-Q4 2018	Ethane		6,500	$	11.86
Q2-Q4 2018	Natural Gasoline		5,500	$	54.24
Q2-Q4 2018	Normal Butane		6,750	$	38.46
Q2-Q4 2018	Propane		10,500	$	33.30

As of March 31, 2018, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.

Period	Product	Volume (Total)			Weighted Average Price Paid	Weighted Average Price Received
Q2 2018-Q1 2019	Propane		688	MBbls	Index	$0.75/gal
Q2 2018-Q4 2019	Natural Gas		71,418	MMBtu/d	Index	$2.10/MMBtu

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Interest Rate Derivatives

As of March 31, 2018, Devon had the following open interest rate derivative positions:

Notional		Rate Received	Rate Paid	Expiration
$	750	Three Month LIBOR	2.98%	December 2048 ⁽¹⁾
$	100	1.76%	Three Month LIBOR	January 2019

(1)

Mandatory settlement in December 2018.

Financial Statement Presentation

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

	Three Months Ended March 31,
	2018			2017
Commodity derivatives:
Upstream revenues	$	(41	)	$	232
Marketing and midstream revenues		1			4
Interest rate derivatives:
Other expenses		46			5
Net gains recognized	$	6		$	241

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

	March 31, 2018		December 31, 2017
Commodity derivative assets:
Other current assets	$	193	$	209
Other long-term assets		22		2
Interest rate derivative assets:
Other current assets		1		1
Total derivative assets	$	216	$	212
Commodity derivative liabilities:
Other current liabilities	$	328	$	267
Other long-term liabilities		27		27
Interest rate derivative liabilities:
Other current liabilities		22		64
Total derivative liabilities	$	377	$	358

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5.	Share-Based Compensation

The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings.

	Three Months Ended March 31,
	2018		2017
G&A	$	37	$	34
Exploration expenses		2		2
Total Devon		39		36
G&A		3		14
Marketing and midstream expenses		2		5
Total EnLink		5		19
Total	$	44	$	55
Related income tax benefit	$	1	$	1

Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first three months of 2018. 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
	Awards and Units					Restricted Stock Awards					Share Units
	Awards and Units			Weighted Average Grant-Date Fair Value		Awards			Weighted Average Grant-Date Fair Value		Units					Weighted Average Grant-Date Fair Value
	(Thousands, except fair value data)
Unvested at 12/31/17		6,328		$	36.81		575		$	38.92		2,758				$	41.21
Granted		3,425		$	35.77		—		$	—		845				$	37.40
Vested		(2,286	)	$	38.82		(227	)	$	43.14		(571	)			$	84.22
Forfeited		(85	)	$	35.13		—		$	—		(3	)			$	27.12
Unvested at 3/31/18		7,382		$	35.72		348		$	36.17		3,029		⁽¹	⁾	$	30.35

(1)	A maximum of 6.1 million common shares could be awarded based upon Devon’s final TSR ranking relative to Devon’s peer group established under applicable award agreements.

The following table presents the assumptions related to the performance share units granted in 2018, as indicated in the previous summary table.

	2018
Grant-date fair value		$36.23	—	$	37.88
Risk-free interest rate	2.28%
Volatility factor	45.8%
Contractual term (years)	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, 2018.

			Performance-Based
	Restricted Stock		Restricted Stock		Performance
	Awards and Units		Awards		Share Units
Unrecognized compensation cost	$	213	$	3	$	53
Weighted average period for recognition (years)		2.9		1.5		2.2

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

EnLink Share-Based Awards

The General Partner and EnLink issue restricted incentive units as bonus payments to officers and certain employees in the first quarter each year for the prior year’s performance. For the first quarter of 2018 and the first quarter of 2017, the combined grant date fair value for these awards was $6 million and $10 million, respectively.

The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of March 31, 2018.

	General Partner				EnLink
	Restricted		Performance		Restricted		Performance
	Incentive Units		Units		Incentive Units		Units
Unrecognized compensation cost	$	19	$	8	$	20	$	8
Weighted average period for recognition (years)		2.1		2.3		2.2		2.3

6.	Asset Impairments

Unproved Impairments

In the first quarter of 2018 and 2017, Devon allowed certain non-core acreage to expire without plans for development, resulting in unproved impairments of $8 million and $41 million, respectively. Unproved impairments are included in exploration expenses in the consolidated comprehensive statements of earnings.

7.	Other Expenses

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

	Three Months Ended March 31,
	2018			2017
Foreign exchange (gain) loss, net	$	50		$	(15	)
Asset retirement obligation accretion		16			17
Other, net		(47	)		(33	)
Total	$	19		$	(31	)

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Certain of Devon’s non-Canadian foreign subsidiaries have a U.S. dollar functional currency, hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. During the first quarter of 2018, Devon recognized foreign exchange losses related to these activities resulting from the strengthening of the U.S. dollar in relation to the Canadian dollar.

Restructuring and Transaction Costs

The following table summarizes Devon’s restructuring liabilities.

	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
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

Balance as of December 31, 2016		48			62			110
Changes related to prior years' restructurings		(15	)		(5	)		(20	)
Balance as of March 31, 2017	$	33		$	57		$	90

In April 2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon will incur additional restructuring charges and liabilities, ranging from $75 million to $100 million, beginning in the second quarter of 2018.

8.	Income Taxes

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,
	2018			2017
Current income tax expense	$	4		$	20
Deferred income tax benefit		(32	)		(12	)
Total income tax expense (benefit)	$	(28	)	$	8

U.S. statutory income tax rate		21	%		35	%
State income taxes		1	%		2	%
Other		(5	%)		(1	%)
Deferred tax asset valuation allowance		(2	%)		(34	%)
Effective income tax rate		15	%		2	%

Devon estimates its annual effective income tax rate in recording 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. Under the Tax Reform Legislation, the U.S. corporate income tax rate was reduced to 21% effective January 1, 2018.

In the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on Devon’s effective income tax rate. However, these items have a more noticeable impact to the rate in the first quarter of 2018 due to lower relative earnings during the period.

Throughout 2017 and through the first quarter of 2018, Devon continued to maintain a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to oil and gas impairments and significant net

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

operating losses for U.S. federal and state income tax. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.

During the first quarter of 2018, Devon repatriated approximately $92 million from certain international entities. This repatriation had no tax impact.

In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, Devon considers the accounting of the transition tax, deferred tax remeasurements and other items to be incomplete due to the forthcoming guidance and ongoing analysis of Devon’s tax positions. Devon expects to complete its analysis within the measurement period in accordance with SAB 118. No material changes to the provisional amounts recorded in the fourth quarter of 2017 have been made during the first quarter of 2018.

Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. The timing of resolution of income tax examinations is uncertain as are the amounts and timing of tax payments that are part of any audit settlement process. Devon believes that within the next 12 months it is reasonably possible that certain tax examinations will be resolved by settlement with the taxing authorities.

9.	Net Earnings (Loss) Per Share Attributable to Devon

The following table reconciles net earnings (loss) attributable to Devon and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.

	Three Months Ended March 31,
	2018			2017
Net earnings (loss):
Net earnings (loss) attributable to Devon	$	(197	)	$	303
Attributable to participating securities		—			(3	)
Basic and diluted earnings (loss)	$	(197	)	$	300
Common shares:
Common shares outstanding - total		527			525
Attributable to participating securities		(7	)		(6	)
Common shares outstanding - basic		520			519
Dilutive effect of potential common shares issuable		—			3
Common shares outstanding - diluted		520			522
Net earnings (loss) per share attributable to Devon:
Basic	$	(0.38	)	$	0.58
Diluted	$	(0.38	)	$	0.58
Antidilutive options ⁽¹⁾		2			3

(1)	Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

10.	Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

	Three Months Ended March 31,
	2018			2017
Foreign currency translation and other:
Beginning accumulated foreign currency translation and other	$	1,309		$	1,226
Change in cumulative translation adjustment and other		(61	)		11
Income tax benefit (expense)		13			(3	)
Ending accumulated foreign currency translation and other		1,261		$	1,234
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(143	)		(172	)
Recognition of net actuarial loss and prior service cost in earnings ⁽¹⁾		4			5
Ending accumulated pension and postretirement benefits		(139	)		(167	)
Accumulated other comprehensive earnings, net of tax	$	1,122		$	1,067

(1)	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of Other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 18 for additional details.

11.	Supplemental Information to Statements of Cash Flows

	Three Months Ended March 31,
	2018			2017
Changes in assets and liabilities, net
Accounts receivable	$	(27	)	$	48
Other current assets		(79	)		(21	)
Other long-term assets		(52	)		1
Accounts payable		14			4
Revenues and royalties payable		84			73
Other current liabilities		76			(89	)
Other long-term liabilities		(10	)		20
Total	$	6		$	36
Interest paid (net of capitalized interest)	$	76		$	92
Income taxes paid	$	1		$	3

12.	Accounts Receivable

Components of accounts receivable include the following:

	March 31, 2018			December 31, 2017
Oil, gas and NGL sales	$	536		$	559
Joint interest billings		132			134
Marketing and midstream revenues		989			959
Other		50			29
Gross accounts receivable		1,707			1,681
Allowance for doubtful accounts		(12	)		(11	)
Net accounts receivable	$	1,695		$	1,670

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

13.Property, Plant and Equipment

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

	March 31, 2018			December 31, 2017
Property and equipment, at cost:
Proved	$	47,685		$	47,295
Unproved and properties under development		2,478			2,457
Total oil and gas		50,163			49,752
Less accumulated DD&A		(36,688	)		(36,434	)
Oil and gas property and equipment, net		13,475			13,318
EnLink midstream and other		9,298			9,120
Devon midstream and other		1,957			1,955
Less accumulated DD&A		(3,347	)		(3,222	)
Midstream and other property and equipment, net		7,908			7,853
Property and equipment, net	$	21,383		$	21,171

14.	Other Intangible Assets

The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.

	March 31, 2018			December 31, 2017
Customer relationships	$	1,796		$	1,796
Accumulated amortization		(330	)		(299	)
Net intangibles	$	1,466		$	1,497

The weighted-average amortization period for other intangible assets is 15 years. Amortization expense for intangibles was $31 million and $29 million for the three months ended March 31, 2018 and 2017, respectively. The remaining amortization expense is estimated to be $123 million for each of the next five years.

15.	Other Current Liabilities

Components of other current liabilities include the following:

	March 31, 2018		December 31, 2017
Derivative liabilities	$	350	$	331
Installment payment		—		250
Income taxes payable		142		145
Accrued interest payable		147		131
Restructuring liabilities		18		19
Other		340		325
Other current liabilities	$	997	$	1,201

EnLink’s final installment payment relating to its acquisition of Anadarko Basin gathering and processing midstream assets in 2016 was paid in January 2018 using borrowings under EnLink’s credit facility.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

16.Debt and Related Expenses

A summary of debt is as follows:

	March 31, 2018			December 31, 2017
Devon debt:
8.25% due July 1, 2018	$	20		$	20
2.25% due December 15, 2018		95			95
6.30% due January 15, 2019		162			162
4.00% due July 15, 2021		500			500
3.25% due May 15, 2022		1,000			1,000
5.85% due December 15, 2025		485			485
7.50% due September 15, 2027		73			73
7.875% due September 30, 2031 ⁽¹⁾		675			1,059
7.95% due April 15, 2032 ⁽¹⁾		366			789
5.60% due July 15, 2041		1,250			1,250
4.75% due May 15, 2042		750			750
5.00% due June 15, 2045		750			750
Net discount on debentures and notes		(25	)		(30	)
Debt issuance costs		(35	)		(39	)
Total Devon debt		6,066			6,864
EnLink and General Partner debt:
Credit facilities		447			74
2.70% due April 1, 2019		400			400
4.40% due April 1, 2024		550			550
4.15% due June 1, 2025		750			750
4.85% due July 15, 2026		500			500
5.60% due April 1, 2044		350			350
5.05% due April 1, 2045		450			450
5.45% due June 1, 2047		500			500
Net discount on debentures and notes		(6	)		(6	)
Debt issuance costs		(25	)		(26	)
Total EnLink and General Partner debt		3,916			3,542
Total debt		9,982			10,406
Less amount classified as short-term debt⁽²⁾		354			115
Total long-term debt	$	9,628		$	10,291

(1)	These senior notes were included in the 2018 tender offer repurchases discussed below.

(2)

Short-term debt as of March 31, 2018 consists of Devon’s $20 million of 8.25% senior notes due July 1, 2018, $95 million of 2.25% senior notes due December 15, 2018 and $162 million of 6.30% senior notes due January 15, 2019 and $77 million of borrowings under the General Partner’s credit facility due March 7, 2019.

Credit Lines

Devon has a $3.0 billion Senior Credit Facility. As of March 31, 2018, Devon had $51 million in outstanding letters of credit under the Senior Credit Facility. There were no outstanding borrowings under the Senior Credit Facility at March 31, 2018. 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, 2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 26.2%.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Retirement of Senior Notes

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.

EnLink Debt

All of EnLink’s and the General Partner’s debt is non-recourse to Devon.

EnLink has a $1.5 billion unsecured revolving credit facility. As of March 31, 2018, there were $10 million in outstanding letters of credit and $370 million in outstanding borrowings at an average rate of 3.3% under the $1.5 billion credit facility. The General Partner has a $250 million secured revolving credit facility. As of March 31, 2018, the General Partner had $77 million in outstanding borrowings at an average rate of 3.5%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of March 31, 2018.

Net Financing Costs

The following schedule includes the components of net financing costs.

	Three Months Ended March 31,
	2018			2017
Devon net financing costs:
Interest based on debt outstanding	$	96		$	97
Early retirement of debt		312			—
Capitalized interest		(18	)		(16	)
Other		(3	)		2
Total Devon net financing costs		387			83
EnLink net financing costs:
Interest based on debt outstanding		44			40
Interest accretion on deferred installment payment		1			7
Other		(1	)		(2	)
Total EnLink net financing costs		44			45
Total net financing costs	$	431		$	128

17. Asset Retirement Obligations

The following table presents the changes in Devon’s asset retirement obligations.

	Three Months Ended March 31,
	2018			2017
Asset retirement obligations as of beginning of period	$	1,152		$	1,272
Liabilities incurred and assumed through acquisitions		15			10
Liabilities settled and divested		(20	)		(13	)
Revision of estimated obligation		23			(184	)
Accretion expense on discounted obligation		16			17
Foreign currency translation adjustment		(13	)		4
Asset retirement obligations as of end of period		1,173			1,106
Less current portion		32			39
Asset retirement obligations, long-term	$	1,141		$	1,067

During the first quarter of 2017, Devon reduced its estimated asset retirement obligations by $184 million primarily due to changes in the assumed inflation rate and retirement dates for its oil and gas assets.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

18.	Retirement Plans

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

	Pension Benefits
	Three Months Ended
	March 31,
	2018			2017

Service cost	$	3		$	4
Interest cost		10			11
Expected return on plan assets		(14	)		(14	)
Amortization of prior service cost ⁽¹⁾		—			1
Net actuarial loss ⁽¹⁾		4			4
Net periodic benefit cost ⁽²⁾	$	3		$	6

(1)

These net periodic benefit costs were reclassified out of other comprehensive earnings.

(2)

The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in Other expenses in the accompanying consolidated comprehensive statements of earnings.

19.	Stockholders’ Equity

Devon announced a share-repurchase program to buy up to $1.0 billion of shares of common stock, which expires March 7, 2019. During the first quarter of 2018, Devon repurchased 2.6 million shares of common stock for $83 million, or $32.19 per share, under this program.

Devon paid common stock dividends of $32 million, or $0.06 per share, in the first three months of 2018 and 2017, respectively. Additionally, Devon announced a 33% increase to its quarterly dividend beginning in the second quarter of 2018.

20.	Noncontrolling Interests

Subsidiary Equity Transactions

As of March 31, 2018, Devon’s ownership interest in EnLink was 23%, excluding the interest held by the General Partner. Devon’s controlling ownership interest in the General Partner as of March 31, 2018 was 64%.

EnLink has the ability to sell common units through its “at the market” equity offering programs. During the first three months of 2017, EnLink issued and sold 3 million common units through its programs and generated $55 million in net proceeds.

Distributions to Noncontrolling Interests

EnLink and the General Partner distributed $102 million and $81 million to non-Devon unitholders during the first three months of 2018 and 2017, respectively.

21.	Commitments and Contingencies

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Royalty Matters

Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

Environmental Matters

Devon is subject to certain environmental, health and safety laws and regulations, including with respect to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.

Other Matters

Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.

22.	Fair Value Measurements

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at March 31, 2018 and December 31, 2017. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items is provided in Note 6 and Note 14, respectively.

							Fair Value
							Measurements Using:
	Carrying			Total Fair			Level 1		Level 2
	Amount			Value			Inputs		Inputs
March 31, 2018 assets (liabilities):
Cash equivalents	$	335		$	335		$	259	$	76
Commodity derivatives	$	215		$	215		$	—	$	215
Commodity derivatives	$	(355	)	$	(355	)	$	—	$	(355	)
Interest rate derivatives	$	1		$	1		$	—	$	1
Interest rate derivatives	$	(22	)	$	(22	)	$	—	$	(22	)
Debt	$	(9,982	)	$	(10,719	)	$	—	$	(10,719	)
Capital lease obligations	$	(4	)	$	(3	)	$	—	$	(3	)

December 31, 2017 assets (liabilities):
Cash equivalents	$	1,533		$	1,533		$	1,454	$	79
Commodity derivatives	$	211		$	211		$	—	$	211
Commodity derivatives	$	(294	)	$	(294	)	$	—	$	(294	)
Interest rate derivatives	$	1		$	1		$	—	$	1
Interest rate derivatives	$	(64	)	$	(64	)	$	—	$	(64	)
Debt	$	(10,406	)	$	(11,782	)	$	—	$	(11,782	)
Installment payment	$	(250	)	$	(250	)	$	—	$	(250	)
Capital lease obligations	$	(4	)	$	(3	)	$	—	$	(3	)

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Level 1 Fair Value Measurements

Cash equivalents – Amounts consist primarily of money market investments and U.S. and Canadian treasury securities. The fair value approximates the carrying value.

Level 2 Fair Value Measurements

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

Commodity and interest rate derivatives – The fair values of commodity and interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. The fair value of the credit facility balance is the carrying value.

Installment payment – The fair value of the EnLink installment payment was based on Level 2 inputs from third-party market quotations.

Capital lease obligations – The fair value was calculated using inputs from third-party banks.

23.	Segment Information

Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian 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.

Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

	U.S.			Canada			EnLink			Eliminations			Total
Three Months Ended March 31, 2018:
Revenues from external customers	$	1,879		$	319		$	1,612		$	—		$	3,810
Intersegment revenues	$	—		$	—		$	149		$	(149	)	$	—
Depreciation, depletion and amortization	$	305		$	94		$	138		$	—		$	537
Interest expense	$	247		$	164		$	44		$	(16	)	$	439
Asset dispositions	$	(12	)	$	—		$	—		$	—		$	(12	)
Earnings (loss) before income taxes	$	(100	)	$	(145	)	$	64		$	—		$	(181	)
Income tax expense (benefit)	$	1		$	(35	)	$	6		$	—		$	(28	)
Net earnings (loss)	$	(101	)	$	(110	)	$	58		$	—		$	(153	)
Net earnings attributable to noncontrolling interests	$	—		$	—		$	44		$	—		$	44
Net earnings (loss) attributable to Devon	$	(101	)	$	(110	)	$	14		$	—		$	(197	)
Property and equipment, net	$	10,538		$	4,186		$	6,659		$	—		$	21,383
Total assets	$	13,477		$	5,271		$	10,615		$	(47	)	$	29,316
Capital expenditures, including acquisitions	$	612		$	89		$	181		$	—		$	882
Three Months Ended March 31, 2017:
Revenues from external customers	$	2,081		$	319		$	1,151		$	—		$	3,551
Intersegment revenues	$	—		$	—		$	171		$	(171	)	$	—
Depreciation, depletion and amortization	$	302		$	98		$	128		$	—		$	528
Interest expense	$	80		$	20		$	45		$	(15	)	$	130
Asset impairments	$	—		$	—		$	7		$	—		$	7
Asset dispositions	$	(7	)	$	(1	)	$	5		$	—		$	(3	)
Earnings (loss) before income taxes	$	325		$	(12	)	$	12		$	—		$	325
Income tax expense	$	3		$	2		$	3		$	—		$	8
Net earnings (loss)	$	322		$	(14	)	$	9		$	—		$	317
Net earnings attributable to noncontrolling interests	$	—		$	—		$	14		$	—		$	14
Net earnings (loss) attributable to Devon	$	322		$	(14	)	$	(5	)	$	—		$	303
Property and equipment, net	$	10,030		$	4,078		$	6,396		$	—		$	20,504
Total assets	$	13,644		$	4,869		$	10,177		$	(55	)	$	28,635
Capital expenditures, including acquisitions	$	346		$	82		$	248		$	—		$	676

Table of Contents

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, 2018 compared to previous periods and in our financial condition and liquidity since December 31, 2017. For information regarding our critical accounting policies and estimates, see our 2017 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Overview of 2018 Results

Key components of our financial performance as compared to prior quarter are summarized below.

	Q1 2018 ⁽³⁾			Q4 2017 ⁽³⁾		Change
Net earnings (loss) attributable to Devon	$	(197	)	$	183		- 208	%
Net earnings (loss) per diluted share attributable to Devon	$	(0.38	)	$	0.35		- 209	%
Core earnings attributable to Devon⁽¹⁾	$	108		$	199		- 46	%
Core earnings per diluted share attributable to Devon ⁽¹⁾	$	0.20		$	0.38		- 48	%
Retained production (MBoe/d)		511			512	0		%
Total production (MBoe/d)		544			548		- 1	%
Realized price per Boe ⁽²⁾	$	27.75		$	27.59		+1	%
Operating cash flow	$	804		$	725		+11	%
Capitalized expenditures, including acquisitions	$	882		$	840		+5	%
Shareholder and noncontrolling interests distributions	$	134		$	139		- 4	%
Cash and cash equivalents	$	1,424		$	2,673		- 47	%
Total debt	$	9,982		$	10,406		- 4	%

(1)

Core earnings and core earnings per diluted share attributable to Devon are financial measures not prepared in accordance with GAAP. For a description of core earnings and core earnings per diluted share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.

(2)	Excludes any impact of oil, gas and NGL derivatives.

(3)	Except for balance sheet amounts, which are presented as of period end.

During the first three months of 2018, we generated solid operating results with our three-fold strategy of operating in North America’s best resource plays, delivering superior execution and maintaining a high degree of financial strength. Led by our development in the STACK and Delaware Basin, we continued to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells.

We continue to focus on our “2020 Vision,” which is our plan through the end of the decade intended to optimize returns and deliver top-tier, capital-efficient cash flow growth. Our 2020 Vision is focused on the following strategic priorities:

•

Maximize cash flow by optimizing base production and reducing per-unit cash costs;

•

Improve capital efficiency with a concentration of investment on highest-returning development projects in the Delaware Basin and STACK;

•

Simplify our portfolio by monetizing non-core assets;

•

Improve financial strength by reducing debt; and

•

Return cash to shareholders.

During the first three months of 2018, we made several strides to achieve our 2020 Vision and enhance shareholder value. Specifically, we had several key achievements:

•

Reduced long-term debt by approximately $800 million using cash on hand.

•

Authorized and began executing a $1.0 billion share-repurchase program.

•

Announced the sale of our Johnson County assets for $553 million. Upon expected closing in the second quarter of 2018, divestiture proceeds associated with our 2020 Vision will reach approximately $1.1 billion since 2017.

•

Increased our quarterly common stock dividends 33% to $0.08 per share beginning in the second quarter of 2018.

•

Subsequent to quarter-end, we completed a workforce reduction and we continue other cost reduction initiatives expected to generate $110 million of annualized savings.

Table of Contents

We exited the first quarter of 2018 with liquidity comprised of $1.4 billion of cash and $2.9 billion of available credit under our Senior Credit Facility. We have no significant debt maturities until 2021. We currently have approximately 60% of our expected oil and gas production protected for the remainder of 2018. 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, including Western Canadian Select and Midland Sweet basis oil hedges. We are building our 2019 hedge positions at market prices.

Results of Operations – Q1 2018 vs. Q4 2017

The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Due to the nature of our business, including an inherently volatile commodity price environment, we have provided a sequential quarter analysis in order to facilitate the review of our operational results and provide further transparency of our business. Specifically, the graph below shows the change in net earnings from the three months ended December 31, 2017 to the three months ended March 31, 2018. 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. Additional information regarding noncontrolling interests is discussed in Note 20 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

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

Table of Contents

Upstream Operations

Oil, Gas and NGL Production

	Q1 2018		% of Total			Q4 2017		Change
Oil and bitumen (MBbls/d)
STACK		35		14	%		30		+20	%
Delaware Basin		36		14	%		32		+13	%
Rockies Oil		18		7	%		15		+17	%
Heavy Oil		18		7	%		18		+1	%
Eagle Ford		23		9	%		27		- 16	%
Barnett Shale		1		0	%		1		+18	%
Other		9		5	%		9		- 5	%
Retained assets		140		56	%		132		+6	%
Divested assets		—		0	%		—		N/M
Total Oil		140		56	%		132		+6	%
Bitumen		111		44	%		114		- 3	%
Total Oil and bitumen		251					246		+2	%

	Q1 2018		% of Total			Q4 2017		Change
Gas (MMcf/d)
STACK		344		29	%		316		+9	%
Delaware Basin		97		8	%		89		+9	%
Rockies Oil		18		2	%		14		+27	%
Heavy Oil		12		1	%		15		- 18	%
Eagle Ford		63		5	%		87		- 27	%
Barnett Shale		470		40	%		466		+1	%
Other		10		1	%		13		- 27	%
Retained assets		1,014		86	%		1,000		+1	%
Divested assets		163		14	%		175		- 7	%
Total		1,177					1,175		+0	%

	Q1 2018		% of Total			Q4 2017		Change
NGLs (MBbls/d)
STACK		37		38	%		34		+7	%
Delaware Basin		11		12	%		13		- 9	%
Rockies Oil		2		2	%		1		+38	%
Eagle Ford		8		8	%		13		- 41	%
Barnett Shale		31		32	%		36		- 13	%
Other		2		2	%		3		- 40	%
Retained assets		91		94	%		100		- 9	%
Divested assets		6		6	%		6		- 5	%
Total		97					106		- 8	%

	Q1 2018		% of Total			Q4 2017		Change
Combined (MBoe/d)
STACK		129		24	%		117		+11	%
Delaware Basin		64		12	%		60		+7	%
Rockies Oil		23		4	%		19		+20	%
Heavy Oil		131		24	%		134		- 2	%
Eagle Ford		41		8	%		55		- 25	%
Barnett Shale		110		20	%		114		- 3	%
Other		13		2	%		13		- 2	%
Retained assets		511		94	%		512		- 0	%
Divested assets		33		6	%		36		- 7	%
Total		544					548		- 1	%

Production declines reduced our upstream revenue by $15 million. Retained production results were highlighted by strong oil production in the STACK, Delaware Basin and Rockies, averaging 16% growth from prior quarter. These noted production gains were offset by reduced completion activity in the Eagle Ford.

Oil, Gas and NGL Prices

	Q1 2018			Realization		Q4 2017			Change
Oil and bitumen (per Bbl)
WTI index	$	62.93				$	55.49			+13	%
Access Western Blend index	$	35.44				$	40.94			- 13	%
U.S.	$	61.79			98%	$	54.18			+14	%
Canada	$	19.74			31%	$	32.54			- 39	%
Realized price, unhedged	$	40.15			64%	$	42.59			- 6	%
Cash settlements	$	(0.10	)			$	(0.38	)
Realized price, with hedges	$	40.05			64%	$	42.21			- 5	%

	Q1 2018		Realization		Q4 2017		Change
Gas (per Mcf)
Henry Hub index	$	3.01			$	2.93		+3	%
Realized price, unhedged	$	2.41		80%	$	2.29		+5	%
Cash settlements	$	0.17			$	0.19
Realized price, with hedges	$	2.58		86%	$	2.48		+4	%

	Q1 2018			Realization		Q4 2017			Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	25.88				$	28.61			- 10	%
Realized price, unhedged	$	22.56			87%	$	18.46			+22	%
Cash settlements	$	(0.53	)			$	(0.30	)
Realized price, with hedges	$	22.03			85%	$	18.16			+21	%

(1)	Based upon composition of our NGL barrel.

Table of Contents

	Q1 2018		Q4 2017		Change
Combined (per Boe)
U.S.	$	30.39	$	26.18		+16	%
Canada	$	19.45	$	31.95		- 39	%
Realized price, unhedged	$	27.75	$	27.59		+1	%
Cash settlements	$	0.23	$	0.19
Realized price, with hedges	$	27.98	$	27.78		+1	%

Oil, gas and NGL sales decreased $15 million primarily as a result of three pricing factors during the quarter. First, our U.S. oil revenues benefitted $70 million from a 13% increase in the average WTI index during the quarter. Second, the average realization in Canada was significantly lower than prior quarter due to export and pipeline constraints that reduced our revenues approximately $150 million. Third, as discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $62 million during the first quarter of 2018 with no impact to net earnings.

Commodity Derivatives

	Q1 2018			Q4 2017			Change
	Q
Oil	$	(2	)	$	(8	)		+76	%
Natural gas		18			21			- 13	%
NGL		(5	)		(3	)		- 68	%
Total cash settlements		11			10			+7	%
Valuation changes		(52	)		(67	)		+22	%
Total	$	(41	)	$	(57	)		+28	%

Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

In addition to cash settlements, we also 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.

Production Expenses

	Q1 2018			Q4 2017			Change
LOE	$	241		$	236			+2	%
Gathering, processing & transportation		228			163			+40	%
Production taxes		59			51			+16	%
Property taxes		15			13			+15	%
Total	$	543		$	463			+17	%
Per Boe:
LOE	$	4.91		$	4.68			+5	%
Gathering, processing & transportation	$	4.65		$	3.23			+44	%
Percent of oil, gas and NGL sales:
Production taxes		4.4	%		3.7	%		+19	%

As discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, gathering, processing and transportation expense increased $65 million primarily due to the presentation of certain processing arrangements changing from a net to a gross presentation. The change resulted in increases to our upstream revenues and production expense by $62 million during the first quarter of 2018, with no impact to net earnings.

Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed.

Marketing & Midstream Operations

	Q1 2018			Q4 2017			Change
Operating revenues	$	1,761		$	1,756			+0	%
Product purchases		(1,381	)		(1,374	)		+1	%
Operations and maintenance expenses		(109	)		(110	)		- 1	%
EnLink margin		271			272			- 0	%
Devon margin		6			—		N/M
Total	$	277		$	272			+2	%

As further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, in 2018 EnLink’s marketing and midstream revenues decreased by $138 million with a corresponding decrease to marketing and midstream expenses as a result of complying with the new revenue recognition accounting standard.

Exploration Expenses

	Q1 2018		Q4 2017		Change
Unproved impairments	$	8	$	137		- 94	%
Geological and geophysical		10		17		- 41	%
Exploration overhead and other		15		17		- 12	%
Total	$	33	$	171		- 81	%

Unproved impairments primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development.

Depreciation, Depletion and Amortization

	Q1 2018		Q4 2017		Change
Oil and gas per Boe	$	7.63	$	7.14		+7	%
Oil and gas	$	374	$	360		+4	%
Midstream and other assets		25		30		- 14	%
Devon		399		390		+2	%
EnLink		138		138		- 0	%
Total	$	537	$	528		+2	%

Our oil and gas DD&A remained relatively flat as compared to the prior period. Increases in oil and gas DD&A rates were due to continued development in the STACK and Delaware Basin.

Table of Contents

Financing Costs, net

Financing costs, net increased $305 million primarily as a result of costs associated with our $800 million early debt retirement in 2018. We estimate that total cash interest expense will be reduced by approximately $64 million on an annualized basis as a result of the early retirement. For additional information on our debt and related expenses, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Income Taxes

	Q1 2018			Q4 2017
Current expense	$	4		$	41
Deferred benefit		(32	)		(245	)
Total benefit	$	(28	)	$	(204	)
Effective income tax rate		15	%		(203	%)

For discussion on income taxes, see Note 8 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Table of Contents

Results of Operations – Q1 2018 vs. Q1 2017

The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Specifically, the graph below shows the change in net earnings from the three months ended March 31, 2017 to the three months ended March 31, 2018. 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. Additional information regarding noncontrolling interests is discussed in Note 20 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

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

Table of Contents

Upstream Operations

Oil, Gas and NGL Production

	Q1 2018		% of Total			Q1 2017		Change
Oil and bitumen (MBbls/d)
STACK		35		14	%		21		+68	%
Delaware Basin		36		14	%		30		+21	%
Rockies Oil		18		7	%		13		+38	%
Heavy Oil		18		7	%		18		- 1	%
Eagle Ford		23		9	%		46		- 51	%
Barnett Shale		1		0	%		1		- 21	%
Other		9		5	%		11		- 21	%
Retained assets		140		56	%		140		- 0	%
Divested assets		—		0	%		2		- 100	%
Total oil		140		56	%		142		- 1	%
Bitumen		111		44	%		119		- 7	%
Total oil and bitumen		251					261		- 4	%

	Q1 2018		% of Total			Q1 2017		Change
Gas (MMcf/d)
STACK		344		29	%		287		+20	%
Delaware Basin		97		8	%		87		+12	%
Rockies Oil		18		2	%		15		+22	%
Heavy Oil		12		1	%		23		- 46	%
Eagle Ford		63		5	%		115		- 45	%
Barnett Shale		470		40	%		498		- 6	%
Other		10		1	%		12		- 17	%
Retained assets		1,014		86	%		1,037		- 2	%
Divested assets		163		14	%		191		- 14	%
Total		1,177					1,228		- 4	%

	Q1 2018		% of Total			Q1 2017		Change
NGLs (MBbls/d)
STACK		37		38	%		26		+41	%
Delaware Basin		11		12	%		10		+20	%
Rockies Oil		2		2	%		1		+71	%
Eagle Ford		8		8	%		15		- 47	%
Barnett Shale		31		32	%		36		- 12	%
Other		2		2	%		2		- 13	%
Retained assets		91		94	%		90		+2	%
Divested assets		6		6	%		8		- 24	%
Total		97					98		- 0	%

	Q1 2018		% of Total			Q1 2017		Change
Combined (MBoe/d)
STACK		129		24	%		95		+36	%
Delaware Basin		64		12	%		54		+18	%
Rockies Oil		23		4	%		17		+38	%
Heavy Oil		131		24	%		141		- 7	%
Eagle Ford		41		8	%		80		- 49	%
Barnett Shale		110		20	%		120		- 8	%
Other		13		2	%		14		- 10	%
Retained assets		511		94	%		521		- 2	%
Divested assets		33		6	%		42		- 21	%
Total		544					563		- 3	%

Production declines reduced our upstream revenues by $38 million due to reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale. These decreases were partially offset by our focused development activities in the STACK, Delaware Basin and Rockies, where we saw production increases averaging 30% from Q1 2017.

Oil, Gas and NGL Prices

	Q1 2018			Realization		Q1 2017		Change
Oil and bitumen (per Bbl)
WTI index	$	62.93				$	52.00		+21	%
Access Western Blend index	$	35.44				$	35.16		+1	%
U.S.	$	61.79			98%	$	49.65		+24	%
Canada	$	19.74			31%	$	26.30		- 25	%
Realized price, unhedged	$	40.15			64%	$	37.33		+8	%
Cash settlements	$	(0.10	)			$	0.50
Realized price, with hedges	$	40.05			64%	$	37.83		+6	%

	Q1 2018		Realization		Q1 2017			Change
Gas (per Mcf)
Henry Hub index	$	3.01			$	3.32			- 9	%
Realized price, unhedged	$	2.41		80%	$	2.68			- 10	%
Cash settlements	$	0.17			$	(0.03	)
Realized price, with hedges	$	2.58		86%	$	2.65			- 3	%

	Q1 2018			Realization		Q1 2017		Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	25.88				$	23.93		+8	%
Realized price, unhedged	$	22.56			87%	$	15.46		+46	%
Cash settlements	$	(0.53	)			$	—
Realized price, with hedges	$	22.03			85%	$	15.46		+42	%

(1)

Based upon composition of our NGL barrel.

Table of Contents

	Q1 2018		Q1 2017		Change
Combined (per Boe)
U.S.	$	30.39	$	25.86		+18	%
Canada	$	19.45	$	25.73		- 24	%
Realized price, unhedged	$	27.75	$	25.82		+7	%
Cash settlements	$	0.23	$	0.15
Realized price, with hedges	$	27.98	$	25.97		+8	%

Upstream revenues increased $89 million as a result of higher unhedged, realized prices for our oil and NGLs. The increase in oil sales primarily resulted from higher average WTI crude index prices, which were 21% higher in 2018. Additionally, NGL prices improved 8% at the Mont Belvieu, Texas hub compared to Q1 2017. Slightly offsetting these increases were widening oil and bitumen differentials in Canada due to export and pipeline constraints. Gas prices were lower due to lower North American regional index prices upon which our gas sales are based.

As further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $62 million during the first quarter of 2018 with no impact to net earnings.

Commodity Derivatives

	Q1 2018			Q1 2017			Change

Oil	$	(2	)	$	12			- 117	%
Natural gas		18			(4	)		+550	%
NGL		(5	)		—		N/M
Total cash settlements		11			8			+38	%
Valuation changes		(52	)		224			- 123	%
Total	$	(41	)	$	232			- 118	%

Production Expenses

	Q1 2018			Q1 2017			Change
LOE	$	241		$	223			+8	%
Gathering, processing & transportation		228			163			+40	%
Production taxes		59			55			+7	%
Property taxes		15			16			- 6	%
Total	$	543		$	457			+19	%
Per Boe:
LOE	$	4.91		$	4.41			+11	%
Gathering, processing & transportation	$	4.65		$	3.21			+45	%
Percent of oil, gas and NGL sales:
Production taxes		4.4	%		4.2	%		+4	%

Gathering, processing and transportation expense increased $65 million primarily due to the presentation of certain processing arrangements changing from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $62 million during the first quarter of 2018 with no impact to net earnings.

Marketing & Midstream Operations

	Q1 2018			Q1 2017			Change
Operating revenues	$	1,761		$	1,322			+33	%
Product purchases		(1,381	)		(1,002	)		+38	%
Operations and maintenance expenses		(109	)		(104	)		+5	%
EnLink margin		271			216			+25	%
Devon margin		6			(20	)		- 130	%
Total	$	277		$	196			+42	%

The overall increase in marketing and midstream operating margin was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities.

Exploration Expenses

	Q1 2018		Q1 2017		Change
Unproved impairments	$	8	$	41		- 80	%
Geological and geophysical		10		42		- 76	%
Exploration overhead and other		15		12		+25	%
Total	$	33	$	95		- 65	%

Unproved impairments primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs decreased primarily in the STACK and Delaware Basin as we move into full-scale development.

Depreciation, Depletion and Amortization

	Q1 2018		Q1 2017		Change
Oil and gas per Boe	$	7.63	$	7.35		+4	%
Oil and gas	$	374	$	372		+1	%
Midstream and other assets		25		28		- 9	%
Devon		399		400		- 0	%
EnLink		138		128		+8	%
Total	$	537	$	528		+2	%

Financing Costs, net

Financing costs, net increased $303 million primarily as a result of our $800 million early debt retirement in 2018. For additional information on our debt and related expenses, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Table of Contents

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the three months ended March 31, 2018 and 2017.

	Devon						EnLink						Consolidated
	2018			2017			2018			2017			2018			2017
Operating cash flow	$	610		$	569		$	194		$	177		$	804		$	746
Divestitures of property and investments		47			32			1			190			48			222
EnLink and General Partner distributions		67			66			(67	)		(66	)		—			—
Capital expenditures		(651	)		(397	)		(181	)		(256	)		(832	)		(653	)
Acquisitions of property and equipment		(6	)		(20	)		—			—			(6	)		(20	)
Debt activity, net		(1,111	)		—			122			(24	)		(989	)		(24	)
Shareholder and noncontrolling interests distributions		(32	)		(32	)		(102	)		(81	)		(134	)		(113	)
Repurchases of common stock		(71	)		—			—			—			(71	)		—
Subsidiary unit transactions		—			—			1			55			1			55
Effect of exchange rate and other		(53	)		(61	)		18			8			(35	)		(53	)
Net change in cash, cash equivalents and restricted cash	$	(1,200	)	$	157		$	(14	)	$	3		$	(1,214	)	$	160
Cash, cash equivalents and restricted cash at end of period	$	1,453		$	2,104		$	17		$	15		$	1,470		$	2,119

Devon Sources and Uses of Cash

Operating Cash Flow

Net cash provided by operating activities increased 7% primarily due to higher commodity prices as compared to the first quarter of 2017.

Our operating cash flow funded 94% of our capital expenditures during the first quarter of 2018.

Divestitures of Property and Equipment

During the first three months of 2018, as part of our announced divestiture program, we sold non-core U.S. assets for approximately $47 million, net of customary purchase price adjustments.

EnLink and General Partner Distributions

Devon received $67 million and $66 million in distributions from EnLink and the General Partner during the first three months of 2018 and 2017, respectively.

Capital Expenditures and Acquisitions of Property and Equipment

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

	Q1 2018		Q1 2017
Oil and gas	$	626	$	383
Corporate and other		25		14
Total capital expenditures		651		397
Acquisitions	$	6	$	20

Capital expenditures consist of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Devon’s 2018 objectives are to concentrate capital spend in the STACK and Delaware Basin, while investing within cash flow and maintaining significant flexibility. Our capital investment program is driven by a disciplined

Table of Contents

allocation process focused on returns. Our capital expenditures are higher in 2018 due to our continued development in the STACK and Delaware Basin.

Debt Activity

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 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Shareholder Distributions and Stock Activity

Devon paid $32 million, or $0.06 per share, in common stock dividends during the first three months of 2018 and 2017. Devon announced an increase to its quarterly dividend to $0.08 per share beginning in the second quarter of 2018.

In March 2018, we announced a share-repurchase program to buy up to $1.0 billion of shares of common stock, which expires March 7, 2019. Including unsettled shares, we repurchased 2.6 million shares of common stock for $83 million, or $32.19 per share through March 31, 2018.

EnLink Sources and Uses of Cash

EnLink’s operating cash flow has increased $17 million as a result of its continued development activities. Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. EnLink’s capital expenditures are lower in 2018 primarily due to lower capital expenditure levels for expansion projects.

During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. Proceeds were primarily used to pay a portion of the $250 million installment payment related to EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets.

During the first quarter of 2018, EnLink’s consolidated net debt borrowings increased $122 million. The increase was partially due to EnLink’s increased credit facility borrowings to fund growth capital expenditures and was partially offset by the payment of the remaining portion of the deferred installment payment related to its acquisition of Anadarko Basin gathering and processing midstream assets.

During the first quarter of 2017, EnLink’s consolidated net debt borrowings decreased $24 million. The decrease was partially due to EnLink’s payment of a portion of the deferred installment payment related to its acquisition of Anadarko Basin gathering and processing midstream assets and was partially offset by increased credit facility borrowings to fund growth capital expenditures.

EnLink and the General Partner distributed $102 million and $81 million to non-Devon unitholders during the first three months of 2018 and 2017, respectively.

During the first quarter 2017, EnLink issued and sold 3 million common units and generated $55 million in net proceeds, through its “at the market” programs. During the first three months of 2018, EnLink issued and sold an immaterial amount of common units through its “at the market” programs.

Devon Liquidity

Our primary sources of capital and liquidity are our operating cash flow, asset divestiture proceeds and cash on hand. 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. Available sources of capital and liquidity also include, among other things, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. We estimate the combination of these sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments, share repurchases and other contractual commitments as discussed in this section.

Table of Contents

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our operating cash flow increased approximately $58 million in the first three months of 2018 compared to the first three months of 2017 largely due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as we adjust our capital program to invest within our operating cash flow. Furthermore, proceeds from non-core asset divestitures will provide additional liquidity as needed.

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 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 additional information on our derivative positions in place at March 31, 2018, see Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Divestitures of Property and Equipment

To further focus our resource-rich portfolio, we are targeting asset divestiture proceeds in excess of $5 billion. In March 2018, we advanced this divestiture goal by announcing the sale of our Johnson Country asset in the southern part of the Barnett Shale position for $553 million, subject to customary purchase price adjustments. This transaction is expected to close during the second quarter of 2018.

In a separate transaction within the Barnett, we formed a partnership in April 2018 under which we will monetize half our working interest across 116 gross undrilled locations for an approximate $75 million payment spread over the next five years. With this agreement, we will also drill and operate up to 24 wells per year, with volumes dedicated to the EnLink gathering and processing infrastructure.

Overall, these two Barnett transactions, combined with other asset sales previously disclosed, will generate $1.1 billion of total divestiture proceeds. We are also marketing approximately $1 billion of non-core assets across our U.S. portfolio as we progress toward the $5 billion target.

Capital Expenditures

The following table below presents our expected 2018 capital expenditures.

	Q2 2018 - Q4 2018				Full Year 2018
	(Billions)
Exploration and production		$1.5	—	$1.7		$2.2	—	$2.4
Total Devon		$1.6	—	$1.9		$2.3	—	$2.6

Credit Availability

We have a $3.0 billion Senior Credit Facility. As of March 31, 2018, we had approximately $2.9 billion available under this facility, net of $51 million in outstanding letters of credit, and were in compliance with the facility’s financial covenant. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At March 31, 2018, there were no borrowings under our commercial paper program.

Debt Ratings

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 near-term and long-term production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Ba1 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Table of Contents

There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should a debt rating fall below a specified level. However, these downgrades could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Common Stock Repurchase Program

During March 2018, our Board of Directors authorized a $1.0 billion share-repurchase program of our common stock, which expires March 7, 2019. Through March 31, 2018, we repurchased 2.6 million common shares for $83 million, or $32.19 per share, with up to approximately $917 million expected to be repurchased under the share-repurchase program through the end of 2018.

EnLink Liquidity

EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million secured revolving credit facility. As of March 31, 2018, there were $10 million in outstanding letters of credit and $370 million in outstanding borrowings under the $1.5 billion credit facility and $77 million in outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.

In January 2018, EnLink paid the final $250 million installment payment related to the 2016 Anadarko Basin gathering and processing midstream assets acquisition.

Critical Accounting Estimates

Income Taxes

As discussed in our 2017 Annual Report on Form 10-K, in December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, we consider the accounting of the transition tax, deferred tax remeasurements, and other items to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. We expect to complete our analysis within the measurement period in accordance with SAB 118.

Absent unexpected events and unexpected effects of the Tax Reform Legislation, Devon expects a positive impact on its future after-tax earnings, primarily due to the lower federal statutory tax rate.

Non-GAAP Measures

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2018 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. 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 and dry hole costs relating to exploration expenses), deferred tax asset valuation allowance, derivatives and financial instrument fair value changes and costs associated with early retirement of debt.

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.

Table of Contents

Below are reconciliations of our core earnings and core earnings per share attributable to Devon to their comparable GAAP measures for the three months ended March 31, 2018 and 2017.

	Before tax			After tax			After Noncontrolling Interests			Per Diluted Share
2018
Loss attributable to Devon (GAAP)	$	(181	)	$	(153	)	$	(197	)	$	(0.38	)
Adjustments:
Asset dispositions		(12	)		(9	)		(9	)		(0.02	)
Asset and exploration impairments		10			7			7			0.01
Deferred tax asset valuation allowance		—			6			6			0.01
Fair value changes in financial instruments and foreign currency		63			62			61			0.12
Early retirement of debt		312			240			240			0.46
Core earnings attributable to Devon (Non-GAAP)	$	192		$	153		$	108		$	0.20
2017
Earnings attributable to Devon (GAAP)	$	325		$	317		$	303		$	0.58
Adjustments:
Asset dispositions		(3	)		(1	)		(3	)		(0.01	)
Asset and exploration impairments		48			32			29			0.06
Deferred tax asset valuation allowance		—			(101	)		(101	)		(0.19	)
Fair value changes in financial instruments and foreign currency		(251	)		(163	)		(160	)		(0.31	)
Core earnings attributable to Devon (Non-GAAP)	$	119		$	84		$	68		$	0.13

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

As of March 31, 2018, we have commodity derivatives that pertain to a portion of our production for the last nine months of 2018, as well as 2019 and 2020. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 4 in “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, 2018, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately $375 million.

Interest Rate Risk

As of March 31, 2018, we had total debt of $10 billion. Of this amount, $9.6 billion bears fixed interest rates averaging 5.1%, and $447 million is comprised of floating rate debt with interest rates averaging 3.3%.

As of March 31, 2018, we had open interest rate swap positions that are presented in Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the 3-month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet at March 31, 2018.

Foreign Currency Risk

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 Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our March 31, 2018 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, certain of our subsidiaries hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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, 2018 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.

Changes in Internal Control Over Financial Reporting

There were no 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.

Table of Contents

PART II. Other Information

Item 1. Legal Proceedings

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.

Please see our 2017 Annual Report on Form 10-K for additional information.

Item 1A. Risk Factors

There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2017 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information regarding purchases of our common stock that were made by us during the first quarter of 2018 (shares in thousands).

Period	Total Number of Shares Purchased ⁽²⁾		Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs ⁽¹⁾		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽¹⁾
January 1 - January 31		16	$	42.83		—		—
February 1 - February 28		547	$	35.75		—		—
March 1 - March 31		2,822	$	32.04		2,561	$	917
Total		3,385	$	32.69		2,561

(1)

On March 7, 2018, we announced a $1.0 billion share repurchase program. This program expires March 7, 2019. As of March 31, 2018, we had repurchased 2.6 million common shares for $83 million, or $32.19 per share, under this program. Future purchases under the program will be made in open market or private transactions, depending on market conditions, and may be discontinued at any time.

(2)

In addition to shares purchased under the share repurchase program described above, these amounts also included 824,000 shares received by us from employees for the payment of personal income tax withholding on vesting transactions.

Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 14,300 shares of our common stock in the first quarter of 2018, 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 2018, there were approximately 3,200 shares purchased by Canadian employees.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Table of Contents

Item 6. Exhibits

Exhibit Number		Description


4.1		Fourth Supplemental Indenture, dated March 22, 2018, among Devon Energy Corporation and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as trustee, to the Indenture, dated as of March 1, 2002, among Devon Energy Corporation and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to Devon Energy Corporation’s Form 8-K, filed on March 22, 2018; File No. 001-32318).

10.1		2018 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 officers for restricted stock awarded.*

10.2		2018 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 officers for performance based restricted share units awarded.*

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		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

_______________

*Indicates management contract or compensatory plan or arrangement.

Table of Contents

SIGNATURES

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.

				DEVON ENERGY CORPORATION

Date: May 2, 2018				/s/ Jeremy D. Humphers
				Jeremy D. Humphers
				Senior Vice President and Chief Accounting Officer