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 September 30, ~~2017~~2021

☐	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

Securities registered pursuant to Section 12(b) of the Act:


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

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 October ~~18, 2017, 525.5~~20, 2021, 677.0 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 Comprehensive Earnings	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Equity	9
	Notes to Consolidated Financial Statements	10
	Note 1 – Summary of Significant Accounting Policies	10
	Note 2 – Acquisitions and Divestitures	11
	Note 3 – Derivative Financial Instruments	13
	Note 4 – Share-Based Compensation	15
	Note 5 – Asset Impairments	16
	Note 6 – Restructuring and Transaction Costs	17
	Note 7 – Income Taxes	18
	Note 8 – Net Earnings (Loss) Per Share From Continuing Operations	19
	Note 9 – Other Comprehensive Earnings (Loss)	19
	Note 10 – Supplemental Information to Statements of Cash Flows	20
	Note 11 – Accounts Receivable	20
	Note 12 – Property, Plant and Equipment	20
	Note 13 – Debt and Related Expenses	21
	Note 14 – Leases	22
	Note 15 – Asset Retirement Obligations	23
	Note 16 – Stockholders’ Equity	23
	Note 17 – Discontinued Operations	24
	Note 18 – Commitments and Contingencies	25
	Note 19 – Fair Value Measurements	26
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2928
	Executive Overview	28
	Results of Operations	30
	Capital Resources, Uses and Liquidity	37
	Critical Accounting Estimates	40
	Non-GAAP Measures	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4344
Item 4.	Controls and Procedures	4344

Part II. Other Information
Item 1.	Legal Proceedings	4445
Item 1A.	Risk Factors	4445
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4445
Item 3.	Defaults Upon Senior Securities	4445
Item 4.	Mine Safety Disclosures	4445
Item 5.	Other Information	4445
Item 6.	Exhibits	4546

Signatures		4647

Table of Contents

~~DEFINITIONS~~

DEFINITIONS

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

~~“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.~~

~~“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.~~

~~“ASU” means Accounting Standards Update.~~

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

“BKV” means Banpu Kalnin Ventures.

“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. On June 27, 2019, all of Devon’s Canadian operating assets and operations were divested. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.

“~~Canadian Plan”~~Catalyst” means ~~Devon Canada Corporation Incentive Savings Plan.~~Catalyst Midstream Partners, LLC.

“CDM” means Cotton Draw Midstream, L.L.C.

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

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

~~“E&P” means exploration~~environmental, social and ~~production activities.~~

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

~~“FASB” means Financial Accounting Standards Board.~~governance.

“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.

“Merger” means the merger of Merger Sub with and into WPX, with WPX continuing as the surviving corporation and a wholly-owned subsidiary of the Company, pursuant to the terms of the Merger Agreement.

“Merger Agreement” means that certain Agreement and Plan of Merger, dated September 26, 2020, by and among the Company, Merger Sub and WPX.

“Merger Sub” means East Merger Sub, Inc., a wholly-owned subsidiary of the Company.

“MMBoe” means million Boe.

~~Table of Contents~~

“MMBtu” means million Btu.

“MMcf” means million cubic feet.

Table of Contents

“N/M” means not meaningful.

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

“NYMEX” means New York Mercantile Exchange.

“~~OPIS”~~OPEC” means ~~Oil Price Information Service.~~Organization of the Petroleum Exporting Countries.

“SEC” means United States Securities and Exchange Commission.

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

“TSR” means total shareholder return.

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

“VIE” means variable interest entity.

“WPX” means WPX Energy, Inc.

“WTI” means West Texas Intermediate.

“/Bbl” means per barrel.

“/d” means per day.

“/~~Bbl”~~Mcf” means per ~~barrel.~~Mcf.

“/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 and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. ~~Such forward-looking~~All statements, ~~are based on our examination~~other than statements of historical ~~operating trends,~~facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the ~~information used to prepare our December 31, 2016 reserve reports and other data in our possession or available from third parties.~~future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially and adversely from our expectations due to a number of factors, including, but not limited to:

~~the volatility of oil, gas and NGL prices;~~

•

the volatility of oil, gas and NGL prices;

~~uncertainties inherent in estimating oil, gas and NGL reserves;~~

•

risks relating to the COVID-19 pandemic or other future pandemics;

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

•

uncertainties inherent in estimating oil, gas and NGL reserves;

~~the uncertainties, costs and risks involved in exploration and development activities;~~

•

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

~~risks related to our hedging activities;~~

•

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

~~counterparty credit risks;~~

•

risks related to regulatory, social and market efforts to address climate change;

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

•

the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct;

~~risks relating to our indebtedness;~~

•

risks related to our hedging activities;

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

•

counterparty credit risks;

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

•

risks relating to our indebtedness;

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

•

cyberattack risks;

~~midstream capacity constraints and potential interruptions in production;~~

•

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

~~competition for leases, materials, people and capital;~~

•

midstream capacity constraints and potential interruptions in production;

~~cyberattacks targeting our systems and infrastructure; and~~

•

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

•

competition for assets, materials, people and capital;

~~any of the other risks and uncertainties discussed in this report, our 2016 Annual Report on Form 10-K and our other filings with the SEC.~~
•
risks related to investors attempting to effect change;

•

our ability to successfully complete mergers, acquisitions and divestitures;

•

risks related to the Merger, including the risk that we may not realize the anticipated benefits of the Merger or successfully integrate the two legacy businesses; and

•

any of the other risks and uncertainties discussed in this report, our 2020 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 COMPREHENSIVE EARNINGS

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Unaudited)

(Millions, except per share amounts)

Oil, gas and NGL sales

$
1,245

$
1,113

$
3,760

$
3,023

Oil, gas and NGL derivatives

(144
)

79

214

(30
)
Marketing and midstream revenues

2,055

1,690

5,992

4,503

Asset dispositions and other

—

1,351

10

1,351

Total revenues and other

3,156

4,233

9,976

8,847

Lease operating expenses

391

355

1,176

1,215

Marketing and midstream operating expenses

1,813

1,480

5,319

3,884

General and administrative expenses

153

141

498

482

Production and property taxes

71

67

227

220

Depreciation, depletion and amortization

400

394

1,162

1,420

Asset impairments

2

319

9

4,851

Restructuring and transaction costs

—

(5
)

—

266

Other operating items

—

17

11

41

Total operating expenses

2,830

2,768

8,402

12,379

Operating income (loss)

326

1,465

1,574

(3,532
)
Net financing costs

127

243

370

570

Other nonoperating items

(73
)

44

(124
)

150

Earnings (loss) before income taxes

272

1,178

1,328

(4,252
)
Income tax expense (benefit)

25

171

51

(228
)
Net earnings (loss)

247

1,007

1,277

(4,024
)
Net earnings (loss) attributable to noncontrolling interests

19

14

59

(391
)
Net earnings (loss) attributable to Devon

$
228

$
993

$
1,218

$
(3,633
)
Net earnings (loss) per share attributable to Devon:

Basic

$
0.43

$
1.90

$
2.32

$
(7.22
)
Diluted

$
0.43

$
1.89

$
2.31

$
(7.22
)
Comprehensive earnings (loss):

Net earnings (loss)

$
247

$
1,007

$
1,277

$
(4,024
)
Other comprehensive earnings, net of tax:

Foreign currency translation

1

2

1

28

Pension and postretirement plans

5

11

14

20

Other

—

—

(2
)

—

Other comprehensive earnings, net of tax

6

13

13

48

Comprehensive earnings (loss)

253

1,020

1,290

(3,976
)
Comprehensive earnings (loss) attributable to
noncontrolling interests

19

14

59

(391
)
Comprehensive earnings (loss) attributable to Devon

$
234

$
1,006

$
1,231

$
(3,585
)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(Unaudited)
Oil, gas and NGL sales	$	2,635		$	678		$	6,546		$	1,909
Oil, gas and NGL derivatives		(335	)		(87	)		(1,566	)		272
Marketing and midstream revenues		1,166			476			2,953			1,367
Total revenues		3,466			1,067			7,933			3,548
Production expenses		555			271			1,526			852
Exploration expenses		3			39			9			163
Marketing and midstream expenses		1,165			478			2,972			1,395
Depreciation, depletion and amortization		578			299			1,581			999
Asset impairments		—			—			—			2,666
Asset dispositions		—			—			(119	)		—
General and administrative expenses		95			75			296			256
Financing costs, net		86			66			243			200
Restructuring and transaction costs		18			32			230			32
Other, net		2			—		��	(41	)		(35	)
Total expenses		2,502			1,260			6,697			6,528
Earnings (loss) from continuing operations before income taxes		964			(193	)		1,236			(2,980	)
Income tax expense (benefit)		120			(90	)		(85	)		(510	)
Net earnings (loss) from continuing operations		844			(103	)		1,321			(2,470	)
Net earnings (loss) from discontinued operations, net of income taxes		—			13			—			(103	)
Net earnings (loss)		844			(90	)		1,321			(2,573	)
Net earnings attributable to noncontrolling interests		6			2			14			5
Net earnings (loss) attributable to Devon	$	838		$	(92	)	$	1,307		$	(2,578	)
Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share	$	1.24		$	(0.29	)	$	1.95		$	(6.58	)
Basic earnings (loss) from discontinued operations per share		—			0.04			—			(0.27	)
Basic net earnings (loss) per share	$	1.24		$	(0.25	)	$	1.95		$	(6.85	)
Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share	$	1.24		$	(0.29	)	$	1.95		$	(6.58	)
Diluted earnings (loss) from discontinued operations per share		—			0.04			—			(0.27	)
Diluted net earnings (loss) per share	$	1.24		$	(0.25	)	$	1.95		$	(6.85	)
Comprehensive earnings (loss):
Net earnings (loss)	$	844		$	(90	)	$	1,321		$	(2,573	)
Other comprehensive earnings, net of tax:
Pension and postretirement plans		1			1			27			3
Other comprehensive earnings, net of tax		1			1			27			3
Comprehensive earnings (loss):		845			(89	)		1,348			(2,570	)
Comprehensive earnings attributable to noncontrolling interests		6			2			14			5
Comprehensive earnings (loss) attributable to Devon	$	839		$	(91	)	$	1,334		$	(2,575	)

See accompanying notes to consolidated financial statements

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Unaudited)

(Millions)

Cash flows from operating activities:

Net earnings (loss)

$
247

$
1,007

$
1,277

$
(4,024
)
Adjustments to reconcile net earnings (loss) to net
cash from operating activities:

Depreciation, depletion and amortization

400

394

1,162

1,420

Asset impairments

2

319

9

4,851

Gains and losses on asset sales

1

(1,351
)

(6
)

(1,351
)
Deferred income tax expense (benefit)

(14
)

86

(20
)

(300
)
Commodity derivatives

144

(79
)

(214
)

30

Cash settlements on commodity derivatives

24

12

43

15

Other derivatives and financial instruments

9

21

16

329

Cash settlements on other derivatives and
financial instruments

—

3

—

(148
)
Asset retirement obligation accretion

16

19

47

58

Share-based compensation

33

23

122

163

Other

(85
)

127

(134
)

(31
)
Net change in working capital

7

137

94

208

Change in long-term other assets

2

(3
)

12

10

Change in long-term other liabilities

(10
)

12

12

7

Net cash from operating activities

776

727

2,420

1,237

Cash flows from investing activities:

Capital expenditures

(735
)

(421
)

(2,203
)

(1,659
)
Acquisitions of property, equipment and businesses

(6
)

(3
)

(39
)

(1,641
)
Proceeds from sale of investment

—

—

190

—

Divestitures of property and equipment

209

1,680

323

1,889

Other

(1
)

34

(5
)

7

Net cash from investing activities

(533
)

1,290

(1,734
)

(1,404
)
Cash flows from financing activities:

Borrowings of long-term debt, net of issuance costs

413

816

2,208

1,662

Repayments of long-term debt

(571
)

(2,173
)

(1,950
)

(2,722
)
Payment of installment payable

—

—

(250
)

—

Net short-term debt repayments

—

—

—

(626
)
Early retirement of debt

—

(82
)

(6
)

(82
)
Issuance of common stock

—

—

—

1,469

Issuance of subsidiary units

414

59

486

835

Dividends paid on common stock

(30
)

(32
)

(95
)

(190
)
Contributions from noncontrolling interests

18

146

47

152

Distributions to noncontrolling interests

(84
)

(77
)

(247
)

(224
)
Shares exchanged for tax withholdings

(3
)

(2
)

(67
)

(30
)
Other

—

(1
)

(2
)

(7
)
Net cash from financing activities

157

(1,346
)

124

237

Effect of exchange rate changes on cash

12

(9
)

12

5

Net change in cash and cash equivalents

412

662

822

75

Cash and cash equivalents at beginning of period

2,369

1,723

1,959

2,310

Cash and cash equivalents at end of period

$
2,781

$
2,385

$
2,781

$
2,385

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(Unaudited)
Cash flows from operating activities:
Net earnings (loss)	$	844		$	(90	)	$	1,321		$	(2,573	)
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Net (earnings) loss from discontinued operations, net of income taxes		—			(13	)		—			103
Depreciation, depletion and amortization		578			299			1,581			999
Asset impairments		—			—			—			2,666
Leasehold impairments		1			36			3			149
(Amortization) accretion of liabilities		(7	)		8			(21	)		24
Total (gains) losses on commodity derivatives		335			87			1,566			(272	)
Cash settlements on commodity derivatives		(370	)		10			(969	)		343
Gains on asset dispositions		—			—			(119	)		—
Deferred income tax expense (benefit)		119			—			(100	)		(311	)
Share-based compensation		19			31			80			70
Early retirement of debt		—			—			(30	)		—
Other		11			1			13			5
Changes in assets and liabilities, net		68			58			(42	)		(97	)
Net cash from operating activities - continuing operations		1,598			427			3,283			1,106
Cash flows from investing activities:
Capital expenditures		(474	)		(204	)		(1,477	)		(936	)
Acquisitions of property and equipment		(10	)		—			(15	)		(5	)
Divestitures of property and equipment		1			1			65			29
WPX acquired cash		—			—			344			—
Distributions from equity method investments		9			—			27			—
Net cash from investing activities - continuing operations		(474	)		(203	)		(1,056	)		(912	)
Cash flows from financing activities:
Repayments of long-term debt		—			—			(1,243	)		—
Early retirement of debt		—			—			(59	)		—
Repurchases of common stock		—			—			—			(38	)
Dividends paid on common stock		(329	)		(43	)		(761	)		(119	)
Contributions from noncontrolling interests		1			1			4			12
Distributions to noncontrolling interests		(6	)		(4	)		(15	)		(10	)
Acquisition of noncontrolling interests		—			—			(24	)		—
Shares exchanged for tax withholdings and other		(3	)		—			(45	)		(17	)
Net cash from financing activities - continuing operations		(337	)		(46	)		(2,143	)		(172	)
Effect of exchange rate changes on cash - continuing operations		(5	)		—			—			—
Net change in cash, cash equivalents and restricted cash of continuing operations		782			178			84			22
Cash flows from discontinued operations:
Operating activities		0			45			0			(129	)
Investing activities		0			1			0			171
Financing activities		0			0			0			0
Effect of exchange rate changes on cash		0			4			0			(11	)
Net change in cash, cash equivalents and restricted cash of discontinued operations		0			50			0			31
Net change in cash, cash equivalents and restricted cash		782			228			84			53
Cash, cash equivalents and restricted cash at beginning of period		1,539			1,669			2,237			1,844
Cash, cash equivalents and restricted cash at end of period	$	2,321		$	1,897		$	2,321		$	1,897

Reconciliation of cash, cash equivalents and restricted cash:
Cash and cash equivalents	$	2,144		$	1,707		$	2,144		$	1,707
Restricted cash		177			190			177			190
Total cash, cash equivalents and restricted cash	$	2,321		$	1,897		$	2,321		$	1,897

See accompanying notes to consolidated financial statements

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	September 30, 2017			December 31, 2016
	(Unaudited)						September 30, 2021			December 31, 2020
	(Millions, except share data)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,781		$	1,959
Cash, cash equivalents and restricted cash							$	2,321		$	2,237
Accounts receivable		1,462			1,356			1,517			601
Assets held for sale		—			193
Income taxes receivable								80			174
Other current assets		379			264			309			248
Total current assets		4,622			3,772			4,227			3,260
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		78,470			75,648
Not subject to amortization		2,853			3,437
Total oil and gas		81,323			79,085
Midstream and other		11,097			10,455
Total property and equipment, at cost		92,420			89,540
Less accumulated depreciation, depletion and amortization		(75,338	)		(73,350	)
Property and equipment, net		17,082			16,190
Oil and gas property and equipment, based on successful efforts accounting, net								13,613			4,436
Other property and equipment, net ($106 million and $102 million related to CDM in 2021 and 2020, respectively)								1,465			957
Total property and equipment, net								15,078			5,393
Goodwill		3,964			3,964			753			753
Right-of-use assets								244			223
Investments								388			12
Other long-term assets		1,891			1,987			367			271
Total assets	$	27,559		$	25,913		$	21,057		$	9,912
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	797		$	642		$	537		$	242
Revenues and royalties payable		1,012			908			1,443			662
Short-term debt		20			—
Other current liabilities		1,003			1,066			1,525			536
Total current liabilities		2,832			2,616			3,505			1,440
Long-term debt		10,383			10,154			6,492			4,298
Lease liabilities								256			246
Asset retirement obligations		1,100			1,226			462			358
Other long-term liabilities		645			894			1,281			551
Deferred income taxes		665			648
Equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 525 million and 523 million shares in 2017 and 2016, respectively		53			52
Stockholders' equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 677 million and 382 million shares in 2021 and 2020, respectively								68			38
Additional paid-in capital		7,207			7,237			8,206			2,766
Accumulated deficit		(428	)		(1,646	)
Accumulated other comprehensive earnings		297			284
Retained earnings								750			208
Accumulated other comprehensive loss								(100	)		(127	)
Total stockholders’ equity attributable to Devon		7,129			5,927			8,924			2,885
Noncontrolling interests		4,805			4,448			137			134
Total equity		11,934			10,375			9,061			3,019
Total liabilities and equity	$	27,559		$	25,913		$	21,057		$	9,912

See accompanying notes to consolidated financial statements

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

											Accumulated																						Other
					Additional			Retained			Other																Additional						Comprehensive
	Common Stock				Paid-In			Earnings			Comprehensive		Treasury			Noncontrolling			Total			Common Stock					Paid-In			Retained			Earnings			Treasury			Noncontrolling			Total
	Shares		Amount		Capital			(Accumulated Deficit)			Earnings		Stock			Interests			Equity			Shares			Amount		Capital			Earnings			(Loss)			Stock			Interests			Equity
	(Unaudited)																					(Unaudited)
	(Millions)
Nine Months Ended September 30, 2017
Balance as of December 31, 2016		523	$	52	$	7,237		$	(1,646	)	$	284	$	—		$	4,448		$	10,375
Three Months Ended September 30, 2021
Balance as of June 30, 2021																							677		$	68	$	8,189		$	243		$	(101	)	$	—		$	136		$	8,535
Net earnings		—		—		—			1,218			—		—			59			1,277			—			—		—			838			—			—			6			844
Other comprehensive earnings, net of tax		—		—		—			—			13		—			—			13			—			—		—			—			1			—			—			1
Restricted stock grants, net of cancellations		1		1		—			—			—		—			—			1			—			—		(1	)		—			—			—			—			(1	)
Common stock repurchased		—		—		—			—			—		(43	)		—			(43	)		—			—		—			—			—			(1	)		—			(1	)
Common stock retired		—		—		(43	)		—			—		43			—			—			—			—		(1	)		—			—			1			—			—
Common stock dividends		—		—		(95	)		—			—		—			—			(95	)		—			—		—			(331	)		—			—			—			(331	)
Share-based compensation		1		—		96			—			—		—			—			96			—			—		19			—			—			—			—			19
Subsidiary equity transactions		—		—		12			—			—		—			545			557
Contributions from noncontrolling interests																							—			—		—			—			—			—			1			1
Distributions to noncontrolling interests		—		—		—			—			—		—			(247	)		(247	)		—			—		—			—			—			—			(6	)		(6	)
Balance as of September 30, 2017		525	$	53	$	7,207		$	(428	)	$	297	$	—		$	4,805		$	11,934
Nine Months Ended September 30, 2016
Balance as of December 31, 2015		418	$	42	$	4,996		$	1,781		$	230	$	—		$	3,940		$	10,989
Net loss		—		—		—			(3,633	)		—		—			(391	)		(4,024	)
Balance as of September 30, 2021																							677		$	68	$	8,206		$	750		$	(100	)	$	—		$	137		$	9,061
Three Months Ended September 30, 2020
Balance as of June 30, 2020																							383		$	38	$	2,720		$	586		$	(117	)	$	—		$	126		$	3,353
Net earnings (loss)																							—			—		—			(92	)		—			—			2			(90	)
Other comprehensive earnings, net of tax																							—			—		—			—			1			—			—			1
Common stock repurchased																							—			—		—			—			—			(1	)		—			(1	)
Common stock retired																							—			—		(1	)		—			—			1			—			—
Common stock dividends																							—			—		—			(143	)		—			—			—			(143	)
Share-based compensation																							—			—		31			—			—			—			—			31
Contributions from noncontrolling interests																							—			—		—			—			—			—			1			1
Distributions to noncontrolling interests																							—			—		—			—			—			—			(4	)		(4	)
Balance as of September 30, 2020																							383		$	38	$	2,750		$	351		$	(116	)	$	—		$	125		$	3,148
Nine Months Ended September 30, 2021
Balance as of December 31, 2020																							382		$	38	$	2,766		$	208		$	(127	)	$	—		$	134		$	3,019
Net earnings																							—			—		—			1,307			—			—			14			1,321
Other comprehensive earnings, net of tax		—		—		—			—			48		—			—			48			—			—		—			—			27			—			—			27
Restricted stock grants, net of cancellations		3		—		—			—			—		—			—			—			6			1		(2	)		—			—			—			—			(1	)
Common stock repurchased		—		—		—			—			—		(23	)		—			(23	)		—			—		—			—			—			(41	)		—			(41	)
Common stock retired		—		—		(23	)		—			—		23			—			—			(2	)		—		(41	)		—			—			41			—			—
Common stock dividends		—		—		(65	)		(125	)		—		—			—			(190	)		—			—		—			(765	)		—			—			—			(765	)
Common stock issued		103		10		2,117			—			—		—			—			2,127			290			29		5,403			—			—			—			—			5,432
Share-based compensation		—		—		142			—			—		—			—			142			1			—		80			—			—			—			—			80
Subsidiary equity transactions		—		—		320			—			—		—			896			1,216
Contributions from noncontrolling interests																							—			—		—			—			—			—			3			3
Distributions to noncontrolling interests		—		—		—			—			—		—			(224	)		(224	)		—			—		—			—			—			—			(14	)		(14	)
Balance as of September 30, 2016		524	$	52	$	7,487		$	(1,977	)	$	278	$	—		$	4,221		$	10,061
Balance as of September 30, 2021																							677		$	68	$	8,206		$	750		$	(100	)	$	—		$	137		$	9,061
Nine Months Ended September 30, 2020
Balance as of December 31, 2019																							382		$	38	$	2,735		$	3,148		$	(119	)	$	—		$	118		$	5,920
Net earnings (loss)																							—			—		—			(2,578	)		—			—			5			(2,573	)
Other comprehensive earnings, net of tax																							—			—		—			—			3			—			—			3
Restricted stock grants, net of cancellations																							3			—		—			—			—			—			—			—
Common stock repurchased																							—			—		—			—			—			(55	)		—			(55	)
Common stock retired																							(3	)		—		(55	)		—			—			55			—			—
Common stock dividends																							—			—		—			(219	)		—			—			—			(219	)
Share-based compensation																							1			—		70			—			—			—			—			70
Contributions from noncontrolling interests																							—			—		—			—			—			—			12			12
Distributions to noncontrolling interests																							—			—		—			—			—			—			(10	)		(10	)
Balance as of September 30, 2020																							383		$	38	$	2,750		$	351		$	(116	)	$	—		$	125		$	3,148

See accompanying notes to consolidated financial statements

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	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 ~~2016~~2020 Annual Report on Form ~~10-K.~~

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 and nine-month periods ended September 30, ~~2017~~2021 and ~~2016~~2020 and Devon’s financial position as of September 30, ~~2017.~~2021.

~~Recently Adopted Accounting Standards~~

In Devon and WPX completed an all-stock merger of equals on January ~~2017, Devon adopted ASU 2016-09,~~ ~~Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting~~7, 2021. ~~Its objective is to simplify several aspects~~On the closing date of the Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. The transaction has been accounted for using the acquisition method of accounting, with Devon being treated as the accounting acquirer. See Note 2for ~~share-based payments, including income taxes when awards vest or are settled, statutory withholding and forfeitures.~~further discussion.

As further discussed in Note 17, Devon closed on the ~~result~~sale of ~~adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefits and deficiencies~~its Barnett Shale assets in ~~the~~October 2020. Prior to December 31, 2020, activity relating to Devon’s Barnett Shale assets is classified as discontinued operations within Devon’s consolidated ~~comprehensive~~ statements of comprehensive earnings and ~~as operating cash flows in the~~ consolidated statements of cash flows.

As of September 30, 2021,Devon classified approximately $165 million of cash as restricted cash on the consolidated balance sheets for obligations retained related to the Barnett Shale assets and the Canadian business. Cash payments for these charges related to the Barnett assets and Canada business total approximately $10 million per quarter.

Variable Interest Entity

Cotton Draw Midstream, L.L.C. (“CDM”) is a joint venture entity formed by Devon and an affiliate of QL Capital Partners, LP. CDM provides gathering, compression and dehydration services for natural gas production in the Cotton Draw area of the Delaware Basin. Devon holds a controlling interest in CDM and the portions of CDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon. The assets of CDM cannot be used by Devon for general corporate purposes and are included in, and disclosed parenthetically, on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which the creditors do not have recourse to Devon's assets are also ~~retrospectively applied~~included in, and disclosed parenthetically, if material, on Devon's consolidated balance sheets.

Investments

In conjunction with the ~~new cash flow statement guidance dictating~~Merger, Devon acquired an interest in Catalyst which is a joint venture established between WPX and Howard Energy Partners (“HEP”) to develop oil gathering and natural gas processing infrastructure in the ~~presentation~~Stateline area of ~~shares exchanged~~the Delaware Basin. Under the terms of the arrangement, Devon and HEP each have a 50 percent voting interest in the joint venture legal entity, and HEP serves as the operator. Through 2038, Devon’s production from 50,000 net acres in the Stateline area of the Delaware Basin has been dedicated to Catalyst subject to fixed-fee oil gathering and natural gas processing agreements. The agreements do not include any minimum volume commitments. Devon accounts for ~~tax-withholding purposes~~the investment in Catalyst as an equity method investment. Devon’s investment in Catalyst is shown within investments on the consolidated balance sheet and Devon’s share of Catalyst earnings are reflected as a ~~financing activity.~~ component of other, net in the accompanying consolidated statements of comprehensive earnings.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Oil	$	1,900	$	504	$	4,917	$	1,462
Gas		309		79		699		221
NGL		426		95		930		226
Oil, gas and NGL sales		2,635		678		6,546		1,909

Oil		649		233		1,758		702
Gas		196		100		477		275
NGL		321		143		718		390
Marketing and midstream revenues		1,166		476		2,953		1,367
Total revenues from contracts with customers	$	3,801	$	1,154	$	9,499	$	3,276

2.Acquisitions and Divestitures

WPX Merger

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX was an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. On the closing date of the ~~new guidance did not materially impact~~Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. No fractional shares of Devon’s common stock were issued in the Merger, and holders of WPX common stock instead received cash in lieu of fractional shares of Devon common stock, if any. Based on the closing price of Devon’s common stock on January 7, 2021, the total value of Devon common stock issued to holders of WPX common stock as part of this transaction was approximately $5.4 billion. The Merger was structured as a tax-free reorganization for United States federal income tax purposes.

Purchase Price Allocation

The transaction has been accounted for using the acquisition method of accounting, with Devon being treated as the accounting acquirer. Under the acquisition method of accounting, the assets and liabilities of WPX and its subsidiaries have been recorded at their respective fair values as of the date of completion of the Merger and added to Devon’s. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing date of the Merger. Determining the fair value of the assets and liabilities of WPX requires judgment and certain assumptions to be made, the most significant of these being related to the valuation of WPX’s oil and gas properties. The inputs and assumptions related to the oil and gas properties are categorized as level 3 in the fair value hierarchy.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table represents the preliminary allocation of the total purchase price of WPX to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date.

	Preliminary Purchase
	Price Allocation
	as of September 30, 2021
Consideration:
WPX Common Stock outstanding		561.2
Exchange Ratio		0.5165
Devon common stock issued		289.9
Devon closing price on January 7, 2021	$	18.57
Total common equity consideration		5,383
Share-based replacement awards		49
Total consideration	$	5,432
Assets acquired:
Cash, cash equivalents and restricted cash	$	344
Accounts receivable		425
Other current assets		49
Right-of-use assets		38
Proved oil and gas property and equipment		7,017
Unproved and properties under development		2,362
Other property and equipment		485
Investments		400
Other long-term assets		43
Total assets acquired	$	11,163
Liabilities assumed:
Accounts payable	$	346
Revenue and royalties payable		223
Other current liabilities		454
Debt		3,562
Lease liabilities		38
Asset retirement obligations		94
Deferred income taxes		249
Other long-term liabilities		765
Total liabilities assumed		5,731
Net assets acquired	$	5,432

WPX Revenues and Earnings

The following table represents WPX’s revenues and earnings included in Devon’s consolidated ~~financial~~ statements of comprehensive earnings subsequent to the closing date of the Merger.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021		2021
Total revenues	$	1,564	$	3,977
Net earnings	$	414	$	969

Pro Forma Financial Information

Due to the Merger closing on January 7, 2021, all activity in the first nine months of 2021 except for the first six days of January is included in Devon’s consolidated statements of comprehensive earnings for the nine months ended September 30, ~~2017 or previously reported~~2021. The following unaudited pro forma financial information ~~but could have a more material future impact.~~

~~In January 2017, the FASB issued ASU 2017-04,~~ ~~Intangibles – Goodwill And Other (Topic 350)~~, ~~Simplifying the Test for Goodwill Impairment~~ ("ASU 2017-04"). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test. Under ASU 2017-04, an entity should perform its goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the ~~amount by which~~three and nine months ended September 30, 2020 is based on our historical consolidated financial statements adjusted to reflect as if the carrying amount exceeds the reporting unit's fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application for interim or annual goodwill impairment tests performedMerger had occurred on ~~testing dates after~~ January 1, ~~2017. In January 2017, Devon elected~~2020. The information below reflects pro forma adjustments to ~~early adopt ASU 2017-04, and the adoption had no impact on the consolidated~~conform WPX’s historical financial ~~statements. Devon will perform future goodwill impairment tests according~~information to ~~ASU 2017-04.~~Devon’s financial statement presentation.

~~Issued Accounting Standards Not Yet Adopted~~

~~The FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606). This ASU will supersede the revenue recognition requirements in Topic 605,~~ ~~Revenue Recognition~~ ~~and industry-specific guidance in Subtopic 932-605,~~ ~~Extractive Activities – Oil and Gas – Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to~~ ~~increase the usefulness of~~ ~~information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14,~~ ~~Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018, with early adoption permitted in 2017. Devon has not early adopted this ASU. The ASU is required~~ to be adopted using either the retrospective transition method, which requires restating previously reported results or the 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 intends to use the cumulative effect transition method and does not anticipate this ASU will have a material impact on its balance sheet or related consolidated statements of earnings, equity or cash flows. However, Devon continues to evaluate the “gross versus net” presentation of certain revenues and associated expenses in its consolidated statements of earnings. Any presentation changes would have no impact on operating income, earnings or cash flows. Devon does not expect significant changes to its annual disclosures; however, Devon’s quarterly disclosures will expand upon adoption of this ASU. Devon has implemented a process to gather and provide the quarterly disclosures required by the ASU.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The ~~FASB issued ASU 2016-02,~~ ~~Leases (Topic 842). This ASU will supersede~~unaudited pro forma financial information is not necessarily indicative of what would have occurred if 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 and will be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into afterMerger had been completed as of the beginning of the ~~earliest period in the financial statements. Early adoption~~periods presented, nor is ~~permitted, but Devon does not plan to early adopt. Devon is in the process~~it indicative of evaluating contracts and gathering the necessary terms and data elements for purposes of determining the impact this ASU will have on its consolidated financial statements and related disclosures. Recently, the FASB ~~issued~~ ~~Proposed Accounting Standards Update (ASU) No. 2017-290,~~ ~~Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842. This proposed 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 contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.~~

Based on continuing research, Devon estimates a large number of contracts and data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls and is evaluating technology requirements and solutions needed to comply with the requirements of this ASU.

~~The FASB issued ASU No. 2017-07,~~ ~~Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.~~ ~~This ASU will~~ require entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs and present the other components of net periodic benefit cost outside of operating income in the statement of earnings. Only the service cost component of net periodic benefit cost is eligible for capitalization. This ASU is effective for Devon beginning January 1, 2018, and presentation changes in the statement of earnings will be applied retrospectively, while service cost component capitalization will be applied prospectively. Upon adoption of this ASU, Devon will reclassify $7 million, $14 million and $16 million of non-service cost components of net periodic benefit costs for 2017, 2016 and 2015, respectively, as other nonoperating items. Such amounts are currently classified in Devon’s G&A. No other changes upon adopting this ASU are expected to be material.future results.

2.	~~Acquisitions and Divestitures~~

	Three Months Ended September 30,			Nine Months Ended September 30,
Continuing operations:	2020			2020
Total revenues	$	1,540		$	5,452
Net loss	$	(281	)	$	(3,247	)
Basic net loss per share	$	(0.42	)	$	(4.87	)

~~Devon Acquisitions~~

Divestitures

In ~~January 2016,~~the first quarter of 2021, Devon ~~acquired approximately 80,000 net acres (unaudited) and~~completed the sale of non-core assets in the ~~STACK play~~Rockies for ~~approximately $1.5 billion. Devon funded the acquisition with $849~~proceeds of $9 million, net of ~~cash, after~~purchase price adjustments, and ~~$659~~recognized a $35 million gain related to the sale. The transaction includes contingent earnout payments of ~~common equity shares.~~ up to $8 million. The ~~purchase price allocation was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.~~

~~2017 Devon Asset Divestitures~~

In May 2017, Devon announced a program to divest approximately $1 billion of upstream assets. The non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, before purchase price adjustments. Estimatedtotal estimated proved reserves associated with these divested assets ~~were less than 1%~~was approximately 3 MMBoe. As of ~~total U.S. proved reserves.~~

~~2016 Devon Asset Divestitures~~

InDecember 31, 2020, the ~~second quarter of 2016, Devon divested non-core assets for approximately $200 million. Estimated proved reserves~~ associated ~~with these assets were less than 1% of total U.S. proved reserves.~~

In the third quarter of 2016, in several separate transactions with different purchasers, Devon divested non-core upstream assets located in east Texas, the Anadarko Basin and the Midland Basin for approximately $1.7 billion. Estimated proved reserves associated with these assets were approximately 146 MMBoe, or approximately 9% of total U.S. proved reserves.

~~Table of Contents~~

~~DEVON ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~Proceeds from the transactions were used primarily for debt repayment and to support capital investment in Devon’s core resource plays.~~

The divestiture transactions that closed in the third quarter of 2016 significantly altered the costs and reserves relationship of Devon’s U.S. cost center. Therefore, Devon recognized a $1.4 billion gain in the third quarter of 2016 associated with these divestitures. A summary of the gain computation follows.

Three Months Ended September 30, 2016

(Millions)

Proceeds received, net of purchase price adjustments and selling costs

$
1,653

Asset retirement obligation assumed by purchasers

250

Total consideration received

1,903

Allocated oil and gas property basis sold

355

Allocated goodwill

197

Total assets sold

552

Gain on asset sales

$
1,351

~~EnLink Acquisitions~~

In January 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.4 billion. The purchase price allocation was $1.0 billion to intangible assets and ~~approximately $400 million to property~~liabilities were classified as assets held for sale and equipment. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily funded with the issuance of EnLink preferred units. The remaining $500 million of the purchase price was to be paid within one year with the option to defer $250 million of the final payment 24 months from the close date. The first installment payment of $250 million was paid in ~~January 2017. The remaining $250 million payment is reported~~included in other current assets and other current liabilities, inrespectively.

In the ~~accompanying consolidated balance sheets.~~fourth quarter of 2020, Devon completed the sale of its Barnett Shale assets to BKV for proceeds, net of purchase price adjustments, of $490 million. The ~~accretion~~agreement with BKV also provides for contingent earnout payments to Devon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commenced on January 1, 2021 and has a term of four years. The valuation of the ~~discount is reported~~future contingent earnout payments included within ~~net financing costs in the accompanying consolidated comprehensive statement of earnings.~~

~~In August 2016, EnLink formed a joint venture to operate~~other current assets and ~~expand its midstream~~other long-term assets in the ~~Delaware Basin. The joint venture is initially owned 50.1% by EnLink~~September 30, 2021 consolidated balance sheet was $46 million and ~~49.9% by~~$85 million, respectively. During the ~~joint venture partner. EnLink contributed approximately $244~~first nine months of 2021, Devon recorded a $65 million ~~of existing non-monetary assets~~increase to the ~~joint venture~~fair value within asset dispositions on the consolidated statements of comprehensive earnings. The value was derived utilizing a Monte Carlo valuation model and ~~committed an additional $262 million~~qualifies as a level 3 fair value measurement. Additional information can be found in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including initial cash contributions of approximately $138 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.

~~EnLink Asset Divestitures~~

D~~uring the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.~~Note 17.

3.	~~Derivative Financial~~ 3.Derivative Financial Instruments

Objectives and Strategies

Devon ~~periodically~~ 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~~enters into derivative financial instruments with respect to a portion of ~~their~~its oil, gas and NGL marketing activities. These commodity derivative financial instruments include financial price swaps, price swaptions, basis swaps, ~~and~~ costless price ~~collars.~~collars and call options. Devon periodically enters into interest rate swaps to manage its exposure to interest rate ~~volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates.~~volatility. As of September 30, ~~2017,~~2021, Devon did not have any open ~~foreign exchange~~interest rate swap contracts.

~~Table of Contents~~

~~DEVON ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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. As of September 30, 2021, Devon neither held cash collateral of its counterparties 0r posted cash collateral to its counterparties.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Commodity Derivatives

As of September 30, ~~2017,~~2021, 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.~~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)

Q4 2017

82,167

$
53.87

79,200

$
45.51

$
57.41

Q1-Q4 2018

22,792

$
51.13

34,121

$
45.71

$
55.71

Q1-Q4 2019

1,356

$
49.79

2,096

$
44.10

$
54.10

	Price Swaps				Price Swaptions				Price Collars						Call Options Sold
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q4 2021		66,460	$	41.24		—	$	—		48,250	$	38.82	$	48.82		5,000	$	39.50
Q1-Q4 2022		26,112	$	43.75		10,000	$	46.67		20,233	$	46.41	$	56.41		—	$	—

Oil Basis Swaps

Period

Index

Volume (Bbls/d)

Weighted Average
Differential to WTI
($/Bbl)

Q4 2017

Midland Sweet

20,000

$
(0.41
)
Q4 2017

Western Canadian Select

87,304

$
(14.57
)
Q1-Q4 2018

Midland Sweet

23,000

$
(1.02
)
Q1-Q4 2018

Western Canadian Select

59,718

$
(14.85
)
Q1-Q4 2019

Midland Sweet

1,000

$
(0.80
)

	Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q4 2021	Midland Sweet		23,000	$	0.84
Q4 2021	Guernsey Light Sweet		4,000	$	(1.49	)
Q4 2021	BRENT		1,000	$	(8.00	)
Q4 2021	NYMEX Roll		13,000	$	0.39
Q1-Q4 2022	BRENT		1,000	$	(7.75	)
Q1-Q4 2022	NYMEX Roll		29,000	$	0.45

As of September 30, ~~2017,~~2021, 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 and the end of month NYMEX index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.

Price Swaps

Price Collars

Period

Volume (MMBtu/d)

Weighted Average Price ($/MMBtu)

Volume (MMBtu/d)

Weighted Average Floor Price ($/MMBtu)

Weighted Average
Ceiling Price ($/MMBtu)

Q4 2017

331,196

$
3.21

455,000

$
3.03

$
3.41

Q1-Q4 2018

261,888

$
3.09

149,982

$
2.99

$
3.30

Q1-Q4 2019

6,164

$
3.08

8,630

$
2.92

$
3.22

	Price Swaps ⁽¹⁾				Price Swaptions ⁽²⁾				Price Collars ⁽²⁾						Call Options Sold ⁽²⁾
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Q4 2021		254,000	$	2.63		—	$	—		133,000	$	2.55	$	3.05		50,000	$	2.68
Q1-Q4 2022		3,452	$	2.85		100,000	$	2.70		145,507	$	2.69	$	3.40		—	$	—
Q1-Q4 2023		—	$	—		—	$	—		10,603	$	3.11	$	4.56		—	$	—

(1)

Related to the 2021 open positions, 14,000 MMBtu/d settle against the Inside FERC first of month Henry Hub index at an average price of $2.85 and 240,000 MMBtu/d settle against the end of month NYMEX index at an average price of $2.62. All 2022 open positions settle against the Inside FERC first of month Henry Hub index.

(2)

Price swaptions and call options settle against end of month NYMEX index. Price collars settle against the Inside FERC first of month Henry Hub Index.

	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q4 2021	El Paso Natural Gas		35,000	$	(0.92	)
Q4 2021	WAHA		80,000	$	(0.65	)
Q1-Q4 2022	WAHA		70,000	$	(0.57	)
Q1-Q4 2023	WAHA		70,000	$	(0.51	)
Q1-Q4 2024	WAHA		40,000	$	(0.51	)

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Natural Gas Basis Swaps

Period

Index

Volume
(MMBtu/d)

Weighted Average
Differential to
Henry Hub
($/MMBtu)

Q4 2017

Panhandle Eastern Pipe Line

150,000

$
(0.34
)
Q4 2017

El Paso Natural Gas

80,000

$
(0.13
)
Q4 2017

Houston Ship Channel

35,000

$
0.06

Q4 2017

Transco Zone 4

205,000

$
0.03

Q1-Q4 2018

Panhandle Eastern Pipe Line

50,000

$
(0.29
)

As of September 30, ~~2017,~~2021, 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				Price Collars							Price Swaps
Period	Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)		Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q4 2017	Propane		2,663	$	31.98		1,000	$	28.35	$	30.45
Q4 2021												Natural Gasoline		1,000	$	47.57
Q4 2021												Normal Butane		1,000	$	31.40
Q4 2021												Propane		1,000	$	27.88

AsFinancial Statement Presentation

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the consolidated balance sheets. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the consolidated balance sheets. The tables below present a summary of these positions as of September 30, ~~2017, EnLink had the following open derivative positions associated with gas processing~~2021 and ~~fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index.~~

December 31, 2020.

~~Period~~	~~Product~~	~~Volume (Total)~~			~~Weighted Average Price Paid~~	~~Weighted Average Price Received~~
~~Q4 2017-Q3 2018~~	~~Propane~~		~~537~~	~~MBbls~~	~~Index~~	~~$0.66/gal~~
~~Q4 2017-Q3 2018~~	~~Normal Butane~~		~~344~~	~~MBbls~~	~~Index~~	~~$0.77/gal~~

	September 30, 2021									December 31, 2020
	Gross Fair Value			Amounts Netted			Net Fair Value			Gross Fair Value			Amounts Netted			Net Fair Value			Balance Sheet Classification
Commodity derivatives:
Short-term derivative asset	$	3		$	(1	)	$	2		$	23		$	(18	)	$	5		Other current assets
Long-term derivative asset		—			—			—			1			—			1		Other long-term assets
Short-term derivative liability		(984	)		1			(983	)		(161	)		18			(143	)	Other current liabilities
Long-term derivative liability		(103	)		—			(103	)		(5	)		—			(5	)	Other long-term liabilities
Total derivative liability	$	(1,084	)	$	—		$	(1,084	)	$	(142	)	$	—		$	(142	)

~~Interest Rate Derivatives~~4.Share-Based Compensation

~~As of September 30, 2017, Devon had the following open interest rate derivative positions:~~

Notional

Rate Received

Rate Paid

Expiration
(Millions)

$
750

Three Month LIBOR

2.98%

December 2048 ⁽¹⁾
$
100

1.76%

Three Month LIBOR

January 2019

~~(1)~~

~~Mandatory settlement in December 2018.~~

~~Table of Contents~~

~~DEVON ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~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
September 30,

Nine Months Ended
September 30,

2017

2016

2017

2016

(Millions)

Commodity derivatives:

Oil, gas and NGL derivatives

$
(144
)

$
79

$
214

$
(30
)
Marketing and midstream revenues

(5
)

(1
)

3

(7
)
Interest rate derivatives:

Other nonoperating items

(4
)

(20
)

(19
)

(163
)
Foreign currency derivatives:

Other nonoperating items

—

—

—

(159
)
Net gains (losses) recognized

$
(153
)

$
58

$
198

$
(359
)

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

September 30, 2017

December 31, 2016

(Millions)

Commodity derivative assets:

Other current assets

$
39

$
9

Other long-term assets

4

1

Interest rate derivative assets:

Other current assets

1

1

Total derivative assets

$
44

$
11

Commodity derivative liabilities:

Other current liabilities

$
53

$
187

Other long-term liabilities

7

16

Interest rate derivative liabilities:

Other current liabilities

1

—

Other long-term liabilities

61

41

Total derivative liabilities

$
122

$
244

~~Table of Contents~~

~~DEVON ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

4.	~~Share-Based Compensation~~

In the second quarter of 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards under the 2015 Plan that are transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.

~~The following table presents the effects of~~ share-based compensation expense included in Devon’s accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings. Gross G&A expense for the first nine months of 2017 and 2016 includes $28 million and $18 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.

The vesting for certain share-based awards was accelerated in ~~2016 in~~ conjunction with the reduction of workforce described in Note ~~6. For the nine months ended September 30, 2016, approximately $60 million of associated expense for these accelerated awards~~6 and is included in restructuring and transaction costs in the accompanying consolidated ~~comprehensive~~ statements of ~~earnings.~~comprehensive earnings.

Nine Months Ended September 30,

2017

2016

(Millions)

Gross G&A for share-based compensation

$
141

$
117

Share-based compensation expense capitalized pursuant to
the full cost method of accounting for oil and gas properties

$
31

$
30

Related income tax benefit

$
3

$
3

	Nine Months Ended September 30,
	2021		2020
G&A	$	58	$	58
Exploration expenses		1		1
Restructuring and transaction costs		21		11
Total	$	80	$	70
Related income tax benefit	$	8	$	—

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Under its approved long-term incentive plan, Devon ~~granted~~grants share-based awards to certain ~~employees in the first nine months of 2017.~~employees. The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plan.

	Restricted Stock					Performance-Based					Performance														Performance-Based					Performance
	Awards and Units					Restricted Stock Awards					Share Units							Restricted Stock Awards & 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		Awards/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)																	(Thousands, except fair value data)
Unvested at 12/31/16		6,407		$	34.40		585		$	37.60		2,604				$	46.66
Unvested at 12/31/20																			5,316				$	25.82		44		$	44.70		1,994				$	31.89
Granted		2,691		$	44.87		223		$	44.85		1,010				$	52.58		7,711		⁽¹	⁾	$	19.69		—		$	—		861				$	18.08
Vested		(2,321	)	$	39.51		(233	)	$	41.27		(832	)			$	78.19		(5,006	)			$	22.35		(44	)	$	44.70		(754	)			$	37.40
Forfeited		(252	)	$	36.06		—		$	—		(24	)			$	40.70		(126	)			$	23.21		—		$	—		(25	)			$	36.04
Unvested at 9/30/17		6,525		$	36.83		575		$	38.92		2,758		⁽¹	⁾	$	41.21
Unvested at 9/30/21																			7,895				$	22.08		—		$	—		2,076		⁽²	⁾	$	24.12

(1)

Due to the closing of the Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. As a result, approximately 4.9 million awards relate to the conversion of WPX equity awards to Devon equity awards.

(2)

A maximum of ~~5.5~~4.2 million common shares could be awarded based upon Devon’s final TSR ~~ranking relative to Devon’s peer group established under applicable award agreements.~~ranking.

The following table presents the assumptions related to the performance share units granted in ~~2017,~~2021, as indicated in the previous summary table.

	2017					2021
Grant-date fair value	$	51.05	—	$	53.12	$	18.08
Risk-free interest rate	1.50%					0.18%
Volatility factor	45.8%					67.8%
Contractual term (years)	2.89					2.89

~~Table of Contents~~

~~DEVON ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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 September 30, ~~2017.~~2021.

			Performance-Based
	Restricted Stock		Restricted Stock		Performance		Restricted Stock		Performance
	Awards and Units		Awards		Share Units		Awards/Units		Share Units
Unrecognized compensation cost (millions)	$	160	$	6	$	35
Unrecognized compensation cost							$	97	$	15
Weighted average period for recognition (years)		2.5		1.8		2.0		2.5		1.9

~~EnLink Share-Based Awards~~

In March 2017, the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees. The combined grant fair value was $10 million, and the total cost was recognized in the first quarter of 2017 due to the awards vesting immediately.

5.Asset Impairments

The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the ~~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~~consolidated statements of ~~September 30, 2017.~~comprehensive earnings.

General Partner

EnLink

Restricted

Performance

Restricted

Performance

Incentive Units

Units

Incentive Units

Units

Unrecognized compensation cost (millions)

$
14

$
6

$
15

$
6

Weighted average period for recognition (years)

1.8

2.0

1.7

1.9

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Proved oil and gas assets	$	—	$	—	$	—	$	2,664
Other assets		—		—		—		2
Total asset impairments	$	—	$	—	$	—	$	2,666

Unproved impairments	$	1	$	36	$	3	$	149

5.	~~Asset Impairments~~

~~The following table presents the components of asset impairments.~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Millions)

U.S. oil and gas assets

$
—

$
317

$
—

$
2,810

Canada oil and gas assets

—

—

—

1,166

EnLink goodwill

—

—

—

873

Other assets

2

2

9

2

Total asset impairments

$
2

$
319

$
9

$
4,851

~~Oil and Gas Impairments~~

Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10% per annum, net of related tax effects. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months.

The oil and gas impairments in 2016 resulted from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves.

~~EnLink Goodwill Impairments~~

~~In the first quarter of 2016, EnLink recognized goodwill impairments. See Note 12 for additional details.~~

1716

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Proved Oil and Gas and Other AssetImpairments

Due to the reduced demand from the COVID-19 pandemic causing an unprecedented downturn in the price of oil and reductions in near-term capital investment, Devon recognized approximately $2.7 billion of proved asset impairments during the first quarter of 2020. These impairments related to the Anadarko Basin and Rockies fields in which the cost basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher. During the first quarter of 2020, Devon also recognized $2 million of product line fill impairments.

UnprovedImpairments

Due to the downturn in the commodity price environment and reduced near-term investment as discussed above, Devon also recognized $149 million of unproved impairments during the first nine months of 2020, primarily in the Rockies field.

6.Restructuring and Transaction Costs

The following table summarizes Devon’s restructuring and transaction costs.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Restructuring costs	$	16	$	32	$	182	$	32
Transaction costs		2		—		48		—
Total costs	$	18	$	32	$	230	$	32

In conjunction with the Merger closing, Devon recognized $182 million of restructuring expenses during the first nine months of 2021 related to employee severance and termination benefits, settlements and curtailments from defined retirement benefits and contract terminations. Of these expenses, $65 million related to non-cash charges which primarily consisted of settlements and curtailments of defined retirement benefits of $40 million and the accelerated vesting of share-based grants of $21 million. Additionally, in conjunction primarily with the Merger closing, Devon recognized $48 million of transaction costs ~~presented in~~primarily comprised of bank, legal and accounting fees.

In the ~~accompanying consolidated comprehensive statement~~third quarter of ~~earnings.~~2020, Devon recognized $32 million of restructuring expenses. Of these expenses, $11 million resulted from the accelerated vesting of share-based grants, which are non-cash charges.

September 30, 2016

Three Months Ended

Nine Months Ended

(Millions)

2016 reduction in workforce:

Employee related costs

$
(7
)

$
229

Lease obligations

—

17

Asset impairments

—

3

Transaction costs

2

17

Restructuring and transaction costs

$
(5
)

$
266

The following table summarizes Devon’s restructuring liabilities.

Other

Other

Current

Long-term

Liabilities

Liabilities

Total

(Millions)

Balance as of December 31, 2016

$
48

$
62

$
110

Changes due to 2016 workforce reductions

(25
)

(2
)

(27
)
Changes related to prior years' restructurings

(3
)

(24
)

(27
)
Balance as of September 30, 2017

$
20

$
36

$
56

Balance as of December 31, 2015

$
13

$
63

$
76

Changes due to 2016 workforce reductions

58

13

71

Changes related to prior years' restructurings

5

(8
)

(3
)
Balance as of September 30, 2016

$
76

$
68

$
144

	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
Balance as of December 31, 2020	$	35		$	137		$	172
Changes related to 2021 merger integration		27			—			27
Changes related to prior years' restructurings		(8	)		(18	)		(26	)
Balance as of September 30, 2021	$	54		$	119		$	173

Balance as of December 31, 2019	$	20		$	1		$	21
Changes related to prior years' restructurings		(3	)		—			(3	)
Balance as of September 30, 2020	$	17		$	1		$	18

~~Reduction in Workforce~~

In the first nine months of 2016, Devon recognized $229 million in employee-related costs associated with a reduction in workforce. Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $30 million resulted from estimated settlements of defined retirement benefits.

As a result of the reduction of workforce, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Devon recognized restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using.

~~Transaction Costs~~

~~In the first nine months of 2016, Devon and EnLink recognized transaction costs primarily associated with the closing of the acquisitions discussed in Note 2.~~

1817

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7.Income Taxes

~~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 September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Millions)

Current income tax expense

$
39

$
85

$
71

$
72

Deferred income tax expense (benefit)

(14
)

86

(20
)

(300
)
Total income tax expense (benefit)

$
25

$
171

$
51

$
(228
)

U.S. statutory income tax rate

35
%

35
%

35
%

35
%
Deferred tax asset valuation allowance

(9
%)

(35
%)

(25
%)

(20
%)
Non-deductible goodwill impairments

0
%

6
%

0
%

(9
%)
Change in unrecognized tax benefits

3
%

7
%

1
%

(2
%)
Taxation on Canadian operations

(1
%)

0
%

0
%

(3
%)
State income taxes

0
%

2
%

0
%

1
%
Other

(19
%)

0
%

(7
%)

3
%
Effective income tax rate

9
%

15
%

4
%

5
%

	Three Months Ended September 30,					Nine Months Ended September 30,
	2021		2020			2021			2020
Earnings (loss) from continuing operations before income taxes	$	964	$	(193	)	$	1,236		$	(2,980	)

Current income tax expense (benefit)	$	1	$	(90	)	$	15		$	(199	)
Deferred income tax expense (benefit)		119		—			(100	)		(311	)
Total income tax expense (benefit)	$	120	$	(90	)	$	(85	)	$	(510	)

U.S. statutory income tax rate	21	%	21	%	21	%	21	%
State income taxes	0	%	0	%	0	%	1	%
Unrecognized tax benefits	0	%	18	%	0	%	0	%
Deferred tax asset valuation allowance	(9	%)	4	%	(33	%)	(7	%)
Other	0	%	4	%	5	%	2	%
Effective income tax rate	12	%	47	%	(7	%)	17	%

~~Devon estimates its annual effective~~The deferred 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~~benefit recognized ~~as discrete items in the quarter in which they occur.~~

Throughout 2016 and through the first nine months of 2017, 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 full cost impairments. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.

~~Devon provided an additional $796 million to the U.S. segment valuation allowance~~ in the first nine months of ~~2016 based~~2021 primarily relates to the Merger and a reduced valuation allowance due to increased earnings. As shown in Note 2, Devon recognized $249 million of deferred tax liabilities to account for the Merger. The recognition of these deferred tax liabilities caused a decrease to Devon’s net deferred tax assets and a corresponding decrease to the valuation allowance Devon has recognized on ~~the financial loss recorded during the period. Also, during the third quarter of 2016, Devon’s Canadian segment recorded a $71 million partial valuation allowance. Devon reduced~~ its U.S. ~~segment~~Federal deferred tax assets. Additionally, improved commodity prices and post-merger operating performance are causing reductions to Devon’s net operating losses, which also cause corresponding decreases to the associated deferred tax assets and valuation allowance.

As of September 30, 2021, Devon continued to maintain a valuation allowance ~~by $348 million~~against certain U.S. deferred tax assets. Devon continues to assess its valuation allowance position every quarter. Subject to any additional objective negative evidence or the addition of subjective evidence such as forecasted income, Devon may continue to adjust the valuation allowance on its deferred tax assets in ~~the first nine months of 2017 based on the financial income recorded during the period.~~

Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in the third quarter of 2017 due to lower relative earnings during the period. During the third quarter of 2017, “other” is primarily related to the taxation of foreign earnings and other financing items.future periods.

In the ~~first~~fourth quarter of ~~2016, EnLink~~2020, Devon recorded ~~goodwill impairments totaling $873 million. These impairments are not~~a deferred tax asset representing the deductible ~~for purposes~~outside basis difference in its investment in a consolidated subsidiary. In the second quarter of ~~calculating income~~2021, Devon realized this deferred tax ~~and, therefore, have an impact on the effective tax rate.~~asset, increasing its U.S. federal net operating loss carryforwards by $1.8 billion.

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.

1918

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8.	Net Earnings (Loss) Per Share ~~Attributable to Devon~~from Continuing Operations

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

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2021			2020			2021			2020
	(Millions, except per share amounts)
Net earnings (loss):
Net earnings (loss) attributable to Devon	$	228		$	993		$	1,218		$	(3,633	)
Net earnings (loss) from continuing operations:
Net earnings (loss) from continuing operations													$	838		$	(105	)	$	1,307		$	(2,475	)
Attributable to participating securities		(2	)		(11	)		(13	)		(1	)		(6	)		(2	)		(11	)		(3	)
Basic and diluted earnings (loss)	$	226		$	982		$	1,205		$	(3,634	)
Basic and diluted earnings (loss) from continuing operations													$	832		$	(107	)	$	1,296		$	(2,478	)
Common shares:
Common shares outstanding - total		526			524			525			509			677			383			670			383
Attributable to participating securities		(6	)		(6	)		(6	)		(6	)		(6	)		(6	)		(6	)		(6	)
Common shares outstanding - basic		520			518			519			503			671			377			664			377
Dilutive effect of potential common shares issuable		3			3			3			—			2			—			2			—
Common shares outstanding - diluted		523			521			522			503			673			377			666			377
Net earnings (loss) per share attributable to Devon:
Net earnings (loss) per share from continuing operations:
Basic	$	0.43		$	1.90		$	2.32		$	(7.22	)	$	1.24		$	(0.29	)	$	1.95		$	(6.58	)
Diluted	$	0.43		$	1.89		$	2.31		$	(7.22	)	$	1.24		$	(0.29	)	$	1.95		$	(6.58	)
Antidilutive options ⁽¹⁾		2			3			2			3

~~(1)~~

9.Other Comprehensive Earnings (Loss)

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

9.	~~Other Comprehensive Earnings~~

Components of other comprehensive earnings (loss) consist of the following:

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Millions)

Foreign currency translation:

Beginning accumulated foreign currency translation

$
456

$
450

$
456

$
424

Change in cumulative translation adjustment

17

(1
)

31

52

Income tax benefit (expense)

(16
)

3

(30
)

(24
)
Ending accumulated foreign currency translation

457

452

457

452

Pension and postretirement benefit plans:

Beginning accumulated pension and postretirement benefits

(163
)

(185
)

(172
)

(194
)
Recognition of net actuarial loss and prior
service cost in earnings ⁽¹⁾

5

7

14

20

Income tax benefit

—

4

—

—

Ending accumulated pension and postretirement benefits

(158
)

(174
)

(158
)

(174
)
Other

(2
)

—

(2
)

—

Accumulated other comprehensive earnings, net of tax

$
297

$
278

$
297

$
278

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits	$	(101	)	$	(117	)	$	(127	)	$	(119	)
Recognition of net actuarial loss and prior service cost in earnings ⁽¹⁾		1			1			2			4
Settlement of pension benefits ⁽²⁾		—			—			18			—
Income tax expense		—			—			—			(1	)
Other ⁽³⁾		—			—			7			—
Accumulated other comprehensive loss, net of tax	$	(100	)	$	(116	)	$	(100	)	$	(116	)

~~(1)~~

~~These accumulated other comprehensive earnings components~~(1)

Recognition of net actuarial loss and prior service cost are included in the computation of net periodic benefit cost, which is a component of ~~G&A on~~other, net in the accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings. ~~See Note 16 for additional details.~~

(2)

The Merger triggered settlement payments to certain plan participants, and the expense associated with this settlement is recognized as a component of restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.

(3)

Other includes a remeasurement of the pension obligation due to the Merger, which was partially offset by a change in mortality assumption.

2019

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

10.	Supplemental Information to Statements of Cash Flows

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Millions)

Net change in working capital accounts,
net of assets and liabilities assumed:

Accounts receivable

$
(215
)

$
81

$
(85
)

$
87

Income taxes receivable

—

6

8

107

Other current assets

12

98

(43
)

242

Accounts payable

48

(34
)

98

(185
)
Revenues and royalties payable

63

40

92

34

Other current liabilities

99

(54
)

24

(77
)
Net change in working capital

$
7

$
137

$
94

$
208

Interest paid (net of capitalized interest)

$
49

$
113

$
285

$
402

Income taxes paid (received)

$
—

$
(7
)

$
(1)

$
(130
)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Changes in assets and liabilities, net:
Accounts receivable	$	(332	)	$	21		$	(495	)	$	339
Income tax receivable		(40	)		—			94			(112	)
Other current assets		21			18			(36	)		10
Other long-term assets		14			(9	)		(9	)		(33	)
Accounts payable and revenues and royalties payable		469			100			557			(160	)
Other current liabilities		(49	)		15			(30	)		(82	)
Other long-term liabilities		(15	)		(87	)		(123	)		(59	)
Total	$	68		$	58		$	(42	)	$	(97	)
Supplementary cash flow data - total operations:
Interest paid	$	100		$	64		$	319		$	194
Income taxes paid (refunded)	$	(4	)	$	(2	)	$	(116	)	$	170

~~Devon’s acquisition~~As of ~~certain STACK assets during~~September 30, 2021, Devon had approximately $200 million of accrued capital expenditures included in total property and equipment, net and accounts payable on the ~~first three months~~consolidated balance sheets. As of ~~2016~~December 31, 2020 (pre-merger), Devon had approximately $100 million of accrued capital expenditures in total property and equipment, net and accounts payable on the consolidated balance sheets. As of January 7, 2021 (date of Merger closing), Devon assumed approximately $150 million of accrued capital expenditures included ~~the noncash issuance of Devon common stock. See Note 2 for additional details.~~

EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016 included the noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions. See Note 2 for additional details.

in accounts payable.

11.	Accounts Receivable

Components of accounts receivable include the following:

	September 30, 2017			December 31, 2016
	(Millions)						September 30, 2021			December 31, 2020
Oil, gas and NGL sales	$	528		$	487		$	986		$	335
Joint interest billings		111			110			150			57
Marketing and midstream revenues		792			708			371			195
Other		44			69			22			25
Gross accounts receivable		1,475			1,374			1,529			612
Allowance for doubtful accounts		(13	)		(18	)		(12	)		(11	)
Net accounts receivable	$	1,462		$	1,356		$	1,517		$	601

12.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.

	September 30, 2021			December 31, 2020
Property and equipment:
Proved	$	36,489		$	27,589
Unproved and properties under development		2,169			392
Total oil and gas		38,658			27,981
Less accumulated DD&A		(25,045	)		(23,545	)
Oil and gas property and equipment, net		13,613			4,436
Other property and equipment		2,113			1,737
Less accumulated DD&A		(648	)		(780	)
Other property and equipment, net ⁽¹⁾		1,465			957
Property and equipment, net	$	15,078		$	5,393

~~12.~~

~~Goodwill~~(1)

$106 million and ~~Other Intangible Assets~~$102 million related to CDM in 2021 and 2020, respectively.

~~Goodwill~~

Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a noncash goodwill impairment of $873 million in the first quarter of 2016. This consisted of a full impairment charge of $93 million related to EnLink’s Crude and Condensate reporting unit and partial impairments to EnLink’s Texas and General Partner reporting units of $473 million and $307 million, respectively.

~~Asset Divestitures~~

~~During the third quarter of 2016, Devon derecognized $197 million of goodwill in conjunction with the upstream oil and gas asset divestitures discussed in Note 2.~~

2120

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

~~Other Intangible Assets~~

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

September 30, 2017

December 31, 2016

(Millions)

Customer relationships

$
1,796

$
1,796

Accumulated amortization

(202
)

(172
)
Net intangibles

$
1,594

$
1,624

The weighted-average amortization period for other intangible assets is 15 years. Amortization expense for intangibles was $37 million and $29 million for the three months ended September 30, 2017 and 2016, respectively, and $96 million and $87 million for the nine months ended September 30, 2017 and 2016, respectively. The remaining amortization expense is estimated to be $123 million for each of the next five years.

13.	~~Other Current Liabilities~~

~~Components of other current liabilities include the following:~~

September 30, 2017

December 31, 2016

(Millions)

Installment payment - see Note 2
$
243

$
249

Accrued interest payable

204

130

Income taxes payable

197

32

Derivative liabilities

54

187

Restructuring liabilities

20

48

Other

285

420

Other current liabilities
$
1,003

$
1,066

~~14.~~

Debt and Related Expenses

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

September 30, 2017

December 31, 2016

(Millions)

Devon debt:

Debentures and notes

$
6,933

$
6,933

Net discount on debentures and notes

(30
)

(30
)
Debt issuance costs

(41
)

(44
)
Total Devon debt

6,862

6,859

EnLink debt:

Credit facilities

74

148

Debentures and notes

3,500

3,163

Net premium (discount) on debentures and notes

(6
)

9

Debt issuance costs

(27
)

(25
)
Total EnLink debt

3,541

3,295

Total debt

10,403

10,154

Less amount classified as short-term debt⁽¹⁾

20

—

Total long-term debt

$
10,383

$
10,154

	September 30, 2021			December 31, 2020
8.25% due August 1, 2023 ⁽¹⁾	$	242		$	—
5.25% due September 15, 2024 ⁽¹⁾		472			—
5.85% due December 15, 2025		485			485
7.50% due September 15, 2027		73			73
5.25% due October 15, 2027 ⁽¹⁾		390			—
5.875% due June 15, 2028 ⁽¹⁾		325			—
4.50% due January 15, 2030 ⁽¹⁾		585			—
7.875% due September 30, 2031		675			675
7.95% due April 15, 2032		366			366
5.60% due July 15, 2041		1,250			1,250
4.75% due May 15, 2042		750			750
5.00% due June 15, 2045		750			750
Net premium (discount) on debentures and notes		160			(20	)
Debt issuance costs		(31	)		(31	)
Total long-term debt	$	6,492		$	4,298

~~(1)~~

~~Short-term~~(1)

These instruments were assumed by Devon in January 2021 in conjunction with the Merger. Subsequent to debt asretirements and the obligor exchange transaction completed during the first nine months of ~~September 30, 2017 consists of $20~~2021, approximately $51 million of ~~8.25% senior notes due July 1, 2018.~~these instruments remain the unsecured and unsubordinated obligation of WPX, a wholly-owned subsidiary of Devon.

22Debt maturities as of September 30, 2021, excluding debt issuance costs, premiums and discounts, are as follows:

	Total
2022	$	—
2023		242
2024		472
2025		485
2026		—
Thereafter		5,164
Total	$	6,363

The following schedule includes the summary of the WPX debt Devon assumed upon closing of the Merger on January 7, 2021.

	Face Value		Fair Value		Optional Redemption⁽¹⁾
6.00% due January 15, 2022	$	43	$	44
8.25% due August 1, 2023		242		281	June 1, 2023
5.25% due September 15, 2024		472		530	June 15, 2024
5.75% due June 1, 2026		500		529	June 1, 2021
5.25% due October 15, 2027		600		646	October 15, 2022
5.875% due June 15, 2028		500		554	June 15, 2023
4.50% due January 15, 2030		900		978	January 15, 2025
	$	3,257	$	3,562

(1)

At any time prior to these dates, Devon has or had the option to redeem (i) some or all of the notes at a specified "make whole" premium and (ii) a portion of certain of the notes at applicable redemption prices, in each case as described in the indenture documents governing the notes to be redeemed. On or after these dates, Devon has or had the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture documents, plus accrued and unpaid interest thereon to the redemption date as more fully described in such documents.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

~~Credit Lines~~

Devon has a $3.0 billion Senior Credit Facility. As of September 30, 2017, Devon had $59 million in outstanding letters of credit under the Senior Credit Facility. There were no outstanding borrowings under the Senior Credit Facility at September 30, 2017. 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 full cost ceiling impairments or goodwill impairments. As of September 30, 2017, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 18.9%.

Retirement of Senior Notes

In the ~~third quarter~~first nine months of ~~2016,~~2021, Devon ~~completed tender offers to repurchase $1.2 billion~~redeemed $43 million of ~~debt securities, using proceeds from~~ the ~~asset divestitures discussed in Note 2.~~6.00% senior notes due 2022, $175 million of the 5.875% senior notes due 2028, $315 million of the 4.50% senior notes due 2030, $210 million of the 5.25% senior notes due 2027 and $500 million of the 5.75% senior notes due 2026. In the first nine months of 2021, Devon recognized ~~a loss~~$30 million of gains on early retirement of debt, ~~primarily~~ consisting of ~~$82~~$89 million inof non-cash premium accelerations, partially offset by $59 million of cash retirement ~~costs and other fees. These costs, along with other minimal noncash charges associated with retiring the debt, are~~costs. The gain on early retirement is included in ~~net~~ financing costs, net in the consolidated ~~comprehensive~~ statements of comprehensive earnings.

~~EnLink Debt~~

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

~~EnLink~~Devon has a ~~$1.5~~$3.0 billion ~~unsecured revolving credit facility.~~Senior Credit Facility. As of September 30, ~~2017, there were $9~~2021, Devon had 0 outstanding borrowings under the Senior Credit Facility and had issued $2 million in outstanding letters of credit ~~and no outstanding borrowings~~ under ~~the $1.5 billion credit~~this facility. The ~~General Partner has a $250 million secured revolving~~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 ~~facility.~~agreement, to be no greater than 65%. Under the terms of the credit agreement, total capitalization is adjusted to add back non-cash financial write-downs such as impairments. As of September 30, ~~2017, the General Partner had $74 million in outstanding borrowings at an average rate of 3.2%. EnLink and the General Partner were~~2021, Devon was in compliance with ~~all financial covenants in their respective credit facilities as~~this covenant with a debt-to-capitalization ratio of ~~September 30, 2017.~~

In the second quarter of 2017, EnLink issued $500 million of 5.45% unsecured senior notes due in 2047. The proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive statement of earnings.25.1%.

Net Financing Costs

The following schedule includes the components of net financing costs.

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

Devon net financing costs:

Interest based on debt outstanding

$
97

$
120

$
292

$
376

Early retirement of debt

—

84

—

84

Capitalized interest

(19
)

(16
)

(53
)

(47
)
Other

(1
)

7

(3
)

18

Total Devon net financing costs

77

195

236

431

EnLink net financing costs:

Interest based on debt outstanding

43

37

125

105

Interest accretion on deferred installment payment

7

13

20

39

Early retirement of debt

—

—

(9
)

—

Other

—

(2
)

(2
)

(5
)
Total EnLink net financing costs

50

48

134

139

Total net financing costs

$
127

$
243

$
370

$
570

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Interest based on debt outstanding	$	93		$	65		$	296		$	195
Gain on early retirement of debt		—			—			(30	)		—
Interest income		(1	)		(5	)		(2	)		(12	)
Other		(6	)		6			(21	)		17
Total net financing costs	$	86		$	66		$	243		$	200

2314.Leases

The following table presents Devon’s right-of-use assets and lease liabilities as of September 30, 2021 and December 31, 2020.

	September 30, 2021						December 31, 2020
	Finance		Operating		Total		Finance		Operating		Total
Right-of-use assets	$	214	$	30	$	244	$	220	$	3	$	223
Lease liabilities:
Current lease liabilities ⁽¹⁾	$	8	$	20	$	28	$	8	$	1	$	9
Long-term lease liabilities		246		10		256		244		2		246
Total lease liabilities	$	254	$	30	$	284	$	252	$	3	$	255

(1)Current lease liabilities are included in other current liabilities on the consolidated balance sheets.

Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

15.	Asset Retirement Obligations

~~15. Asset Retirement Obligations~~

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

Nine Months Ended September 30,

2017

2016

(Millions)

Asset retirement obligations as of beginning of period

$
1,272

$
1,414

Liabilities incurred and assumed through acquisitions

30

18

Liabilities settled and divested

(53
)

(310
)
Revision of estimated obligation

(184
)

70

Accretion expense on discounted obligation

47

58

Foreign currency translation adjustment

29

26

Asset retirement obligations as of end of period

1,141

1,276

Less current portion

41

46

Asset retirement obligations, long-term

$
1,100

$
1,230

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.

During the first nine months of 2016, Devon reduced its asset retirement obligation by $285 million for those obligations that were assumed by purchasers of certain upstream U.S. assets. See Note 2 for additional details.

~~16.~~

~~Retirement Plans~~

~~The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.~~

Pension Benefits

Postretirement Benefits

Three Months Ended

Nine Months Ended

Three Months Ended

Nine Months Ended

September 30,

September 30,

September 30,

September 30,

2017

2016

2017

2016

2017

2016

2017

2016

(Millions)

Service cost

$
4

$
3

$
12

$
12

$
—

$
—

$
—

$
—

Interest cost

11

9

32

32

—

—

—

—

Expected return on plan assets

(14
)

(14
)

(41
)

(40
)

—

—

—

—

Amortization of prior service cost ⁽¹⁾

—

1

1

2

—

—

(1
)

(1
)
Net actuarial loss ⁽¹⁾

5

6

14

19

—

—

—

—

Net periodic benefit cost ⁽²⁾

$
6

$
5

$
18

$
25

$
—

$
—

$
(1
)

$
(1
)

	Nine Months Ended September 30,
	2021			2020
Asset retirement obligations as of beginning of period	$	369		$	398
Assumed WPX obligations		98			—
Liabilities incurred		28			15
Liabilities settled and divested		(52	)		(24	)
Revision of estimated obligation		11			4
Accretion expense on discounted obligation		21			15
Asset retirement obligations as of end of period		475			408
Less current portion		13			10
Asset retirement obligations, long-term	$	462		$	398

~~(1)~~

~~These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.~~

~~(2) Net periodic benefit cost is a component of G&A in the accompanying consolidated comprehensive statements of earnings.~~

~~17.~~16.

Stockholders’ Equity

~~Common Stock Issued~~WPX Merger

InOn January ~~2016,~~7, 2021, Devon and WPX completed an all-stock merger of equals. On the closing date of the Merger, each share of WPX common stock was automatically converted into the right to receive0.5165 of a share of Devon common stock. Consequently, Devon issued approximately 23290 million shares of ~~common stock in conjunction with the STACK asset acquisition discussed in Note 2.~~

~~In February 2016,~~ Devon ~~issued 79 million shares of~~ common stock to holders of WPX common stock to effect the ~~public, inclusive~~Merger on January 7, 2021.

Share Repurchases

The table below provides information regarding purchases of ~~10 million shares sold as part~~Devon’s common stock that were made in 2020 under a share repurchase program that expired at the end of ~~the underwriters’ option. Net proceeds from the offering were $1.5 billion.~~2020 (shares in thousands).

	Total Number of Shares Purchased		Dollar Value of Shares Purchased		Average Price Paid per Share

First quarter 2020		2,243	$	38	$	16.85
Total		2,243	$	38	$	16.85

In November 2021, Devon authorized a share repurchase program to buy up to $1.0 billion of common stock. This program expires December 31, 2022.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

~~Dividends~~

~~The table below summarizes~~Dividends

Upon completion of the ~~dividends~~Merger, Devon ~~paid on~~continued its ~~common stock.~~

Amounts

Rate

(Millions)

(Per Share)

Quarter Ended 2017:

First quarter 2017
$
32

$
0.06

Second quarter 2017

33

$
0.06

Third quarter 2017

30

$
0.06

Total year-to-date
$
95

Quarter Ended 2016:

First quarter 2016
$
125

$
0.24

Second quarter 2016

33

$
0.06

Third quarter 2016

32

$
0.06

Total year-to-date
$
190

~~In response~~commitment to ~~the depressed commodity price environment, Devon reduced its~~pay a quarterly dividend ~~to $0.06 per share in the second quarter of 2016.~~

~~18.~~

~~Noncontrolling Interests~~

~~Subsidiary Equity Transactions~~

EnLink has the ability to sell common units through its “at the market” equity offering programs. In the third quarter of 2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common units through its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. Duringat a fixed rate and instituted a variable quarterly dividend, which is dependent on quarterly cash flows, among other factors. The following table summarizes Devon’s fixed and variable dividends for the first nine months of ~~2017, EnLink issued~~2021 and ~~sold 5 million common units through its programs and generated $92 million in net proceeds.~~2020, respectively.

	Fixed		Variable		Total		Rate Per Share
2021:
First quarter	$	76	$	127	$	203	$	0.30
Second quarter		75		154		229	$	0.34
Third quarter		74		255		329	$	0.49
Total year-to-date	$	225	$	536	$	761
2020:
First quarter	$	34	$	—	$	34	$	0.09
Second quarter		42		—		42	$	0.11
Third quarter		43		—		43	$	0.11
Total year-to-date	$	119	$	—	$	119

In ~~September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds~~November 2021, Devon announced a cash dividend in the amount of $0.84 per share payable in the fourth quarter of 2021. The dividend consists of a fixed quarterly dividend in the amount of approximately ~~$394 million.~~

~~During the first nine months of 2016, EnLink issued~~$74 million (or $0.11 per share) and sold 7 million common units for net proceeds of $110 million. In conjunction with its acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016, EnLink issued preferred units as discussed in Note 2.

~~As of September 30, 2017, Devon’s ownership interest in EnLink was 23%, excluding the interest held by the General Partner. Devon’s controlling ownership interest~~a variable quarterly dividend in the ~~General Partner as~~amount of ~~September 30, 2017 was 64%~~approximately $494 million (or $0.73 per share). The net gains and losses and related income taxes resulting from these transactions have been recorded as an adjustment to equity, with the change in ownership reflected as an adjustment to noncontrolling interests.

~~Distributions to~~ Noncontrolling Interests

~~EnLink~~The noncontrolling interests’ share of CDM’s net earnings and the ~~General Partner distributed $247~~contributions from and distributions to the noncontrolling interests are presented as components of equity.

17.	Discontinued Operations

On October 1, 2020, Devon completed the sale of its Barnett Shale assets to BKV for proceeds, net of purchase price adjustments, of $490 million. Additionally, the agreement provides for contingent earnout payments to Devon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commenced on January 1, 2021 and ~~$224 million to non-Devon unitholders during~~has a term of four years.

The following table presents the ~~first nine months~~amounts reported in the consolidated statements of ~~2017 and 2016, respectively.~~comprehensive earnings as discontinued operations.

	Three Months Ended September 30, 2020			Nine Months Ended September 30, 2020
Oil, gas and NGL sales	$	94		$	263
Total revenues		94			263
Production expenses		66			214
Asset impairments ⁽¹⁾		3			182
Asset dispositions		—			(2	)
General and administrative expenses		2			3
Financing costs, net		(1	)		(3	)
Other, net		26			19
Total expenses		96			413
Loss from discontinued operations before income taxes		(2	)		(150	)
Income tax benefit		(15	)		(47	)
Net earnings (loss) from discontinued operations, net of tax	$	13		$	(103	)

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

~~19.~~

(1)

Devon recognized $182 million of asset impairments in the first nine months of 2020 related to the Barnett Shale assets primarily due to the difference between the net carrying value and the purchase price, net of estimated customary purchase price adjustments, which qualified as a level 2 fair value measurement.

18.	Commitments and Contingencies

Devon is party to various legal ~~actions arising~~proceedings and other matters that may result in ~~the normal course of~~future payment obligations or other adverse consequences to its business. Matters that are probable of an unfavorable outcome to Devon and which any related potential payment obligation or other liability 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~~While management does not believe any current matter is likely to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded ~~accruals. Actual~~accruals, the ultimate outcome of such matters and the amounts involved could differ materially from management’s ~~estimates.~~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. ~~The~~Devon is currently defending against a number of such lawsuits, either as a named defendant in the action or pursuant to indemnity obligations for the benefit of a third party. Plaintiffs in some of these lawsuits are seeking class certification. Among the allegations typically asserted in these suits ~~allege~~are claims that ~~the producers and related parties~~Devon used below-market prices, made improper deductions, failed to “enhance” the value of gas through processing, used improper measurement techniques, ~~and~~ entered into ~~gas~~ purchase and ~~processing~~midstream arrangements with affiliates that resulted in underpayment of royalties ~~in connection with~~or otherwise failed to prudently market oil, natural gas and NGLs produced and ~~sold.~~sold and pay royalties on the highest obtainable price. 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 and Climate Change Matters

~~Devon~~Devon’s business is subject to ~~certain environmental, health~~numerous federal, state, local and ~~safety~~Native American tribal laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, as well as remediation costs. Although Devon believes that it is in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, there can be no assurance that this will continue in the future.

Beginning in 2013, various parishes in Louisiana filed suit against numerous oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs’ claims against Devon relate primarily to the operations of several of Devon’s corporate predecessors. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon believes these claims to be baseless and is vigorously defending against these claims.

The State of Delaware and various municipalities and other governmental and private parties in California have filed legal proceedings against numerous oil and gas companies, including Devon, seeking relief to abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctive relief. Although Devon cannot predict the ultimate outcome of these matters,Devon believes these claims to be baseless and intends to vigorously defend against the proceedings.

Williams’ Former Power Business Matter

Direct and indirect purchasers of natural gas in various states filed individual and class action lawsuits against The Williams Companies, Inc. (“Williams”) and other parties alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. WPX and certain of its subsidiaries, which were then affiliates of Williams, were also named as defendants in these actions.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Devon cannot reasonably estimate a range of potential exposure at this time for these matters. In connection with its spin-off from Williams in 2011, WPX entered into a separation and distribution agreement with Williams, pursuant to which Williams agreed to indemnify and hold WPX and its subsidiaries harmless from any losses arising out of these matters.

Other Indemnifications and Legacy Matters

Pursuant to various sale agreements relating to divested businesses and assets, Devon has indemnified various purchasers against liabilities that they may incur with respect to ~~environmental remediation~~the businesses and assets acquired from Devon. Additionally, federal, state and other laws in areas of former operations may require previous operators (including corporate successors of previous operators) to perform or make payments in certain circumstances where the current operator may no longer be able to satisfy the applicable obligation. Such obligations may include plugging and abandoning wells, removing production facilities or performing requirements under surface agreements in existence at the time of disposition.

In November 2020, the Department of the Interior, Bureau of Safety and Environmental Enforcement, ordered several oil and gas operators, including Devon, to perform decommissioning and reclamation activities ~~associated with past operations, such as~~related to two California offshore oil and gas production platforms and related facilities. The current operator and owner of the ~~Comprehensive Environmental Response, Compensation,~~platforms contends that it does not have the financial ability to perform these obligations and ~~Liability Act and similar state statutes.~~relinquished the related federal lease in October 2020. In response to ~~liabilities associated with these activities, loss accruals primarily consist~~the apparent insolvency of ~~estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected~~the current operator, the government has ordered the former operators and alleged former lease record title owners to decommission the platforms. The government contends that an alleged corporate predecessor of Devon owned a partial interest in the subject lease and platforms. Although Devon cannot predict the ultimate outcome of this matter, Devon denies any obligation to decommission the subject platforms, has appealed the order, and believes any decommissioning obligation related to the subject platforms should 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.assumed by others.

~~20.~~19.

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 and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at September 30, ~~2017~~2021 and December 31, ~~2016.~~2020, as applicable. Therefore, such financial assets and liabilities are not presented in the following ~~table.~~table. Additionally, information regarding 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 5 ~~and Note 12, respectively.~~.

Fair Value

Measurements Using:

Carrying

Total Fair

Level 1

Level 2

Amount

Value

Inputs

Inputs

(Millions)

September 30, 2017 assets (liabilities):

Cash equivalents

$
1,510

$
1,510

$
1,431

$
79

Commodity derivatives

$
43

$
43

$
—

$
43

Commodity derivatives

$
(60
)

$
(60
)

$
—

$
(60
)
Interest rate derivatives

$
1

$
1

$
—

$
1

Interest rate derivatives

$
(62
)

$
(62
)

$
—

$
(62
)
Debt

$
(10,403
)

$
(11,480
)

$
—

$
(11,480
)
Installment payment

$
(243
)

$
(244
)

$
—

$
(244
)
Capital lease obligations

$
(4
)

$
(4
)

$
—

$
(4
)

December 31, 2016 assets (liabilities):

Cash equivalents

$
1,542

$
1,542

$
1,298

$
244

Commodity derivatives

$
10

$
10

$
—

$
10

Commodity derivatives

$
(203
)

$
(203
)

$
—

$
(203
)
Interest rate derivatives

$
1

$
1

$
—

$
1

Interest rate derivatives

$
(41
)

$
(41
)

$
—

$
(41
)
Debt

$
(10,154
)

$
(10,760
)

$
—

$
(10,760
)
Installment payment

$
(473
)

$
(477
)

$
—

$
(477
)
Capital lease obligations

$
(7
)

$
(6
)

$
—

$
(6
)

							Fair Value Measurements Using:
	Carrying			Total Fair			Level 1		Level 2			Level 3
	Amount			Value			Inputs		Inputs			Inputs
September 30, 2021 assets (liabilities):
Cash equivalents	$	1,321		$	1,321		$	1,321	$	—		$	—
Commodity derivatives	$	2		$	2		$	—	$	2		$	—
Commodity derivatives	$	(1,086	)	$	(1,086	)	$	—	$	(1,086	)	$	—
Debt	$	(6,492	)	$	(7,629	)	$	—	$	(7,629	)	$	—
Contingent earnout payments	$	135		$	135		$	—	$	—		$	135
December 31, 2020 assets (liabilities):
Cash equivalents	$	1,436		$	1,436		$	1,436	$	—		$	—
Commodity derivatives	$	6		$	6		$	—	$	6		$	—
Commodity derivatives	$	(148	)	$	(148	)	$	—	$	(148	)	$	—
Debt	$	(4,298	)	$	(5,365	)	$	—	$	(5,365	)	$	—
Contingent earnout payments	$	66		$	66		$	—	$	—		$	66

~~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~~the fair value approximates the carrying value.

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Level 2 Fair Value Measurements

~~Cash equivalents~~

Commodity derivatives – ~~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~~is estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Debt – Devon’s debt instruments do not consistently trade 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~~maturity when active trading is not available.

Level 3 Fair Value Measurements

Contingent Earnout Payments – Devon has the ~~credit facility balance is~~right to receive contingent consideration related to the ~~carrying value.~~

~~Installment payment~~ ~~– The fair value of the EnLink installment payment was~~Barnett and non-core Rockies asset divestitures based on ~~Level 2 inputs from third-party market quotations.~~

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

~~21.~~

~~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 infuture 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.~~prices. These values were derived using a Monte Carlo valuation model 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 presentedqualify as a ~~separate reporting segment.~~level 3 fair value measurement. For additional information, see Note 2.

Table of Contents

~~DEVON ENERGY CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

U.S.

Canada

EnLink

Eliminations

Total

(Millions)

Three Months Ended September 30, 2017:

Revenues from external customers

$
1,575

$
358

$
1,223

$
—

$
3,156

Asset dispositions and other

$
1

$
—

$
(1
)

$
—

$
—

Intersegment revenues

$
—

$
—

$
174

$
(174
)

$
—

Depreciation, depletion and amortization

$
195

$
63

$
142

$
—

$
400

Interest expense

$
82

$
17

$
49

$
(15
)

$
133

Asset impairments

$
—

$
—

$
2

$
—

$
2

Earnings before income taxes

$
167

$
85

$
20

$
—

$
272

Income tax expense

$
(5
)

$
28

$
2

$
—

$
25

Net earnings

$
172

$
57

$
18

$
—

$
247

Net earnings attributable to noncontrolling interests

$
—

$
—

$
19

$
—

$
19

Net earnings (loss) attributable to Devon

$
172

$
57

$
(1
)

$
—

$
228

Capital expenditures, including acquisitions

$
560

$
103

$
170

$
—

$
833

Three Months Ended September 30, 2016:

Revenues from external customers

$
1,653

$
305

$
924

$
—

$
2,882

Asset dispositions and other

$
1,351

$
—

$
—

$
—

$
1,351

Intersegment revenues

$
—

$
—

$
180

$
(180
)

$
—

Depreciation, depletion and amortization

$
196

$
72

$
126

$
—

$
394

Interest expense

$
185

$
34

$
49

$
(23
)

$
245

Asset impairments

$
317

$
2

$
—

$
—

$
319

Restructuring and transaction costs

$
(10
)

$
5

$
—

$
—

$
(5
)
Earnings before income taxes

$
1,122

$
37

$
19

$
—

$
1,178

Income tax expense

$
5

$
159

$
7

$
—

$
171

Net earnings (loss)

$
1,117

$
(122
)

$
12

$
—

$
1,007

Net earnings attributable to noncontrolling interests

$
—

$
—

$
14

$
—

$
14

Net earnings (loss) attributable to Devon

$
1,117

$
(122
)

$
(2
)

$
—

$
993

Capital expenditures, including acquisitions

$
277

$
48

$
132

$
—

$
457

Nine Months Ended September 30, 2017:

Revenues from external customers

$
5,547

$
951

$
3,468

$
—

$
9,966

Asset dispositions and other

$
11

$
—

$
(1
)

$
—

$
10

Intersegment revenues

$
—

$
—

$
515

$
(515
)

$
—

Depreciation, depletion and amortization

$
556

$
199

$
407

$
—

$
1,162

Interest expense

$
243

$
48

$
133

$
(42
)

$
382

Asset impairments

$
—

$
—

$
9

$
—

$
9

Earnings before income taxes

$
1,133

$
126

$
69

$
—

$
1,328

Income tax expense

$
—

$
42

$
9

$
—

$
51

Net earnings

$
1,133

$
84

$
60

$
—

$
1,277

Net earnings attributable to noncontrolling interests

$
—

$
—

$
59

$
—

$
59

Net earnings attributable to Devon

$
1,133

$
84

$
1

$
—

$
1,218

Property and equipment, net

$
7,726

$
2,787

$
6,569

$
—

$
17,082

Total assets

$
13,302

$
3,761

$
10,548

$
(52
)

$
27,559

Capital expenditures, including acquisitions

$
1,460

$
275

$
636

$
—

$
2,371

Nine Months Ended September 30, 2016:

Revenues from external customers

$
4,320

$
688

$
2,488

$
—

$
7,496

Asset dispositions and other

$
1,351

$
—

$
—

$
—

$
1,351

Intersegment revenues

$
—

$
—

$
539

$
(539
)

$
—

Depreciation, depletion and amortization

$
763

$
284

$
373

$
—

$
1,420

Interest expense

$
400

$
101

$
140

$
(66
)

$
575

Asset impairments

$
2,810

$
1,168

$
873

$
—

$
4,851

Restructuring and transaction costs

$
245

$
15

$
6

$
—

$
266

Loss before income taxes

$
(2,040
)

$
(1,359
)

$
(853
)

$
—

$
(4,252
)
Income tax expense (benefit)

$
(6
)

$
(223
)

$
1

$
—

$
(228
)
Net loss

$
(2,034
)

$
(1,136
)

$
(854
)

$
—

$
(4,024
)
Net earnings (loss) attributable to noncontrolling interests

$
1

$
—

$
(392
)

$
—

$
(391
)
Net loss attributable to Devon

$
(2,035
)

$
(1,136
)

$
(462
)

$
—

$
(3,633
)
Property and equipment, net

$
7,196

$
2,778

$
6,195

$
—

$
16,169

Total assets

$
12,317

$
4,355

$
10,197

$
(56
)

$
26,813

Capital expenditures, including acquisitions

$
2,454

$
158

$
816

$
—

$
3,428

~~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 ~~and capital resources and uses~~ for the three-month and nine-month periods ended September 30, ~~2017~~2021 compared to ~~the three-month and nine-month~~previous periods ~~ended September 30, 2016~~ and in our financial condition and liquidity since December 31, ~~2016. For~~2020. To help facilitate comparisons to the three-month period ended June 30, 2021, information regarding our second quarter 2021 financial results can be found in our Second Quarter 2021 Quarterly Report on Form 10-Q . Additionally, for information regarding our critical accounting policies and estimates, see our ~~2016~~2020 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Executive Overview ~~of 2017 Results~~

~~Key components of our financial performance are summarized below.~~

Three Months Ended September 30,

Nine Months Ended September 30, ⁽³⁾

2017

2016

Change

2017

2016

Change

(Millions, except per share amounts)

Net earnings (loss) attributable to Devon

$
228

$
993

- 77
%

$
1,218

$
(3,633
)

N/M

Net earnings (loss) per diluted share attributable to Devon

$
0.43

$
1.89

- 77
%

$
2.31

$
(7.22
)

N/M

Core earnings (loss) attributable to Devon⁽¹⁾

$
242

$
47

+415
%

$
636

$
(169
)

N/M

Core earnings (loss) per diluted share attributable to Devon ⁽¹⁾

$
0.46

$
0.09

+411
%

$
1.20

$
(0.34
)

N/M

Retained production (MBoe/d)

527

550

- 4
%

542

578

- 6
%
Total production (MBoe/d)

527

577

- 9
%

542

635

- 15
%
Realized price per Boe ⁽²⁾

$
25.67

$
20.98

+22
%

$
25.41

$
17.37

+46
%
Operating cash flow

$
776

$
727

+7
%

$
2,420

$
1,237

+96
%
Capital expenditures, including acquisitions

$
833

$
457

+82
%

$
2,371

$
3,428

- 31
%
Shareholder and noncontrolling interests distributions

$
114

$
109

+5
%

$
342

$
414

- 17
%
Cash and cash equivalents

$
2,781

$
2,385

+17
%
Total debt

$
10,403

$
11,354

- 8
%

On September 26, 2020, we entered into the Merger Agreement, providing for an all-stock merger of equals with WPX which successfully closed on January 7, 2021. The Merger has created a leading unconventional oil producer in the U.S., with an asset base underpinned by premium acreage in the economic core of the Delaware Basin. This strategic combination accelerates our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy. We remain focused on building economic value by executing on our strategic priorities of disciplined oil volume growth while capturing operational and corporate synergies, reducing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our recent performance highlights for these priorities include the following items:

~~(1)~~

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

Third quarter oil production totaled 303 MBbls/d, exceeding our plan by 3%.

~~(2)~~

~~Excludes any impact~~•

On pace to achieve approximately $600 million in annual cost savings by the end of ~~oil, gas and NGL derivatives.~~2021.

~~(3)~~

~~Except for balance sheet amounts, which are presented as~~•

Redeemed approximately $1.2 billion of ~~September 30.~~senior notes in 2021.

•

Exited the third quarter with $5.3 billion of liquidity, including $2.3 billion of cash, with no debt maturities until 2023.

•

Generated $3.3 billion of operating cash flow through the first three quarters of 2021.

•

Including variable dividends, paid dividends of approximately $761 million in the first nine months of 2021 and have declared $568 million of dividends to be paid in the fourth quarter of 2021.

•

Authorized a $1.0 billion share repurchase program, representing 4% of outstanding shares at the time of announcement.

~~During the first nine months of 2017, we generated solid operating~~We operate under a disciplined returns-driven strategy focused on delivering strong operational results, financial strength and value to our shareholders and continuing our commitment to ESG excellence, which provides us with a strong foundation to grow returns, margin and profitability. We continue to execute on our ~~three-fold~~ strategy ~~of operating in North America’s best resource plays, delivering superior execution~~ and navigate through various economic environments by protecting our financial strength, maintaining a ~~high degree of financial strength. Led by~~commitment to capital discipline, improving our ~~development in the STACK, we continued to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics~~cash cost structure and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells. Even though our 2017 production volumes have declined from 2016 due to reduced capital investment, we estimate our highest-margin U.S. oil production from retained assets will exit 2017 at levels approximately 20% higher than year-end 2016.preserving operational continuity.

~~Compared to 2016, commodity~~Commodity prices ~~increased~~have strengthened throughout 2021 which has significantly ~~and were the primary driver for improvements in Devon’s operating margins,~~improved our earnings and cash flow generation. The increase in commodity prices has been primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic, as well as OPEC+ and other oil and natural gas producers not rapidly increasing current production levels.

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

Table of Contents

Our earnings increased from the second quarter of 2021 to the third quarter of 2021 primarily due to an increase in overall commodity prices as well as higher sold volumes. Led by a 42% and 7% increase in Henry Hub and WTI from the second quarter of 2021 to the third quarter of 2021, respectively, our unhedged combined realized price rose 13%. Volumes increased due to new well activity in the Delaware Basin and Eagle Ford.

Our net earnings in recent quarters have been significantly impacted by non-cash adjustments to the value of our commodity hedges. Net earnings in the second quarter of 2021, the first quarter of 2021, the fourth quarter of 2020 and the third quarter of 2020 each included a hedge valuation loss, net of tax of $0.3 billion, $0.2 billion, $0.1 billion and $0.1 billion, respectively. Excluding these amounts, our core earnings have been more stable over recent quarters but continue to be heavily influenced by commodity prices.

Like earnings, our operating cash flow is sensitive to volatile commodity prices. Our cash flow and EBITDAX increased during the first, ~~nine months~~second and third quarters of ~~2017.~~ 2021 primarily due to higher commodity prices and an increase in sold volumes driven by our WPX merger and improved post-merger operating performance.

We exited the third quarter of ~~2017~~2021 with $5.3 billion of liquidity, comprised of ~~$2.8~~$2.3 billion of cash and ~~$2.9~~$3.0 billion of available credit under our Senior Credit Facility. We currently have $6.5 billion of debt outstanding with no ~~significant debt~~ maturities until ~~2021. At September 30, 2017, we also had~~August 2023. We currently have approximately ~~65%~~45% and 50% of our remaining ~~2017 forecasted~~2021 oil and gas production hedged, respectively, and 20% and 30% of our 2022 oil and gas production hedged, respectively. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub and NYMEX last day natural gas indices. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our portfolio.

As commodity prices and our operating performance strengthen and bolster our financial condition, we have authorized opportunistic repurchases of up to $1.0 billion of our common shares through the end of 2022. Additionally, we continue funding our fixed plus variable dividends, which have grown 13%, 44% and 71% over the past three quarters, respectively, including the recently declared dividend payable in the fourth quarter of 2021.

Table of Contents

Results of Operations

The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. To facilitate the review, these numbers are being presented before consideration of earnings attributable to discontinued operations or noncontrolling interests.

Q3 2021 vs. Q2 2021

Our third quarter 2021 net earnings were $844 million, compared to net earnings of $261 million for the second quarter of 2021. The graph below shows the change in net earnings from the second quarter of 2021 to the third quarter of 2021. The material changes are further discussed by category on the following pages.

Table of Contents

Production Volumes

	Q3 2021		% of Total			Q2 2021		Change
Oil (MBbls/d)
Delaware Basin		213		70	%		191		+11	%
Anadarko Basin		14		5	%		17		- 15	%
Williston Basin		39		13	%		46		- 15	%
Eagle Ford		20		6	%		18		+11	%
Powder River Basin		14		5	%		16		- 13	%
Other		3		1	%		3		+1	%
Total		303		100	%		291		+4	%

	Q3 2021		% of Total			Q2 2021		Change
Gas (MMcf/d)
Delaware Basin		578		62	%		513		+13	%
Anadarko Basin		219		23	%		225		- 3	%
Williston Basin		59		6	%		61		- 4	%
Eagle Ford		67		7	%		59		+14	%
Powder River Basin		19		2	%		21		- 10	%
Other		1		0	%		2		- 45	%
Total		943		100	%		881		+7	%

	Q3 2021		% of Total			Q2 2021		Change
NGLs (MBbls/d)
Delaware Basin		100		68	%		82		+23	%
Anadarko Basin		25		17	%		26		- 4	%
Williston Basin		9		6	%		9		- 3	%
Eagle Ford		11		7	%		9		+25	%
Powder River Basin		3		2	%		3		- 4	%
Other		—		0	%		—	N/M
Total		148		100	%		129		+15	%

	Q3 2021		% of Total			Q2 2021		Change
Combined (MBoe/d)
Delaware Basin		409		67	%		358		+14	%
Anadarko Basin		75		12	%		80		- 6	%
Williston Basin		58		10	%		66		- 12	%
Eagle Ford		42		7	%		37		+15	%
Powder River Basin		20		3	%		22		- 12	%
Other		4		1	%		4		+0	%
Total		608		100	%		567		+7	%

From the second quarter of 2021 to the third quarter of 2021, the change in volumes contributed to a $149 million increase in earnings. The increase in volumes was primarily due to new well activity in the Delaware Basin and Eagle Ford which was partially offset by lower volumes in the Anadarko, Williston and Powder River Basins.

Realized Prices

	Q3 2021			Realization	Q2 2021			Change
Oil (per Bbl)
WTI index	$	70.64			$	66.04			+7	%
Realized price, unhedged	$	68.19		97%	$	63.63			+7	%
Cash settlements	$	(10.60	)		$	(13.29	)
Realized price, with hedges	$	57.59		82%	$	50.34			+14	%

	Q3 2021			Realization	Q2 2021			Change
Gas (per Mcf)
Henry Hub index	$	4.02			$	2.83			+42	%
Realized price, unhedged	$	3.55		88%	$	2.35			+51	%
Cash settlements	$	(0.78	)		$	(0.15	)
Realized price, with hedges	$	2.77		69%	$	2.20			+26	%

	Q3 2021			Realization	Q2 2021			Change
NGLs (per Bbl)
WTI index	$	70.64			$	66.04			+7	%
Realized price, unhedged	$	31.25		44%	$	23.89			+31	%
Cash settlements	$	(0.45	)		$	(0.25	)
Realized price, with hedges	$	30.80		44%	$	23.64			+30	%

	Q3 2021			Q2 2021			Change
Combined (per Boe)
Realized price, unhedged	$	47.08		$	41.75			+13	%
Cash settlements	$	(6.60	)	$	(7.11	)
Realized price, with hedges	$	40.48		$	34.64			+17	%

From the second quarter of 2021 to the third quarter of 2021, realized prices contributed to a $332 million increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices.

We currently have approximately 45% of our remaining 2021 oil production hedged atwith an average floor price of ~~$50/~~$40/Bbl and approximately ~~66%~~50% of our remaining ~~2017 forecasted natural~~2021 gas production hedged atwith an average floor price of ~~$3.10/MMBtu.~~$2.60/Mcf. We ~~are building~~currently have approximately 20% of our ~~2018~~2022 oil production hedged with an average floor price of $45/Bbl and ~~2019 hedge positions at similar prices.~~approximately 30% of our 2022 gas production hedged with an average floor price of $2.70/Mcf.

We expect to further enhance our financial strength with our announced $1 billion asset divestiture program. The planned divestitures include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, we have closed non-core divestitures totaling approximately $400 million under this program.

~~Table of Contents~~

We recently unveiled our “2020 Vision,” which is a strategic plan through the end of the decade intended to deliver top-tier returns on invested capital, while delivering sustainable, long-term growth for our business. We plan to attain leading returns with our 2020 Vision by pursing the following objectives:Hedge Settlements

	Q3 2021			Q2 2021			Change
	Q
Oil	$	(296	)	$	(352	)		+16	%
Natural gas		(68	)		(12	)	N/M
NGL		(6	)		(3	)		- 100	%
Total cash settlements ⁽¹⁾	$	(370	)	$	(367	)		- 1	%

1.(1)

~~Disciplined capital allocation that builds scale in the STACK and Delaware Basin.~~

~~Maximize returns by growing higher-value liquids production and lowering operating expenses with~~Included as a ~~technology focus across all areas of the business.~~

~~Further high-grade portfolio with monetization of several billion dollars of assets.~~

~~Reduce debt balances.~~

~~Return cash to shareholders.~~

~~Table of Contents~~

~~Results of Operations~~

~~Oil, Gas and NGL Production~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

Oil (MBbls/d)

Barnett Shale

1

1

- 13
%

1

1

- 22
%
Delaware Basin

31

31

+0
%

31

35

- 12
%
Eagle Ford

30

33

- 10
%

38

44

- 15
%
Heavy Oil

18

22

- 15
%

18

23

- 22
%
Rockies Oil

12

11

+9
%

13

14

- 9
%
STACK

27

21

+31
%

24

18

+34
%
Other

11

11

+ 4
%

10

12

- 17
%
Retained assets

130

130

+0
%

135

147

- 8
%
Divested assets

—

6

N/M

—

13

N/M

Total

130

136

- 5
%

135

160

- 16
%
Bitumen (MBbls/d)

Heavy Oil

103

115

- 11
%

109

105

+4
%
Gas (MMcf/d)

Barnett Shale

672

730

- 8
%

677

752

- 10
%
Delaware Basin

90

92

- 3
%

91

92

- 0
%
Eagle Ford

88

85

+4
%

101

111

- 9
%
Heavy Oil

16

18

- 11
%

17

20

- 14
%
Rockies Oil

11

19

- 39
%

14

27

- 47
%
STACK

313

292

+7
%

300

296

+1
%
Other

11

13

- 16
%

12

14

- 16
%
Retained assets

1,201

1,249

- 4
%

1,212

1,312

- 8
%
Divested assets

—

75

N/M

—

165

N/M

Total

1,201

1,324

- 9
%

1,212

1,477

- 18
%
NGLs (MBbls/d)

Barnett Shale

36

44

- 18
%

40

45

- 10
%
Delaware Basin

11

12

- 14
%

10

12

- 19
%
Eagle Ford

12

13

- 8
%

13

18

- 29
%
Rockies Oil

1

1

+9
%

1

1

- 2
%
STACK

32

23

+37
%

30

28

+7
%
Other

2

3

- 10
%

2

3

- 13
%
Retained assets

94

96

- 2
%

96

107

- 10
%
Divested assets

—

8

N/M

—

17

N/M

Total

94

104

- 10
%

96

124

- 22
%
Combined (MBoe/d)

Barnett Shale

148

166

- 11
%

154

171

- 10
%
Delaware Basin

57

59

- 3
%

56

62

- 11
%
Eagle Ford

57

61

- 7
%

67

81

- 17
%
Heavy Oil

124

140

- 11
%

130

132

- 1
%
Rockies Oil

16

16

+0
%

17

20

- 17
%
STACK

111

92

+20
%

104

95

+9
%
Other

14

16

- 8
%

14

17

- 17
%
Retained assets

527

550

- 4
%

542

578

- 6
%
Divested assets

—

27

N/M

—

57

N/M

Total

527

577

- 9
%

542

635

- 15
%

~~Table of Contents~~

~~Oil, Gas and NGL Pricing~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017 ⁽¹⁾

2016 ⁽¹⁾

Change

2017 ⁽¹⁾

2016 ⁽¹⁾

Change

Oil (per Bbl)

U.S.

$
47.12

$
42.51

+11
%

$
47.84

$
36.89

+30
%

Canada

$
35.02

$
27.46

+28
%

$
32.77

$
22.26

+47
%

Total

$
45.41

$
40.12

+13
%

$
45.83

$
34.78

+32
%

Bitumen (per Bbl)

Canada

$
31.75

$
23.00

+38
%

$
28.49

$
17.77

+60
%

Gas (per Mcf)

U.S.

$
2.45

$
2.24

+10
%

$
2.54

$
1.70

+50
%

NGLs (per Bbl)

U.S.

$
15.15

$
9.80

+55
%

$
14.62

$
8.84

+65
%

Combined (per Boe)

U.S.

$
23.85

$
20.26

+18
%

$
24.44

$
17.16

+42
%

Canada

$
31.59

$
23.23

+36
%

$
28.50

$
18.15

+57
%

Total

$
25.67

$
20.98

+22
%

$
25.41

$
17.37

+46
%

~~(1)~~

~~Prices presented exclude any effects~~component of oil, gas and NGL ~~derivatives.~~derivatives on the consolidated statements of comprehensive earnings.

~~Commodity Sales~~

~~The volume and price changes in the tables above caused the following changes to our commodity sales between the three and nine months ended September 30, 2017 and 2016.~~

Three Months Ended September 30,

Oil

Bitumen

Gas

NGLs

Total

(Millions)

2016 sales

$
502

$
244

$
273

$
94

$
1,113

Change due to volumes

(23
)

(26
)

(25
)

(9
)

(83
)
Change due to prices

63

83

23

46

215

2017 sales

$
542

$
301

$
271

$
131

$
1,245

Nine Months Ended September 30,

Oil

Bitumen

Gas

NGLs

Total

(Millions)

2016 sales

$
1,523

$
512

$
688

$
300

$
3,023

Change due to volumes

(243
)

16

(125
)

(68
)

(420
)
Change due to prices

407

319

279

152

1,157

2017 sales

$
1,687

$
847

$
842

$
384

$
3,760

Commodity sales increased in the third quarter and the first nine months of 2017 due to price increases for all commodities. The increase in oil and bitumen sales resulted from a higher average WTI crude oil index price. Additionally, our bitumen sales benefited from tighter heavy oil differentials. The increases in gas and NGL sales were due to higher North American regional index prices upon which our gas sales are based and higher NGL prices at the Mont Belvieu, Texas hub.

The increases in sales due to the favorable movement in commodity prices was partially offset by a decline in production volumes. In 2016, we significantly reduced our drilling and completion capital programs in response to depressed commodity prices. Consequently, production from our retained U.S. assets, other than STACK, steadily declined throughout 2016 and into 2017. Our 2016 asset divestiture program also caused our volumes to decline significantly in the third and fourth quarters of 2016. Additionally, Hurricane Harvey negatively impacted our third quarter 2017 production in the Eagle Ford as we temporarily suspended operations.

~~Table of Contents~~

~~Oil, Gas and NGL Derivatives~~

A summary of our open commodity derivative positions is included in Note 3 to the financial statements included in “Part I. Financial Information – Item 1. Financial Statements” of this report. The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Millions)

Cash settlements:

Oil derivatives

$
11

$
20

$
29

$
(41
)
Gas derivatives

13

(4
)

14

47

NGL derivatives

—

—

—

(2
)
Total cash settlements

24

16

43

4

Gains (losses) on fair value changes:

Oil derivatives

(157
)

23

72

(7
)
Gas derivatives

(7
)

35

101

(26
)
NGL derivatives

(4
)

5

(2
)

(1
)
Total gains (losses) on fair value changes

(168
)

63

171

(34
)
Oil, gas and NGL derivatives

$
(144
)

$
79

$
214

$
(30
)

Three Months Ended September 30, 2017

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
45.41

$
31.75

$
2.45

$
15.15

$
25.67

Cash settlements of hedges

0.96

—

0.12

(0.03
)

0.52

Realized price, including cash settlements

$
46.37

$
31.75

$
2.57

$
15.12

$
26.19

��

Three Months Ended September 30, 2016

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
40.12

$
23.00

$
2.24

$
9.80

$
20.98

Cash settlements of hedges

1.56

—

(0.04
)

0.10

0.32

Realized price, including cash settlements

$
41.68

$
23.00

$
2.20

$
9.90

$
21.30

Nine Months Ended September 30, 2017

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
45.83

$
28.49

$
2.54

$
14.62

$
25.41

Cash settlements of hedges

0.80

—

0.05

(0.02
)

0.29

Realized price, including cash settlements

$
46.63

$
28.49

$
2.59

$
14.60

$
25.70

Nine Months Ended September 30, 2016

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
34.78

$
17.77

$
1.70

$
8.84

$
17.37

Cash settlements of hedges

(0.94
)

—

0.12

(0.06
)

0.02

Realized price, including cash settlements

$
33.84

$
17.77

$
1.82

$
8.78

$
17.39

~~Table of Contents~~

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

Table of Contents

Production Expenses

	Q3 2021			Q2 2021			Change
LOE	$	215		$	210			+2	%
Gathering, processing & transportation		157			147			+7	%
Production taxes		176			143			+23	%
Property taxes		7			13			- 46	%
Total	$	555		$	513			+8	%
Per Boe:
LOE	$	3.85		$	4.06			- 5	%
Gathering, processing & transportation	$	2.81		$	2.85			- 1	%
Percent of oil, gas and NGL sales:
Production taxes		6.7	%		6.7	%		- 0	%

Production expenses increased from the second quarter of 2021 to the third quarter of 2021 primarily due to new well activity in the Delaware Basin. Production taxes also increased due to the rise in commodity ~~derivatives. In addition~~prices.

Field-Level Cash Margin

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

	Q3 2021		$ per BOE		Q2 2021		$ per BOE
Field-level cash margin (Non-GAAP)
Delaware Basin	$	1,480	$	39.28	$	1,102	$	33.79
Anadarko Basin		174	$	25.20		145	$	19.86
Williston Basin		192	$	36.12		197	$	32.98
Eagle Ford		147	$	37.81		106	$	31.88
Powder River Basin		69	$	38.18		74	$	36.78
Other		18	$	49.53		17	$	42.85
Total	$	2,080	$	37.17	$	1,641	$	31.79

DD&A and Asset Impairments

	Q3 2021		Q2 2021		Change
Oil and gas per Boe	$	9.85	$	9.88		- 0	%

Oil and gas	$	551	$	510		+8	%
Other property and equipment		27		26		+4	%
Total	$	578	$	536		+8	%

DD&A increased in the third quarter of 2021 primarily due to higher volumes.

Other Items

	Q3 2021		Q2 2021			Change in earnings
Commodity hedge valuation changes ⁽¹⁾	$	35	$	(336	)	$	371
Marketing and midstream operations		1		1			—
Exploration expenses		3		3			—
Asset dispositions		—		(87	)		(87	)
Net financing costs		86		80			(6	)
Restructuring and transaction costs		18		23			5
Other, net		2		(14	)		(16	)
						$	267

(1)

Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the ~~relationships~~relationship between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred a net loss in the third quarter of 2017 and generated a net gain in the third quarter of 2016. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gain during the first nine months of 2017 and incurred a net loss during the first nine months of 2016.

~~Marketing and Midstream Revenues and Operating Expenses~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Operating revenues

$
2,055

$
1,690

+22
%

$
5,992

$
4,503

+33
%
Product purchases

(1,721
)

(1,391
)

+24
%

(5,043
)

(3,618
)

+39
%
Operations and maintenance expenses

(92
)

(89
)

+3
%

(276
)

(266
)

+4
%
Operating profit

$
242

$
210

+15
%

$
673

$
619

+9
%

Devon loss

$
(11
)

$
(18
)

+39
%

$
(47
)

$
(37
)

-27
%
EnLink profit

253

228

+11
%

720

656

+10
%
Total profit

$
242

$
210

+15
%

$
673

$
619

+9
%

The overall increase in marketing and midstream operating margin during the third quarter and the first nine months of 2017 was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities, offset by a decline in margins on Devon’s downstream marketing commitments. Devon is actively engaged in optimization activities to improve margins to help offset the costs of downstream commitments; however, we expect those commitments to negatively impact our margins throughout 2017.

~~Asset Dispositions and Other~~

~~In conjunction with the non-core upstream asset divestitures, we recognized a gain during the third quarter of 2016.~~ For ~~further discussion,~~additional information, see Note 23 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

~~Lease Operating Expenses~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions, except per Boe amounts)

LOE:

U.S.

$
256

$
248

+3
%

$
761

$
886

- 14
%
Canada

135

107

+26
%

415

329

+26
%
Total

$
391

$
355

+10
%

$
1,176

$
1,215

- 3
%
LOE per Boe:

U.S.

$
6.89

$
6.17

+12
%

$
6.76

$
6.42

+5
%
Canada

$
11.81

$
8.31

+42
%

$
11.70

$
9.13

+28
%
Total

$
8.05

$
6.69

+20
%

$
7.95

$
6.98

+14
%

Total LOE and LOE per Boe increased during the third quarter of 2017 primarily due to higher transportation of $38 million resulting from tolls on Canada’s Access Pipeline of $27 million, which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline, and continued development of the STACK.

Total LOE decreased during the first nine months of 2017 primarily due to our non-core U.S. property divestitures during 2016 and continued well optimization and cost reduction initiatives across our portfolio which have offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers. These cost savings and non-core divestitures impact were partially offset by Access Pipeline transportation tolls of $87 million during the first nine months of 2017, which was the primary driver of the increase in total LOE per Boe.

~~Table of Contents~~

~~General and Administrative Expenses~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Gross G&A

$
196

$
184

+7
%

$
623

$
642

- 3
%
Capitalized G&A

(55
)

(54
)

+3
%

(170
)

(183
)

- 7
%
Reimbursed G&A

(19
)

(19
)

+1
%

(53
)

(66
)

- 20
%
Devon Net G&A

122

111

+10
%

400

393

+2
%
EnLink Net G&A

31

30

+2
%

98

89

+10
%
Net G&A

$
153

$
141

+8
%

$
498

$
482

+3
%

Gross G&A increased during the third quarter of 2017 due to an increase in costs related to automation and process improvement initiatives and decreased the first nine months of 2017 largely due to lower Devon employee costs resulting from our 2016 workforce reduction and other cost reduction initiatives. During the first nine months of 2017, reimbursed G&A decreased primarily due to the divestitures of operated properties in 2016. EnLink net G&A increased during the third quarter and for the first nine months of 2017 primarily due to higher employee compensation costs.

~~Production and Property Taxes~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Production taxes

$
40

$
39

+3
%

$
131

$
110

+19
%
Property and other taxes

20

19

+2
%

62

79

- 21
%
Devon production and property taxes

60

58

+4
%

193

189

+2
%
EnLink property taxes

11

9

+24
%

34

31

+7
%
Production and property taxes

$
71

$
67

+5
%

$
227

$
220

+3
%
Percentage of oil, gas and NGL sales:

Production taxes

3.2
%

3.5
%

- 8
%

3.5
%

3.6
%

- 4
%
Property and other taxes

2.5
%

2.6
%

- 3
%

2.6
%

3.7
%

- 30
%
Total

5.7
%

6.1
%

- 6
%

6.1
%

7.3
%

- 17
%

~~Production taxes increased during each period in 2017 on an absolute dollar basis primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.~~

During the first nine months of 2017, property and other taxes decreased primarily as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our non-core oil and gas property divestitures during 2016. Property taxes do not always change in direct correlation with the change in oil, gas and NGL sales and are generally determined based on the valuation of the underlying assets.

~~Depreciation, Depletion and Amortization~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions, except per Boe amounts)

DD&A:

Oil and gas properties

$
232

$
239

- 3
%

$
675

$
930

- 27
%
Other assets

26

29

- 9
%

80

117

- 31
%
Devon DD&A

258

268

- 4
%

755

1,047

- 28
%
EnLink DD&A

142

126

+13
%

407

373

+9
%
Total DD&A

$
400

$
394

+2
%

$
1,162

$
1,420

- 18
%
DD&A per Boe:

Oil and gas properties

$
4.78

$
4.51

+6
%

$
4.56

$
5.35

- 15
%

~~Table of Contents~~

~~DD&A from our oil and gas properties decreased~~Asset dispositions in the ~~third~~second quarter ~~primarily due to lower production and decreased during the first nine months~~ of ~~2017 largely due to lower DD&A rates, resulting from the oil and gas asset impairments and non-core U.S. divestures in 2016. DD&A from our other assets decreased due~~2021 includes $65 million related to the ~~divestiture~~re-valuation of ~~Access Pipeline in the fourth quarter of 2016.~~

~~EnLink’s DD&A increased primarily due to acquisitions made during 2016 and gathering system expansions in 2017.~~

~~Asset Impairments~~

~~During the third quarter and the first nine months of 2016, we recognized asset impairments totaling $319 million and $4.9 billion, respectively.~~contingent earnout payments associated with our divested Barnett Shale assets. For ~~further discussion,~~additional information, see Note 52 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

~~Restructuring and Transaction Costs~~

During the first nine months of 2016, we recognized restructuring costs of $249 million as a result of a reduction in workforce driven by our cost reduction initiatives and divestiture of non-core properties.Income Taxes

~~During the first nine months of 2016, we recognized transaction costs of $17 million, primarily associated with the closing of the acquisitions discussed in~~

	Q3 2021			Q2 2021
Current expense	$	1		$	19
Deferred expense		119			24
Total expense	$	120		$	43
Effective income tax rate		12	%		14	%

For discussion on income taxes, see Note 27 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

~~Net Financing Costs~~

Table of Contents

September 30, 2021 YTD vs. September 30, 2020 YTD

Our nine months ended September 30, 2021 net earnings were $1.3 billion, compared to a net loss of $2.5 billion (excludes discontinued operations) for the nine months ended September 30, 2020. The graph below shows the change in the net earnings (loss) from the nine months ended September 30, 2020 to the nine months ended September 30, 2021. The material changes are further discussed by category on the following pages.

Table of Contents

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Devon net financing costs:

Interest based on debt outstanding

$
97

$
120

- 19
%

$
292

$
376

- 22
%
Early retirement of debt

—

84

N/M

—

84

N/M

Capitalized interest

(19
)

(16
)

+21
%

(53
)

(47
)

+12
%
Other

(1
)

7

- 114
%

(3
)

18

- 117
%
Total Devon net financing costs

77

195

- 60
%

236

431

- 45
%
EnLink net financing costs:

Interest based on debt outstanding

43

37

+16
%

125

105

+19
%
Interest accretion on deferred installment payment

7

13

- 46
%

20

39

- 49
%
Early retirement of debt

—

—

N/M

(9
)

—

N/M

Other

—

(2
)

N/M

(2
)

(5
)

- 60
%
Total EnLink net financing costs

50

48

+2
%

134

139

- 3
%
Total net financing costs

$
127

$
243

- 48
%

$
370

$
570

- 35
%

Production Volumes

	Nine Months Ended September 30,
	2021		% of Total			2020		Change
Oil (MBbls/d)
Delaware Basin		192		67	%		80		+140	%
Anadarko Basin		14		5	%		21		- 32	%
Williston Basin		43		15	%		—	N/M
Eagle Ford		18		6	%		25		- 29	%
Powder River Basin		16		5	%		20		- 23	%
Other		4		2	%		8		- 42	%
Total		287		100	%		154		+87	%

	Nine Months Ended September 30,
	2021		% of Total			2020		Change
Gas (MMcf/d)
Delaware Basin		521		60	%		241		+116	%
Anadarko Basin		215		25	%		258		- 17	%
Williston Basin		56		6	%		—	N/M
Eagle Ford		57		7	%		82		- 30	%
Powder River Basin		21		2	%		24		- 14	%
Other		2		0	%		4		- 48	%
Total		872		100	%		609		+43	%

	Nine Months Ended September 30,
	2021		% of Total			2020		Change
NGLs (MBbls/d)
Delaware Basin		81		65	%		35		+132	%
Anadarko Basin		24		19	%		28		- 16	%
Williston Basin		9		7	%		—	N/M
Eagle Ford		9		7	%		11		- 18	%
Powder River Basin		3		2	%		3		+0	%
Other		—		0	%		1		- 100	%
Total		126		100	%		78		+62	%

	Nine Months Ended September 30,
	2021		% of Total			2020		Change
Combined (MBoe/d)
Delaware Basin		360		64	%		155		+132	%
Anadarko Basin		74		13	%		92		- 20	%
Williston Basin		61		11	%		—	N/M
Eagle Ford		36		7	%		50		- 27	%
Powder River Basin		22		4	%		27		- 19	%
Other		5		1	%		9		- 43	%
Total		558		100	%		333		+68	%

From the nine months ended 2020 to the nine months ended 2021, the change in volumes contributed to a $1.5 billion increase in earnings. Due to the Merger closing on January 7, 2021, volumes now include WPX legacy assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Volumes associated with these WPX legacy assets were approximately 225 MBoe/d for the nine months ended 2021. Continued development of Devon legacy assets in the Delaware Basin also increased volumes. These increases were partially offset by reduced activity across Devon’s ~~net financing costs decreased during~~remaining legacy assets.

Realized Prices

	Nine Months Ended September 30,
	2021			Realization	2020		Change
Oil (per Bbl)
WTI index	$	64.85			$	38.57		+68	%
Realized price, unhedged	$	62.69		97%	$	34.63		+81	%
Cash settlements	$	(11.06	)		$	7.06
Realized price, with hedges	$	51.63		80%	$	41.69		+24	%

	Nine Months Ended September 30,
	2021			Realization	2020		Change
Gas (per Mcf)
Henry Hub index	$	3.19			$	1.88		+70	%
Realized price, unhedged	$	2.93		92%	$	1.32		+122	%
Cash settlements	$	(0.38	)		$	0.24
Realized price, with hedges	$	2.55		80%	$	1.56		+63	%

	Nine Months Ended September 30,
	2021			Realization	2020		Change
NGLs (per Bbl)
WTI index	$	64.85			$	38.57		+68	%
Realized price, unhedged	$	27.11		42%	$	10.66		+154	%
Cash settlements	$	(0.32	)		$	0.25
Realized price, with hedges	$	26.79		41%	$	10.91		+146	%

	Nine Months Ended September 30,
	2021			2020		Change
Combined (per Boe)
Realized price, unhedged	$	42.94		$	20.91		+105	%
Cash settlements	$	(6.35	)	$	3.76
Realized price, with hedges	$	36.59		$	24.67		+48	%

From the ~~third quarter~~nine months ended 2020 to the nine months ended 2021, realized prices contributed to a $3.1 billion increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices. The increase in index prices was partially offset by hedge cash settlements related to all products in the first nine months of ~~2017 primarily due~~2021.

Hedge Settlements

	Nine Months Ended September 30,
	2021			2020		Change
Oil	$	(868	)	$	298	N/M
Natural gas		(90	)		40	N/M
NGL		(11	)		5	N/M
Total cash settlements ⁽¹⁾	$	(969	)	$	343	N/M

(1)

Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

Cash settlements as presented in the tables above represent realized gains or losses related to the ~~2016 repayment of $2.5 billion~~instruments described in ~~borrowings, including scheduled maturities and early retirements funded with asset divestiture proceeds.~~

EnLink’s interest on debt outstanding increased during the third quarter and the first nine months of 2017 due to increased borrowings. In the first nine months of 2017, EnLink recognized a gain on extinguishment of debt as disclosed in Note 143 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

~~Income Taxes~~34

Table of Contents

Production Expenses

	Nine Months Ended September 30,
	2021			2020			Change
LOE	$	624		$	334			+87	%
Gathering, processing & transportation		433			378			+15	%
Production taxes		436			123			+254	%
Property taxes		33			17			+94	%
Total	$	1,526		$	852			+79	%
Per Boe:
LOE	$	4.09		$	3.66			+12	%
Gathering, processing & transportation	$	2.84		$	4.15			- 31	%
Percent of oil, gas and NGL sales:
Production taxes		6.7	%		6.4	%		+4	%

~~Table of Contents~~

~~We continue~~Production expenses increased primarily due to ~~expect low current income tax rates in~~ the ~~U.S. segment based~~Merger closing on ~~our continuing net operating loss position.~~January 7, 2021. For ~~further discussion on income taxes,~~additional information, see Note 72 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report. Partially offsetting increases to gathering, processing and transportation costs were approximately $39 million of Anadarko volume commitments which expired at the end of 2020. Production taxes also increased due to the rise in commodity prices.

Field-Level Cash Margin

	Nine Months Ended September 30,
	2021		$ per BOE		2020		$ per BOE
Field-level cash margin (Non-GAAP)
Delaware Basin	$	3,477	$	35.41	$	602	$	14.16
Anadarko Basin		404	$	19.93		143	$	5.62
Williston Basin		550	$	32.91		—	N/M
Eagle Ford		325	$	32.74		170	$	12.54
Powder River Basin		210	$	35.53		121	$	16.45
Other		54	$	37.69		21	$	8.77
Total	$	5,020	$	32.93	$	1,057	$	11.58

DD&A and Asset Impairments

	Nine Months Ended September 30,
	2021		2020		Change
Oil and gas per Boe	$	9.84	$	10.19		- 3	%

Oil and gas	$	1,500	$	929		+61	%
Other property and equipment		81		70		+16	%
Total	$	1,581	$	999		+58	%

Asset impairments	$	—	$	2,666	N/M

DD&A increased in 2021 primarily due to the Merger closing on January 7, 2021. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

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

General and Administrative Expense

	Nine Months Ended September 30,
	2021		2020		Change
G&A per Boe	$	1.94	$	2.81		- 31	%

Labor and benefits	$	197	$	157		+25	%
Non-labor		99		99		+0	%
Total	$	296	$	256		+16	%

Labor and benefits increased primarily due to the Merger closing on January 7, 2021. However, Devon’s G&A per Boe rate decreased 31% primarily due to synergies resulting from the Merger.

Other Items

	Nine Months Ended September 30,
	2021			2020			Change in earnings
Commodity hedge valuation changes ⁽¹⁾	$	(597	)	$	(71	)	$	(526	)
Marketing and midstream operations		(19	)		(28	)		9
Exploration expenses		9			163			154
Asset dispositions		(119	)		—			119
Net financing costs		243			200			(43	)
Restructuring and transaction costs		230			32			(198	)
Other, net		(41	)		(35	)		6
							$	(479	)

(1)

Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

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information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Exploration expenses decreased primarily due to unproved asset impairments of $149 million in the first nine months of 2020. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Asset dispositions includes $65 million related to the re-valuation of contingent earnout payments associated with our divested Barnett Shale assets and $35 million related to the sale of non-core assets in the Rockies. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Net financing costs increased as a result of WPX debt assumed in the Merger, partially offset by a $30 million gain associated with our debt retirements in the first nine months of 2021. For additional information, see Note 13 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Restructuring and transaction costs in 2021 reflect workforce reductions in conjunction with the Merger, as well as various transaction costs related to the Merger. For additional information, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Income Taxes

	Nine Months Ended September 30,
	2021			2020
Current expense (benefit)	$	15		$	(199	)
Deferred benefit		(100	)		(311	)
Total benefit	$	(85	)	$	(510	)
Effective income tax rate		(7	%)		17	%

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

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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 and nine months ended September 30, ~~2017~~2021 and ~~2016.~~2020.

Devon

EnLink

Consolidated

2017

2016

2017

2016

2017

2016

(Millions)

Operating cash flow

$
1,892

$
724

$
528

$
513

$
2,420

$
1,237

Divestitures of property and equipment

321

1,884

2

5

323

1,889

Issuance of common stock

—

1,469

—

—

—

1,469

Proceeds from sale of investment

—

—

190

—

190

—

Capital expenditures

(1,541
)

(1,235
)

(662
)

(424
)

(2,203
)

(1,659
)
Acquisitions of property, equipment and businesses

(39
)

(849
)

—

(792
)

(39
)

(1,641
)
Debt activity, net

—

(1,946
)

252

178

252

(1,768
)
Payment of installment payable

—

—

(250
)

—

(250
)

—

Shareholder and noncontrolling interests distributions

(95
)

(190
)

(247
)

(224
)

(342
)

(414
)
EnLink and General Partner distributions

199

199

(199
)

(199
)

—

—

Issuance of subsidiary units

—

—

486

835

486

835

Effect of exchange rate and other

(45
)

(23
)

30

150

(15
)

127

Net change in cash and cash equivalents

$
692

$
33

$
130

$
42

$
822

$
75

Cash and cash equivalents at end of period

$
2,639

$
2,325

$
142

$
60

$
2,781

$
2,385

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Operating cash flow from continuing operations	$	1,598		$	427		$	3,283		$	1,106
WPX acquired cash		—			—			344			—
Divestitures of property and equipment		1			1			65			29
Capital expenditures		(474	)		(204	)		(1,477	)		(936	)
Debt activity, net		—			—			(1,302	)		—
Repurchases of common stock		—			—			—			(38	)
Common stock dividends		(329	)		(43	)		(761	)		(119	)
Noncontrolling interest activity, net		(5	)		(3	)		(35	)		2
Other		(9	)		—			(33	)		(22	)
Net change in cash, cash equivalents and restricted cash from discontinued operations		—			50			—			31
Net change in cash, cash equivalents and restricted cash	$	782		$	228		$	84		$	53
Cash, cash equivalents and restricted cash at end of period	$	2,321		$	1,897		$	2,321		$	1,897

Operating Cash Flow and WPX Acquired Cash

~~Net~~

As presented in the table above, net cash provided by operating activities ~~increased 96% primarily~~continued to be a significant source of capital and liquidity. Operating cash flow nearly tripled during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. The increase was due to the Merger and prices significantly ~~higher commodity prices as compared to~~increasing in the first nine months of ~~2016.~~

~~Our consolidated operating cash flow funded 100%~~2021. Additionally, despite our portfolio enhancements, aggressive cost reductions and operational advancements, our 2020 financial results were challenged by commodity prices and deterioration of ~~our capital expenditures during~~ the ~~first nine months of 2017. In 2016, leveraging our liquidity, we also used cash balances and proceeds~~macro-economic environment resulting from ~~our common stock offering and non-core asset divestitures to fund our acquisitions and capital expenditures.~~the unprecedented COVID-19 pandemic.

~~Divestitures of Property and Equipment~~

During the first nine months of 2017, as part of our announced divestiture program, we sold non-core U.S. assets for approximately $320 million, net of customary purchase price adjustments. During the first nine months of 2016, we divested certain non-core upstream assets in the U.S. for approximately $1.9 billion. For further discussion, see Note 2 in “Part 1. Financial Information – Item 1. Financial Statements” in this report.

~~Issuance of Common Stock~~

In February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.

~~Proceeds from Sale of Investment~~

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 2016 acquisition further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

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~~Capital Expenditures and Acquisitions of Property, Equipment and Businesses~~

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

Nine Months Ended September 30,

2017

2016

(Millions)

Oil and gas

$
1,480

$
1,212

Corporate and other

61

23

Devon capital expenditures

1,541

1,235

EnLink capital expenditures

662

424

Total capital expenditures

$
2,203

$
1,659

Devon acquisitions

39

849

EnLink acquisitions

—

792

Total acquisitions

$
39

$
1,641

Capital expenditures consist of amounts related to our oil and gas exploration and development operations, midstream operations, other corporate activities and EnLink growth and maintenance activities. The vast majority of Devon’s capital expenditures are for the acquisition, drilling and development of oil and gas properties. Devon’s 2017 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 allocation process focused on returns.

Capital expenditures for midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. Midstream capital expenditures are largely impacted by oil and gas development activities.

Acquisition capital for the first nine months of 2016 primarily consisted of Devon’s acquisition of assets in the STACK play for approximately $1.5 billion and EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets for $1.4 billion. Approximately $850 million and $800 million, respectively, was paid in cash at the closings with the remainder funded with equity consideration and debt. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

~~Debt Activity, Net~~

During the first nine months of 2017, consolidated net debt borrowings increased $252 million. In May 2017, EnLink issued $500 million of 5.45% senior notes due in 2047 to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. In June 2017, EnLink redeemed its 7.125% senior unsecured notes due in 2022 for aggregate cash consideration of $174 million. Additionally, EnLink reduced its credit facility borrowings $74 million during the first nine months of 2017.

During the first nine months of 2016, our consolidated net debt borrowings decreased $1.8 billion. The decrease was primarily due to completed tender offers to purchase and redeem $1.2 billion of debt securities. For additional information, see Note 14 in “Part I. Financial Information – Item 1. Financial Statements” in this report. The remaining decrease was due to reducing our commercial paper balances by $626 million during the first nine months of 2016.

~~Payment of Installment Payable~~

During the first quarter of 2017, EnLink made the first installment payment related to its 2016 acquisition further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

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~~Shareholder and Noncontrolling Interests Distributions~~

The following table summarizes our common stock dividends during the first nine months of 2017 and 2016. In the second quarter of 2016, we decreased our quarterly cash dividend rate to $0.06 per share.

~~EnLink and the General Partner distributed $247 million and $224 million to non-Devon unitholders during the first nine months of 2017 and 2016, respectively.~~

~~EnLink and General Partner Distributions~~

~~Devon received $199 million in distributions from EnLink and the General Partner during the first nine months of 2017 and 2016.~~

~~Issuance of Subsidiary Units~~

During the first nine months of 2017, EnLink issued and sold 5 million common units through its “at the market” programs and generated $92 million in net proceeds. In September 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.

In January 2016, as part of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction. Additionally, during the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million through its “at the market” programs.

~~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 and other contractual commitments as discussed in this section.

~~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 consolidated operating cash flow increased approximately $1.2 billion in the first nine months of 2017 compared to the first nine months of 2016 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.

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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 September 30, 2017, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Divestitures of Property and Equipment

~~In May 2017,~~During the first nine months of 2021, we ~~announced a program to divest approximately $1 billion of upstream assets. These~~sold non-core assets ~~identified~~ for ~~monetization include select portions~~approximately $65 million, net of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, beforecustomary purchase price adjustments. ~~The most significant asset remaining~~For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this ~~program is select Barnett Shale leasehold. Data rooms for the Barnett properties opened in September 2017 and initial bids are expected during the fourth quarter of 2017.~~report.

Capital Expenditures

~~Excluding EnLink, our 2017~~The amounts in the table below reflect cash payments for capital expenditures, ~~are expected~~including cash paid for capital expenditures incurred in prior periods.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Delaware Basin	$	375	$	147	$	1,150	$	560
Anadarko Basin		11		2		29		20
Williston Basin		13		—		59		—
Eagle Ford		45		17		88		153
Powder River Basin		13		24		53		155
Other		1		3		1		9
Total oil and gas		458		193		1,380		897
Midstream		5		7		53		26
Other		11		4		44		13
Total capital expenditures	$	474	$	204	$	1,477	$	936

Capital expenditures consist primarily of amounts related to ~~range from $2.4 billion to $2.5 billion, including $2.0 billion to $2.1 billion for~~ our oil and gas exploration and development operations, midstream operations and other corporate activities. Capital expenditures increased in 2021 primarily due to the Merger closing on January 7,

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2021 and results now include activity related to WPX legacy assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Our capital ~~program. O~~urprogram is designed to operate within operating cash flow. This is evidenced by our operating cash flow funding all of our capital expenditures ~~excluding EnLink were $1.7~~for the nine months ended September 30, 2021. Our capital investment program is driven by a disciplined allocation process focused on returns.

Debt Activity

Subsequent to the Merger closing, we redeemed $1.2 billion of senior notes in the first nine months of ~~2017~~2021. We also paid $59 million of cash retirement costs related to these redemptions.

Shareholder Distributions and Stock Activity

The following table summarizes our common stock dividends during the third quarter and total for the first nine months of 2021 and 2020. We raised our quarterly dividend by 22% to $0.11 per share in the second quarter of 2020. In addition to the fixed quarterly dividend, we paid a variable dividend in each quarter of 2021.

	Fixed		Variable		Total		Rate Per Share
2021:
First quarter	$	76	$	127	$	203	$	0.30
Second quarter		75		154		229	$	0.34
Third quarter		74		255		329	$	0.49
Total year-to-date	$	225	$	536	$	761
2020:
First quarter	$	34	$	—	$	34	$	0.09
Second quarter		42		—		42	$	0.11
Third quarter		43		—		43	$	0.11
Total year-to-date	$	119	$	—	$	119

We repurchased 2.2 million shares of common stock for $38 million in the first nine months of 2020. For additional information, see Note 16in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Noncontrolling Interest Activity, net

During the first nine months of 2021, we received $4 million of contributions from our noncontrolling interests in CDM and distributed $15 million to our noncontrolling interests in CDM. In the first quarter of 2021, we paid $24 million to purchase the noncontrolling interest portion of a partnership that WPX had formed to acquire minerals in the Delaware Basin.

During the first nine months of 2020, we received $12 million in contributions from our noncontrolling interests in CDM and distributed $10 million to our noncontrolling interests in CDM.

Liquidity

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

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. With the Merger, we accelerated our transition to a cash-return business model, which moderates growth, emphasizes capital efficiencies and prioritizes cash returns to shareholders. These principles will position Devon to be a consistent builder of economic value through the cycle. The post-merger scalability enhanced Devon’s free cash flow, credit profile and decreased the overall cost of capital.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to fund our planned post-merger capital requirements as discussed in this section as well as accelerate our cash-return business model.

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Operating Cash Flow

Key inputs into determining our planned capital investment are the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of the third quarter of 2021, we held approximately $2.3 billion of cash, inclusive of $177 million of cash restricted primarily for retained obligations related to divested assets. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as these variables may differ from our expectations.

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

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to ~~range~~protect a portion of our production against downside price risk. We hedge our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. The key terms to our oil, gas and NGL derivative financial instruments as of September 30, 2021 are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, as commodity prices have increased, we remain committed to a maintenance capital program for the foreseeable future. We do not intend to add any growth projects until market fundamentals recover, excess inventory clears up and OPEC+ curtailed volumes are effectively absorbed by the world markets.

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

Merger Synergies – Cost savings from ~~$0.7~~synergies resulting from the Merger are expected to be attained through cost reductions and efficiencies related to our capital programs, G&A, financing costs and production expenses. We anticipate the planned $600 million reduction of annualized costs will occur by year-end 2021. Approximately 35% of the reduced costs are related to our capital programs and the remainder relate to our operating expenses, including G&A, interest expense and production expenses.

Restructuring and Transaction Related Costs – The majority of the Merger-related restructuring and transaction cost cash outflows were paid in the first nine months of 2021 and the remaining costs will be paid mostly over the remaining three months of 2021. These payments relate to workforce reductions and the associated employee severance benefits, costs to modify or abandon vendor contracts and the acceleration of certain employee benefits triggered by the Merger.

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

Assumption and Repayment of WPX Debt

In conjunction with the Merger closing on January 7, 2021, we assumed a principal value of $3.3 billion of WPX debt. Subsequent to ~~$0.8~~the Merger closing, we have reduced our debt by approximately $1.2 billion in the ~~fourth quarter~~first half of ~~2017.~~2021. We expect these redemptions to lower our annual cash net financing costs by approximately $70 million.

Credit Availability

~~We have a $3.0 billion Senior Credit Facility.~~ As of September 30, ~~2017,~~2021, we had approximately ~~$2.9~~$3.0 billion of available borrowing capacity under ~~this facility, net of $59 million in outstanding letters of credit, and were in compliance with the facility’s financial covenant.~~our Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At September 30, ~~2017,~~2021, there were no borrowings under our commercial paper ~~program.~~program, and we were in compliance with the Senior Credit Facility’s financial covenant.

~~EnLink Liquidity~~39

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EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million secured revolving credit facility. As of September 30, 2017, there were $9 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility and $74 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 2017, EnLink paid the first $250 million installment payment related to the 2016 Anadarko Basin gathering and processing midstream assets acquisition. The remaining $250 million installment payment is payable by January 2018.

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~~BBB- with a positive outlook. Our credit rating from Fitch is BBB+ with a stable outlook. ~~In March 2017, Fitch Ratings affirmed our BBB+~~Our credit rating ~~and revised our outlook to stable~~ from ~~negative. In April 2017,~~ Moody’s Investor Service ~~upgraded our credit rating from Ba2 to~~is Ba1 with a ~~stable~~positive outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

There are no “rating triggers” in any of our ~~or EnLink’s~~ contractual debt obligations that would accelerate scheduled maturities should aour debt rating fall below a specified level. However, ~~these downgrades~~a downgrade 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.

~~Table of Contents~~Fixed Plus Variable Dividend

Following the closing of the Merger, we initiated a new “fixed plus variable” dividend strategy. The fixed dividend is currently paid quarterly at a rate of $0.11 per share, and our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In addition to the fixed quarterly dividend, we may pay a variable dividend up to 50% of our excess free cash flow, which is a non-GAAP measure. Each quarter’s excess free cash flow is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects, COVID-19 impacts and other factors deemed relevant by the Board.

In November 2021, Devon announced a cash dividend in the amount of $0.84 per share payable in the fourth quarter of 2021. The dividend consists of a fixed quarterly dividend in the amount of approximately $74 million (or $0.11 per share) and a variable quarterly dividend in the amount of approximately $494 million (or $0.73 per share).

Capital Expenditures

Our 2021 exploration and development budget for the fourth quarter of 2021 is expected to range from approximately $440 million to $490 million.

Share Repurchases

In November 2021, our Board of Directors authorized a $1.0 billion share repurchase program, which expires December 31, 2022.

Critical Accounting Estimates

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. ~~At September 30, 2017,~~Due primarily to significant cumulative losses, we ~~continued to have~~recorded a ~~100%~~full valuation allowance against ~~the~~ U.S. deferred tax assets ~~that largely resulted from prior year cumulative financial losses primarily due to full cost impairments. Further, we continue to record~~in 2020 and remain in a partial valuation allowance ~~against certain Canadian deferred tax assets.~~

~~The accruals for~~position at September 30, 2021.Subject to any additional objective negative evidence or the addition of subjective evidence such as forecasted income, Devon may continue to adjust the valuation allowance on its deferred tax assets in future periods.

Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change has occurred during 2021 for Devon, but the Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next three years.

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Purchase Accounting

Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Merger with WPX. In connection with the Merger, as the accounting acquirer, we allocated the $5.4 billion of purchase price consideration to the assets acquired and liabilities ~~are often~~assumed based on ~~assumptions that are~~estimated fair values as of the date of the Merger. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing date of the Merger.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the Merger. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. Since sufficient market data was not available regarding the fair values of proved and unproved oil and gas properties, we prepared estimates and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserve quantities, estimates of future commodity prices, drilling plans, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates.

Estimated fair values ascribed to assets acquired can have a significant ~~amount~~impact on future results of ~~judgment by management. These assumptions~~operations presented in Devon’s financial statements. A higher fair value ascribed to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserve quantities, development costs and ~~judgments~~operating costs. In the event that future commodity prices or reserve quantities are ~~reviewed~~lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.

In addition to the fair value of proved and ~~adjusted as facts~~unproved oil and ~~circumstances change. Material changes to our income tax accruals may occur~~gas properties, other significant fair value assessments for the assets acquired and liabilities assumed in the ~~future~~Merger relate to debt, the equity method investment in Catalyst and out-of-market contract assets and liabilities. The fair value of the assumed WPX publicly traded debt was based on available third party quoted prices. We prepared estimates and engaged third party valuation experts to assist in the ~~progress~~valuation of ~~ongoing audits, changes~~the equity method investment in ~~legislation or resolution~~Catalyst. Significant judgments and assumptions inherent in this estimate included projected Catalyst cash flows, comparable companies cash flow multiples and an estimate of ~~other pending matters.~~an applicable market participant discount rate. The fair value of assumed out-of-market contract assets and liabilities associated with longer-term marketing, gathering, processing and transportation contracts included significant judgments and assumptions related to determining the market rates, estimates of future reserves and production associated with the respective contracts and applying an applicable market participant discount rate.

For additional information regarding our critical accounting policies and estimates, see our 2020 Annual Report on Form 10-K.

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 ~~2017~~2021 Results” in this Item 2.2 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~~non-cash 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 ~~for the third quarter and first nine months of 2017~~ relate to asset dispositions, non-cash asset impairments (including non-cash unproved asset impairments), deferred tax asset valuation allowance, changes in ~~derivatives and~~tax legislation, fair value changes in derivative financial ~~instrument fair values~~instruments and foreign currency, ~~gains and losses on asset sales, noncash asset impairments, gains~~costs associated with early retirement of debt and deferred tax asset valuation allowance. Amounts excluded for the third quarter and first nine months of 2016 relate to changes in derivatives and financial instrument fair values and foreign currency, noncash asset impairments (including an impairment of goodwill), restructuring and transaction costs ~~gains on asset sales, costs~~ associated with the ~~early retirement of debt and deferred tax asset valuation allowance.~~ workforce reductions described further in Note 6.

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.

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

Three Months Ended September 30,

Nine Months Ended September 30,

Before tax

After tax

After Noncontrolling Interests

Per Share

Before tax

After tax

After Noncontrolling Interests

Per Share

(Millions, except per share amounts)

2017

Earnings attributable to Devon
    (GAAP)

$
272

$
247

$
228

$
0.43

$
1,328

$
1,277

$
1,218

$
2.31

Adjustments:

Fair value changes in financial
   instruments and foreign currency

106

40

39

0.08

(292
)

(233
)

(232
)

(0.44
)
Gains and losses on asset sales

1

1

—

—

(6
)

(4
)

(4
)

(0.01
)
Asset impairments

2

1

1

—

9

7

4

0.01

Early retirement of debt

—

—

—

—

(9
)

(7
)

(4
)

(0.01
)
Deferred tax asset valuation allowance

—

(26
)

(26
)

(0.05
)

—

(346
)

(346
)

(0.66
)
Core earnings attributable to Devon
   (Non-GAAP)

$
381

$
263

$
242

$
0.46

$
1,030

$
694

$
636

$
1.20

2016

Earnings (loss) attributable to Devon
    (GAAP)

$
1,178

$
1,007

$
993

$
1.89

$
(4,252
)

$
(4,024
)

$
(3,633
)

$
(7.22
)
Adjustments:

Fair value changes in financial
   instruments and foreign currency

(16
)

(3
)

(3
)

(0.01
)

201

91

86

0.17

Asset impairments

319

202

202

0.38

4,851

3,492

3,076

6.12

Restructuring and transaction costs

(5
)

(3
)

(3
)

(0.01
)

266

171

169

0.33

Gains on asset sales

(1,351
)

(787
)

(787
)

(1.48
)

(1,351
)

(787
)

(787
)

(1.56
)
Early retirement of debt

84

53

53

0.10

84

53

53

0.11

Deferred tax asset valuation allowance

—

(408
)

(408
)

(0.78
)

—

867

867

1.71

Core earnings (loss) attributable to
    Devon (Non-GAAP)

$
209

$
61

$
47

$
0.09

$
(201
)

$
(137
)

$
(169
)

$
(0.34
)

	Three Months Ended September 30,												Nine Months Ended September 30,
	Before Tax			After Tax			After Noncontrolling Interests			Per Diluted Share			Before Tax			After Tax			After Noncontrolling Interests			Per Diluted Share
2021
Total
Earnings attributable to Devon (GAAP)	$	964		$	844		$	838		$	1.24		$	1,236		$	1,321		$	1,307		$	1.95
Adjustments:
Asset dispositions		—			—			—			—			(119	)		(91	)		(91	)		(0.13	)
Asset and exploration impairments		1			1			1			0.00			3			2			2			0.00
Deferred tax asset valuation allowance		—			(101	)		(101	)		(0.15	)		—			(479	)		(479	)		(0.71	)
Change in tax legislation		—			—			—			—			—			62			62			0.09
Fair value changes in financial instruments and foreign currency		(31	)		(23	)		(23	)		(0.04	)		597			460			460			0.68
Restructuring and transaction costs		18			18			18			0.03			230			201			201			0.29
Early retirement of debt		—			—			—			—			(30	)		(23	)		(23	)		(0.03	)
Core earnings attributable to Devon (Non-GAAP)	$	952		$	739		$	733		$	1.08		$	1,917		$	1,453		$	1,439		$	2.14
2020
Continuing Operations
Loss attributable to Devon (GAAP)	$	(193	)	$	(103	)	$	(105	)	$	(0.29	)	$	(2,980	)	$	(2,470	)	$	(2,475	)	$	(6.58	)
Adjustments:
Asset and exploration impairments		36			29			29			0.08			2,816			2,178			2,178			5.80
Deferred tax asset valuation allowance		—			(5	)		(5	)		(0.01	)		—			252			252			0.65
Fair value changes in financial instruments		97			74			74			0.19			71			55			55			0.14
Change in tax legislation		—			(43	)		(43	)		(0.11	)		—			(105	)		(105	)		(0.27	)
Restructuring and transaction costs		32			25			25			0.07			32			25			25			0.06
Core loss attributable to Devon (Non-GAAP)	$	(28	)	$	(23	)	$	(25	)	$	(0.07	)	$	(61	)	$	(65	)	$	(70	)	$	(0.20	)
Discontinued Operations
Earnings (loss) attributable to Devon (GAAP)	$	(2	)	$	13		$	13		$	0.04		$	(150	)	$	(103	)	$	(103	)	$	(0.27	)
Adjustments:
Asset dispositions		—			—			—			—			(2	)		(1	)		(1	)		(0.00	)
Asset impairments		3			3			3			0.00			182			143			143			0.37
Fair value changes in foreign currency and other		(2	)		(3	)		(3	)		(0.01	)		4			2			2			0.01
Core earnings (loss) attributable to Devon (Non-GAAP)	$	(1	)	$	13		$	13		$	0.03		$	34		$	41		$	41		$	0.11
Total
Loss attributable to Devon (GAAP)	$	(195	)	$	(90	)	$	(92	)	$	(0.25	)	$	(3,130	)	$	(2,573	)	$	(2,578	)	$	(6.85	)
Adjustments:
Continuing Operations		165			80			80			0.22			2,919			2,405			2,405			6.38
Discontinued Operations		1			—			—			(0.01	)		184			144			144			0.38
Core loss attributable to Devon (Non-GAAP)	$	(29	)	$	(10	)	$	(12	)	$	(0.04	)	$	(27	)	$	(24	)	$	(29	)	$	(0.09	)

EBITDAX and Field-Level Cash Margin

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

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

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restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.

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

Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Net earnings (loss) (GAAP)	$	844		$	(90	)	$	1,321		$	(2,573	)
Net (earnings) loss from discontinued operations, net of tax		—			(13	)		—			103
Financing costs, net		86			66			243			200
Income tax expense (benefit)		120			(90	)		(85	)		(510	)
Exploration expenses		3			39			9			163
Depreciation, depletion and amortization		578			299			1,581			999
Asset impairments		—			—			—			2,666
Asset dispositions		—			—			(119	)		—
Share-based compensation		18			19			58			58
Derivative and financial instrument non-cash valuation changes		(35	)		97			597			71
Restructuring and transaction costs		18			32			230			32
Accretion on discounted liabilities and other		2			—			(41	)		(35	)
EBITDAX (Non-GAAP)		1,634			359			3,794			1,174
Marketing and midstream revenues and expenses, net		(1	)		2			19			28
Commodity derivative cash settlements		370			(10	)		969			(343	)
General and administrative expenses, cash-based		77			56			238			198
Field-level cash margin (Non-GAAP)	$	2,080		$	407		$	5,020		$	1,057

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Item 3. Quantitative and ~~Qualitati~~veQualitative Disclosures About Market Risk

Commodity Price Risk

As of September 30, ~~2017,~~2021, we have commodity derivatives that pertain to a portion of our estimated production for the last three months of ~~2017,~~2021, as well as ~~2018~~for 2022, 2023 and ~~2019.~~2024. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At September 30, ~~2017,~~2021, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net ~~asset~~ positions by approximately ~~$170~~$280 million.

Interest Rate Risk

As of September 30, ~~2017,~~2021, we had total debt of ~~$10.4~~$6.5 billion. ~~Of this amount, $10.3 billion bears~~All of our debt is based on fixed interest rates averaging ~~5.3%, and $74 million is comprised of floating rate debt with interest rates averaging 3.2%~~5.7%.

As of September 30, 2017, we had open interest rate swap positions that are presented in Note 3 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 September 30, 2017.

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 ourWe had no material foreign currency risk at September 30, ~~2017 balance sheet.~~2021.

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 September 30, ~~2017~~2021 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

In conjunction with the Merger closing, we have integrated WPX’s operations into our overall system of internal controls over financial reporting and they are now included in our assessment of the effectiveness of our internal controls over financial reporting. For additional information regarding the Merger, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

There were no other changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 and subject to the environmental matters noted in Part II, Item 1. Legal Proceedings of our Second Quarter 2021 Quarterly Report on Form 10-Q, 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 ~~2016~~2020 Annual Report on Form 10-K and other SEC filings for additional ~~information regarding certain environmental matters involving the Company.~~information.

Item 1A. Risk Factors

There have been no material changes to the information included in Item 1A. “Risk Factors” in our ~~2016~~2020 Annual Report on Form ~~10-K.~~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 third quarter of ~~2017.~~

2021 (shares in thousands).

Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share		Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share
July 1 - July 31		48,112	$	32.08		16	$	27.64
August 1 - August 31		16,504	$	31.69		41	$	25.65
September 1 - September 30		1,108	$	31.81		18	$	29.29
Total		65,724	$	31.97		75	$	26.95

~~(1)~~

~~Share repurchases represent~~(1)

These amounts reflect the 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 10,400 shares of our common stock in the third quarter of 2017, 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 third quarter of 2017, there were approximately 4,200 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.

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Item 6. E~~xhibits~~Exhibits

Exhibit Number		Description

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

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

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

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

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

101.SCH			Inline XBRL Taxonomy Extension Schema Document.

101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			Inline XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document.

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

4546

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~~SIGNATURES~~

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: November ~~1, 2017~~3, 2021				/s/ Jeremy D. Humphers
				Jeremy D. Humphers
				Senior Vice President and Chief Accounting Officer

4647

	Three Months Ended September 30, 2016
	(Millions)
Proceeds received, net of purchase price adjustments and selling costs	$	1,653
Asset retirement obligation assumed by purchasers		250
Total consideration received		1,903

Allocated oil and gas property basis sold		355
Allocated goodwill		197
Total assets sold		552

Gain on asset sales	$	1,351

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Commodity derivatives:
Oil, gas and NGL derivatives	$	(144	)	$	79		$	214		$	(30	)
Marketing and midstream revenues		(5	)		(1	)		3			(7	)
Interest rate derivatives:
Other nonoperating items		(4	)		(20	)		(19	)		(163	)
Foreign currency derivatives:
Other nonoperating items		—			—			—			(159	)
Net gains (losses) recognized	$	(153	)	$	58		$	198		$	(359	)

	General Partner				EnLink
	Restricted		Performance		Restricted		Performance
	Incentive Units		Units		Incentive Units		Units
Unrecognized compensation cost (millions)	$	14	$	6	$	15	$	6
Weighted average period for recognition (years)		1.8		2.0		1.7		1.9

	September 30, 2016
	Three Months Ended			Nine Months Ended
	(Millions)
2016 reduction in workforce:
Employee related costs	$	(7	)	$	229
Lease obligations		—			17
Asset impairments		—			3
Transaction costs		2			17
Restructuring and transaction costs	$	(5	)	$	266

	Pension Benefits												Postretirement Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,
	2017			2016			2017			2016			2017		2016		2017			2016
	(Millions)
Service cost	$	4		$	3		$	12		$	12		$	—	$	—	$	—		$	—
Interest cost		11			9			32			32			—		—		—			—
Expected return on plan assets		(14	)		(14	)		(41	)		(40	)		—		—		—			—
Amortization of prior service cost ⁽¹⁾		—			1			1			2			—		—		(1	)		(1	)
Net actuarial loss ⁽¹⁾		5			6			14			19			—		—		—			—
Net periodic benefit cost ⁽²⁾	$	6		$	5		$	18		$	25		$	—	$	—	$	(1	)	$	(1	)

	Amounts		Rate
	(Millions)		(Per Share)
Quarter Ended 2017:
First quarter 2017	$	32	$	0.06
Second quarter 2017		33	$	0.06
Third quarter 2017		30	$	0.06
Total year-to-date	$	95
Quarter Ended 2016:
First quarter 2016	$	125	$	0.24
Second quarter 2016		33	$	0.06
Third quarter 2016		32	$	0.06
Total year-to-date	$	190

							Fair Value
							Measurements Using:
	Carrying			Total Fair			Level 1		Level 2
	Amount			Value			Inputs		Inputs
	(Millions)
September 30, 2017 assets (liabilities):
Cash equivalents	$	1,510		$	1,510		$	1,431	$	79
Commodity derivatives	$	43		$	43		$	—	$	43
Commodity derivatives	$	(60	)	$	(60	)	$	—	$	(60	)
Interest rate derivatives	$	1		$	1		$	—	$	1
Interest rate derivatives	$	(62	)	$	(62	)	$	—	$	(62	)
Debt	$	(10,403	)	$	(11,480	)	$	—	$	(11,480	)
Installment payment	$	(243	)	$	(244	)	$	—	$	(244	)
Capital lease obligations	$	(4	)	$	(4	)	$	—	$	(4	)

December 31, 2016 assets (liabilities):
Cash equivalents	$	1,542		$	1,542		$	1,298	$	244
Commodity derivatives	$	10		$	10		$	—	$	10
Commodity derivatives	$	(203	)	$	(203	)	$	—	$	(203	)
Interest rate derivatives	$	1		$	1		$	—	$	1
Interest rate derivatives	$	(41	)	$	(41	)	$	—	$	(41	)
Debt	$	(10,154	)	$	(10,760	)	$	—	$	(10,760	)
Installment payment	$	(473	)	$	(477	)	$	—	$	(477	)
Capital lease obligations	$	(7	)	$	(6	)	$	—	$	(6	)

	U.S.			Canada			EnLink			Eliminations			Total
	(Millions)
Three Months Ended September 30, 2017:
Revenues from external customers	$	1,575		$	358		$	1,223		$	—		$	3,156
Asset dispositions and other	$	1		$	—		$	(1	)	$	—		$	—
Intersegment revenues	$	—		$	—		$	174		$	(174	)	$	—
Depreciation, depletion and amortization	$	195		$	63		$	142		$	—		$	400
Interest expense	$	82		$	17		$	49		$	(15	)	$	133
Asset impairments	$	—		$	—		$	2		$	—		$	2
Earnings before income taxes	$	167		$	85		$	20		$	—		$	272
Income tax expense	$	(5	)	$	28		$	2		$	—		$	25
Net earnings	$	172		$	57		$	18		$	—		$	247
Net earnings attributable to noncontrolling interests	$	—		$	—		$	19		$	—		$	19
Net earnings (loss) attributable to Devon	$	172		$	57		$	(1	)	$	—		$	228
Capital expenditures, including acquisitions	$	560		$	103		$	170		$	—		$	833
Three Months Ended September 30, 2016:
Revenues from external customers	$	1,653		$	305		$	924		$	—		$	2,882
Asset dispositions and other	$	1,351		$	—		$	—		$	—		$	1,351
Intersegment revenues	$	—		$	—		$	180		$	(180	)	$	—
Depreciation, depletion and amortization	$	196		$	72		$	126		$	—		$	394
Interest expense	$	185		$	34		$	49		$	(23	)	$	245
Asset impairments	$	317		$	2		$	—		$	—		$	319
Restructuring and transaction costs	$	(10	)	$	5		$	—		$	—		$	(5	)
Earnings before income taxes	$	1,122		$	37		$	19		$	—		$	1,178
Income tax expense	$	5		$	159		$	7		$	—		$	171
Net earnings (loss)	$	1,117		$	(122	)	$	12		$	—		$	1,007
Net earnings attributable to noncontrolling interests	$	—		$	—		$	14		$	—		$	14
Net earnings (loss) attributable to Devon	$	1,117		$	(122	)	$	(2	)	$	—		$	993
Capital expenditures, including acquisitions	$	277		$	48		$	132		$	—		$	457
Nine Months Ended September 30, 2017:
Revenues from external customers	$	5,547		$	951		$	3,468		$	—		$	9,966
Asset dispositions and other	$	11		$	—		$	(1	)	$	—		$	10
Intersegment revenues	$	—		$	—		$	515		$	(515	)	$	—
Depreciation, depletion and amortization	$	556		$	199		$	407		$	—		$	1,162
Interest expense	$	243		$	48		$	133		$	(42	)	$	382
Asset impairments	$	—		$	—		$	9		$	—		$	9
Earnings before income taxes	$	1,133		$	126		$	69		$	—		$	1,328
Income tax expense	$	—		$	42		$	9		$	—		$	51
Net earnings	$	1,133		$	84		$	60		$	—		$	1,277
Net earnings attributable to noncontrolling interests	$	—		$	—		$	59		$	—		$	59
Net earnings attributable to Devon	$	1,133		$	84		$	1		$	—		$	1,218
Property and equipment, net	$	7,726		$	2,787		$	6,569		$	—		$	17,082
Total assets	$	13,302		$	3,761		$	10,548		$	(52	)	$	27,559
Capital expenditures, including acquisitions	$	1,460		$	275		$	636		$	—		$	2,371
Nine Months Ended September 30, 2016:
Revenues from external customers	$	4,320		$	688		$	2,488		$	—		$	7,496
Asset dispositions and other	$	1,351		$	—		$	—		$	—		$	1,351
Intersegment revenues	$	—		$	—		$	539		$	(539	)	$	—
Depreciation, depletion and amortization	$	763		$	284		$	373		$	—		$	1,420
Interest expense	$	400		$	101		$	140		$	(66	)	$	575
Asset impairments	$	2,810		$	1,168		$	873		$	—		$	4,851
Restructuring and transaction costs	$	245		$	15		$	6		$	—		$	266
Loss before income taxes	$	(2,040	)	$	(1,359	)	$	(853	)	$	—		$	(4,252	)
Income tax expense (benefit)	$	(6	)	$	(223	)	$	1		$	—		$	(228	)
Net loss	$	(2,034	)	$	(1,136	)	$	(854	)	$	—		$	(4,024	)
Net earnings (loss) attributable to noncontrolling interests	$	1		$	—		$	(392	)	$	—		$	(391	)
Net loss attributable to Devon	$	(2,035	)	$	(1,136	)	$	(462	)	$	—		$	(3,633	)
Property and equipment, net	$	7,196		$	2,778		$	6,195		$	—		$	16,169
Total assets	$	12,317		$	4,355		$	10,197		$	(56	)	$	26,813
Capital expenditures, including acquisitions	$	2,454		$	158		$	816		$	—		$	3,428

	Three Months Ended September 30,							Nine Months Ended September 30, ⁽³⁾
	2017		2016		Change			2017		2016			Change
	(Millions, except per share amounts)
Net earnings (loss) attributable to Devon	$	228	$	993		- 77	%	$	1,218	$	(3,633	)		N/M
Net earnings (loss) per diluted share attributable to Devon	$	0.43	$	1.89		- 77	%	$	2.31	$	(7.22	)		N/M
Core earnings (loss) attributable to Devon⁽¹⁾	$	242	$	47		+415	%	$	636	$	(169	)		N/M
Core earnings (loss) per diluted share attributable to Devon ⁽¹⁾	$	0.46	$	0.09		+411	%	$	1.20	$	(0.34	)		N/M
Retained production (MBoe/d)		527		550		- 4	%		542		578			- 6	%
Total production (MBoe/d)		527		577		- 9	%		542		635			- 15	%
Realized price per Boe ⁽²⁾	$	25.67	$	20.98		+22	%	$	25.41	$	17.37			+46	%
Operating cash flow	$	776	$	727		+7	%	$	2,420	$	1,237			+96	%
Capital expenditures, including acquisitions	$	833	$	457		+82	%	$	2,371	$	3,428			- 31	%
Shareholder and noncontrolling interests distributions	$	114	$	109		+5	%	$	342	$	414			- 17	%
Cash and cash equivalents								$	2,781	$	2,385			+17	%
Total debt								$	10,403	$	11,354			- 8	%

	Three Months Ended September 30,							Nine Months Ended September 30,
	2017 ⁽¹⁾		2016 ⁽¹⁾		Change			2017 ⁽¹⁾		2016 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	47.12	$	42.51		+11	%	$	47.84	$	36.89		+30	%
Canada	$	35.02	$	27.46		+28	%	$	32.77	$	22.26		+47	%
Total	$	45.41	$	40.12		+13	%	$	45.83	$	34.78		+32	%
Bitumen (per Bbl)
Canada	$	31.75	$	23.00		+38	%	$	28.49	$	17.77		+60	%
Gas (per Mcf)
U.S.	$	2.45	$	2.24		+10	%	$	2.54	$	1.70		+50	%
NGLs (per Bbl)
U.S.	$	15.15	$	9.80		+55	%	$	14.62	$	8.84		+65	%
Combined (per Boe)
U.S.	$	23.85	$	20.26		+18	%	$	24.44	$	17.16		+42	%
Canada	$	31.59	$	23.23		+36	%	$	28.50	$	18.15		+57	%
Total	$	25.67	$	20.98		+22	%	$	25.41	$	17.37		+46	%

	Three Months Ended September 30,
	Oil			Bitumen			Gas			NGLs			Total
	(Millions)
2016 sales	$	502		$	244		$	273		$	94		$	1,113
Change due to volumes		(23	)		(26	)		(25	)		(9	)		(83	)
Change due to prices		63			83			23			46			215
2017 sales	$	542		$	301		$	271		$	131		$	1,245

	Nine Months Ended September 30,
	Oil			Bitumen			Gas			NGLs			Total

	(Millions)
2016 sales	$	1,523		$	512		$	688		$	300		$	3,023
Change due to volumes		(243	)		16			(125	)		(68	)		(420	)
Change due to prices		407			319			279			152			1,157
2017 sales	$	1,687		$	847		$	842		$	384		$	3,760

	Three Months Ended September 30, 2017
	Oil			Bitumen		Gas			NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)			(Per Bbl)			(Per Boe)
Realized price without hedges	$	45.41		$	31.75	$	2.45		$	15.15		$	25.67
Cash settlements of hedges		0.96			—		0.12			(0.03	)		0.52
Realized price, including cash settlements	$	46.37		$	31.75	$	2.57		$	15.12		$	26.19
				��
	Three Months Ended September 30, 2016
	Oil			Bitumen		Gas			NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)			(Per Bbl)			(Per Boe)
Realized price without hedges	$	40.12		$	23.00	$	2.24		$	9.80		$	20.98
Cash settlements of hedges		1.56			—		(0.04	)		0.10			0.32
Realized price, including cash settlements	$	41.68		$	23.00	$	2.20		$	9.90		$	21.30

	Nine Months Ended September 30, 2017
	Oil			Bitumen		Gas			NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)			(Per Bbl)			(Per Boe)
Realized price without hedges	$	45.83		$	28.49	$	2.54		$	14.62		$	25.41
Cash settlements of hedges		0.80			—		0.05			(0.02	)		0.29
Realized price, including cash settlements	$	46.63		$	28.49	$	2.59		$	14.60		$	25.70

	Nine Months Ended September 30, 2016
	Oil			Bitumen		Gas			NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)			(Per Bbl)			(Per Boe)
Realized price without hedges	$	34.78		$	17.77	$	1.70		$	8.84		$	17.37
Cash settlements of hedges		(0.94	)		—		0.12			(0.06	)		0.02
Realized price, including cash settlements	$	33.84		$	17.77	$	1.82		$	8.78		$	17.39

	Devon						EnLink						Consolidated
	2017			2016			2017			2016			2017			2016
	(Millions)
Operating cash flow	$	1,892		$	724		$	528		$	513		$	2,420		$	1,237
Divestitures of property and equipment		321			1,884			2			5			323			1,889
Issuance of common stock		—			1,469			—			—			—			1,469
Proceeds from sale of investment		—			—			190			—			190			—
Capital expenditures		(1,541	)		(1,235	)		(662	)		(424	)		(2,203	)		(1,659	)
Acquisitions of property, equipment and businesses		(39	)		(849	)		—			(792	)		(39	)		(1,641	)
Debt activity, net		—			(1,946	)		252			178			252			(1,768	)
Payment of installment payable		—			—			(250	)		—			(250	)		—
Shareholder and noncontrolling interests distributions		(95	)		(190	)		(247	)		(224	)		(342	)		(414	)
EnLink and General Partner distributions		199			199			(199	)		(199	)		—			—
Issuance of subsidiary units		—			—			486			835			486			835
Effect of exchange rate and other		(45	)		(23	)		30			150			(15	)		127
Net change in cash and cash equivalents	$	692		$	33		$	130		$	42		$	822		$	75
Cash and cash equivalents at end of period	$	2,639		$	2,325		$	142		$	60		$	2,781		$	2,385