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

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

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

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

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~~July 18, ~~2017, 525.5~~2018, 508.8 million shares of common stock were outstanding.

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

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

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

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

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

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

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

This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, ~~2016~~2017 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to:

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

Three Months Ended 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 June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(Unaudited)
Upstream revenues	$	1,069		$	1,332		$	2,388		$	2,873
Marketing revenues		1,180			833			2,059			1,692
Total revenues		2,249			2,165			4,447			4,565
Production expenses		572			455			1,115			912
Exploration expenses		68			57			101			152
Marketing expenses		1,160			849			2,033			1,728
Depreciation, depletion and amortization		420			369			819			769
Asset impairments		154			—			154			—
Asset dispositions		23			(22	)		11			(30	)
General and administrative expenses		153			181			352			376
Financing costs, net		62			77			449			160
Restructuring and transaction costs		94			—			94			—
Other expenses		24			(8	)		45			(22	)
Total expenses		2,730			1,958			5,173			4,045
Earnings (loss) from continuing operations before income taxes		(481	)		207			(726	)		520
Income tax benefit		(7	)		(5	)		(41	)		—
Net earnings (loss) from continuing operations		(474	)		212			(685	)		520
Net earnings from discontinued operations, net of income tax expense		139			33			197			42
Net earnings (loss)		(335	)		245			(488	)		562
Net earnings attributable to noncontrolling interests		90			26			134			40
Net earnings (loss) attributable to Devon	$	(425	)	$	219		$	(622	)	$	522
Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share	$	(0.92	)	$	0.40		$	(1.33	)	$	0.99
Basic earnings from discontinued operations per share		0.09			0.01			0.13			—
Basic net earnings (loss) per share	$	(0.83	)	$	0.41		$	(1.20	)	$	0.99
Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share	$	(0.92	)	$	0.40		$	(1.33	)	$	0.99
Diluted earnings from discontinued operations per share		0.09			0.01			0.13			—
Diluted net earnings (loss) per share	$	(0.83	)	$	0.41		$	(1.20	)	$	0.99
Comprehensive earnings (loss):
Net earnings (loss)	$	(335	)	$	245		$	(488	)	$	562
Other comprehensive earnings (loss), net of tax:
Foreign currency translation		(34	)		28			(82	)		36
Pension and postretirement plans		3			4			7			9
Other comprehensive earnings (loss), net of tax		(31	)		32			(75	)		45
Comprehensive earnings (loss)		(366	)		277			(563	)		607
Comprehensive earnings attributable to noncontrolling interests		90			26			134			40
Comprehensive earnings (loss) attributable to Devon	$	(456	)	$	251		$	(697	)	$	567

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 June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(Unaudited)
Cash flows from operating activities:
Net earnings (loss)	$	(335	)	$	245		$	(488	)	$	562
Adjustments to reconcile net earnings to net cash from operating activities:
Earnings from discontinued operations, net of tax		(139	)		(33	)		(197	)		(42	)
Depreciation, depletion and amortization		420			369			819			769
Asset impairments		154			—			154			—
Leasehold impairments		53			22			61			64
Accretion on discounted liabilities		15			15			31			32
Total (gains) losses on commodity derivatives		497			(126	)		538			(358	)
Cash settlements on commodity derivatives		(131	)		11			(120	)		19
(Gains) losses on asset dispositions		23			(22	)		11			(30	)
Deferred income tax expense (benefit)		20			(17	)		(18	)		(32	)
Share-based compensation		58			45			96			81
Early retirement of debt		—			—			312			—
Total (gains) losses on foreign exchange		31			(49	)		81			(64	)
Settlements of intercompany foreign denominated assets/liabilities		(244	)		1			(243	)		10
Other		(20	)		23			(50	)		11
Changes in assets and liabilities, net		(133	)		102			(108	)		133
Net cash from operating activities - continuing operations		269			586			879			1,155
Cash flows from investing activities:
Capital expenditures		(602	)		(434	)		(1,253	)		(831	)
Acquisitions of property and equipment		(10	)		(13	)		(16	)		(33	)
Divestitures of property and equipment		560			75			607			107
Net cash from investing activities - continuing operations		(52	)		(372	)		(662	)		(757	)
Cash flows from financing activities:
Repayments of long-term debt principal		—			—			(807	)		—
Early retirement of debt		—			—			(304	)		—
Repurchases of common stock		(428	)		—			(499	)		—
Dividends paid on common stock		(42	)		(33	)		(74	)		(65	)
Shares exchanged for tax withholdings		(6	)		(3	)		(44	)		(56	)
Net cash from financing activities - continuing operations		(476	)		(36	)		(1,728	)		(121	)
Effect of exchange rate changes on cash:
Settlements of intercompany foreign denominated assets/liabilities		244			(1	)		243			(10	)
Other		(17	)		9			(31	)		10
Total effect of exchange rate changes on cash - continuing operations		227			8			212			—
Net change in cash, cash equivalents and restricted cash of continuing operations		(32	)		186			(1,299	)		277
Cash flows from discontinued operations:
Operating activities		236			151			430			328
Investing activities		(222	)		(215	)		(402	)		(284	)
Financing activities		73			128			112			89
Net change in cash, cash equivalents and restricted cash of discontinued operations		87			64			140			133
Net change in cash, cash equivalents and restricted cash		55			250			(1,159	)		410
Cash, cash equivalents and restricted cash at beginning of period		1,470			2,119			2,684			1,959
Cash, cash equivalents and restricted cash at end of period	$	1,525		$	2,369		$	1,525		$	2,369

Reconciliation of cash, cash equivalents and restricted cash:
Cash and cash equivalents	$	1,460		$	2,358		$	1,460		$	2,358
Restricted cash included in other current assets		28			—			28			—
Cash and cash equivalents included in current assets held for sale		37			11			37			11
Total cash, cash equivalents and restricted cash	$	1,525		$	2,369		$	1,525		$	2,369

	September 30, 2017			December 31, 2016
	(Unaudited)						June 30, 2018			December 31, 2017
	(Millions, except share data)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,781		$	1,959		$	1,460		$	2,642
Accounts receivable		1,462			1,356			1,141			989
Assets held for sale		—			193
Current assets held for sale								10,764			760
Other current assets		379			264			455			400
Total current assets		4,622			3,772			13,820			4,791
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								12,957			13,318
Other property and equipment, net								1,164			1,266
Total property and equipment, net								14,121			14,584
Goodwill		3,964			3,964			841			841
Other long-term assets		1,891			1,987			377			296
Long-term assets held for sale								—			9,729
Total assets	$	27,559		$	25,913		$	29,159		$	30,241
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	797		$	642		$	771		$	633
Revenues and royalties payable		1,012			908			959			748
Short-term debt		20			—			277			115
Current liabilities held for sale								5,291			991
Other current liabilities		1,003			1,066			1,079			828
Total current liabilities		2,832			2,616			8,377			3,315
Long-term debt		10,383			10,154			5,790			6,749
Asset retirement obligations		1,100			1,226			1,088			1,099
Other long-term liabilities		645			894			624			549
Long-term liabilities held for sale								—			3,936
Deferred income taxes		665			648			432			489
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
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 515 million and 525 million shares in 2018 and 2017, respectively								51			53
Additional paid-in capital		7,207			7,237			6,888			7,333
Accumulated deficit		(428	)		(1,646	)
Retained earnings								6			702
Accumulated other comprehensive earnings		297			284			1,091			1,166
Treasury stock, at cost, 0.5 million shares in 2018								(22	)		—
Total stockholders’ equity attributable to Devon		7,129			5,927			8,014			9,254
Noncontrolling interests		4,805			4,448			4,834			4,850
Total equity		11,934			10,375			12,848			14,104
Total liabilities and equity	$	27,559		$	25,913		$	29,159		$	30,241

Accumulated

Additional

Retained

Other

Common Stock

Paid-In

Earnings

Comprehensive

Treasury

Noncontrolling

Total

Shares

Amount

Capital

(Accumulated Deficit)

Earnings

Stock

Interests

Equity

(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

Net earnings

—

—

—

1,218

—

—

59

1,277

Other comprehensive earnings, net of tax

—

—

—

—

13

—

—

13

Restricted stock grants, net of cancellations

1

1

—

—

—

—

—

1

Common stock repurchased

—

—

—

—

—

(43
)

—

(43
)
Common stock retired

—

—

(43
)

—

—

43

—

—

Common stock dividends

—

—

(95
)

—

—

—

—

(95
)
Share-based compensation

1

—

96

—

—

—

—

96

Subsidiary equity transactions

—

—

12

—

—

—

545

557

Distributions to noncontrolling interests

—

—

—

—

—

—

(247
)

(247
)
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
)
Other comprehensive earnings, net of tax

—

—

—

—

48

—

—

48

Restricted stock grants, net of cancellations

3

—

—

—

—

—

—

—

Common stock repurchased

—

—

—

—

—

(23
)

—

(23
)
Common stock retired

—

—

(23
)

—

—

23

—

—

Common stock dividends

—

—

(65
)

(125
)

—

—

—

(190
)
Common stock issued

103

10

2,117

—

—

—

—

2,127

Share-based compensation

—

—

142

—

—

—

—

142

Subsidiary equity transactions

—

—

320

—

—

—

896

1,216

Distributions to noncontrolling interests

—

—

—

—

—

—

(224
)

(224
)
Balance as of September 30, 2016

524

$
52

$
7,487

$
(1,977
)

$
278

$
—

$
4,221

$
10,061

										Retained			Accumulated
							Additional			Earnings			Other
	Common Stock						Paid-In			(Accumulated			Comprehensive			Treasury			Noncontrolling			Total
	Shares			Amount			Capital			Deficit)			Earnings			Stock			Interests			Equity
	(Unaudited)
Six Months Ended June 30, 2018
Balance as of December 31, 2017		525		$	53		$	7,333		$	702		$	1,166		$	—		$	4,850		$	14,104
Net earnings (loss)		—			—			—			(622	)		—			—			134			(488	)
Other comprehensive loss, net of tax		—			—			—			—			(75	)		—			—			(75	)
Restricted stock grants, net of cancellations		3			—			—			—			—			—			—			—
Common stock repurchased		—			(1	)		—			—			—			(555	)		—			(556	)
Common stock retired		(14	)		(1	)		(532	)		—			—			533			—			—
Common stock dividends		—			—			—			(74	)		—			—			—			(74	)
Share-based compensation		1			—			89			—			—			—			—			89
Subsidiary equity transactions		—			—			(2	)		—			—			—			69			67
Distributions to noncontrolling interests		—			—			—			—			—			—			(219	)		(219	)
Balance as of June 30, 2018		515		$	51		$	6,888		$	6		$	1,091		$	(22	)	$	4,834		$	12,848
Six Months Ended June 30, 2017
Balance as of December 31, 2016		523		$	52		$	7,237		$	(69	)	$	1,054		$	—		$	4,448		$	12,722
Net earnings		—			—			—			522			—			—			40			562
Other comprehensive earnings, net of tax		—			—			—			—			45			—			—			45
Restricted stock grants, net of cancellations		2			1			—			—			—			—			—			1
Common stock repurchased		—			—			—			—			—			(41	)		—			(41	)
Common stock retired		—			—			(41	)		—			—			41			—			—
Common stock dividends		—			—			—			(65	)		—			—			—			(65	)
Share-based compensation		1			—			69			—			—			—			—			69
Subsidiary equity transactions		—			—			11			—			—			—			106			117
Distributions to noncontrolling interests		—			—			—			—			—			—			(163	)		(163	)
Balance as of June 30, 2017		526		$	53		$	7,276		$	388		$	1,099		$	—		$	4,431		$	13,247

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~~2017 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~~six-month periods ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 and Devon’s financial position as of ~~September~~June 30, ~~2017.~~2018. As further discussed in Note 3, during the second quarter of 2018, Devon announced the sale of its interests in the General Partner and EnLink, which closed on July 18, 2018. Activity relating to the General Partner and EnLink have now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows. The associated assets and liabilities of EnLink and the General Partner are presented as assets and liabilities held for sale on the consolidated balance sheets.

In January ~~2017,~~2018, Devon adopted ASU ~~2016-09,~~2014-09, ~~Compensation – Stock Compensation (Topic 718)~~Revenue from Contracts with Customers (ASC 606), ~~Improvements to Employee Share-Based Payment Accounting. Its objective is to simplify several aspects of~~using the ~~accounting~~modified retrospective method. See Note 2 for ~~share-based payments, including income taxes when awards vest or are settled, statutory withholding and forfeitures.~~ As the result of adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefits and deficiencies in the consolidated comprehensive statements of earnings and as operating cash flows in the consolidated statements of cash flows. ~~Devon also retrospectively applied the new cash flow statement guidance dictating the presentation of shares exchanged for tax-withholding purposes as a financing activity. The~~further discussion regarding Devon’s adoption of the ~~new guidance did not materially impact~~revenue recognition standard.

In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU requires entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. As a result of the adoption of this ASU, consolidated ~~financial statements for the nine months ended September 30, 2017 or previously reported financial information but could have a more material future impact.~~statement of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively.

In January ~~2017,~~2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires an entity to show the ~~FASB issued ASU 2017-04,~~ ~~Intangibles – Goodwill And Other (Topic 350)~~, ~~Simplifying~~changes in the ~~Test for Goodwill Impairment~~ ~~("ASU 2017-04"). ASU 2017-04 simplifies~~total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the ~~accounting for goodwill impairments by eliminating the requirement~~statement of cash flows and to ~~compare the implied fair value of goodwill with its carrying amount as part of step two~~provide a reconciliation of the ~~goodwill impairment test. Under ASU 2017-04, an entity should perform its goodwill impairment test by comparing~~totals in the ~~fair value~~statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the impairment loss recognized should not exceed the total amountresult 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 performed on testing dates after January 1, 2017. In January 2017, Devon elected to early adopt ASU 2017-04, and the adoption ~~had no~~of this ASU, Devon made changes to the statement of cash flows to include the required presentation and reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on ~~the~~Devon’s consolidated ~~financial statements. Devon will perform future goodwill impairment tests according to ASU 2017-04.~~statement of cash flows.

~~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.

The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, ~~2019 and will~~2019. Early adoption is permitted, but Devon does not plan to early adopt. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. ~~Early~~However, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842), Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its adoption ~~is permitted, but Devon does not plan to early adopt. Devon is~~date instead of at the earliest comparative period presented in the ~~process of evaluating contracts and gathering the necessary terms and data elements for purposes of determining the impact this~~consolidated financial statements. The proposed ASU will ~~have on~~allow entities to continue to apply the legacy guidance in Topic 840, including its ~~consolidated financial statements and related disclosures. Recently,~~disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. The FASB issued ~~Proposed Accounting Standards Update (ASU)~~ASU No. ~~2017-290,~~ 2018-01, 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 easement and right-of-way contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.

~~Based~~Devon has determined its portfolio of leased assets and is reviewing all related contracts to determine the impact the adoption will have on ~~continuing research, Devon estimates a large number of contracts~~its consolidated financial statements and ~~data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective.~~related disclosures. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls. Devon is in the process of designing processes and controls and ~~is evaluating~~has implemented a technology ~~requirements and solutions~~solution needed to comply with the requirements of this ASU. While Devon cannot currently estimate the quantitative effect that ASU 2016-02 will have on its consolidated financial statements, the adoption will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities.

The FASB issued ASU ~~No. 2017-07,~~2017-12, ~~Compensation – Retirement Benefits~~Derivatives and Hedging (Topic ~~715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.~~815): Targeted Improvements to Accounting for Hedging Activities. This ASU will ~~require~~expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company’s risk management activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This ASU only applies to entities 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 eligiblethat elect hedge accounting, which Devon has not for ~~capitalization. This~~derivative financial instruments. This ASU is effective for ~~Devon~~annual and interim periods beginning January 1, ~~2018, and presentation changes~~2019, with early adoption permitted in 2018. The ASU is required to be adopted using a cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the ~~statement~~period of ~~earnings will be applied retrospectively, while service cost component capitalization will be applied prospectively. Upon~~ adoption to account for prior period effects rather than restating previously reported results. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements if hedge accounting were elected by Devon ~~will reclassify $7 million, $14 million~~in the future.

The FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220). This ASU allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and ~~$16 million~~allows for early adoption in any interim period after issuance of ~~non-service cost components of net periodic benefit costs for 2017, 2016 and 2015, respectively, as other nonoperating items. Such amounts are~~the update. Devon is currently ~~classified in Devon’s G&A. No other changes upon adopting~~assessing the impact this ASU ~~are expected to be material.~~

In January ~~2016,~~2018, Devon ~~acquired approximately 80,000 net acres (unaudited)~~adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and ~~assets~~has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.

The impact of adoption in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of common equity shares. The purchase price allocation was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.current period results is as follows:

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. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves.

~~In 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.

~~Proceeds~~Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the ~~transactions were used primarily~~third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for ~~debt repayment~~these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to ~~support capital investment in Devon’s core resource plays.~~

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

~~In January 2016, EnLink acquired Anadarko Basin gathering~~Upstream revenues include the sale of oil, gas and ~~processing midstream assets, along with dedicated acreage service rights~~NGL production. Oil, gas and ~~service contracts, for approximately $1.4 billion. The purchase~~NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, ~~allocation was $1.0 billion to intangible assets~~delivery has occurred, control has transferred and approximately $400 million to property 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 millioncollectability of the ~~purchase~~revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price ~~was~~used to ~~be paid within one year with the option to defer $250 million~~recognize revenue is a function of the ~~final~~contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment ~~24 months~~typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from ~~the close date. The first installment payment of $250 million was paid in~~ ~~January 2017. The remaining $250 million payment is reported in other current liabilities~~such revenues in the accompanying consolidated ~~balance sheets. The accretion~~comprehensive statements of earnings.

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

In ~~August 2016, EnLink formed~~certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a ~~joint venture~~contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to ~~operate~~the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and ~~expand its midstream assets~~compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the ~~Delaware Basin. The joint venture~~consolidated comprehensive statement of earnings.

Devon’s oil sales contracts are generally structured in one of two ways. First, production is ~~initially owned 50.1% by EnLink and 49.9% by~~sold at the ~~joint venture partner. EnLink contributed approximately $244 million~~wellhead at an agreed-upon index price, net of ~~existing non-monetary assets~~pricing differentials. In this scenario, revenue is recognized when control transfers to the ~~joint venture~~purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and ~~committed an additional $262 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate~~risk 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~~loss of the ~~joint venture partner’s interest.~~product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statement of earnings.

D~~uring~~Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the ~~first quarter~~time contract specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of ~~2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.~~the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically

receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership.

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

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

Cash received relating to future performance obligations are deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of June 30, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets under ASC 606.

Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. The following table presents revenue from contracts with customers that are disaggregated based on the type of good. The difference between revenue from external customers in Note 22 and the totals listed below represents the net impact from commodity derivatives.

During the second quarter of 2018, Devon sold a portion of its Barnett Shale assets, primarily located in Johnson County for $553 million ($481 million after customary purchase price adjustments). Estimated proved reserves associated with these assets are approximately 10% of total proved reserves. The transaction resulted in an adjustment to Devon’s capitalized costs with no gain recognized in the consolidated statement of earnings. In conjunction with the divestiture, Devon settled certain gas processing contracts and recognized an approximately $40 million settlement expense, which is included in asset dispositions within the consolidated statement of earnings.

In June 2018, Devon announced the sale of its aggregate ownership interests in EnLink and the General Partner for approximately $3.1 billion. The proceeds from the sale will be utilized to increase Devon’s share repurchase program to $4.0 billion, which is discussed further in Note 18. Devon completed the sale of its interests in EnLink and the General Partner in July 2018 and expects to recognize a gain of approximately $2.5 billion in the third quarter. Additional information on these discontinued operations can be found in Note 19.

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, basis swaps and costless price collars. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of ~~September~~June 30, ~~2017,~~2018, Devon did not have any open foreign exchange contracts.

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

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~~June 30, ~~2017,~~2018, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

As of ~~September~~June 30, ~~2017,~~2018, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.

As of ~~September~~June 30, ~~2017,~~2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.

As of September 30, 2017, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index.

As of ~~September~~June 30, ~~2017,~~2018, Devon had the following open interest rate derivative ~~positions:~~position:

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.

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

~~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 below presents the ~~effects of~~ share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of 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.

Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first ~~nine~~six months of ~~2017.~~2018. The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plan.

The following table presents the assumptions related to the performance share units granted in ~~2017,~~2018, as indicated in the previous summary table.

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~~June 30, ~~2017.~~2018.

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.

The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of September 30, 2017.

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.

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

~~The following table summarizes restructuring and transaction costs presented in the accompanying consolidated comprehensive statement of earnings.~~

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.

~~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.~~

During the first six months of 2018 and 2017, Devon impaired certain non-core acreage in the U.S. that it no longer intends to pursue for exploration opportunities, resulting in unproved impairments of $61 million and $62 million, respectively. Unproved impairments are included in exploration expenses in the consolidated comprehensive statements of earnings.

During the second quarter of 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and approximately $45 million of non-oil and gas asset impairments.

In April 2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized $94 million in personnel related restructuring expenses during the second quarter of 2018. Of these expenses, $26 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, $15 million resulted from estimated settlements of defined retirement benefits.

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

The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. The amounts in the table above includes both unrealized and realized foreign exchange impacts of foreign currency denominated monetary assets and liabilities, including intercompany loans between subsidiaries with different functional currencies. Unrealized gains and losses arise from the remeasurement of these foreign currency denominated

monetary assets and liabilities and intercompany loans. Realized gains and losses arise when there are settlements of these foreign currency denominated monetary assets and liabilities and intercompany loans.

Foreign currency denominated intercompany loan activity in the second quarter of 2018 resulted in a realized loss of $244 million as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. This loss was offset by reversing $254 million of previously recognized unrealized losses on intercompany loan activity.

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.

Devon estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

~~Throughout 2016 and through~~ Under 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~~Tax Reform Legislation, the U.S. segment valuation allowance in the first nine months of 2016 based 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. Devoncorporate income tax rate was reduced ~~its U.S. segment valuation allowance by $348 million in the first nine months of 2017 based on the financial income recorded during the period.~~to 21% effective January 1, 2018.

~~Also in~~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~~Devon’s effective income tax rate. However, these items have a more noticeable impact to ~~our~~the rate in the ~~third quarter~~first six months of ~~2017~~2018 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.~~

In the first quarter of 2016, EnLink recorded goodwill impairments totaling $873 million. These impairments are not deductible for purposes of calculating income tax and, therefore, have an impact on the effective tax rate.

Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. ~~The timing~~In the second quarter of ~~resolution~~2018, Devon realized $14 million of income tax ~~examinations is uncertain~~benefits in conjunction with favorable tax settlements as ~~are the amounts and timing~~a result of ~~tax payments that are part of any audit settlement process.~~these audits. 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.

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

Throughout 2017 and through the first six months of 2018, Devon continued to maintain a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to oil and gas impairments and significant net operating losses for U.S. federal and state income tax. Devon provided an additional $129 million to its U.S. segment valuation allowance in the first six months of 2018 based on the financial losses recorded during the period. Upon closing of the EnLink divestiture in the third quarter of 2018, Devon expects to record a gain of approximately $2.5 billion. This gain is expected to significantly reduce Devon’s U.S. deferred tax valuation allowance and Devon will further evaluate its position in the third quarter of 2018. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets. During the second quarter of 2018, the Canadian segment reduced its valuation allowance by approximately $74 million.

In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance

and interpretations are expected over the next 12 months, Devon considers the accounting of the transition tax, deferred tax remeasurements and other items to be incomplete due to the forthcoming guidance and ongoing analysis of Devon’s tax positions. This analysis will be materially complete upon the filing of the 2017 U.S. tax return in the fourth quarter of 2018. Devon expects to complete its analysis within the measurement period in accordance with SAB 118. No material changes to the provisional amounts recorded in the fourth quarter of 2017 have been made during the first six months of 2018.

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.

~~Devon’s acquisition of certain STACK assets during the first three months of 2016 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.

~~Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that~~The following table presents 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 millionaggregate capitalized costs 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.~~

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

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

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.

Devon has a $3.0 billion Senior Credit Facility. As of ~~September~~June 30, ~~2017,~~2018, Devon had ~~$59~~$51 million in outstanding letters of credit under the Senior Credit Facility. There were no outstanding borrowings under the Senior Credit Facility at ~~September~~June 30, ~~2017.~~2018. The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. Under the terms of the credit agreement, total capitalization is adjusted to add back noncash financial write-downs such as ~~full cost ceiling impairments or goodwill~~ impairments. As of ~~September~~June 30, ~~2017,~~2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of ~~18.9%~~26.1%.

In the ~~third~~first quarter of ~~2016,~~2018, Devon completed tender offers to repurchase ~~$1.2 billion~~$807 million in aggregate principal amount of debt securities, using ~~proceeds from~~cash on hand. This included $384 million of the ~~asset divestitures discussed in Note 2.~~7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million loss on early retirement of debt, ~~primarily~~ consisting of ~~$82~~$304 million in cash retirement costs and ~~other fees.~~$8 million of noncash charges. These costs, along with other ~~minimal noncash~~ charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.

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

EnLink has a $1.5 billion unsecured revolving credit facility. As of September 30, 2017, there were $9 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility. The General Partner has a $250 million secured revolving credit facility. 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 in compliance with all financial covenants in their respective credit facilities as 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.

~~15. Asset Retirement Obligations~~In July 2018, Devon repaid the $20 million of 8.25% Senior Notes at maturity.

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

During the second quarter of 2018, Devon reduced its asset retirement obligation by $34 million for those obligations that were assumed by purchasers of certain Barnett Shale assets. For additional information, see Note 3.

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.

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

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

~~In January 2016, Devon issued approximately~~ 23 ~~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 the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.

In March 2018, Devon announced a share repurchase program to buy up to $1 billion of shares of common stock. In June 2018, in conjunction with the divestiture of its investment in EnLink and the General Partner, Devon announced the expansion of the share repurchase by an additional $3 billion, bringing the total repurchase program to $4 billion. The share repurchase program expires December 31, 2019. During the first six months of 2018, Devon repurchased 13.7 million shares of common stock for $521 million, or $38.01 per share, under this program.

~~In response to~~Devon increased the ~~depressed commodity price environment, Devon reduced its~~ quarterly dividend by 33% to ~~$0.06~~$0.08 per share in the second quarter of ~~2016.~~2018.

~~EnLink has the ability~~On June 6, 2018, Devon announced it had entered into an agreement to sell ~~common units through~~ its ~~“at~~aggregate ownership interests in EnLink and the ~~market” equity offering programs. In~~General Partner for approximately $3.1 billion. On July 18, 2018, Devon completed the sale and expects to recognize a gain of approximately $2.5 billion in the third quarter of ~~2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common units through~~2018. As part of the agreement, Devon extended its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. During the first nine months of 2017, EnLink issued and sold 5 million common units through its programs and generated $92 million in net proceeds.

~~In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds of approximately $394 million.~~

~~During the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million. In conjunction with its acquisition of Anadarko Basin~~fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029.

Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire midstream business ownership; 2) EnLink and the General Partner is a separate reportable segment and is a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, ~~during~~debt, revenues, net earnings and operating cash flows. As a result, Devon classified the ~~first quarter~~results of ~~2016,~~operations and cash flows related to EnLink ~~issued preferred units~~and the General Partner as ~~discussed in Note 2.~~discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was signed.

As of ~~September~~June 30, ~~2017,~~2018, Devon’s ownership interest in EnLink was 23%, excluding the interest held by the General Partner. Devon’s controlling ownership interest in the General Partner as of ~~September~~June 30, ~~2017~~2018 was 64%.

The ~~net gains~~following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations.

The following table presents the carrying amounts of the assets and ~~losses and related income taxes resulting from these transactions have been recorded~~liabilities classified as ~~an adjustment to equity, with~~held for sale on the ~~change in ownership reflected as an adjustment to noncontrolling interests.~~consolidated balance sheets.

~~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.~~

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

Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase

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

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

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.

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016.~~2017. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets ~~goodwill~~ and ~~other intangible assets~~goodwill and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items is provided in Note 56.

As discussed further in Note 19, Devon’s announcement of the sale of its aggregate ownership interests in EnLink and ~~Note 12, respectively.~~the General Partner resulted in Devon reclassifying the related assets and liabilities to held for sale on the consolidated balance sheets.

							Fair Value											Fair Value Measurements Using:
							Measurements Using:					Carrying			Total Fair			Level 1		Level 2
	Carrying			Total Fair			Level 1		Level 2			Amount			Value			Inputs		Inputs
	Amount			Value			Inputs		Inputs
	(Millions)
September 30, 2017 assets (liabilities):
June 30, 2018 assets (liabilities):
Cash equivalents	$	1,510		$	1,510		$	1,431	$	79		$	321		$	321		$	321	$	—
Commodity derivatives	$	43		$	43		$	—	$	43		$	240		$	240		$	—	$	240
Commodity derivatives	$	(60	)	$	(60	)	$	—	$	(60	)	$	(740	)	$	(740	)	$	—	$	(740	)
Interest rate derivatives	$	1		$	1		$	—	$	1		$	1		$	1		$	—	$	1
Interest rate derivatives	$	(62	)	$	(62	)	$	—	$	(62	)	$	(1	)	$	(1	)	$	—	$	(1	)
Debt	$	(10,403	)	$	(11,480	)	$	—	$	(11,480	)	$	(6,067	)	$	(6,572	)	$	—	$	(6,572	)
Installment payment	$	(243	)	$	(244	)	$	—	$	(244	)
Capital lease obligations	$	(4	)	$	(4	)	$	—	$	(4	)

December 31, 2016 assets (liabilities):
December 31, 2017 assets (liabilities):
Cash equivalents	$	1,542		$	1,542		$	1,298	$	244		$	1,533		$	1,533		$	1,454	$	79
Commodity derivatives	$	10		$	10		$	—	$	10		$	205		$	205		$	—	$	205
Commodity derivatives	$	(203	)	$	(203	)	$	—	$	(203	)	$	(286	)	$	(286	)	$	—	$	(286	)
Interest rate derivatives	$	1		$	1		$	—	$	1		$	1		$	1		$	—	$	1
Interest rate derivatives	$	(41	)	$	(41	)	$	—	$	(41	)	$	(64	)	$	(64	)	$	—	$	(64	)
Debt	$	(10,154	)	$	(10,760	)	$	—	$	(10,760	)	$	(6,864	)	$	(8,131	)	$	—	$	(8,131	)
Installment payment	$	(473	)	$	(477	)	$	—	$	(477	)
Capital lease obligations	$	(7	)	$	(6	)	$	—	$	(6	)

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

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

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

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

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

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

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

Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian E&P operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas E&P activities.

Devon considers EnLink, combined with the General Partner, to be ~~an operating~~a segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located ~~across~~in the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. ~~Therefore,~~However, with Devon’s recent divestiture announcement, activity related to the General Partner and EnLink ishave now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows, and the associated assets and liabilities of EnLink and the General Partner are presented as ~~a separate reporting segment.~~assets and liabilities held for sale on the consolidated balance sheets. Additional information can be found in Note 19.

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

	U.S.			Canada			Total
Three Months Ended June 30, 2018:
Revenues from external customers	$	1,922		$	327		$	2,249
Depreciation, depletion and amortization	$	342		$	78		$	420
Interest expense	$	72		$	(3	)	$	69
Asset impairments	$	154		$	—		$	154
Asset dispositions	$	23		$	—		$	23
Restructuring and transaction costs	$	85		$	9		$	94
Loss from continuing operations before income taxes	$	(471	)	$	(10	)	$	(481	)
Income tax expense (benefit)	$	13		$	(20	)	$	(7	)
Net earnings (loss) from continuing operations	$	(484	)	$	10		$	(474	)
Capital expenditures, including acquisitions	$	585		$	60		$	645
Three Months Ended June 30, 2017:
Revenues from external customers	$	1,891		$	274		$	2,165
Depreciation, depletion and amortization	$	283		$	86		$	369
Interest expense	$	81		$	—		$	81
Asset dispositions	$	(22	)	$	—		$	(22	)
Earnings (loss) from continuing operations before income taxes	$	213		$	(6	)	$	207
Income tax expense (benefit)	$	2		$	(7	)	$	(5	)
Net earnings from continuing operations	$	211		$	1		$	212
Capital expenditures, including acquisitions	$	385		$	71		$	456
Six Months Ended June 30, 2018:
Revenues from external customers	$	3,801		$	646		$	4,447
Depreciation, depletion and amortization	$	647		$	172		$	819
Interest expense	$	319		$	145		$	464
Asset impairments	$	154		$	—		$	154
Asset dispositions	$	11		$	—		$	11
Restructuring and transaction costs	$	85		$	9		$	94
Loss from continuing operations before income taxes	$	(587	)	$	(139	)	$	(726	)
Income tax expense (benefit)	$	14		$	(55	)	$	(41	)
Net loss from continuing operations	$	(601	)	$	(84	)	$	(685	)
Property and equipment, net	$	10,031		$	4,090		$	14,121
Total continuing assets (1)	$	13,247		$	5,148		$	18,395
Capital expenditures, including acquisitions	$	1,197		$	149		$	1,346
Six Months Ended June 30, 2017:
Revenues from external customers	$	3,972		$	593		$	4,565
Depreciation, depletion and amortization	$	585		$	184		$	769
Interest expense	$	161		$	5		$	166
Asset dispositions	$	(29	)	$	(1	)	$	(30	)
Earnings (loss) from continuing operations before income taxes	$	523		$	(3	)	$	520
Income tax expense (benefit)	$	5		$	(5	)	$	—
Net earnings from continuing operations	$	518		$	2		$	520
Property and equipment, net	$	10,051		$	4,166		$	14,217
Total continuing assets (1)	$	13,907		$	5,020		$	18,927
Capital expenditures, including acquisitions	$	731		$	153		$	884

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~~six-month periods ended ~~September~~June 30, ~~2017~~2018 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.~~2017. For information regarding our critical accounting policies and estimates, see our ~~2016~~2017 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Key components of our financial performance as compared to prior quarter 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
%

	Q2 2018 ⁽³⁾			Q1 2018 ⁽³⁾			Change
Net loss from continuing operations	$	(474	)	$	(211	)		- 125	%
Net loss per diluted share from continuing operations	$	(0.92	)	$	(0.41	)		- 123	%
Net earnings attributable to Devon from discontinued operations	$	49		$	14			+259	%
Net earnings per diluted share attributable to Devon from discontinued operations	$	0.09		$	0.03			+243	%
Net loss attributable to Devon	$	(425	)	$	(197	)		- 116	%
Net loss per diluted share attributable to Devon	$	(0.83	)	$	(0.38	)		- 120	%
Core earnings attributable to Devon⁽¹⁾	$	177		$	108			+65	%
Core earnings attributable to Devon per diluted share ⁽¹⁾	$	0.34		$	0.20			+75	%
Retained production (MBoe/d)		520			511			+2	%
Total production (MBoe/d)		541			544			- 1	%
Realized price per Boe ⁽²⁾	$	31.81		$	27.75			+15	%
Operating cash flow from continuing operations	$	269		$	610			- 56	%
Capitalized expenditures, including acquisitions	$	645		$	701			- 8	%
Cash and cash equivalents	$	1,460		$	1,407			+4	%
Total debt	$	6,067		$	6,066			+0	%

During the first ~~nine~~six months of ~~2017,~~2018, we generated solid operating results with our three-fold strategy of operating in North America’s best resource plays, delivering superior execution and maintaining a high degree of financial strength. Led by our development in the STACK and Delaware Basin, we continued to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells. 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.

~~Compared~~We continue to ~~2016, commodity prices increased significantly~~focus on our “2020 Vision,” which is our plan through the end of the decade intended to optimize returns and ~~were the primary driver for improvements in Devon’s operating margins, earnings and~~deliver top-tier, capital-efficient cash flow ~~during~~growth. Our 2020 Vision is focused on the following strategic priorities:

During the first ~~nine~~six months of 2018, we made significant progress toward achieving our 2020 Vision. Specifically, we had several key achievements:

We exited the ~~third~~second quarter of ~~2017~~2018 with liquidity comprised of ~~$2.8~~$1.5 billion of cash and $2.9 billion of available credit under our Senior Credit Facility. We have no significant debt maturities until 2021. ~~At September 30, 2017, we also had~~We currently have approximately ~~65%~~50% of our ~~remaining 2017 forecasted~~expected oil and gas production ~~hedged at an average floor price~~protected for the remainder of ~~$50/Bbl~~2018. These contracts consist of collars and ~~approximately 66% of our remaining 2017 forecasted~~swaps based off the WTI oil benchmark and the Henry Hub natural gas ~~production hedged at~~index. Additionally, we have entered into regional basis swaps in an ~~average floor~~effort to protect price ~~of $3.10/MMBtu.~~realizations across our portfolio in the U.S. and Canada, including Western Canadian Select and Midland Sweet basis oil hedges. We are building our ~~2018~~2019 and ~~2019~~2020 hedge positions at ~~similar~~market prices.

The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Due to the nature of our business, including an inherently volatile commodity price environment, we have provided a sequential quarter analysis in order to facilitate the review of our operational results and provide further ~~enhance~~transparency of our ~~financial strength with our announced $1 billion asset divestiture program.~~business. Specifically, the graph below shows the change in net earnings from the three months ended March 31, 2018 to the three months ended June 30, 2018. The ~~planned divestitures include select portions~~material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

The graph below presents the drivers of the ~~Barnett Shale focused primarily in~~upstream operations change presented above, with additional details 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.discussion of the drivers following the graph.

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:

~~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 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.~~Upstream Operations

Production Volumes

	Q2 2018		% of Total			Q1 2018		Change
Oil and bitumen (MBbls/d)
STACK		35		14	%		35		- 1	%
Delaware Basin		46		19	%		36		+29	%
Rockies Oil		16		7	%		18		- 10	%
Heavy Oil		17		7	%		18		- 5	%
Eagle Ford		28		11	%		23		+25	%
Barnett Shale		1		0	%		1		- 10	%
Other		10		4	%		9		+14	%
Retained assets		153		62	%		140		+9	%
Divested assets		—		0	%		—	N/M
Total Oil		153		62	%		140		+9	%
Bitumen		92		38	%		111		- 17	%
Total Oil and bitumen		245					251		- 3	%

~~Table of Contents~~

	Q2 2018		% of Total			Q1 2018		Change
Gas (MMcf/d)
STACK		352		31	%		344		+3	%
Delaware Basin		100		9	%		97		+3	%
Rockies Oil		18		1	%		18		- 2	%
Heavy Oil		12		1	%		12		- 4	%
Eagle Ford		74		7	%		63		+17	%
Barnett Shale		460		41	%		470		- 2	%
Other		9		1	%		10		- 7	%
Retained assets		1,025		91	%		1,014		+1	%
Divested assets		103		9	%		163		- 37	%
Total		1,128					1,177		- 4	%

	Q2 2018		% of Total			Q1 2018		Change
NGLs (MBbls/d)
STACK		38		35	%		37		+5	%
Delaware Basin		16		14	%		11		+37	%
Rockies Oil		2		2	%		2		+45	%
Eagle Ford		13		12	%		8		+67	%
Barnett Shale		34		31	%		31		+10	%
Other		2		2	%		2		+5	%
Retained assets		105		96	%		91		+15	%
Divested assets		4		4	%		6		- 32	%
Total		109					97		+12	%

~~Results~~

	Q2 2018		% of Total			Q1 2018		Change
Combined (MBoe/d)
STACK		132		25	%		129		+2	%
Delaware Basin		79		15	%		64		+24	%
Rockies Oil		21		4	%		23		- 9	%
Heavy Oil		111		20	%		131		- 16	%
Eagle Ford		54		10	%		41		+31	%
Barnett Shale		111		20	%		110		+0	%
Other		12		2	%		13		- 5	%
Retained assets		520		96	%		511		+2	%
Divested assets		21		4	%		33		- 35	%
Total		541					544		- 1	%

Strong performance in the Delaware Basin and Eagle Ford drove retained asset production growth during the second quarter of ~~Operations~~2018. These production gains were offset by lower production volumes from our heavy oil operations due to a scheduled turnaround at Jackfish 1 as well as by lower production resulting from our Johnson County divestiture.

~~Oil, Gas and NGL Production~~Field Prices

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
%

	Q2 2018			Realization		Q1 2018			Change
Oil and bitumen (per Bbl)
WTI index	$	67.83				$	62.93			+8	%
Access Western Blend index	$	45.56				$	35.44			+29	%
U.S.	$	65.41			96%	$	61.79			+6	%
Canada	$	31.70			47%	$	19.74			+61	%
Realized price, unhedged	$	50.43			74%	$	40.15			+26	%
Cash settlements	$	(5.80	)			$	(0.10	)
Realized price, with hedges	$	44.63			66%	$	40.05			+11	%

	Q2 2018		Realization		Q1 2018		Change
Gas (per Mcf)
Henry Hub index	$	2.80			$	3.01		- 7	%
Realized price, unhedged	$	2.01		72%	$	2.41		- 17	%
Cash settlements	$	0.13			$	0.17
Realized price, with hedges	$	2.14		77%	$	2.58		- 17	%

	Q2 2018			Realization		Q1 2018			Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	28.05				$	25.88			+8	%
Realized price, unhedged	$	24.10			86%	$	22.56			+7	%
Cash settlements	$	(1.66	)			$	(0.53	)
Realized price, with hedges	$	22.44			80%	$	22.03			+2	%

(1)	Based upon composition of our NGL barrel.

~~(1)~~

~~Prices presented exclude any effects of oil, gas and NGL derivatives.~~

~~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

	Q2 2018			Q1 2018		Change
Combined (per Boe)
U.S.	$	31.97		$	30.39		+5	%
Canada	$	31.17		$	19.45		+60	%
Realized price, unhedged	$	31.81		$	27.75		+15	%
Cash settlements	$	(2.68	)	$	0.23
Realized price, with hedges	$	29.13		$	27.98		+4	%

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 inOil, gas and NGL sales ~~were~~increased $206 million primarily as a result of higher WTI and Mont Belvieu index prices as well as a significant increase in the average Canadian realizations due to ~~higher North American regional~~industry plant turnarounds and seasonal lower blending requirements. These increases were slightly offset by lower realized gas prices as a result of lower Henry Hub index prices ~~upon which our~~as well as natural gas ~~sales are based and higher NGL prices at the Mont Belvieu, Texas hub.~~ transportation constraints.

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.Hedging

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

	Q2 2018			Q1 2018			Change
	Q
Oil	$	(129	)	$	(2	)		N/M
Natural gas		14			18			- 22	%
NGL		(16	)		(5	)		N/M
Total cash settlements		(131	)		11			N/M
Valuation changes		(366	)		(52	)		N/M
Total	$	(497	)	$	(41	)		N/M

~~Table of Contents~~

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

In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the ~~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~~

Production 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
%

	Q2 2018		Q1 2018		Change
LOE	$	269	$	241		+12	%
Gathering, processing & transportation		224		228		- 2	%
Production taxes		67		59		+14	%
Property taxes		12		15		- 20	%
Total	$	572	$	543		+5	%
Per Boe:
LOE	$	5.45	$	4.91		+11	%
Gathering, processing & transportation	$	4.55	$	4.65		- 2	%
Percent of oil, gas and NGL sales:
Production taxes		4.2%		4.4%		- 3	%

~~The overall increase in marketing and midstream operating margin during the third quarter and the first nine months of 2017 was~~Production expenses increased $29 million 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 impactscheduled turnaround expenses incurred at 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, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” of 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
%

Jackfish 1 facility. Production taxes also increased ~~during each period in 2017~~ on an absolute dollar basis primarily due to anthe increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed.

Exploration Expenses

	Q2 2018		Q1 2018		Change
Unproved impairments	$	53	$	8		+563	%
Geological and geophysical		6		10		- 40	%
Exploration overhead and other		9		15		- 40	%
Total	$	68	$	33		+106	%

Unproved impairments primarily relate to certain non-core acreage in the U.S. that we no longer intend to pursue for exploration opportunities.

Depreciation, Depletion and Amortization

	Q2 2018		Q1 2018		Change
Oil and gas per Boe	$	8.00	$	7.63		+5	%
Oil and gas	$	395	$	374		+6	%
Other assets		25		25		- 1	%
Total	$	420	$	399		+5	%

Our oil and gas DD&A increased during the second quarter primarily due to the change in production mix from our asset portfolio.

Financing Costs, net

During the first ~~nine months~~quarter of ~~2017, property and other taxes decreased primarily as~~2018, we incurred a ~~result~~$312 million loss on early retirement of debt. Additionally, interest expense was 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~~ 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~~2018 due to the ~~divestiture 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. For further discussion, see~~ debt repayments. See Note 515 in “Part I. Financial Information – Item 1. Financial Statements” ofin this ~~report.~~report for additional information.

~~Restructuring and Transaction Costs~~

Other

	Q2 2018		Q1 2018			Change
Asset impairments	$	154	$	—			N/M
Asset dispositions		23		(12	)		+292	%
Restructuring and transaction costs		94		—			N/M
Other		24		21			+14	%
Total	$	295	$	9			+3178	%

During the ~~first nine months~~second quarter of ~~2016,~~2018, we recognized ~~restructuring costs~~$109 million of ~~$249~~proved asset impairments relating to U.S. non-core assets no longer in our development plans and $45 million ~~as a result~~ of ~~a reduction in workforce driven by our cost reduction initiatives~~non-oil and ~~divestiture of non-core properties.~~

~~During the first nine months of 2016, we recognized transaction costs of $17 million, primarily associated with the closing of the acquisitions discussed in~~ gas asset impairments. See Note 26 in “Part I. Financial Information – Item 1. Financial Statements” ofin this ~~report.~~

~~Net Financing Costs~~report for additional information.

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
%

~~Devon’s net financing costs decreased~~We recognized personnel related restructuring charges during the ~~third~~second quarter ~~and the first nine months~~ of ~~2017 primarily due~~2018 relating to ~~the 2016 repayment of $2.5 billion 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 workforce reductions. See Note 147 in “Part I. Financial Information – Item 1. Financial Statements” in this report for additional information.

Income Taxes

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
)
Effective income tax rate

9
%

15
%

4
%

5
%

~~Table of Contents~~

~~We continue to expect low current income tax rates~~

	Q2 2018			Q1 2018
Current expense (benefit)	$	(27	)	$	4
Deferred expense (benefit)		20			(38	)
Total benefit	$	(7	)	$	(34	)
Effective income tax rate		1	%		14	%

For discussion on income taxes, see Note 8 in “Part I. Financial Information – Item 1. Financial Statements” in ~~the U.S. segment based on our continuing net operating loss position. For further discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” of~~ this report.

~~Capital Resources, Uses and Liquidity~~

~~Sources and Uses of Cash~~

~~The following table presents the major changes in cash and cash equivalents for the nine months ended September 30, 2017 and 2016.~~

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

Discontinued Operations

For discussion on discontinued operations, see Note 19 in “Part I. Financial Information – Item 1. Financial Statements” in this report. Discontinued operations net earnings increased primarily due to higher revenues and lower DD&A expense due to ceasing depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the agreement regarding the sale of our investment in EnLink and the General Partner was signed.

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 noncontrolling interests.

The graph below shows the change in net earnings from the three months ended June 30, 2017 to the three months ended June 30, 2018. The material changes are further discussed by category below. Further analysis of the upstream operations change has been provided within a supplemental section to our results of operations beginning on page 36.

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

Net earnings decreased $580 million during the second quarter of 2018 compared to the second quarter of 2017. The decrease primarily related to a $380 million decrease in upstream operations and a $325 million increase in other. These changes were partially offset by a $106 million increase in earnings from discontinued operations. Upstream operations decreased primarily due to $623 million of valuation changes and cash settlements for commodity derivatives and a $117 million increase in production expenses, partially offset by the $317 million effect of higher field prices primarily related to our oil and NGL production. Other increased primarily due to $154 million of asset impairments and $94 million of restructuring charges recognized in the second quarter of 2018. Discontinued operations net earnings increased primarily due to higher revenues and lower DD&A expense.

The graph below shows the change in net earnings from the six months ended June 30, 2017 to the six months ended June 30, 2018. The material changes are further discussed by category below. Further analysis of the upstream operations change has been provided within a supplemental section to our results of operations beginning on page 36.

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

Net earnings decreased approximately $1 billion during the six months ended 2018 compared to the same period in 2017. The decrease primarily related to a $688 million decrease in upstream operations, a $356 million increase in other and a $289 million increase in financing costs, net. These changes were partially offset by a $155 million increase in discontinued operations. Upstream revenues decreased primarily due to $896 million of valuation changes and cash settlements for commodity derivatives and a $203 million increase in production expenses, partially offset by the $403 million effect of higher field prices primarily related to our oil and NGL production. Other increased primarily due to $154 million of asset impairments and $94 million of restructuring charges during the second quarter of 2018. Financing costs, net increased $289 million primarily from $312 million of early retirement costs associated with our $800 million debt retirement in 2018. As a result of this early retirement of debt, we estimate that total cash interest expense has been reduced by approximately $64 million on an annualized basis. Discontinued operations net earnings increased primarily due to higher revenues and lower DD&A expense.

The supplemental graphs and charts below present the drivers and details of the upstream operations changes discussed in the previous section.

	Three Months Ended June 30,										Six Months Ended June 30,
	2018		% of Total			2017		Change			2018		% of Total			2017		Change
Oil and bitumen (MBbls/d)
STACK		35		14	%		25		+41	%		35		14	%		23		+54	%
Delaware Basin		46		19	%		30		+54	%		41		17	%		30		+38	%
Rockies Oil		16		7	%		13		+22	%		17		7	%		13		+30	%
Heavy Oil		17		7	%		17		+1	%		18		7	%		18		+0	%
Eagle Ford		28		11	%		34		- 17	%		26		10	%		40		- 36	%
Barnett Shale		1		0	%		1		- 9	%		1		0	%		1		- 16	%
Other		10		4	%		10		+0	%		9		4	%		10		- 11	%
Retained assets		153		62	%		130		+17	%		147		59	%		135		+9	%
Divested assets		—		0	%		3		- 99	%		—		0	%		2		- 100	%
Total Oil		153		62	%		133		+15	%		147		59	%		137		+7	%
Bitumen		92		38	%		105		- 12	%		101		41	%		112		- 10	%
Total Oil and bitumen		245		100	%		238		+3	%		248		100	%		249		- 1	%
Gas (MMcf/d)
STACK		352		31	%		298		+18	%		348		30	%		293		+19	%
Delaware Basin		100		9	%		94		+6	%		98		8	%		91		+7	%
Rockies Oil		18		1	%		17		+6	%		18		2	%		16		+14	%
Heavy Oil		12		1	%		14		- 13	%		12		1	%		18		- 34	%
Eagle Ford		74		7	%		92		- 19	%		69		6	%		103		- 33	%
Barnett Shale		460		41	%		496		- 7	%		465		40	%		497		- 6	%
Other		9		1	%		13		- 32	%		9		1	%		12		- 23	%
Retained assets		1,025		91	%		1,024		+0	%		1,019		88	%		1,030		- 1	%
Divested assets		103		9	%		184		- 44	%		133		12	%		188		- 29	%
Total		1,128		100	%		1,208		- 7	%		1,152		100	%		1,218		- 5	%
NGLs (MBbls/d)
STACK		38		35	%		31		+25	%		38		37	%		28		+32	%
Delaware Basin		16		14	%		10		+65	%		14		13	%		10		+43	%
Rockies Oil		2		2	%		1		+104	%		2		2	%		1		+44	%
Eagle Ford		13		12	%		10		+26	%		10		9	%		13		- 24	%
Barnett Shale		34		31	%		35		- 2	%		32		32	%		35		- 9	%
Other		2		2	%		3		- 36	%		2		2	%		2		- 12	%
Retained assets		105		96	%		90		+17	%		98		95	%		89		+11	%
Divested assets		4		4	%		7		- 44	%		5		5	%		8		- 34	%
Total		109		100	%		97		+12	%		103		100	%		97		+6	%
Combined (MBoe/d)
STACK		132		25	%		105		+26	%		131		24	%		100		+31	%
Delaware Basin		79		15	%		55		+42	%		71		13	%		54		+30	%
Rockies Oil		21		4	%		17		+19	%		22		4	%		17		+28	%
Heavy Oil		111		20	%		124		- 11	%		121		22	%		133		- 9	%
Eagle Ford		54		10	%		60		- 10	%		48		9	%		70		- 32	%
Barnett Shale		111		20	%		118		- 7	%		110		20	%		119		- 8	%
Other		12		2	%		16		- 24	%		13		3	%		15		- 14	%
Retained assets		520		96	%		495		+5	%		516		95	%		508		+2	%
Divested assets		21		4	%		41		- 47	%		27		5	%		42		- 36	%
Total		541		100	%		536		+1	%		543		100	%		550		- 1	%

Focused development activities in the STACK, Delaware Basin and Rockies resulted in an approximate 30% increase in production compared to the three and six months ended 2017. This strong performance led to the overall growth in our retained assets as compared to 2017. Production increases from our capital focused assets were partially offset by production decreases related to natural production declines in the Barnett Shale, operational issues at Jackfish as well as volumes associated with divested assets.

	Three Months Ended June 30,											Six Months Ended June 30,
	2018			Realization		2017			Change			2018			Realization		2017			Change
Oil and bitumen (per Bbl)
WTI index	$	67.83				$	48.32			+40	%	$	65.38				$	50.16			+30	%
Access Western Blend index	$	45.56				$	35.23			+29	%	$	40.50				$	35.20			+15	%
U.S.	$	65.41			96%	$	46.65			+40	%	$	63.71			97%	$	48.18			+32	%
Canada	$	31.70			47%	$	29.05			+9	%	$	25.24			39%	$	27.60			- 9	%
Realized price, unhedged	$	50.43			74%	$	37.63			+34	%	$	45.25			69%	$	37.48			+21	%
Cash settlements	$	(5.80	)			$	0.29					$	(2.93	)			$	0.39
Realized price, with hedges	$	44.63			66%	$	37.92			+18	%	$	42.32			65%	$	37.87			+12	%
Gas (per Mcf)
Henry Hub index	$	2.80				$	3.19			- 12	%	$	2.90				$	3.25			- 10	%
Realized price, unhedged	$	2.01			72%	$	2.50			- 20	%	$	2.21			76%	$	2.59			- 15	%
Cash settlements	$	0.13				$	0.04					$	0.16				$	—
Realized price, with hedges	$	2.14			77%	$	2.54			- 16	%	$	2.37			82%	$	2.59			- 9	%
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	28.05				$	21.78			+29	%	$	26.97				$	22.86			+18	%
Realized price, unhedged	$	24.10			86%	$	13.26			+82	%	$	23.38			87%	$	14.36			+63	%
Cash settlements	$	(1.66	)			$	(0.03	)				$	(1.13	)			$	(0.02	)
Realized price, with hedges	$	22.44			80%	$	13.23			+70	%	$	22.25			82%	$	14.34			+55	%
Combined (per Boe)
U.S.	$	31.97				$	23.58			+36	%	$	31.20				$	24.72			+26	%
Canada	$	31.17				$	28.50			+9	%	$	24.84				$	27.03			- 8	%
Realized price, unhedged	$	31.81				$	24.72			+29	%	$	29.79				$	25.28			+18	%
Cash settlements	$	(2.68	)			$	0.22					$	(1.23	)			$	0.19
Total	$	29.13				$	24.94			+17	%	$	28.56				$	25.47			+12	%

As further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $65 million and $127 million, respectively, during the three months and six months ended 2018 with no impact to net earnings.

The following table presents the major changes in cash and cash equivalents for the six months ended June 30, 2018 and 2017.

Net cash provided by operating activities decreased 24% as compared to the first six months of 2017.

The three months and six months ended June 30, 2018 operating cash flows included a realized foreign exchange loss of $244 million relating to foreign currency denominated intercompany loan activity as described in Note 7in “Part I. Financial Information – Item 1. Financial Statements” in this report. There was an offset due to the effect of exchange rate and other line in the above table, resulting in no impact to the net change in cash, cash equivalents and restricted cash.

~~During~~Net cash provided by operating activities decreased 24% as compared to the first ~~nine~~six months of ~~2017,~~2017.

The three months and six months ended June 30, 2018 operating cash flows included a realized foreign exchange loss of $244 million relating to foreign currency denominated intercompany loan activity 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 assetsdescribed 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.~~

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

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

~~Capital expenditures consist of amounts related~~no impact 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 paidnet change in cash, ~~at the closings with the remainder funded with equity consideration~~cash equivalents and ~~debt. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.~~restricted cash.

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.

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.

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.~~

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

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.

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.

Net cash provided by operating activities decreased 24% as compared to the first six months of 2017.

During the first six months of 2018, we sold non-core U.S. assets, including certain Barnett Shale assets, for $607 million. For additional information, please see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report. During the first six months of 2017, we sold non-core U.S. assets for $107 million.

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

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

During the first six months of 2018, our debt decreased approximately $800 million due to completed tender offers of certain long-term debt. In conjunction with the tender offers, we recognized a $312 million loss on the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see Note 15 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The following table summarizes our common stock dividends during the first six months of 2018 and 2017. In the second quarter of 2018, we increased the quarterly dividend to $0.08 per share.

In March 2018, we announced a share repurchase program to buy up to $1.0 billion of shares of common stock. In June 2018, in conjunction with the announcement of the divestiture of our investment in EnLink and the General Partner, we announced the expansion of the authorized share repurchase by an additional $3.0 billion, bringing the total to $4.0 billion. The share repurchase program expires December 31, 2019. Including unsettled shares, we repurchased 13.7 million shares of common stock for $521 million, or $38.01 per share, under this program through June 30, 2018.

Cash flows from discontinued operations relate to operating activities of EnLink and the General Partner. EnLink’s operating cash flow from the first six months of 2018 has increased $102 million from the first six months of 2017 as a result of its continued development activities.

Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. During the first six months of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million, resulting in lower net investing cash outflows as compared to the first six months of 2018.

Devon received $134 million and $133 million in distributions from EnLink and the General Partner during the first six months of 2018 and 2017, respectively. During the first six months of 2017, EnLink issued and sold 4 million common units and generated $72 million in net proceeds, through its “at the market” programs.

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. Additionally, the sale of our aggregate ownership interest in EnLink and the General Partner significantly increased our liquidity in the third quarter and will fund our remaining share repurchase program. We estimate the combination of these sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments, share repurchases and other contractual commitments as discussed in this section.

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.

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~~June 30, ~~2017,~~2018, see Note 34 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

To further focus our resource-rich portfolio, we are targeting $5 billion of asset divestiture proceeds. As noted below, we made significant progress to achieving this goal during the first six months of 2018.

In May ~~2017,~~2018, we ~~announced~~completed the sale of our Johnson County asset in the southern part of the Barnett Shale position for $553 million ($481 million after customary purchase price adjustments).

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

In June 2018, we entered into an agreement to sell our aggregate ownership interests in EnLink and the General Partner for approximately $3.1 billion. This transaction closed on July 18, 2018.

Overall, the transactions noted above, combined with other previously disclosed asset sales, generated approximately $4.2 billion of total divestiture proceeds. We are also marketing approximately $1 billion of ~~upstream assets. These~~additional non-core assets ~~identified for monetization include select portions of~~across our U.S. portfolio as we progress toward 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. The most significant asset remaining 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.$5 billion target.

~~Excluding EnLink,~~The following table below presents our ~~2017~~expected 2018 capital ~~expenditures are expected to range from $2.4 billion to $2.5 billion, including $2.0 billion to $2.1 billion for our exploration and development capital program. Our capital expenditures excluding EnLink were $1.7 billion in the first nine months of 2017 and are forecasted to range from $0.7 billion to $0.8 billion in the fourth quarter of 2017.~~expenditures.

We have a $3.0 billion Senior Credit Facility. As of ~~September~~June 30, ~~2017,~~2018, we had approximately $2.9 billion available under this facility, net of ~~$59~~$51 million in outstanding letters of credit, and were in compliance with the facility’s financial covenant. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At ~~September~~June 30, ~~2017,~~2018, there were no borrowings under our commercial paper program.

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.

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items, including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and near-term and long-term production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. ~~In March 2017,~~Our credit rating from Fitch ~~Ratings affirmed our~~is BBB+ with a stable outlook. 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 outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

During March 2018, our Board of Directors authorized a $1.0 billion share repurchase program of our ~~or EnLink’s contractual debt obligations that would accelerate scheduled maturities should a debt rating fall below a specified level. However, these downgrades could adversely impact~~common stock. In June 2018, in conjunction with the announcement of the divestiture of our ~~and EnLink’s interest rate on any credit facility borrowings~~investment in EnLink and the ~~ability~~General Partner, we announced the expansion of the authorized share repurchase by an additional $3.0 billion, bringing the total to ~~economically access debt markets in~~$4.0 billion. The share repurchase program expires December 31, 2019. Through July 27, 2018, we had repurchased 23.2 million common shares for $942 million, or $40.65 per share. We expect to complete the ~~future.~~$4 billion share repurchase program by the first half of 2019.

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

Absent unexpected events and ~~reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all~~unexpected effects of the ~~deferred tax assets will not be realized. At September 30, 2017, we continued to have~~Tax Reform Legislation, Devon expects a ~~100% valuation allowance against the U.S. deferred tax assets that largely resulted from prior year cumulative financial losses~~positive impact on its future after-tax earnings, primarily due to ~~full cost impairments. Further, we continue to record a partial valuation allowance against certain Canadian deferred~~the lower federal statutory tax ~~assets.~~

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of other pending matters.rate.

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of ~~2017~~2018 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 and other items that are typically excluded by securities analysts in their published estimates of our financial results. Additionally, we’ve presented our discontinued operations associated with the sale of our aggregate interests in EnLink and the General Partner, separately, to show our results on a go-forward basis. For more information on the results of operations for EnLink and the General Partner, see Note 19 in “Part I. Financial Information – Item 1. Financial Statements”. 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 ~~changes in derivatives and financial instrument fair values and foreign currency, gains and losses on~~ asset ~~sales,~~ dispositions, noncash asset impairments ~~gains~~(including noncash unproved asset impairments), deferred tax asset valuation allowance, 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~~fair value changes in ~~derivatives and~~derivative financial ~~instrument fair values~~instruments 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~~2018 workforce reduction and ~~deferred tax asset valuation allowance.~~ settlements relating to minimum volume contract commitments.

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

Below are reconciliations of our core earnings ~~(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,												Three Months Ended June 30,													Six Months Ended June 30,
	Before tax			After tax			After Noncontrolling Interests			Per Share			Before tax			After tax			After Noncontrolling Interests			Per Share			Before tax			After tax			After Noncontrolling Interests				Per Diluted Share			Before tax			After tax			After Noncontrolling Interests			Per Diluted Share
2018
Continuing Operations
Loss attributable to Devon (GAAP)																									$	(481	)	$	(474	)	$	(474	)		$	(0.92	)	$	(726	)	$	(685	)	$	(685	)	$	(1.33	)
Adjustments:
Asset dispositions																										23			18			18				0.03			11			9			9			0.02
Asset and exploration impairments																										207			159			159				0.31			217			166			166			0.32
Deferred tax asset valuation allowance																										—			73			73				0.14			—			79			79			0.15
Early retirement of debt																										—			—			—				—			312			240			240			0.46
Fair value changes in financial instruments and foreign currency																										376			291			291				0.56			437			351			351			0.68
Restructuring and transaction costs																										94			72			72				0.14			94			72			72			0.14
Core earnings attributable to Devon (Non-GAAP)																									$	219		$	139		$	139			$	0.26		$	345		$	232		$	232		$	0.44
Discontinued Operations
Earnings attributable to Devon (GAAP)																									$	149		$	139		$	49			$	0.09		$	213		$	197		$	63		$	0.13
Adjustments:
Fair value changes and minimum volume commitment settlement																										(36	)		(30	)		(11	)	`		(0.01	)		(34	)		(28	)		(10	)		(0.03	)
Core earnings attributable to Devon (Non-GAAP)																									$	113		$	109		$	38			$	0.08		$	179		$	169		$	53		$	0.10
Total
Loss attributable to Devon (GAAP)																									$	(332	)	$	(335	)	$	(425	)		$	(0.83	)	$	(513	)	$	(488	)	$	(622	)	$	(1.20	)
Adjustments:
Continuing Operations																										700			613			613				1.18			1,071			917			917			1.77
Discontinued Operations																										(36	)		(30	)		(11	)			(0.01	)		(34	)		(28	)		(10	)		(0.03	)
Core earnings attributable to Devon (Non-GAAP)																									$	332		$	248		$	177			$	0.34		$	524		$	401		$	285		$	0.54
	(Millions, except per share amounts)
2017
Continuing Operations
Earnings attributable to Devon (GAAP)	$	272		$	247		$	228		$	0.43		$	1,328		$	1,277		$	1,218		$	2.31		$	207		$	212		$	212			$	0.40		$	520		$	520		$	520		$	0.99
Adjustments:
Asset dispositions																										(22	)		(13	)		(13	)			(0.03	)		(30	)		(19	)		(19	)		(0.04	)
Asset and exploration impairments																										21			13			13				0.02			62			39			39			0.08
Deferred tax asset valuation allowance																										—			(54	)		(54	)			(0.10	)		—			(155	)		(155	)		(0.30	)
Fair value changes in financial instruments and foreign currency		106			40			39			0.08			(292	)		(233	)		(232	)		(0.44	)		(144	)		(109	)		(109	)			(0.20	)		(389	)		(266	)		(266	)		(0.51	)
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		$	62		$	49		$	49			$	0.09		$	163		$	119		$	119		$	0.22
2016
Earnings (loss) attributable to Devon (GAAP)	$	1,178		$	1,007		$	993		$	1.89		$	(4,252	)	$	(4,024	)	$	(3,633	)	$	(7.22	)
Discontinued Operations
Earnings attributable to Devon (GAAP)																									$	37		$	33		$	7			$	0.01		$	49		$	42		$	2		$	0.00
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
Asset dispositions, impairments, fair value changes and early retirement of debt																										(17	)		(13	)		(8	)		$	(0.01	)		(11	)		(8	)		(5	)	$	0.00
Core earnings (loss) attributable to Devon (Non-GAAP)	$	209		$	61		$	47		$	0.09		$	(201	)	$	(137	)	$	(169	)	$	(0.34	)	$	20		$	20		$	(1	)		$	0.00		$	38		$	34		$	(3	)	$	0.00
Total
Earnings attributable to Devon (GAAP)																									$	244		$	245		$	219			$	0.41		$	569		$	562		$	522		$	0.99
Adjustments:
Continuing Operations																										(145	)		(163	)		(163	)			(0.31	)		(357	)		(401	)		(401	)		(0.77	)
Discontinued Operations																										(17	)		(13	)		(8	)			(0.01	)		(11	)		(8	)		(5	)		0.00
Core earnings attributable to Devon (Non-GAAP)																									$	82		$	69		$	48			$	0.09		$	201		$	153		$	116		$	0.22

As of ~~September~~June 30, ~~2017,~~2018, we have commodity derivatives that pertain to a portion of our production for the last ~~three~~six months of ~~2017,~~2018, as well as ~~2018~~2019 and ~~2019.~~2020. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 34 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At ~~September~~June 30, ~~2017,~~2018, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net ~~asset~~ positions by approximately ~~$170~~$522 million.

As of ~~September~~June 30, ~~2017,~~2018, we had total debt of ~~$10.4~~$6.1 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%~~5.4%.

As of ~~September~~June 30, ~~2017,~~2018, we had an open interest rate swap ~~positions~~position that ~~are~~is presented in Note 34 in “Part I. Financial Information – Item 1. Financial Statements” in this report. The fair ~~values~~value of our interest rate ~~swaps are~~swap is 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~~June 30, ~~2017.~~2018.

Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our ~~September~~June 30, ~~2017~~2018 balance sheet.

~~Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, certain of our subsidiaries hold Canadian-dollar cash and engage~~Devon engages in intercompany ~~loans~~loan activity between subsidiaries with ~~Canadian subsidiaries that are based in Canadian dollars.~~different functional currencies. The value of ~~the Canadian-dollar cash and~~these foreign currency denominated intercompany loans increases or decreases from the remeasurement into the subsidiaries’ functional currency. Based on the amount of the ~~cash and~~intercompany loans ~~into~~as of June 30, 2018, a 10% change in the ~~U.S. dollar functional currency.~~foreign currency exchange rates would not have materially impacted our balance sheet.

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~~June 30, ~~2017~~2018 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

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

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

Please see our ~~2016~~2017 Annual Report on Form 10-K for additional ~~information regarding certain environmental matters involving the Company.~~information.

The following table provides information regarding purchases of our common stock that were made by us during the ~~third~~second quarter of ~~2017.~~

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~~9,800 shares of our common stock in the ~~third~~second quarter of ~~2017,~~2018, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Devon Plan through open-market purchases.

Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In the ~~third~~second quarter of ~~2017,~~2018, there were ~~approximately 4,200~~no shares purchased by Canadian employees.

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

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

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

Part I. Financial Information
Item 1.	Financial Statements	6
	Consolidated Comprehensive Statements of Earnings	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Equity	9
	Notes to Consolidated Financial Statements	10
	Note 1 – Summary of Significant Accounting Policies	10
	Note 2 – Revenue Recognition	11
	Note 3 – Divestitures	14
	Note 4 – Derivative Financial Instruments	14
	Note 5 – Share-Based Compensation	17
	Note 6 – Asset Impairments	18
	Note 7 – Restructuring and Transaction Costs and Other Expenses	18
	Note 8 – Income Taxes	19
	Note 9 – Net Earnings (Loss) Per Share From Continuing Operations	20
	Note 10 – Other Comprehensive Earnings	20
	Note 11 – Supplemental Information to Statements of Cash Flows	21
	Note 12 – Accounts Receivable	21
	Note 13 – Property, Plant and Equipment	21
	Note 14 – Other Current Liabilities	22
	Note 15 – Debt and Related Expenses	22
	Note 16 – Asset Retirement Obligations	23
	Note 17 – Retirement Plans	23
	Note 18 – Stockholders’ Equity	24
	Note 19 – Discontinued Operations	24
	Note 20 – Commitments and Contingencies	25
	Note 21 – Fair Value Measurements	26
	Note 22 – Segment Information	27
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
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

	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

	Price Swaps				Price Collars						Price Swaps				Price Collars
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Price ($/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
Q3-Q4 2018												89,300	$	57.96		100,200	$	52.23	$	62.83
Q1-Q4 2019		1,356	$	49.79		2,096	$	44.10	$	54.10		50,130	$	58.95		65,790	$	52.60	$	62.60

	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	)


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

	Three Months Ended June 30, 2018								Six Months Ended June 30, 2018
	Under ASC 606			Under ASC 605			Increase/ (Decrease)		Under ASC 606			Under ASC 605			Increase/ (Decrease)
Upstream revenues	$	1,069		$	1,004		$	65	$	2,388		$	2,261		$	127
Marketing revenues		1,180			1,180			—		2,059			2,059			—
Total impacted revenues	$	2,249		$	2,184		$	65	$	4,447		$	4,320		$	127

Production expenses	$	572		$	507		$	65	$	1,115		$	988		$	127
Marketing expenses		1,160			1,160			—		2,033			2,033			—
Total impacted expenses	$	1,732		$	1,667		$	65	$	3,148		$	3,021		$	127

Loss from continuing operations before income taxes	$	(481	)	$	(481	)	$	—	$	(726	)	$	(726	)	$	—

	Oil Basis Swaps						Oil Basis Collars
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)			Volume (Bbls/d)		Weighted Average Floor Differential to WTI ($/Bbl)			Weighted Average Ceiling Differential to WTI ($/Bbl)
Q3-Q4 2018	Midland Sweet		23,000	$	(1.02	)		—	$	—		$	—
Q3-Q4 2018	Argus LLS		12,000	$	3.95			—	$	—		$	—
Q3-Q4 2018	Argus MEH		15,832	$	2.82			—	$	—		$	—
Q3-Q4 2018	NYMEX Roll		19,989	$	0.60			—	$	—		$	—
Q3-Q4 2018	Western Canadian Select		64,859	$	(14.91	)		1,663	$	(15.50	)	$	(13.93	)
Q1-Q4 2019	Midland Sweet		28,000	$	(0.46	)		—	$	—		$	—
Q1-Q4 2019	Argus LLS		1,000	$	4.60			—	$	—		$	—
Q1-Q4 2019	Argus MEH		16,000	$	2.84			—	$	—		$	—
Q1-Q4 2019	NYMEX Roll		22,000	$	0.53			—	$	—		$	—
Q1-Q4 2020	NYMEX Roll		22,000	$	0.32			—	$	—		$	—

	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q3-Q4 2018	Panhandle Eastern Pipe Line		120,000	$	(0.51	)
Q3-Q4 2018	El Paso Natural Gas		100,000	$	(1.25	)
Q3-Q4 2018	Houston Ship Channel		115,000	$	0.01
Q3-Q4 2018	Transco Zone 4		15,000	$	(0.03	)
Q1-Q4 2019	Panhandle Eastern Pipe Line		54,548	$	(0.78	)
Q1-Q4 2019	El Paso Natural Gas		110,000	$	(1.50	)
Q1-Q4 2019	Houston Ship Channel		92,500	$	(0.01	)
Q1-Q4 2019	Transco Zone 4		7,397	$	(0.03	)

~~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~~

		Price Swaps
Period	Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q3-Q4 2018	Ethane		6,000	$	11.73
Q3-Q4 2018	Natural Gasoline		6,500	$	56.13
Q3-Q4 2018	Normal Butane		7,000	$	38.69
Q3-Q4 2018	Propane		12,000	$	33.72
Q1-Q4 2019	Ethane		1,000	$	11.55
Q1-Q4 2019	Natural Gasoline		4,500	$	55.93
Q1-Q4 2019	Normal Butane		4,000	$	33.69
Q1-Q4 2019	Propane		8,500	$	30.01

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	)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Commodity derivatives:
Upstream revenues	$	(497	)	$	126		$	(538	)	$	358
Marketing revenues		(1	)		2			(1	)		3
Interest rate derivatives:
Other expenses		19			(20	)		65			(15	)
Net gains (losses) recognized	$	(479	)	$	108		$	(474	)	$	346

	Restricted Stock					Performance-Based					Performance							Restricted Stock					Performance-Based					Performance
	Awards and Units					Restricted Stock Awards					Share Units							Awards and Units					Restricted Stock Awards					Share Units
	Awards and Units			Weighted Average Grant-Date Fair Value		Awards			Weighted Average Grant-Date Fair Value		Units					Weighted Average Grant-Date Fair Value		Awards and Units			Weighted Average Grant-Date Fair Value		Awards			Weighted Average Grant-Date Fair Value		Units					Weighted Average Grant-Date Fair Value
	(Thousands, except fair value data)																	(Thousands, except fair value data)
Unvested at 12/31/16		6,407		$	34.40		585		$	37.60		2,604				$	46.66
Unvested at 12/31/17																			6,328		$	36.81		575		$	38.92		2,758				$	41.21
Granted		2,691		$	44.87		223		$	44.85		1,010				$	52.58		3,501		$	35.89		—		$	—		845				$	37.40
Vested		(2,321	)	$	39.51		(233	)	$	41.27		(832	)			$	78.19		(2,843	)	$	38.83		(231	)	$	43.05		(571	)			$	84.22
Forfeited		(252	)	$	36.06		—		$	—		(24	)			$	40.70		(551	)	$	35.54		—		$	—		(91	)			$	33.37
Unvested at 9/30/17		6,525		$	36.83		575		$	38.92		2,758		⁽¹	⁾	$	41.21
Unvested at 6/30/18																			6,435		$	35.52		344		$	36.14		2,941		⁽¹	⁾	$	30.25

	2017					2018
Grant-date fair value	$	51.05	—	$	53.12		$36.23	—	$	37.88
Risk-free interest rate	1.50%					2.28%
Volatility factor	45.8%					45.8%
Contractual term (years)	2.89					2.89

	General Partner				EnLink						Performance-Based
	Restricted		Performance		Restricted		Performance		Restricted Stock		Restricted Stock		Performance
	Incentive Units		Units		Incentive Units		Units		Awards and Units		Awards		Share Units
Unrecognized compensation cost (millions)	$	14	$	6	$	15	$	6
Unrecognized compensation cost									$	161	$	2	$	39
Weighted average period for recognition (years)		1.8		2.0		1.7		1.9		2.7		1.4		2.0

	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

	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

	June 30, 2018			December 31, 2017
8.25% due July 1, 2018	$	20		$	20
2.25% due December 15, 2018		95			95
6.30% due January 15, 2019		162			162
4.00% due July 15, 2021		500			500
3.25% due May 15, 2022		1,000			1,000
5.85% due December 15, 2025		485			485
7.50% due September 15, 2027		73			73
7.875% due September 30, 2031 ⁽¹⁾		675			1,059
7.95% due April 15, 2032 ⁽¹⁾		366			789
5.60% due July 15, 2041		1,250			1,250
4.75% due May 15, 2042		750			750
5.00% due June 15, 2045		750			750
Net discount on debentures and notes		(25	)		(30	)
Debt issuance costs		(34	)		(39	)
Total debt		6,067			6,864
Less amount classified as short-term debt⁽²⁾		277			115
Total long-term debt	$	5,790		$	6,749

	Pension Benefits												Postretirement Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended				Nine Months Ended						Pension Benefits												Postretirement Benefits
	September 30,						September 30,						September 30,				September 30,						Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	2017			2016			2017			2016			2017		2016		2017			2016			June 30,						June 30,						June 30,						June 30,
	(Millions)																						2018			2017			2018			2017			2018			2017			2018			2017
Service cost	$	4		$	3		$	12		$	12		$	—	$	—	$	—		$	—		$	3		$	4		$	6		$	8		$	—		$	—		$	—		$	—
Interest cost		11			9			32			32			—		—		—			—			10			11			20			21			—			—			—			—
Expected return on plan assets		(14	)		(14	)		(41	)		(40	)		—		—		—			—			(14	)		(14	)		(28	)		(27	)		—			—			—			—
Amortization of prior service cost ⁽¹⁾		—			1			1			2			—		—		(1	)		(1	)		1			—			1			1			(1	)		(1	)		(1	)		(1	)
Net actuarial loss ⁽¹⁾		5			6			14			19			—		—		—			—			3			5			7			9			—			—			—			—
Net periodic benefit cost ⁽²⁾	$	6		$	5		$	18		$	25		$	—	$	—	$	(1	)	$	(1	)	$	3		$	6		$	6		$	12		$	(1	)	$	(1	)	$	(1	)	$	(1	)

	Amounts		Rate		Amounts		Rate Per Share
	(Millions)		(Per Share)
Quarter Ended 2018:
First quarter 2018					$	32	$	0.06
Second quarter 2018						42	$	0.08
Total year-to-date					$	74
Quarter Ended 2017:
First quarter 2017	$	32	$	0.06	$	32	$	0.06
Second quarter 2017		33	$	0.06		33	$	0.06
Third quarter 2017		30	$	0.06
Total year-to-date	$	95			$	65
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

	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

	Q3 2018 - Q4 2018					Full Year 2018
	(Billions)
Exploration and production	$	0.9	—	$	1.1	$	2.2	—	$	2.4
Total	$	1.0	—	$	1.3	$	2.3	—	$	2.6

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

Exhibit Number		Description


2.1		Purchase Agreement, dated June 5, 2018, by and among Devon Gas Services, L.P., Southwestern Gas Pipeline, L.L.C., EnLink Midstream Manager, LLC, GIP III Stetson I, L.P., GIP III Stetson II, L.P. and, solely for certain purposes described therein, Devon Energy Corporation (incorporated by reference to Exhibit 2.1 to Devon Energy Corporation’s Current Report on Form 8-K filed on June 7, 2018).

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

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

				DEVON ENERGY CORPORATION

Date: ~~November~~August 1, ~~2017~~2018				/s/ Jeremy D. Humphers
				Jeremy D. Humphers
				Senior Vice President and Chief Accounting Officer