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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
(Mark One)
☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the quarterly period ended September 30, 2018
or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
Commission File Number 001-32318

DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Delaware	 	73-1567067	
(State or other jurisdiction of
incorporation or organization)	 	(I.R.S. Employer
identification No.)	
 	 	
333 West Sheridan Avenue, Oklahoma City, Oklahoma	 	73102-5015	
(Address of principal executive offices)	 	(Zip code)	
Registrant’s telephone number, including area code: (405) 235-3611
Former name, address and former fiscal year, if changed from last report: Not applicable
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   ☑     No   ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes   ☑     No   ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	 	☑	Accelerated filer	 	☐	Non-accelerated filer	 	☐	
Smaller reporting company	 	☐	Emerging growth company	 	☐	 	 	 	
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes   ☐     No   ☑
On October 17, 2018, 468.2 million shares of common stock were outstanding.

Table of Contents
DEVON ENERGY CORPORATION
FORM 10-Q
TABLE OF CONTENTS
 
Part I. Financial Information	 	
Item 1.	 	Financial Statements	6	
 	 	Consolidated Comprehensive Statements of Earnings	6	
 	 	Consolidated Statements of Cash Flows	7	
 	 	Consolidated Balance Sheets	8	
 	 	Consolidated Statements of Equity	9	
 	 	Notes to Consolidated Financial Statements	10	
 	 	Note 1 – Summary of Significant Accounting Policies	10	
 	 	Note 2 – Revenue Recognition	12	
 	 	Note 3 – Divestitures	14	
 	 	Note 4 – Derivative Financial Instruments	15	
 	 	Note 5 – Share-Based Compensation	18	
 	 	Note 6 – Asset Impairments	19	
 	 	Note 7 – Restructuring and Transaction Costs	19	
 	 	Note 8 – Other Expenses	19	
 	 	Note 9 – Income Taxes	20	
 	 	Note 10 – Net Earnings (Loss) Per Share From Continuing Operations	21	
 	 	Note 11 – Other Comprehensive Earnings	21	
 	 	Note 12 – Supplemental Information to Statements of Cash Flows	22	
 	 	Note 13 – Accounts Receivable	22	
 	 	Note 14 – Property, Plant and Equipment	22	
 	 	Note 15 – Other Current Liabilities	23	
 	 	Note 16 – Debt and Related Expenses	23	
 	 	Note 17 – Asset Retirement Obligations	24	
 	 	Note 18 – Retirement Plans	24	
 	 	Note 19 – Stockholders’ Equity	25	
 	 	Note 20 – Discontinued Operations	26	
 	 	Note 21 – Commitments and Contingencies	28	
 	 	Note 22 – Fair Value Measurements	29	
 	 	Note 23 – Segment Information	29	
Item 2.	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31	
Item 3.	 	Quantitative and Qualitative Disclosures About Market Risk	46	
Item 4.	 	Controls and Procedures	46	
 	 	 	 	
Part II. Other Information	 	
Item 1.	 	Legal Proceedings	47	
Item 1A.	 	Risk Factors	47	
Item 2.	 	Unregistered Sales of Equity Securities and Use of Proceeds	47	
Item 3.	 	Defaults Upon Senior Securities	47	
Item 4.	 	Mine Safety Disclosures	47	
Item 5.	 	Other Information	47	
Item 6.	 	Exhibits	48	
 	 	 	 	
Signatures	 	 	49	

 
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DEFINITIONS
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Quarterly Report on Form 10-Q:
“2012 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 24, 2012.
“2018 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 5, 2018.
“ASC” means Accounting Standards Codification.
“ASR” means an accelerated share-repurchase transaction with a financial institution to repurchase Devon’s common stock.
“ASU” means Accounting Standards Update.
“Bbl” or “Bbls” means barrel or barrels.
“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.
“Btu” means British thermal units, a measure of heating value.
“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.
“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.
“E&P” means exploration and production activities.
“EnLink” means EnLink Midstream Partners, LP, a master limited partnership.
“FASB” means Financial Accounting Standards Board.
“G&A” means general and administrative expenses.
“GAAP” means U.S. generally accepted accounting principles.
“General Partner” means EnLink Midstream, LLC, the indirect general partner of EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.
“Inside FERC” refers to the publication Inside FERC’s Gas Market Report .
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“MBbls” means thousand barrels.
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“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“M&M operations” means marketing revenues minus marketing expenses.
“N/M” means not meaningful.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPIS” means Oil Price Information Service.
“SEC” means United States Securities and Exchange Commission.
“Tax Reform Legislation” means Tax Cuts and Jobs Act.
“TSR” means total shareholder return.
“Upstream operations” means upstream revenues minus production expenses.
“U.S.” means United States of America.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/d” means per day.
“/MMBtu” means per MMBtu.
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2017 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to:
 	•	the volatility of oil, gas and NGL prices;	
 	•	uncertainties inherent in estimating oil, gas and NGL reserves;	
 	•	the extent to which we are successful in acquiring and discovering additional reserves;	
 	•	the uncertainties, costs and risks involved in oil and gas operations;	
 	•	regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;	
 	•	risks related to our hedging activities;	
 	•	counterparty credit risks;	
 	•	risks relating to our indebtedness;	
 	•	cyberattack risks;	
 	•	our limited control over third parties who operate some of our oil and gas properties;	
 	•	midstream capacity constraints and potential interruptions in production;	
 	•	the extent to which insurance covers any losses we may experience;	
 	•	competition for leases, materials, people and capital;	
 	•	our ability to successfully complete mergers, acquisitions and divestitures; and	
 	•	any of the other risks and uncertainties discussed in this report, our 2017 Annual Report on Form 10-K and our other filings with the SEC.	
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

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Part I.  Financial Information
Item 1.  Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
 
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
 	 	(Unaudited)	 	
Upstream revenues	 	$	1,332	 	 	$	1,101	 	 	$	3,720	 	 	$	3,974	 	
Marketing revenues	 	 	1,247	 	 	 	832	 	 	 	3,306	 	 	 	2,524	 	
Total revenues	 	 	2,579	 	 	 	1,933	 	 	 	7,026	 	 	 	6,498	 	
Production expenses	 	 	554	 	 	 	448	 	 	 	1,669	 	 	 	1,360	 	
Exploration expenses	 	 	32	 	 	 	57	 	 	 	133	 	 	 	209	 	
Marketing expenses	 	 	1,217	 	 	 	843	 	 	 	3,250	 	 	 	2,571	 	
Depreciation, depletion and amortization	 	 	416	 	 	 	370	 	 	 	1,235	 	 	 	1,139	 	
Asset impairments	 	 	2	 	 	 	—	 	 	 	156	 	 	 	—	 	
Asset dispositions	 	 	(6	)	 	 	(170	)	 	 	5	 	 	 	(200	)	
General and administrative expenses	 	 	147	 	 	 	170	 	 	 	499	 	 	 	546	 	
Financing costs, net	 	 	75	 	 	 	78	 	 	 	524	 	 	 	238	 	
Restructuring and transaction costs	 	 	11	 	 	 	—	 	 	 	105	 	 	 	—	 	
Other expenses	 	 	(31	)	 	 	(70	)	 	 	14	 	 	 	(92	)	
Total expenses	 	 	2,417	 	 	 	1,726	 	 	 	7,590	 	 	 	5,771	 	
Earnings (loss) from continuing operations before income taxes	 	 	162	 	 	 	207	 	 	 	(564	)	 	 	727	 	
Income tax expense (benefit)	 	 	(138	)	 	 	13	 	 	 	(179	)	 	 	13	 	
Net earnings (loss) from continuing operations	 	 	300	 	 	 	194	 	 	 	(385	)	 	 	714	 	
Net earnings from discontinued operations, net of income tax expense	 	 	2,263	 	 	 	18	 	 	 	2,460	 	 	 	60	 	
Net earnings	 	 	2,563	 	 	 	212	 	 	 	2,075	 	 	 	774	 	
Net earnings attributable to noncontrolling interests	 	 	26	 	 	 	19	 	 	 	160	 	 	 	59	 	
Net earnings attributable to Devon	 	$	2,537	 	 	$	193	 	 	$	1,915	 	 	$	715	 	
Basic net earnings (loss) per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings (loss) from continuing operations per share	 	$	0.61	 	 	$	0.37	 	 	$	(0.76	)	 	$	1.36	 	
Basic earnings from discontinued operations per share	 	 	4.56	 	 	 	—	 	 	 	4.50	 	 	 	—	 	
Basic net earnings per share	 	$	5.17	 	 	$	0.37	 	 	$	3.74	 	 	$	1.36	 	
Diluted net earnings (loss) per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted earnings (loss) from continuing operations per share	 	$	0.61	 	 	$	0.37	 	 	$	(0.76	)	 	$	1.35	 	
Diluted earnings from discontinued operations per share	 	 	4.53	 	 	 	—	 	 	 	4.47	 	 	 	—	 	
Diluted net earnings per share	 	$	5.14	 	 	$	0.37	 	 	$	3.71	 	 	$	1.35	 	
Comprehensive earnings (loss):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	$	2,563	 	 	$	212	 	 	$	2,075	 	 	$	774	 	
Other comprehensive earnings (loss), net of tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign currency translation	 	 	35	 	 	 	42	 	 	 	(47	)	 	 	78	 	
Pension and postretirement plans	 	 	36	 	 	 	5	 	 	 	43	 	 	 	14	 	
Other comprehensive earnings (loss), net of tax	 	 	71	 	 	 	47	 	 	 	(4	)	 	 	92	 	
Comprehensive earnings	 	$	2,634	 	 	$	259	 	 	$	2,071	 	 	$	866	 	
Comprehensive earnings attributable to
   noncontrolling interests	 	 	26	 	 	 	19	 	 	 	160	 	 	 	59	 	
Comprehensive earnings attributable to Devon	 	$	2,608	 	 	$	240	 	 	$	1,911	 	 	$	807	 	
 
See accompanying notes to consolidated financial statements
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
 	 	(Unaudited)	 	
Cash flows from operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	$	2,563	 	 	$	212	 	 	$	2,075	 	 	$	774	 	
Adjustments to reconcile net earnings to net cash
   from operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings from discontinued operations, net of tax	 	 	(2,263	)	 	 	(18	)	 	 	(2,460	)	 	 	(60	)	
Depreciation, depletion and amortization	 	 	416	 	 	 	370	 	 	 	1,235	 	 	 	1,139	 	
Asset impairments	 	 	2	 	 	 	—	 	 	 	156	 	 	 	—	 	
Leasehold impairments	 	 	15	 	 	 	16	 	 	 	76	 	 	 	80	 	
Accretion on discounted liabilities	 	 	15	 	 	 	15	 	 	 	46	 	 	 	47	 	
Total (gains) losses on commodity derivatives	 	 	276	 	 	 	144	 	 	 	814	 	 	 	(214	)	
Cash settlements on commodity derivatives	 	 	(91	)	 	 	24	 	 	 	(211	)	 	 	43	 	
(Gains) losses on asset dispositions	 	 	(6	)	 	 	(170	)	 	 	5	 	 	 	(200	)	
Deferred income tax benefit	 	 	(114	)	 	 	(25	)	 	 	(132	)	 	 	(57	)	
Share-based compensation	 	 	31	 	 	 	33	 	 	 	127	 	 	 	114	 	
Early retirement of debt	 	 	—	 	 	 	—	 	 	 	312	 	 	 	—	 	
Total (gains) losses on foreign exchange	 	 	(28	)	 	 	(74	)	 	 	53	 	 	 	(138	)	
Settlements of intercompany foreign denominated assets/liabilities	 	 	—	 	 	 	—	 	 	 	(243	)	 	 	10	 	
Other	 	 	42	 	 	 	(14	)	 	 	(8	)	 	 	(3	)	
Changes in assets and liabilities, net	 	 	(51	)	 	 	(12	)	 	 	(159	)	 	 	121	 	
Net cash from operating activities - continuing operations	 	 	807	 	 	 	501	 	 	 	1,686	 	 	 	1,656	 	
Cash flows from investing activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(598	)	 	 	(467	)	 	 	(1,851	)	 	 	(1,298	)	
Acquisitions of property and equipment	 	 	(19	)	 	 	(6	)	 	 	(35	)	 	 	(39	)	
Divestitures of property and equipment	 	 	89	 	 	 	280	 	 	 	696	 	 	 	387	 	
Net cash from investing activities - continuing operations	 	 	(528	)	 	 	(193	)	 	 	(1,190	)	 	 	(950	)	
Cash flows from financing activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Repayments of long-term debt principal	 	 	(21	)	 	 	—	 	 	 	(828	)	 	 	—	 	
Early retirement of debt	 	 	—	 	 	 	—	 	 	 	(304	)	 	 	—	 	
Repurchases of common stock	 	 	(1,698	)	 	 	—	 	 	 	(2,197	)	 	 	—	 	
Dividends paid on common stock	 	 	(38	)	 	 	(30	)	 	 	(112	)	 	 	(95	)	
Shares exchanged for tax withholdings	 	 	(3	)	 	 	(1	)	 	 	(47	)	 	 	(57	)	
Net cash from financing activities - continuing operations	 	 	(1,760	)	 	 	(31	)	 	 	(3,488	)	 	 	(152	)	
Effect of exchange rate changes on cash:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Settlements of intercompany foreign denominated assets/liabilities	 	 	—	 	 	 	—	 	 	 	243	 	 	 	(10	)	
Other	 	 	10	 	 	 	12	 	 	 	(21	)	 	 	22	 	
Total effect of exchange rate changes on cash - continuing operations	 	 	10	 	 	 	12	 	 	 	222	 	 	 	12	 	
Net change in cash, cash equivalents and restricted cash of continuing operations	 	 	(1,471	)	 	 	289	 	 	 	(2,770	)	 	 	566	 	
Cash flows from discontinued operations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	 	46	 	 	 	200	 	 	 	476	 	 	 	528	 	
Investing activities	 	 	2,950	 	 	 	(191	)	 	 	2,548	 	 	 	(475	)	
Financing activities	 	 	71	 	 	 	187	 	 	 	183	 	 	 	276	 	
Net change in cash, cash equivalents and restricted cash of discontinued operations	 	 	3,067	 	 	 	196	 	 	 	3,207	 	 	 	329	 	
Net change in cash, cash equivalents and restricted cash	 	 	1,596	 	 	 	485	 	 	 	437	 	 	 	895	 	
Cash, cash equivalents and restricted cash at beginning of period	 	 	1,525	 	 	 	2,369	 	 	 	2,684	 	 	 	1,959	 	
Cash, cash equivalents and restricted cash at end of period	 	$	3,121	 	 	$	2,854	 	 	$	3,121	 	 	$	2,854	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reconciliation of cash, cash equivalents and restricted cash:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	3,102	 	 	$	2,639	 	 	$	3,102	 	 	$	2,639	 	
Restricted cash included in other current assets	 	 	19	 	 	 	73	 	 	 	19	 	 	 	73	 	
Cash and cash equivalents included in current assets held for sale	 	 	—	 	 	 	142	 	 	 	—	 	 	 	142	 	
Total cash, cash equivalents and restricted cash	 	$	3,121	 	 	$	2,854	 	 	$	3,121	 	 	$	2,854	 	
 
See accompanying notes to consolidated financial statements
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
 	 	September 30, 2018	 	 	December 31, 2017	 	
 	 	(Unaudited)	 	 	 	 	 	
ASSETS	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	3,102	 	 	$	2,642	 	
Accounts receivable	 	 	1,226	 	 	 	989	 	
Current assets held for sale	 	 	—	 	 	 	760	 	
Other current assets	 	 	429	 	 	 	400	 	
Total current assets	 	 	4,757	 	 	 	4,791	 	
Oil and gas property and equipment, based on successful efforts
   accounting, net	 	 	13,056	 	 	 	13,318	 	
Other property and equipment, net	 	 	1,146	 	 	 	1,266	 	
Total property and equipment, net	 	 	14,202	 	 	 	14,584	 	
Goodwill	 	 	841	 	 	 	841	 	
Other long-term assets	 	 	372	 	 	 	296	 	
Long-term assets held for sale	 	 	—	 	 	 	9,729	 	
Total assets	 	$	20,172	 	 	$	30,241	 	
LIABILITIES AND EQUITY	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	
Accounts payable	 	$	777	 	 	$	633	 	
Revenues and royalties payable	 	 	947	 	 	 	748	 	
Short-term debt	 	 	257	 	 	 	115	 	
Current liabilities held for sale	 	 	—	 	 	 	991	 	
Other current liabilities	 	 	1,243	 	 	 	828	 	
Total current liabilities	 	 	3,224	 	 	 	3,315	 	
Long-term debt	 	 	5,791	 	 	 	6,749	 	
Asset retirement obligations	 	 	1,103	 	 	 	1,099	 	
Other long-term liabilities	 	 	613	 	 	 	549	 	
Long-term liabilities held for sale	 	 	—	 	 	 	3,936	 	
Deferred income taxes	 	 	543	 	 	 	489	 	
Equity:	 	 	 	 	 	 	 	 	
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued
   474 million and 525 million shares in 2018 and 2017, respectively	 	 	47	 	 	 	53	 	
Additional paid-in capital	 	 	5,217	 	 	 	7,333	 	
Retained earnings	 	 	2,505	 	 	 	702	 	
Accumulated other comprehensive earnings	 	 	1,164	 	 	 	1,166	 	
Treasury stock, at cost, 0.9 million shares in 2018	 	 	(35	)	 	 	—	 	
Total stockholders’ equity attributable to Devon	 	 	8,898	 	 	 	9,254	 	
Noncontrolling interests	 	 	—	 	 	 	4,850	 	
Total equity	 	 	8,898	 	 	 	14,104	 	
Total liabilities and equity	 	$	20,172	 	 	$	30,241	 	
 
See accompanying notes to consolidated financial statements

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
 
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Retained	 	 	Accumulated	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Additional	 	 	Earnings	 	 	Other	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Common Stock	 	 	Paid-In	 	 	(Accumulated	 	 	Comprehensive	 	 	Treasury	 	 	Noncontrolling	 	 	Total	 	
 	 	Shares	 	 	Amount	 	 	Capital	 	 	Deficit)	 	 	Earnings	 	 	Stock	 	 	Interests	 	 	Equity	 	
 	 	(Unaudited)	 	
Nine Months Ended September 30, 2018	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2017	 	 	525	 	 	$	53	 	 	$	7,333	 	 	$	702	 	 	$	1,166	 	 	$	—	 	 	$	4,850	 	 	$	14,104	 	
Net earnings	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,915	 	 	 	—	 	 	 	—	 	 	 	160	 	 	 	2,075	 	
Other comprehensive loss,
   net of tax	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(4)	 	 	 	—	 	 	 	—	 	 	 	(4)	 	
Restricted stock grants, net of
   cancellations	 	 	3	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Common stock repurchased	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(2,271	)	 	 	—	 	 	 	(2,271	)	
Common stock retired	 	 	(55	)	 	 	(6	)	 	 	(2,230	)	 	 	—	 	 	 	—	 	 	 	2,236	 	 	 	—	 	 	 	—	 	
Common stock dividends	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(112	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(112	)	
Share-based compensation	 	 	1	 	 	 	—	 	 	 	114	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	114	 	
Divestment of subsidiary equity investment	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	(4,863	)	 	 	(4,861	)	
Subsidiary equity transactions	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	72	 	 	 	72	 	
Distributions to noncontrolling
   interests	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(219	)	 	 	(219	)	
Balance as of September 30, 2018	 	 	474	 	 	$	47	 	 	$	5,217	 	 	$	2,505	 	 	$	1,164	 	 	$	(35	)	 	$	—	 	 	$	8,898	 	
Nine Months Ended September 30, 2017	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2016	 	 	523	 	 	$	52	 	 	$	7,237	 	 	$	(69	)	 	$	1,054	 	 	$	—	 	 	$	4,448	 	 	$	12,722	 	
Net earnings	 	 	—	 	 	 	—	 	 	 	—	 	 	 	715	 	 	 	—	 	 	 	—	 	 	 	59	 	 	 	774	 	
Other comprehensive earnings,
   net of tax	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	92	 	 	 	—	 	 	 	—	 	 	 	92	 	
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	 	 	$	7,302	 	 	$	551	 	 	$	1,146	 	 	$	—	 	 	$	4,805	 	 	$	13,857	 	

See accompanying notes to consolidated financial statements
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.	Summary of Significant Accounting Policies	
The accompanying unaudited interim financial statements and notes of Devon have been prepared pursuant to the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted. The accompanying unaudited interim financial statements and notes should be read in conjunction with the financial statements and notes included in Devon’s 2017 Annual Report on Form 10-K .
The accompanying unaudited interim financial statements in this report reflect all adjustments that are, in the opinion of management, necessary for a fair statement of Devon’s results of operations and cash flows for the three-month and nine-month periods ended September 30, 2018 and 2017 and Devon’s financial position as of September 30, 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 are 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.
Recently Adopted Accounting Standards
 
In January 2018, Devon adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) , using the modified retrospective method. See Note 2 for further discussion regarding Devon’s adoption of the revenue recognition standard.
 
In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU requires entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. As a result of the adoption of this ASU, consolidated statements of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively.
 
In January 2018 , Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon made changes to the statement of cash flows to include the required presentation and reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents retrospectively. Other than presentation, a doption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows.
Issued Accounting Standards Not Yet Adopted
The FASB issued ASU 2016-02,  Leases (Topic 842) . This ASU will supersede the lease requirements in Topic 840,  Leases . Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Short-term leases can continue being accounted for off balance sheet based on a policy election. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019. Early adoption is permitted, but Devon does not plan to early adopt. The guidance will be applied using a modified retrospective transition method at the beginning of the earliest period presented in the financial statements. Entities will be allowed to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted.
Devon plans to elect the practical expedients provided in the standard that allow entities to not reassess under the new standard our prior conclusions about lease identification and classification related to contracts that commenced prior to adoption and allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also plans to elect a policy to not recognize right-of-use assets and lease liabilities related to short-term leases.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Devon has determined its portfolio of leased assets and is reviewing all related contracts to determine the impact the adoption will have on its consolidated financial statements and related disclosures. Devon anticipates recognizing right-of-use assets and lease liabilities for certain commitments related to real estate, drilling rigs and other equipment related to the exploration and development of oil and gas. Devon has designed processes and controls and has implemented a technology solution needed to comply with the requirements of this ASU. The adoption will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities.
The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This ASU will expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company’s risk management activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This ASU is effective for annual and interim periods beginning January 1, 2019, with early adoption permitted in 2018. This ASU only applies to entities that elect hedge accounting, which Devon has not for derivative financial instruments. Devon continues to evaluate the provisions of this ASU and the impact it may have on its consolidated financial statements if hedge accounting were elected 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 January 1, 2019, including interim periods within those fiscal years and allows for early adoption in any interim period after issuance of the update. Devon is currently assessing the impact this ASU will have on its consolidated financial statements.
The FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement. This ASU will eliminate, add and modify certain disclosure requirements for fair value measurement. The ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the entire standard or only the provisions that eliminate or modify requirements. The ASU requires the additional disclosure requirements to be adopted using a prospective approach and all other amendments are required to be adopted using a retrospective approach . Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its disclosures in the notes to the consolidated financial statements.  
The FASB issued ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU will eliminate and add certain disclosure requirements for employers that sponsor defined benefit pension and/or other postretirement benefit plans. This ASU is effective for annual and interim periods beginning January 1, 2021, with early adoption permitted. The ASU is required to be adopted using a retrospective approach. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its disclosures in the notes to the consolidated financial statements.  
The FASB issued ASU 2018-15, Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40) : Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. This ASU will require a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a hosting arrangement that is a service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. This ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted. Entities have the option to adopt the ASU using either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of adoption. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements.
The SEC released Final Rule Release No. 33-10532 , Disclosure Update and Simplification , which amends various SEC disclosure requirements determined to be redundant, duplicative, overlapping, outdated or superseded as part of the SEC’s ongoing disclosure effectiveness initiative. The rule is effective November 5, 2018. The rule amends numerous SEC rules, items and forms covering a diverse group of topics. As the changes are generally expected to reduce or eliminate disclosures, Devon is currently evaluating and assessing the impact it may have on its disclosures.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
2.	Revenue Recognition	
 
Impact of ASC 606 Adoption
 
In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.
 
The impact of adoption in the current period results is as follows:
 	 	Three Months Ended September 30, 2018	 	 	Nine Months Ended September 30, 2018	 	
 	 	Under ASC
606	 	 	Under ASC
605	 	 	Increase/
(Decrease)	 	 	Under ASC
606	 	 	Under ASC
605	 	 	Increase/
(Decrease)	 	
Upstream revenues	 	$	1,332	 	 	$	1,268	 	 	$	64	 	 	$	3,720	 	 	$	3,529	 	 	$	191	 	
Marketing revenues	 	 	1,247	 	 	 	1,247	 	 	 	—	 	 	 	3,306	 	 	 	3,306	 	 	 	—	 	
Total impacted revenues	 	$	2,579	 	 	$	2,515	 	 	$	64	 	 	$	7,026	 	 	$	6,835	 	 	$	191	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses	 	$	554	 	 	$	490	 	 	$	64	 	 	$	1,669	 	 	$	1,478	 	 	$	191	 	
Marketing expenses	 	 	1,217	 	 	 	1,217	 	 	 	—	 	 	 	3,250	 	 	 	3,250	 	 	 	—	 	
Total impacted expenses	 	$	1,771	 	 	$	1,707	 	 	$	64	 	 	$	4,919	 	 	$	4,728	 	 	$	191	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) from continuing
   operations before income taxes	 	$	162	 	 	$	162	 	 	$	—	 	 	$	(564	)	 	$	(564	)	 	$	—	 	
Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses.
Upstream Revenues
Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings.
Natural gas and NGL sales
Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statements of earnings.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings.
Oil sales
Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings.
Marketing Revenues
Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership.

Satisfaction of Performance Obligations and Revenue Recognitions
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.
Transaction Price Allocated to Remaining Performance Obligations
Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
 
Contract Balances
 
Cash received relating to future performance obligations are deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of September 30, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets under ASC 606.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Disaggregation of Revenue
 
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.

 	 	Three Months Ended September 30, 2018	 	 	Nine Months Ended September 30, 2018	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	 	U.S.	 	 	Canada	 	 	Total	 	
Oil	 	$	794	 	 	$	298	 	 	$	1,092	 	 	$	2,279	 	 	$	841	 	 	$	3,120	 	
Gas	 	 	210	 	 	 	—	 	 	 	210	 	 	 	672	 	 	 	—	 	 	 	672	 	
NGL	 	 	306	 	 	 	—	 	 	 	306	 	 	 	742	 	 	 	—	 	 	 	742	 	
Oil, gas and NGL revenues from
   contracts with customers	 	 	1,310	 	 	 	298	 	 	 	1,608	 	 	 	3,693	 	 	 	841	 	 	 	4,534	 	
Oil, gas and NGL derivatives	 	 	(376	)	 	 	100	 	 	 	(276	)	 	 	(976	)	 	 	162	 	 	 	(814	)	
Upstream revenues	 	 	934	 	 	 	398	 	 	 	1,332	 	 	 	2,717	 	 	 	1,003	 	 	 	3,720	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil	 	 	750	 	 	 	25	 	 	 	775	 	 	 	2,047	 	 	 	66	 	 	 	2,113	 	
Gas	 	 	191	 	 	 	—	 	 	 	191	 	 	 	506	 	 	 	—	 	 	 	506	 	
NGL	 	 	281	 	 	 	—	 	 	 	281	 	 	 	687	 	 	 	—	 	 	 	687	 	
Total marketing revenues from
   contracts with customers	 	 	1,222	 	 	 	25	 	 	 	1,247	 	 	 	3,240	 	 	 	66	 	 	 	3,306	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	$	2,156	 	 	$	423	 	 	$	2,579	 	 	$	5,957	 	 	$	1,069	 	 	$	7,026	 	

3.	Divestitures	
2018 Asset Divestitures
During the third quarter of 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). The proceeds from the sale were utilized to increase Devon’s share repurchase program to $4.0 billion, which is discussed further in Note 19 . Additional information on these discontinued operations can be found in  Note 20 .
Additionally, during the third quarter of 2018, Devon entered into definitive agreements to sell non-core Delaware Basin and Barnett Shale assets for approximately $320 million in the aggregate, before purchase price adjustments. Devon expects to recognize a gain in the consolidated statements of earnings upon closing the transactions in the fourth quarter of 2018.
Subsequent to September 30, 2018, Devon reached an agreement to sell additional non-core assets for $100 million, before purchase price adjustments. The transaction is expected to close in the first quarter of 2019. Devon is currently evaluating the impact this transaction will have on its consolidated financial statements.
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 statements 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 statements of earnings.
2017 Asset Divestitures
Through September 30, 2017, Devon completed divestiture transactions with proceeds totaling approximately $400 million, before purchase price adjustments and recognized a net gain of approximately $200 million in the consolidated statements of earnings. Estimated proved reserves associated with these assets were less than 1% of total proved reserves.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
4. Derivative Financial Instruments
Objectives and Strategies
Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL marketing activities. These commodity derivative financial instruments include financial price swaps, basis swaps and costless price collars. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of September 30, 2018, Devon did not have any open foreign exchange contracts.
Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
Counterparty Credit Risk
By using derivative financial instruments, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally contain provisions that provide for collateral payments if Devon’s or its counterparty’s credit rating falls below certain credit rating levels.
Commodity Derivatives
As of September 30, 2018, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

 	 	Price Swaps	 	 	Price Collars	 	
Period	 	Volume
(Bbls/d)	 	 	Weighted
Average
Price ($/Bbl)	 	 	Volume
(Bbls/d)	 	 	Weighted
Average Floor
Price ($/Bbl)	 	 	Weighted
Average
Ceiling Price
($/Bbl)	 	
Q4 2018	 	 	93,800	 	 	$	58.95	 	 	 	110,200	 	 	$	53.95	 	 	$	64.49	 	
Q1-Q4 2019	 	 	57,130	 	 	$	59.73	 	 	 	79,904	 	 	$	54.23	 	 	$	64.23	 	
Q1-Q4 2020	 	 	1,740	 	 	$	62.88	 	 	 	1,989	 	 	$	57.86	 	 	$	67.86	 	
 
 	 	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)	 	
Q4 2018	 	Midland Sweet	 	 	23,000	 	 	$	(1.02	)	 	 	—	 	 	$	—	 	 	$	—	 	
Q4 2018	 	Argus LLS	 	 	12,000	 	 	$	3.95	 	 	 	—	 	 	$	—	 	 	$	—	 	
Q4 2018	 	Argus MEH	 	 	16,000	 	 	$	2.84	 	 	 	—	 	 	$	—	 	 	$	—	 	
Q4 2018	 	NYMEX Roll	 	 	27,000	 	 	$	0.58	 	 	 	—	 	 	$	—	 	 	$	—	 	
Q4 2018	 	Western Canadian Select	 	 	62,109	 	 	$	(16.41	)	 	 	1,326	 	 	$	(15.50	)	 	$	(13.93	)	
Q1-Q4 2019	 	Midland Sweet	 	 	28,000	 	 	$	(0.46	)	 	 	—	 	 	$	—	 	 	$	—	 	
Q1-Q4 2019	 	Argus LLS	 	 	14,000	 	 	$	4.82	 	 	 	—	 	 	$	—	 	 	$	—	 	
Q1-Q4 2019	 	Argus MEH	 	 	16,000	 	 	$	2.84	 	 	 	—	 	 	$	—	 	 	$	—	 	
Q1-Q4 2019	 	NYMEX Roll	 	 	38,000	 	 	$	0.45	 	 	 	—	 	 	$	—	 	 	$	—	 	
Q1-Q4 2019	 	Western Canadian Select	 	 	10,647	 	 	$	(23.39	)	 	 	—	 	 	$	—	 	 	$	—	 	
Q1-Q4 2020	 	NYMEX Roll	 	 	38,000	 	 	$	0.31	 	 	 	—	 	 	$	—	 	 	$	—	 	
	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
As of September 30, 2018, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.
 
 	 	Price Swaps	 	 	Price Collars	 	
Period	 	Volume (MMBtu/d)	 	 	Weighted Average Price ($/MMBtu)	 	 	Volume (MMBtu/d)	 	 	Weighted Average Floor Price ($/MMBtu)	 	 	Weighted Average
Ceiling Price ($/MMBtu)	 	
Q4 2018	 	 	304,000	 	 	$	2.92	 	 	 	267,000	 	 	$	2.76	 	 	$	3.09	 	
Q1-Q4 2019	 	 	215,129	 	 	$	2.81	 	 	 	187,775	 	 	$	2.65	 	 	$	3.03	 	
Q1-Q4 2020	 	 	6,589	 	 	$	2.81	 	 	 	7,086	 	 	$	2.65	 	 	$	2.95	 	
 
 	 	Natural Gas Basis Swaps	 	
Period	 	Index	 	Volume
(MMBtu/d)	 	 	Weighted Average
Differential to
Henry Hub
($/MMBtu)	 	
Q4 2018	 	Panhandle Eastern Pipe Line	 	 	120,000	 	 	$	(0.51)	 	
Q4 2018	 	El Paso Natural Gas	 	 	100,000	 	 	$	(1.25)	 	
Q4 2018	 	Houston Ship Channel	 	 	110,000	 	 	$	0.01	 	
Q4 2018	 	Transco Zone 4	 	 	30,000	 	 	$	(0.03)	 	
Q1-Q4 2019	 	Panhandle Eastern Pipe Line	 	 	74,384	 	 	$	(0.75)	 	
Q1-Q4 2019	 	El Paso Natural Gas	 	 	130,000	 	 	$	(1.46)	 	
Q1-Q4 2019	 	Houston Ship Channel	 	 	122,637	 	 	$	—	 	
Q1-Q4 2019	 	Transco Zone 4	 	 	7,397	 	 	$	(0.03)	 	
 
As of September 30, 2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.
 
 	 	 	 	Price Swaps	 	
Period	 	Product	 	Volume (Bbls/d)	 	 	Weighted Average Price ($/Bbl)	 	
Q4 2018	 	Ethane	 	 	6,000	 	 	$	11.73	 	
Q4 2018	 	Natural Gasoline	 	 	6,500	 	 	$	56.13	 	
Q4 2018	 	Normal Butane	 	 	7,000	 	 	$	38.69	 	
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	 	
 
Interest Rate Derivatives
As of September 30, 2018, Devon had the following open interest rate derivative position:
 
Notional	 	 	Rate Received	 	 	Rate Paid	 	Expiration	
$	100	 	 	1.76%	 	 	Three Month LIBOR	 	January 2019	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Financial Statement Presentation
The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption.
 	 	Three Months Ended
September 30,	 	 	Nine Months Ended
September 30,	 	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	 	
Commodity derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream revenues	 	$	(276	)	 	$	(144	)	 	$	(814	)	 	$	214	 	 	
Marketing revenues	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	3	 	 	
Interest rate derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other expenses	 	 	—	 	 	 	(4	)	 	 	65	 	 	 	(19	)	 	
Net gains (losses) recognized	 	$	(276	)	 	$	(148	)	 	$	(750	)	 	$	198	 	 	
 
The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.
 	 	September 30, 2018	 	 	December 31, 2017	 	
Commodity derivative assets:	 	 	 	 	 	 	 	 	
Other current assets	 	$	176	 	 	$	203	 	
Other long-term assets	 	 	8	 	 	 	2	 	
Interest rate derivative assets:	 	 	 	 	 	 	 	 	
Other current assets	 	 	—	 	 	 	1	 	
Total derivative assets	 	$	184	 	 	$	206	 	
Commodity derivative liabilities:	 	 	 	 	 	 	 	 	
Other current liabilities	 	$	763	 	 	$	259	 	
Other long-term liabilities	 	 	105	 	 	 	27	 	
Interest rate derivative liabilities:	 	 	 	 	 	 	 	 	
Other current liabilities	 	 	1	 	 	 	64	 	
Total derivative liabilities	 	$	869	 	 	$	350	 	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
5.	Share-Based Compensation	
The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings. The vesting for certain share-based awards was accelerated in conjunction with the reduction of workforce described in Note 7 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.
 
 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	
G&A	 	$	95	 	 	$	107	 	
Exploration expenses	 	 	3	 	 	 	6	 	
Restructuring and transaction costs	 	 	28	 	 	 	—	 	
Total	 	$	126	 	 	$	113	 	
Related income tax benefit	 	$	9	 	 	$	4	 	
 
Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first nine months of 2018. The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plan.
 
 	 	Restricted Stock	 	 	Performance-Based	 	 	Performance	 	
 	 	Awards and Units	 	 	Restricted Stock Awards	 	 	Share Units	 	
 	 	Awards and
Units	 	 	Weighted
Average
Grant-Date
Fair Value	 	 	Awards	 	 	Weighted
Average
Grant-Date
Fair Value	 	 	Units	 	 	 	 	 	Weighted
Average
Grant-Date
Fair Value	 	
 	 	(Thousands, except fair value data)	 	
Unvested at 12/31/17	 	 	6,328	 	 	$	36.81	 	 	 	575	 	 	$	38.92	 	 	 	2,758	 	 	 	 	 	$	41.21	 	
Granted	 	 	3,573	 	 	$	36.00	 	 	 	—	 	 	$	—	 	 	 	845	 	 	 	 	 	$	37.40	 	
Vested	 	 	(3,045	)	 	$	38.76	 	 	 	(273	)	 	$	42.22	 	 	 	(571	)	 	 	 	 	$	84.22	 	
Forfeited	 	 	(753	)	 	$	35.56	 	 	 	—	 	 	$	—	 	 	 	(137	)	 	 	 	 	$	34.04	 	
Unvested at 9/30/18	 	 	6,103	 	 	$	35.52	 	 	 	302	 	 	$	35.93	 	 	 	2,895	 	 	(1	)	 	$	30.17	 	

(1)	A maximum of 5.8 million common shares could be awarded based upon Devon’s final TSR ranking relative to Devon’s peer group established under applicable award agreements.	
The following table presents the assumptions related to the performance share units granted in 2018, as indicated in the previous summary table.
 
 	 	2018	 	
Grant-date fair value	 	 	$36.23	 	 	—	 	$	37.88	 	
Risk-free interest rate	 	2.28%	 	
Volatility factor	 	45.8%	 	
Contractual term (years)	 	2.89	 	
 
The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of September 30, 2018.
 
 	 	 	 	 	 	Performance-Based	 	 	 	 	 	
 	 	Restricted Stock	 	 	Restricted Stock	 	 	Performance	 	
 	 	Awards and Units	 	 	Awards	 	 	Share Units	 	
Unrecognized compensation cost	 	$	139	 	 	$	1	 	 	$	31	 	
Weighted average period for recognition (years)	 	 	2.5	 	 	 	1.0	 	 	 	1.9	 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
6.	Asset Impairments	
Unproved   Impairments
During the first nine 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 $76 million and $80 million, respectively. Unproved impairments are included in exploration expenses in the consolidated comprehensive statements of earnings.
Asset   Impairments
During the first nine months 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 $47 million of non-oil and gas asset impairments.
7.	Restructuring and Transaction Costs	
In April 2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized $105 million ($102 million related to personnel) of restructuring expenses during the first nine months of 2018. Of these expenses, $28 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 restructuring liabilities.

 	 	Other	 	 	Other	 	 	 	 	 	
 	 	Current	 	 	Long-term	 	 	 	 	 	
 	 	Liabilities	 	 	Liabilities	 	 	Total	 	
 	 	(Millions)	 	
Balance as of December 31, 2017	 	$	19	 	 	$	31	 	 	$	50	 	
Changes due to 2018 workforce reductions	 	 	35	 	 	 	—	 	 	 	35	 	
Changes related to prior years' restructurings	 	 	1	 	 	 	(10	)	 	 	(9	)	
Balance as September 30, 2018	 	$	55	 	 	$	21	 	 	$	76	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2016	 	$	48	 	 	$	62	 	 	$	110	 	
Changes related to prior years' restructurings	 	 	(28	)	 	 	(26	)	 	 	(54	)	
Balance as of September 30, 2017	 	$	20	 	 	$	36	 	 	$	56	 	

8.	Other Expenses	
 
The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings.
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Foreign exchange (gain) loss, net	 	$	(28	)	 	$	(74	)	 	$	53	 	 	$	(138	)	
Asset retirement obligation accretion	 	 	14	 	 	 	16	 	 	 	44	 	 	 	47	 	
Other, net	 	 	(17	)	 	 	(12	)	 	 	(83	)	 	 	(1	)	
Total	 	$	(31	)	 	$	(70	)	 	$	14	 	 	$	(92	)	
Foreign exchange (gain) loss, net
 
The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. The amounts in the table above include both unrealized and realized foreign exchange impacts of foreign currency denominated monetary assets and liabilities, including intercompany loans between subsidiaries with different functional currencies. Unrealized gains and losses arise from the remeasurement of these foreign currency denominated monetary assets and liabilities and intercompany loans. Realized gains and losses arise when there are settlements of these foreign currency denominated monetary assets and liabilities and intercompany loans.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
Foreign currency denominated intercompany loan activity in the first nine months of 2018 resulted in a realized loss of $243 million, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. These losses during the first nine months of 2018, were partially offset by reversing $195 million of previously recognized unrealized losses on intercompany loan activity.
 
9.	Income Taxes	
The following table presents Devon’s total income tax expense (benefit) and a reconciliation of its effective income tax rate to the U.S. statutory income tax rate.
 	 	Three Months Ended September 30,	 	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	 	2018	 	 	2017	 	
Current income tax expense (benefit)	 	$	(24	)	 	$	38	 	 	 	$	(47	)	 	$	70	 	
Deferred income tax benefit	 	 	(114	)	 	 	(25	)	 	 	 	(132	)	 	 	(57	)	
Total income tax expense (benefit)	 	$	(138	)	 	$	13	 	 	 	$	(179	)	 	$	13	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. statutory income tax rate	 	 	21	%	 	 	35	%	 	 	 	21	%	 	 	35	%	
State income taxes	 	 	(5	%)	 	 	0	%	 	 	 	1	%	 	 	1	%	
Change in unrecognized tax benefits	 	 	(13	%)	 	 	4	%	 	 	 	4	%	 	 	1	%	
Other	 	 	(7	%)	 	 	(19	%)	 	 	 	(7	%)	 	 	(7	%)	
Deferred tax asset valuation allowance	 	 	(81	%)	 	 	(14	%)	 	 	 	13	%	 	 	(28	%)	
Effective income tax rate	 	 	(85	%)	 	 	6	%	 	 	 	32	%	 	 	2	%	
 
Devon estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. Under the Tax Reform Legislation, the U.S. corporate income tax rate was reduced to 21% effective January 1, 2018.
 
During the third quarter of 2018, Devon realized $22 million of unrecognized benefits, including $2 million of interest, as a result of the expiration of certain U.S. federal statutes of limitation.
In the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on Devon’s effective income tax rate. However, these items have a more noticeable impact to the rate in the first nine months of 2018 due to lower relative earnings during the period.
Throughout 2017 and through the first two quarters of 2018, Devon’s U.S. segment maintained a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses, 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 two quarters of 2018 based on the financial losses recorded during that period. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period projected net operating loss utilization, and projections of future taxable income, Devon reassessed its position and determined that its U.S. segment is no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses. As part of its reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon’s U.S. segment would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the $259 million of deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations. A partial valuation allowance continues to be held against certain Canadian segment deferred tax assets. During the first three quarters of 2018, the Canadian segment reduced its valuation allowance by approximately $76 million.  
During the first quarter of 2018, Devon repatriated approximately $92 million from certain international entities. This repatriation had no tax impact.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a measurement period not to extend beyond one
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
year after the enactment date of the Tax Reform Legislation. The 2017 U.S. federal tax return was filed subsequent to the end of the third quarter of 2018. With the completion of the 2017 federal return, Devon considers the accounting of the transition tax, deferred tax remeasurements and other items to now be substantially complete .
 
10.	Net Earnings (Loss) Per Share from Continuing Operations	
The following table reconciles net earnings (loss) from continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share from continuing operations.
 
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Net earnings (loss) from continuing operations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss) from continuing operations	 	$	300	 	 	$	194	 	 	$	(385	)	 	$	714	 	
Attributable to participating securities	 	 	(3	)	 	 	(2	)	 	 	(1	)	 	 	(8	)	
Basic and diluted earnings (loss) from continuing operations	 	$	297	 	 	$	192	 	 	$	(386	)	 	$	706	 	
Common shares:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common shares outstanding - total	 	 	491	 	 	 	526	 	 	 	513	 	 	 	525	 	
Attributable to participating securities	 	 	(5	)	 	 	(6	)	 	 	(6	)	 	 	(6	)	
Common shares outstanding - basic	 	 	486	 	 	 	520	 	 	 	507	 	 	 	519	 	
Dilutive effect of potential common shares issuable	 	 	3	 	 	 	3	 	 	 	—	 	 	 	3	 	
Common shares outstanding - diluted	 	 	489	 	 	 	523	 	 	 	507	 	 	 	522	 	
Net earnings (loss) per share from continuing operations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	0.61	 	 	$	0.37	 	 	$	(0.76	)	 	$	1.36	 	
Diluted	 	$	0.61	 	 	$	0.37	 	 	$	(0.76	)	 	$	1.35	 	
Antidilutive options (1)	 	 	2	 	 	 	2	 	 	 	2	 	 	 	2	 	

(1)	Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.	
 
11.	Other Comprehensive Earnings	
Components of other comprehensive earnings consist of the following:

 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Foreign currency translation:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning accumulated foreign currency translation	 	$	1,227	 	 	$	1,262	 	 	$	1,309	 	 	$	1,226	 	
Change in cumulative translation adjustment	 	 	35	 	 	 	58	 	 	 	(61	)	 	 	108	 	
Income tax benefit (expense)	 	 	—	 	 	 	(16	)	 	 	14	 	 	 	(30	)	
Ending accumulated foreign currency translation	 	 	1,262	 	 	 	1,304	 	 	 	1,262	 	 	 	1,304	 	
Pension and postretirement benefit plans:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning accumulated pension and postretirement benefits	 	 	(136	)	 	 	(163	)	 	 	(143	)	 	 	(172	)	
Recognition of net actuarial loss and prior service cost in earnings (1)	 	 	92	 	 	 	5	 	 	 	99	 	 	 	14	 	
Curtailment and settlement of pension benefits	 	 	(34	)	 	 	—	 	 	 	(34	)	 	 	—	 	
Income tax expense	 	 	(22	)	 	 	—	 	 	 	(22	)	 	 	—	 	
Ending accumulated pension and postretirement benefits	 	 	(100	)	 	 	(158	)	 	 	(100	)	 	 	(158	)	
Other	 	 	2	 	 	 	—	 	 	 	2	 	 	 	—	 	
Accumulated other comprehensive earnings, net of tax	 	$	1,164	 	 	$	1,146	 	 	$	1,164	 	 	$	1,146	 	

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

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
12.	Supplemental Information to Statements of Cash Flows	
 
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Changes in assets and liabilities, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable	 	$	(65	)	 	$	(102	)	 	$	(216	)	 	$	(28	)	
Other current assets	 	 	1	 	 	 	26	 	 	 	(94	)	 	 	13	 	
Other long-term assets	 	 	(3	)	 	 	3	 	 	 	(84	)	 	 	13	 	
Accounts payable	 	 	14	 	 	 	29	 	 	 	96	 	 	 	97	 	
Revenues and royalties payable	 	 	(12	)	 	 	(30	)	 	 	200	 	 	 	21	 	
Other current liabilities	 	 	38	 	 	 	69	 	 	 	(25	)	 	 	17	 	
Other long-term liabilities	 	 	(24	)	 	 	(7	)	 	 	(36	)	 	 	(12	)	
Total	 	$	(51	)	 	$	(12	)	 	$	(159	)	 	$	121	 	
Supplementary cash flow data - total operations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest paid (net of capitalized interest)	 	$	61	 	 	$	51	 	 	$	275	 	 	$	287	 	
Income taxes paid (received)	 	$	37	 	 	$	—	 	 	$	31	 	 	$	(1	)	

13.	Accounts Receivable	
Components of accounts receivable include the following:
 
 	September 30, 2018	 	 	December 31, 2017	 	
Oil, gas and NGL sales	$	619	 	 	$	559	 	
Joint interest billings	 	176	 	 	 	134	 	
Marketing revenues	 	323	 	 	 	278	 	
Other	 	117	 	 	 	29	 	
Gross accounts receivable	 	1,235	 	 	 	1,000	 	
Allowance for doubtful accounts	 	(9	)	 	 	(11	)	
Net accounts receivable	$	1,226	 	 	$	989	 	
 
14. Property, Plant and Equipment
 
The following table presents the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
 
 	 	September 30, 2018	 	 	December 31, 2017	 	
Property and equipment:	 	 	 	 	 	 	 	 	
Proved	 	$	47,747	 	 	$	47,295	 	
Unproved and properties under development	 	 	2,409	 	 	 	2,457	 	
Total oil and gas	 	 	50,156	 	 	 	49,752	 	
Less accumulated DD&A	 	 	(37,100	)	 	 	(36,434	)	
Oil and gas property and equipment, net	 	 	13,056	 	 	 	13,318	 	
Other property and equipment	 	 	1,845	 	 	 	1,955	 	
Less accumulated DD&A	 	 	(699	)	 	 	(689	)	
Other property and equipment, net	 	 	1,146	 	 	 	1,266	 	
Property and equipment, net	 	$	14,202	 	 	$	14,584	 	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
15.	Other Current Liabilities	
Components of other current liabilities include the following:
 
 	September 30, 2018	 	 	December 31, 2017	 	
Derivative liabilities	$	764	 	 	$	323	 	
Accrued interest payable	 	109	 	 	 	96	 	
Income taxes payable	 	23	 	 	 	144	 	
Restructuring liabilities	 	55	 	 	 	19	 	
Other	 	292	 	 	 	246	 	
Other current liabilities	$	1,243	 	 	$	828	 	

16.	Debt and Related Expenses	
A summary of debt is as follows:
 	 	September 30, 2018	 	 	December 31, 2017	 	
8.25% due July 1, 2018	 	$	—	 	 	$	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	 	 	(24	)	 	 	(30	)	
Debt issuance costs	 	 	(34	)	 	 	(39	)	
Total debt	 	 	6,048	 	 	 	6,864	 	
Less amount classified as short-term debt (2)	 	 	257	 	 	 	115	 	
Total long-term debt	 	$	5,791	 	 	$	6,749	 	

(1)	These senior notes were included in the 2018 tender offer repurchases discussed below.	
(2)	As of September 30, 2018, short-term debt consists of Devon’s $95 million of 2.25% senior notes due December 15, 2018 and $162 million of 6.30% senior notes due January 15, 2019.	
Credit Lines
Under its 2012 Senior Credit Facility, Devon had $3.0 billion of available credit. As of September 30, 2018, Devon had no outstanding borrowings and had issued $50 million in outstanding letters of credit under this facility. The 2012 Senior Credit Facility contained only one material financial covenant. This covenant required Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. Under the terms of the credit agreement, total capitalization is adjusted to add back noncash financial write-downs such as impairments. As of September 30, 2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 21.5%.
On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and subsequently entered into a new $3.0 billion revolving 2018 Senior Credit Facility with a financial covenant and other terms similar to the 2012 Senior Credit Facility. The 2018 Senior Credit Facility matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Retirement of Senior Notes
In the first quarter of 2018, Devon completed tender offers to repurchase $807 million in aggregate principal amount of debt securities, using cash on hand. This included $384 million of the 7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million loss on early retirement of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along with other charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.
In July 2018, Devon repaid the $20 million of 8.25% senior notes at maturity.
Net Financing Costs
The following schedule includes the components of net financing costs.
 
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Interest based on debt outstanding	 	$	81	 	 	$	97	 	 	$	258	 	 	$	292	 	
Early retirement of debt	 	 	—	 	 	 	—	 	 	 	312	 	 	 	—	 	
Capitalized interest	 	 	(6	)	 	 	(18	)	 	 	(41	)	 	 	(50	)	
Other	 	 	—	 	 	 	(1	)	 	 	(5	)	 	 	(4	)	
Total net financing costs	 	$	75	 	 	$	78	 	 	$	524	 	 	$	238	 	
 
17.	Asset Retirement Obligations	
 
The following table presents the changes in Devon’s asset retirement obligations.
 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	
Asset retirement obligations as of beginning of period	 	$	1,138	 	 	$	1,258	 	
Liabilities incurred	 	 	32	 	 	 	30	 	
Liabilities settled and divested	 	 	(83	)	 	 	(53	)	
Revision of estimated obligation	 	 	23	 	 	 	(184	)	
Accretion expense on discounted obligation	 	 	44	 	 	 	47	 	
Foreign currency translation adjustment	 	 	(14	)	 	 	29	 	
Asset retirement obligations as of end of period	 	 	1,140	 	 	 	1,127	 	
Less current portion	 	 	37	 	 	 	41	 	
Asset retirement obligations, long-term	 	$	1,103	 	 	$	1,086	 	
 
During the first nine months of 2018, Devon reduced its asset retirement obligation by $61 million, primarily as a result of Devon’s 2018 divestitures. 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.
 
18.	Retirement Plans	
 
During the third quarter of 2018, Devon entered into a group annuity contract, under which a third party has permanently assumed certain of Devon’s defined benefit pension obligations. The purchase of this group annuity contract reduced Devon’s pension assets and liabilities by approximately $190 million, representing approximately 15% of the total obligations of Devon’s pension plans. In connection with this transaction, Devon recorded a settlement expense of approximately $34 million, which was reclassified from other comprehensive earnings to other expense on the consolidated comprehensive statements of earnings in the current period.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.
 
 	 	Pension Benefits	 	 	Postretirement Benefits	 	
 	 	Three Months Ended	 	 	Nine Months Ended	 	 	Three Months Ended	 	 	Nine Months Ended	 	
 	 	September 30,	 	 	September 30,	 	 	September 30,	 	 	September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Service cost	 	$	2	 	 	$	4	 	 	$	8	 	 	$	12	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Interest cost	 	 	10	 	 	 	11	 	 	 	30	 	 	 	32	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Expected return on plan assets	 	 	(11	)	 	 	(14	)	 	 	(39	)	 	 	(41	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Amortization of prior service cost (1)	 	 	—	 	 	 	—	 	 	 	1	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	(1	)	
Net actuarial loss (1)	 	 	3	 	 	 	5	 	 	 	10	 	 	 	14	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Net periodic benefit cost (2)	 	$	4	 	 	$	6	 	 	$	10	 	 	$	18	 	 	$	—	 	 	$	—	 	 	$	(1	)	 	$	(1	)	

 	(1)	These net periodic benefit costs were reclassified out of other comprehensive earnings.	
 	(2)	The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings.	
 
19.	Stockholders’ Equity	
Share Repurchase Program
In March 2018, Devon announced a share repurchase program to buy up to $1.0 billion of shares of common stock. In June 2018, in conjunction with the announced divestiture of its investment in EnLink and the General Partner, Devon increased its program by an additional $3.0 billion, bringing the total repurchase program to $4.0 billion. The share repurchase program expires December 31, 2019.
During the third quarter of 2018, Devon entered into and completed an ASR transaction to repurchase $1.0 billion of the $4.0 billion program. The table below provides information regarding purchases of Devon’s common stock that were made during the first nine months of 2018 (shares in thousands).  
 	 	Total Number of
Shares Purchased	 	 	Dollar Value of
Shares Purchased	 	 	Average Price Paid
per Share	 	
First quarter 2018:	 	 	 	 	 	 	 	 	 	 	 	 	
Open-Market	 	 	2,561	 	 	$	82	 	 	$	32.19	 	
Second quarter 2018:	 	 	 	 	 	 	 	 	 	 	 	 	
Open-Market	 	 	11,154	 	 	 	439	 	 	 	39.35	 	
Third quarter 2018:	 	 	 	 	 	 	 	 	 	 	 	 	
Open-Market	 	 	16,492	 	 	 	712	 	 	 	43.13	 	
ASR	 	 	24,330	 	 	 	1,000	 	 	 	41.10	 	
Total	 	 	40,822	 	 	 	1,712	 	 	 	41.92	 	
Total year-to-date	 	 	54,537	 	 	$	2,233	 	 	$	40.94	 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Dividends
 
The table below summarizes the dividends Devon paid on its common stock.
 
 	Amounts	 	 	Rate Per Share	 	
Quarter Ended 2018:	 	 	 	 	 	 	 	
First quarter 2018	$	32	 	 	$	0.06	 	
Second quarter 2018	 	42	 	 	$	0.08	 	
Third quarter 2018	 	38	 	 	$	0.08	 	
Total year-to-date	$	112	 	 	 	 	 	
Quarter Ended 2017:	 	 	 	 	 	 	 	
First quarter 2017	$	32	 	 	$	0.06	 	
Second quarter 2017	 	33	 	 	$	0.06	 	
Third quarter 2017	 	30	 	 	$	0.06	 	
Total year-to-date	$	95	 	 	 	 	 	
Devon increased the quarterly dividend by 33% to $0.08 per share in the second quarter of 2018.
 
20.	Discontinued Operations	
 
On June 6, 2018, Devon announced that it had entered into an agreement to sell its aggregate ownership interests in EnLink and the General Partner for $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire midstream business ownership; 2) EnLink and the General Partner 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, debt, revenues, net earnings and operating cash flows. As a result, Devon classified the results of operations and cash flows related to EnLink and the General Partner as discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was signed.
 
On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). As current (cash) income taxes associated with the transaction was approximately $12 million, the vast majority of the tax effect relates to deferred tax expense offset by the valuation allowance adjustment explained in Note 9 .

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations.
 
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Marketing and midstream revenues	 	$	360	 	 	$	1,223	 	 	$	3,567	 	 	$	3,468	 	
Marketing and midstream expenses	 	 	302	 	 	 	981	 	 	 	2,912	 	 	 	2,781	 	
Depreciation, depletion and amortization	 	 	—	 	 	 	142	 	 	 	244	 	 	 	407	 	
General and administrative expenses	 	 	7	 	 	 	31	 	 	 	65	 	 	 	98	 	
Financing costs, net	 	 	9	 	 	 	50	 	 	 	98	 	 	 	134	 	
Asset dispositions	 	 	(2,607	)	 	 	1	 	 	 	(2,607	)	 	 	1	 	
Other expenses	 	 	(1	)	 	 	(2	)	 	 	(8	)	 	 	(22	)	
Total expenses	 	 	(2,290	)	 	 	1,203	 	 	 	704	 	 	 	3,399	 	
Earnings from discontinued operations before
   income taxes	 	 	2,650	 	 	 	20	 	 	 	2,863	 	 	 	69	 	
Income tax expense	 	 	387	 	 	 	2	 	 	 	403	 	 	 	9	 	
Net earnings from discontinued operations, net of
   income tax expense	 	 	2,263	 	 	 	18	 	 	 	2,460	 	 	 	60	 	
Net earnings attributable to noncontrolling interests	 	 	26	 	 	 	19	 	 	 	160	 	 	 	59	 	
Net earnings (loss) from discontinued operations
   attributable to Devon	 	$	2,237	 	 	$	(1	)	 	$	2,300	 	 	$	1	 	

The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets.
 	 	December 31, 2017	 	
Cash and cash equivalents	 	$	31	 	
Accounts receivable	 	 	681	 	
Other current assets	 	 	48	 	
Midstream and other property and equipment, net	 	 	6,587	 	
Goodwill	 	 	1,542	 	
Other long-term assets	 	 	1,600	 	
Total assets held for sale	 	$	10,489	 	
 	 	 	 	 	
Accounts payable	 	$	186	 	
Revenues and royalties payable	 	 	432	 	
Other current liabilities	 	 	373	 	
Long-term debt	 	 	3,542	 	
Deferred income taxes	 	 	346	 	
Other long-term liabilities	 	 	48	 	
Total liabilities held for sale	 	$	4,927	 	
 
As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants continue through year-end 2018 and the Chisholm plant through early 2021, as shown in the following table.
 	 	Minimum	 	Minimum	
 	 	Gathering Volume	 	Processing Volume	
Contract	 	Commitment (MMcf/d)	 	Commitment (MMcf/d)	
Bridgeport gathering and processing contract	 	850	 	650	
Cana gathering and processing contract	 	330	 	330	
Chisholm gathering and processing contract	 	77-128	 	77-128	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
From the period of July 19, 2018 through September 30, 2018, Devon had net outflows of approximately $200 million with EnLink, which primarily related to gathering and processing expenses. These net outflows represent gross cash amounts and not net working interest amounts.
 
Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation.
 
21.	Commitments and Contingencies	
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.
Royalty Matters
Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
Environmental Matters
Devon is subject to certain environmental, health and safety laws and regulations, including with respect to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.
Other Matters
Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
22.	Fair Value Measurements	
The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at September 30, 2018 and December 31, 2017. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets and goodwill and related impairments are measured as of the impairment date using Level 3 inputs. More information on asset impairments is provided in Note 6 .
 
As discussed further in Note 20 , Devon’s announcement of the sale of its aggregate ownership interests in EnLink and the General Partner resulted in Devon reclassifying the related assets and liabilities to held for sale on the consolidated balance sheets as of December 31, 2017.
 
 	 	 	 	 	 	 	 	 	 	Fair Value Measurements Using:	 	
 	 	Carrying	 	 	Total Fair	 	 	Level 1	 	 	Level 2	 	
 	 	Amount	 	 	Value	 	 	Inputs	 	 	Inputs	 	
September 30, 2018 assets (liabilities):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash equivalents	 	$	2,216	 	 	$	2,216	 	 	$	2,216	 	 	$	—	 	
Commodity derivatives	 	$	184	 	 	$	184	 	 	$	—	 	 	$	184	 	
Commodity derivatives	 	$	(868	)	 	$	(868	)	 	$	—	 	 	$	(868	)	
Interest rate derivatives	 	$	(1	)	 	$	(1	)	 	$	—	 	 	$	(1	)	
Debt	 	$	(6,048	)	 	$	(6,458	)	 	$	—	 	 	$	(6,458	)	
December 31, 2017 assets (liabilities):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash equivalents	 	$	1,533	 	 	$	1,533	 	 	$	1,454	 	 	$	79	 	
Commodity derivatives	 	$	205	 	 	$	205	 	 	$	—	 	 	$	205	 	
Commodity derivatives	 	$	(286	)	 	$	(286	)	 	$	—	 	 	$	(286	)	
Interest rate derivatives	 	$	1	 	 	$	1	 	 	$	—	 	 	$	1	 	
Interest rate derivatives	 	$	(64	)	 	$	(64	)	 	$	—	 	 	$	(64	)	
Debt	 	$	(6,864	)	 	$	(8,131	)	 	$	—	 	 	$	(8,131	)	
 
The following methods and assumptions were used to estimate the fair values in the table above.
Level 1 Fair Value Measurements
Cash equivalents – Amounts consist primarily of money market investments and the fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents – Amounts primarily consist of commercial paper and 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.
 
23.	Segment Information	
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian E&P operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas E&P activities.
Devon considers EnLink, combined with the General Partner, to be a segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located in the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. However, with Devon’s recent announcement and closing of the divestment of the General Partner and EnLink, activity related to the General Partner and EnLink
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
have now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows, and the associated assets and liabilities of EnLink and the General Partner are presented as assets and liabilities held for sale on the consolidated balance sheets. Additional information can be found in Note 20 .

 	 	U.S.	 	 	Canada	 	 	Total	 	
Three Months Ended September 30, 2018:	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from external customers	 	$	2,156	 	 	$	423	 	 	$	2,579	 	
Depreciation, depletion and amortization	 	$	342	 	 	$	74	 	 	$	416	 	
Interest expense	 	$	78	 	 	$	8	 	 	$	86	 	
Asset impairments	 	$	2	 	 	$	—	 	 	$	2	 	
Asset dispositions	 	$	(6	)	 	$	—	 	 	$	(6	)	
Restructuring and transaction costs	 	$	7	 	 	$	4	 	 	$	11	 	
Earnings (loss) from continuing operations before income taxes	 	$	(11	)	 	$	173	 	 	$	162	 	
Income tax expense (benefit)	 	$	(164	)	 	$	26	 	 	$	(138	)	
Net earnings from continuing operations	 	$	153	 	 	$	147	 	 	$	300	 	
Capital expenditures, including acquisitions	 	$	492	 	 	$	66	 	 	$	558	 	
Three Months Ended September 30, 2017:	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from external customers	 	$	1,575	 	 	$	358	 	 	$	1,933	 	
Depreciation, depletion and amortization	 	$	278	 	 	$	92	 	 	$	370	 	
Interest expense	 	$	82	 	 	$	3	 	 	$	85	 	
Asset dispositions	 	$	(170	)	 	$	—	 	 	$	(170	)	
Earnings from continuing operations before income taxes	 	$	145	 	 	$	62	 	 	$	207	 	
Income tax expense (benefit)	 	$	(5	)	 	$	18	 	 	$	13	 	
Net earnings from continuing operations	 	$	150	 	 	$	44	 	 	$	194	 	
Capital expenditures, including acquisitions	 	$	482	 	 	$	95	 	 	$	577	 	
Nine Months Ended September 30, 2018:	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from external customers	 	$	5,957	 	 	$	1,069	 	 	$	7,026	 	
Depreciation, depletion and amortization	 	$	989	 	 	$	246	 	 	$	1,235	 	
Interest expense	 	$	397	 	 	$	153	 	 	$	550	 	
Asset impairments	 	$	156	 	 	$	—	 	 	$	156	 	
Asset dispositions	 	$	5	 	 	$	—	 	 	$	5	 	
Restructuring and transaction costs	 	$	92	 	 	$	13	 	 	$	105	 	
Earnings (loss) from continuing operations before income taxes	 	$	(598	)	 	$	34	 	 	$	(564	)	
Income tax benefit	 	$	(150	)	 	$	(29	)	 	$	(179	)	
Net earnings (loss) from continuing operations	 	$	(448	)	 	$	63	 	 	$	(385	)	
Property and equipment, net	 	$	10,053	 	 	$	4,149	 	 	$	14,202	 	
Total assets	 	$	15,104	 	 	$	5,068	 	 	$	20,172	 	
Capital expenditures, including acquisitions	 	$	1,689	 	 	$	215	 	 	$	1,904	 	
Nine Months Ended September 30, 2017:	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from external customers	 	$	5,547	 	 	$	951	 	 	$	6,498	 	
Depreciation, depletion and amortization	 	$	863	 	 	$	276	 	 	$	1,139	 	
Interest expense	 	$	243	 	 	$	8	 	 	$	251	 	
Asset dispositions	 	$	(199	)	 	$	(1	)	 	$	(200	)	
Earnings from continuing operations before income taxes	 	$	668	 	 	$	59	 	 	$	727	 	
Income tax expense	 	$	—	 	 	$	13	 	 	$	13	 	
Net earnings from continuing operations	 	$	668	 	 	$	46	 	 	$	714	 	
Property and equipment, net	 	$	10,110	 	 	$	4,321	 	 	$	14,431	 	
Total continuing assets (1)	 	$	14,105	 	 	$	5,295	 	 	$	19,400	 	
Capital expenditures, including acquisitions	 	$	1,213	 	 	$	248	 	 	$	1,461	 	

(1)	Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion on September 30, 2017.	
 
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Item 2 . Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis addresses material changes in our results of operations for the three-month and nine-month periods ended September 30, 2018 compared to previous periods and in our financial condition and liquidity since December 31, 2017. For information regarding our critical accounting policies and estimates, see our 2017 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Overview of 2018 Results
Key components of our sequential quarter financial performance are summarized below.
 	 	Q3 2018 (3)	 	 	Q2 2018 (3)	 	 	Change	 	
Net earnings (loss) from continuing operations	 	$	300	 	 	$	(474	)	 	 	+163	%	
Net earnings (loss) per diluted share from continuing operations	 	$	0.61	 	 	$	(0.92	)	 	 	+166	%	
Net earnings attributable to Devon from discontinued operations	 	$	2,237	 	 	$	49	 	 	N/M	 	
Net earnings per diluted share attributable to Devon from discontinued operations	 	$	4.53	 	 	$	0.09	 	 	N/M	 	
Net earnings (loss) attributable to Devon	 	$	2,537	 	 	$	(425	)	 	N/M	 	
Net earnings (loss) per diluted share attributable to Devon	 	$	5.14	 	 	$	(0.83	)	 	N/M	 	
Core earnings attributable to Devon  (1)	 	$	324	 	 	$	177	 	 	 	+83	%	
Core earnings attributable to Devon per diluted share (1)	 	$	0.65	 	 	$	0.34	 	 	 	+90	%	
Retained production (MBoe/d)	 	 	500	 	 	 	495	 	 	 	+1	%	
Total production (MBoe/d)	 	 	522	 	 	 	541	 	 	 	- 4	%	
Realized price per Boe (2)	 	$	33.50	 	 	$	31.81	 	 	 	+5	%	
Operating cash flow from continuing operations	 	$	807	 	 	$	269	 	 	 	+200	%	
Capitalized expenditures, including acquisitions	 	$	558	 	 	$	645	 	 	 	- 13	%	
Cash and cash equivalents	 	$	3,102	 	 	$	1,460	 	 	 	+112	%	
Total debt	 	$	6,048	 	 	$	6,067	 	 	 	- 0	%	

(1)	Core earnings and core earnings per diluted share attributable to Devon are financial measures not prepared in accordance with GAAP. For a description of core earnings and core earnings per diluted share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.	
(2)	Excludes any impact of oil, gas and NGL derivatives.	
(3)	Except for balance sheet amounts, which are presented as of period end.	
 
During the first nine months of 2018, we generated solid operating results with our three-fold strategy of operating in North America’s best resource plays, delivering superior execution and maintaining a high degree of financial strength. As we focus on our strategic objectives of monetizing non-core assets, funding high-return projects, generating free cash flow, maintaining financial strength and returning cash to shareholders, we have had several key accomplishments in 2018.
 
 	•	Achieved $4.7 billion in asset sales, including the monetization of EnLink and the General Partner, the closing of the Johnson County divestiture and the announcement of our Delaware Basin divestitures.	
 	•	Continued to improve our 90-day initial production rates and increased STACK and Delaware Basin production 28% in the first nine months of 2018 compared to the first nine months of 2017.	
 	•	Maintained our 2018 capital expenditure forecast.	
 	•	Reduced long-term debt by approximately $830 million, which is expected to reduce annualized borrowing costs by $66 million.	
 	•	Completed a workforce reduction and continue other cost reduction initiatives expected to generate $110 million of annualized savings.	
 	•	Repurchased $2.2 billion of our $4.0 billion share repurchase program, representing a 10% reduction in outstanding shares.	
 	•	Increased our quarterly common stock dividend 33% to $0.08 per share beginning in the second quarter of 2018.	
We exited the third quarter of 2018 with liquidity comprised of $3.1 billion of cash and $2.9 billion of available credit under our 2012 Senior Credit Facility. We have no significant debt maturities until 2021. We currently have approximately 75% of our expected oil production and approximately 50% of our expected gas production protected for the remainder of 2018. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub natural gas index. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our portfolio in the U.S. and Canada, including Western Canadian Select and Midland Sweet basis oil hedges. We are currently building our 2019 and 2020 hedge positions at market prices.
 
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Results of Operations – Q3 2018 vs. Q2 2018
 
The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Due to the nature of our business, including an inherently volatile commodity price environment, we have provided a sequential quarter analysis in order to facilitate the review of our operational results and provide further transparency of our business. Specifically, the graph below shows the change in net earnings from the three months ended June 30, 2018 to the three months ended September 30, 2018. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

* Other includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses.
The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.
 
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Upstream Operations	
Production Volumes
 	 	Q3 2018	 	 	% of Total	 	 	Q2 2018	 	 	Change	 	
Oil and bitumen (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	29	 	 	 	12	%	 	 	34	 	 	 	- 14	%	
Delaware Basin	 	 	44	 	 	 	19	%	 	 	45	 	 	 	- 2	%	
Rockies Oil	 	 	15	 	 	 	6	%	 	 	13	 	 	 	+13	%	
Heavy Oil	 	 	16	 	 	 	7	%	 	 	17	 	 	 	- 5	%	
Eagle Ford	 	 	31	 	 	 	13	%	 	 	28	 	 	 	+10	%	
Other	 	 	6	 	 	 	3	%	 	 	7	 	 	 	- 9	%	
Retained assets	 	 	141	 	 	 	60	%	 	 	144	 	 	 	- 2	%	
U.S. divested assets	 	 	8	 	 	 	4	%	 	 	9	 	 	 	- 20	%	
Total Oil	 	 	149	 	 	 	64	%	 	 	153	 	 	 	- 2	%	
Bitumen	 	 	86	 	 	 	36	%	 	 	92	 	 	 	- 6	%	
Total Oil and bitumen	 	 	235	 	 	 	100	%	 	 	245	 	 	 	- 4	%	
 
 	 	Q3 2018	 	 	% of Total	 	 	Q2 2018	 	 	Change	 	
Gas (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	337	 	 	 	32	%	 	 	329	 	 	 	+2	%	
Delaware Basin	 	 	103	 	 	 	10	%	 	 	94	 	 	 	+9	%	
Rockies Oil	 	 	18	 	 	 	2	%	 	 	13	 	 	 	+42	%	
Heavy Oil	 	 	11	 	 	 	1	%	 	 	12	 	 	 	- 3	%	
Eagle Ford	 	 	84	 	 	 	8	%	 	 	74	 	 	 	+13	%	
Barnett Shale	 	 	447	 	 	 	43	%	 	 	447	 	 	 	+0	%	
Other	 	 	1	 	 	 	0	%	 	 	1	 	 	 	- 34	%	
Retained assets	 	 	1,001	 	 	 	96	%	 	 	970	 	 	 	+3	%	
U.S. divested assets	 	 	45	 	 	 	4	%	 	 	158	 	 	 	- 71	%	
Total	 	 	1,046	 	 	 	100	%	 	 	1,128	 	 	 	- 7	%	
 
 	 	Q3 2018	 	 	% of Total	 	 	Q2 2018	 	 	Change	 	
NGLs (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	40	 	 	 	36	%	 	 	37	 	 	 	+10	%	
Delaware Basin	 	 	19	 	 	 	16	%	 	 	15	 	 	 	+21	%	
Rockies Oil	 	 	2	 	 	 	1	%	 	 	1	 	 	 	+26	%	
Eagle Ford	 	 	15	 	 	 	14	%	 	 	13	 	 	 	+16	%	
Barnett Shale	 	 	30	 	 	 	27	%	 	 	31	 	 	 	- 2	%	
Other	 	 	1	 	 	 	1	%	 	 	1	 	 	 	- 20	%	
Retained assets	 	 	107	 	 	 	95	%	 	 	98	 	 	 	+9	%	
U.S. divested assets	 	 	6	 	 	 	5	%	 	 	11	 	 	 	- 43	%	
Total	 	 	113	 	 	 	100	%	 	 	109	 	 	 	+3	%	
 
 	 	Q3 2018	 	 	% of Total	 	 	Q2 2018	 	 	Change	 	
Combined (MBoe/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	126	 	 	 	24	%	 	 	125	 	 	 	+1	%	
Delaware Basin	 	 	79	 	 	 	15	%	 	 	76	 	 	 	+5	%	
Rockies Oil	 	 	19	 	 	 	4	%	 	 	16	 	 	 	+17	%	
Heavy Oil	 	 	104	 	 	 	20	%	 	 	111	 	 	 	- 6	%	
Eagle Ford	 	 	60	 	 	 	12	%	 	 	54	 	 	 	+12	%	
Barnett Shale	 	 	105	 	 	 	20	%	 	 	105	 	 	 	- 0	%	
Other	 	 	7	 	 	 	1	%	 	 	8	 	 	 	- 19	%	
Retained assets	 	 	500	 	 	 	96	%	 	 	495	 	 	 	+1	%	
U.S. divested assets	 	 	22	 	 	 	4	%	 	 	46	 	 	 	- 53	%	
Total	 	 	522	 	 	 	100	%	 	 	541	 	 	 	- 4	%	
 
Strong performance in the Eagle Ford, Delaware Basin and Rockies drove retained asset production growth during the third quarter of 2018. These production gains were offset by the effects of facility repairs and other maintenance work at the Jackfish 1 facility as well as by lower production volumes associated with U.S. divested assets.
Field Prices
 	 	Q3 2018	 	 	Realization	 	 	Q2  2018	 	 	Change	 	
Oil and bitumen (per Bbl)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
WTI index	 	$	69.60	 	 	 	 	 	 	$	67.83	 	 	+3%	 	
Access Western Blend index	 	$	43.92	 	 	 	 	 	 	$	45.56	 	 	- 4%	 	
U.S.	 	$	64.80	 	 	93%	 	 	$	65.41	 	 	- 1%	 	
Canada	 	$	31.77	 	 	46%	 	 	$	31.70	 	 	+0%	 	
Realized price, unhedged	 	$	50.47	 	 	73%	 	 	$	50.43	 	 	+0%	 	
Cash settlements	 	$	(3.04	)	 	 	 	 	 	$	(5.80	)	 	 	 	 	
Realized price, with hedges	 	$	47.43	 	 	68%	 	 	$	44.63	 	 	+6%	 	
 
 	 	Q3 2018	 	 	Realization	 	 	Q2 2018	 	 	Change	 	
Gas (per Mcf)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Henry Hub index	 	$	2.91	 	 	 	 	 	 	$	2.80	 	 	 	+4	%	
Realized price, unhedged	 	$	2.19	 	 	 	75%	 	 	$	2.01	 	 	 	+9	%	
Cash settlements	 	$	0.01	 	 	 	 	 	 	$	0.13	 	 	 	 	 	
Realized price, with hedges	 	$	2.20	 	 	 	76%	 	 	$	2.14	 	 	 	+3	%	
 
 	 	Q3 2018	 	 	Realization	 	 	Q2 2018	 	 	Change	 	
NGLs (per Bbl)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mont Belvieu blended index (1)	 	$	33.05	 	 	 	 	 	 	$	28.05	 	 	+18%	 	
Realized price, unhedged	 	$	29.59	 	 	90%	 	 	$	24.10	 	 	+23%	 	
Cash settlements	 	$	(2.50	)	 	 	 	 	 	$	(1.66	)	 	 	 	 	
Realized price, with hedges	 	$	27.09	 	 	82%	 	 	$	22.44	 	 	+21%	 	
(1)	Based upon composition of our NGL barrel.	

 
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 	 	Q3 2018	 	 	Q2 2018	 	 	Change	 	
Combined (per Boe)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	$	34.06	 	 	$	31.97	 	 	 	+7	%	
Canada	 	$	31.24	 	 	$	31.17	 	 	 	+0	%	
Realized price, unhedged	 	$	33.50	 	 	$	31.81	 	 	 	+5	%	
Cash settlements	 	$	(1.89	)	 	$	(2.68	)	 	 	 	 	
Realized price, with hedges	 	$	31.61	 	 	$	29.13	 	 	 	+8	%	
 
Commodity index prices improved in the third quarter of 2018 compared to the second quarter of 2018. Primarily driven by a 23% increase in our realized NGL price, our oil, gas and NGL sales increased $68 million.
Hedging
 	 	Q3 2018	 	 	Q2 2018	 	
 	 	 	 	 	 	 	 	 	
Oil	 	$	(66	)	 	$	(129	)	
Natural gas	 	 	1	 	 	 	14	 	
NGL	 	 	(26	)	 	 	(16	)	
Total cash settlements	 	 	(91	)	 	 	(131	)	
Valuation changes	 	 	(185	)	 	 	(366	)	
Total	 	$	(276	)	 	$	(497	)	
 
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report.  
 
In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves.
 
Production Expenses
 	 	Q3 2018	 	 	Q2 2018	 	 	Change	 	
LOE	 	$	234	 	 	$	269	 	 	 	- 13	%	
Gathering, processing & transportation	 	 	219	 	 	 	224	 	 	 	- 2	%	
Production taxes	 	 	82	 	 	 	67	 	 	 	+23	%	
Property taxes	 	 	19	 	 	 	12	 	 	 	+61	%	
Total	 	$	554	 	 	$	572	 	 	 	- 3	%	
Per Boe:	 	 	 	 	 	 	 	 	 	 	 	 	
LOE	 	$	4.89	 	 	$	5.45	 	 	 	- 10	%	
Gathering, processing &
   transportation	 	$	4.55	 	 	$	4.55	 	 	 	+0	%	
Percent of oil, gas and NGL sales:	 	 	 	 	 	 	 	 	 	 	 	 	
Production taxes	 	 	5.1	%	 	 	4.2	%	 	 	+20	%	
LOE decreased primarily due to the scheduled turnaround expenses incurred at our Jackfish 1 facility during the second quarter of 2018. Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed. The increase in Oklahoma severance tax rates that became effective during the third quarter of 2018 also contributed to the increase on an absolute dollar basis and as a percentage of oil, gas and NGL sales. Property taxes increased on our Texas properties.

Exploration Expenses	
 
 	 	Q3 2018	 	 	Q2 2018	 	 	Change	 	
Unproved impairments	 	$	15	 	 	$	53	 	 	 	- 72	%	
Geological and geophysical	 	 	1	 	 	 	6	 	 	 	- 83	%	
Exploration overhead and other	 	 	16	 	 	 	9	 	 	 	+78	%	
Total	 	$	32	 	 	$	68	 	 	 	- 53	%	
 
Unproved impairments primarily relate to certain non-core acreage in the U.S. that we no longer intend to pursue for exploration opportunities.
 
Other	
 
 	 	Q3 2018	 	 	Q2 2018	 	 	Change	 	
Asset impairments	 	$	2	 	 	$	154	 	 	 	- 99	%	
Asset dispositions	 	 	(6	)	 	 	23	 	 	 	- 126	%	
Restructuring and transaction costs	 	 	11	 	 	 	94	 	 	 	- 88	%	
Other	 	 	(31	)	 	 	24	 	 	 	- 229	%	
Total	 	$	(24	)	 	$	295	 	 	 	- 108	%	
 
Other decreased as we did not recognize material asset impairments or restructuring and transaction costs during the third quarter of 2018. See Note 6 and  Note 7 , respectively, in “Part I. Financial Information – Item 1. Financial Statements” in this report for additional information.
 
Income Taxes	
 
 	 	Q3 2018	 	 	Q2 2018	 	
Current benefit	 	$	(24	)	 	$	(27	)	
Deferred expense (benefit)	 	 	(114	)	 	 	20	 	
Total benefit	 	$	(138	)	 	$	(7	)	
Effective income tax rate	 	 	(85	%)	 	 	1	%	
 
For discussion on income taxes, see Note 9 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
 
Discontinued Operations	
 
Discontinued operations net earnings increased primarily due to the gain on the sale of our aggregate ownership interests in EnLink and the General Partner for $2.6 billion ($2.2 billion after-tax). For discussion on discontinued operations, see Note 20 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
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Results of Operations – 2018 vs. 2017
 
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.
 
Q3 2018 vs. Q3 2017
 
The graph below shows the change in net earnings from the three months ended September 30, 2017 to the three months ended September 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 37.

* Other includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses.
 
Net earnings increased $2.4 billion during the third quarter of 2018 compared to the third quarter of 2017. The increase primarily related to a $2.2 billion increase in discontinued operations, a $151 million decrease in income taxes and a $125 million increase in upstream operations. These changes were partially offset by a $216 million change in other items. During the third quarter of 2018, we recognized a $2.6 billion ($2.2 billion after-tax) gain from the sale of our aggregate ownership interests in EnLink and the General Partner. Our income taxes decreased due to the release of our valuation allowance resulting from the gain on the sale of our aggregate ownership interests in EnLink and the General Partner. Upstream operations increased due to a 45% increase in the WTI pricing index, as well as a 95% increase in the realized NGL price, both of which contributed to a $341 million higher field price effect. The higher field prices were partially offset by $132 million of valuation changes and cash settlements for commodity derivatives and a $106 million increase in production expenses. Other items changed due to gains on asset dispositions in the third quarter of 2017 that did not repeat in 2018.

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September 30, 2018 YTD vs. September 30, 2017 YTD
 
The graph below shows the change in net earnings from the nine months ended September 30, 2017 to the nine months ended September 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 37.

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

Net earnings increased approximately $1.3 billion during the nine months ended 2018 compared to the same period in 2017. The increase largely related to a $2.4 billion increase in discontinued operations, partially offset by a $572 million change in other items, $563 million decrease in upstream operations and $286 million increase in financing costs, net. During the third quarter of 2018, we recognized a $2.6 billion ($2.2 billion after-tax) gain from the sale of our aggregate ownership interests in EnLink and the General Partner. Other changed primarily due to $156 million of asset impairments and $105 million of restructuring charges during the first nine months of 2018 and an approximately $200 million net gain recognized during the first nine months of 2017. Upstream operations decreased due to $1.0 billion of valuation changes and cash settlements for commodity derivatives and a $309 million increase in production expenses, partially offset by a $743 million higher field price effect. The higher field prices were supported by a 34% increase in our U.S. oil price as well as a 75% increase in our NGL price. Additionally, our STACK and Delaware Basin assets improved production by 28% to increase revenues from retained production volumes over the first nine months of 2018 compared to the same time period in 2017. Financing costs, net increased $286 million primarily from $312 million of early retirement costs associated with our approximately $830 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 $66 million on an annualized basis.

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Upstream Operations	
The supplemental graphs and charts below present the drivers and details of the upstream operations changes discussed in the previous section.
 
Q3 2018 vs. Q3 2017

* 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 $64 million during the three months ended 2018 with no impact to net earnings.
 
September 30, 2018 YTD vs. September 30, 2017 YTD

 
* 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 $191 million during the nine months ended 2018 with no impact to net earnings.
 
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Production Volumes
 
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	% of Total	 	 	2017	 	 	Change	 	 	2018	 	 	% of Total	 	 	2017	 	 	Change	 	
Oil and bitumen (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	29	 	 	 	12	%	 	 	26	 	 	 	+10	%	 	 	32	 	 	 	13	%	 	 	24	 	 	 	+36	%	
Delaware Basin	 	 	44	 	 	 	19	%	 	 	30	 	 	 	+45	%	 	 	41	 	 	 	17	%	 	 	29	 	 	 	+40	%	
Rockies Oil	 	 	15	 	 	 	6	%	 	 	9	 	 	 	+64	%	 	 	14	 	 	 	6	%	 	 	9	 	 	 	+50	%	
Heavy Oil	 	 	16	 	 	 	7	%	 	 	18	 	 	 	- 11	%	 	 	17	 	 	 	7	%	 	 	18	 	 	 	- 4	%	
Eagle Ford	 	 	31	 	 	 	13	%	 	 	28	 	 	 	+11	%	 	 	27	 	 	 	11	%	 	 	36	 	 	 	- 24	%	
Barnett Shale	 	 	—	 	 	 	0	%	 	 	1	 	 	 	- 100	%	 	 	1	 	 	 	0	%	 	 	1	 	 	 	- 14	%	
Other	 	 	6	 	 	 	3	%	 	 	7	 	 	 	- 10	%	 	 	6	 	 	 	3	%	 	 	7	 	 	 	- 7	%	
Retained assets	 	 	141	 	 	 	60	%	 	 	119	 	 	 	+18	%	 	 	138	 	 	 	57	%	 	 	124	 	 	 	+12	%	
U.S. divested assets	 	 	8	 	 	 	4	%	 	 	11	 	 	 	- 28	%	 	 	9	 	 	 	4	%	 	 	11	 	 	 	- 17	%	
Total Oil	 	 	149	 	 	 	64	%	 	 	130	 	 	 	+15	%	 	 	147	 	 	 	61	%	 	 	135	 	 	 	+9	%	
Bitumen	 	 	86	 	 	 	36	%	 	 	103	 	 	 	- 17	%	 	 	96	 	 	 	39	%	 	 	109	 	 	 	- 12	%	
Total Oil and bitumen	 	 	235	 	 	 	100	%	 	 	233	 	 	 	+1	%	 	 	243	 	 	 	100	%	 	 	244	 	 	 	- 0	%	
Gas (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	337	 	 	 	32	%	 	 	304	 	 	 	+11	%	 	 	330	 	 	 	30	%	 	 	290	 	 	 	+14	%	
Delaware Basin	 	 	103	 	 	 	10	%	 	 	86	 	 	 	+20	%	 	 	97	 	 	 	9	%	 	 	87	 	 	 	+12	%	
Rockies Oil	 	 	18	 	 	 	2	%	 	 	6	 	 	 	+176	%	 	 	14	 	 	 	1	%	 	 	9	 	 	 	+59	%	
Heavy Oil	 	 	11	 	 	 	1	%	 	 	16	 	 	 	- 27	%	 	 	12	 	 	 	1	%	 	 	17	 	 	 	- 32	%	
Eagle Ford	 	 	84	 	 	 	8	%	 	 	86	 	 	 	- 2	%	 	 	74	 	 	 	7	%	 	 	97	 	 	 	- 24	%	
Barnett Shale	 	 	447	 	 	 	43	%	 	 	484	 	 	 	- 8	%	 	 	450	 	 	 	40	%	 	 	482	 	 	 	- 7	%	
Other	 	 	1	 	 	 	0	%	 	 	1	 	 	 	- 29	%	 	 	1	 	 	 	0	%	 	 	1	 	 	 	+27	%	
Retained assets	 	 	1,001	 	 	 	96	%	 	 	983	 	 	 	+2	%	 	 	978	 	 	 	88	%	 	 	983	 	 	 	- 1	%	
U.S. divested assets	 	 	45	 	 	 	4	%	 	 	218	 	 	 	- 79	%	 	 	139	 	 	 	12	%	 	 	229	 	 	 	- 39	%	
Total	 	 	1,046	 	 	 	100	%	 	 	1,201	 	 	 	- 13	%	 	 	1,117	 	 	 	100	%	 	 	1,212	 	 	 	- 8	%	
NGLs (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	40	 	 	 	36	%	 	 	31	 	 	 	+30	%	 	 	38	 	 	 	35	%	 	 	29	 	 	 	+30	%	
Delaware Basin	 	 	19	 	 	 	16	%	 	 	10	 	 	 	+79	%	 	 	15	 	 	 	14	%	 	 	10	 	 	 	+56	%	
Rockies Oil	 	 	2	 	 	 	1	%	 	 	1	 	 	 	+83	%	 	 	1	 	 	 	1	%	 	 	1	 	 	 	+68	%	
Eagle Ford	 	 	15	 	 	 	14	%	 	 	12	 	 	 	+30	%	 	 	12	 	 	 	12	%	 	 	12	 	 	 	- 1	%	
Barnett Shale	 	 	30	 	 	 	27	%	 	 	26	 	 	 	+15	%	 	 	30	 	 	 	28	%	 	 	31	 	 	 	- 2	%	
Other	 	 	1	 	 	 	1	%	 	 	2	 	 	 	- 44	%	 	 	1	 	 	 	1	%	 	 	1	 	 	 	- 25	%	
Retained assets	 	 	107	 	 	 	95	%	 	 	82	 	 	 	+31	%	 	 	97	 	 	 	91	%	 	 	84	 	 	 	+16	%	
U.S. divested assets	 	 	6	 	 	 	5	%	 	 	12	 	 	 	- 51	%	 	 	9	 	 	 	9	%	 	 	12	 	 	 	- 25	%	
Total	 	 	113	 	 	 	100	%	 	 	94	 	 	 	+20	%	 	 	106	 	 	 	100	%	 	 	96	 	 	 	+10	%	
Combined (MBoe/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	126	 	 	 	24	%	 	 	108	 	 	 	+16	%	 	 	125	 	 	 	23	%	 	 	101	 	 	 	+24	%	
Delaware Basin	 	 	79	 	 	 	15	%	 	 	55	 	 	 	+45	%	 	 	72	 	 	 	13	%	 	 	53	 	 	 	+35	%	
Rockies Oil	 	 	19	 	 	 	4	%	 	 	11	 	 	 	+76	%	 	 	18	 	 	 	3	%	 	 	11	 	 	 	+55	%	
Heavy Oil	 	 	104	 	 	 	20	%	 	 	124	 	 	 	- 16	%	 	 	115	 	 	 	22	%	 	 	130	 	 	 	- 11	%	
Eagle Ford	 	 	60	 	 	 	12	%	 	 	54	 	 	 	+11	%	 	 	52	 	 	 	10	%	 	 	65	 	 	 	- 20	%	
Barnett Shale	 	 	105	 	 	 	20	%	 	 	107	 	 	 	- 2	%	 	 	105	 	 	 	20	%	 	 	111	 	 	 	- 5	%	
Other	 	 	7	 	 	 	1	%	 	 	8	 	 	 	- 18	%	 	 	7	 	 	 	1	%	 	 	8	 	 	 	- 7	%	
Retained assets	 	 	500	 	 	 	96	%	 	 	467	 	 	 	+7	%	 	 	494	 	 	 	92	%	 	 	479	 	 	 	+3	%	
U.S. divested assets	 	 	22	 	 	 	4	%	 	 	60	 	 	 	- 64	%	 	 	42	 	 	 	8	%	 	 	63	 	 	 	- 34	%	
Total	 	 	522	 	 	 	100	%	 	 	527	 	 	 	- 1	%	 	 	536	 	 	 	100	%	 	 	542	 	 	 	- 1	%	
 
Focused development activities in the STACK, Delaware Basin and Rockies resulted in an approximate 30% increase in production from those areas compared to the three months and nine 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
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production decreases related to facility repairs and other maintenance work at the Jackfish 1 facility as well as volumes associated with U.S. divested assets.
Field Prices
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	Realization	 	 	2017	 	 	Change	 	 	2018	 	 	Realization	 	 	2017	 	 	Change	 	
Oil and bitumen (per Bbl)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
WTI index	 	$	69.60	 	 	 	 	 	 	$	48.14	 	 	 	+45	%	 	$	66.79	 	 	 	 	 	 	$	49.48	 	 	 	+35	%	
Access Western Blend index	 	$	43.92	 	 	 	 	 	 	$	36.27	 	 	 	+21	%	 	$	41.64	 	 	 	 	 	 	$	35.55	 	 	 	+17	%	
U.S.	 	$	64.80	 	 	 	93%	 	 	$	47.12	 	 	 	+38	%	 	$	64.09	 	 	 	96%	 	 	$	47.84	 	 	 	+34	%	
Canada	 	$	31.77	 	 	 	46%	 	 	$	32.25	 	 	 	- 1	%	 	$	27.22	 	 	 	41%	 	 	$	29.10	 	 	 	- 6	%	
Realized price, unhedged	 	$	50.47	 	 	 	73%	 	 	$	39.36	 	 	 	+28	%	 	$	46.95	 	 	 	70%	 	 	$	38.08	 	 	 	+23	%	
Cash settlements	 	$	(3.04	)	 	 	 	 	 	$	0.54	 	 	 	 	 	 	$	(2.97	)	 	 	 	 	 	$	0.45	 	 	 	 	 	
Realized price, with hedges	 	$	47.43	 	 	 	68%	 	 	$	39.90	 	 	 	+19	%	 	$	43.98	 	 	 	66%	 	 	$	38.53	 	 	 	+14	%	
Gas (per Mcf)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Henry Hub index	 	$	2.91	 	 	 	 	 	 	$	2.99	 	 	 	- 3	%	 	$	2.90	 	 	 	 	 	 	$	3.17	 	 	 	- 9	%	
Realized price, unhedged	 	$	2.19	 	 	 	75%	 	 	$	2.45	 	 	 	- 10	%	 	$	2.21	 	 	 	76%	 	 	$	2.54	 	 	 	- 13	%	
Cash settlements	 	$	0.01	 	 	 	 	 	 	$	0.12	 	 	 	 	 	 	$	0.10	 	 	 	 	 	 	$	0.05	 	 	 	 	 	
Realized price, with hedges	 	$	2.20	 	 	 	76%	 	 	$	2.57	 	 	 	- 15	%	 	$	2.31	 	 	 	80%	 	 	$	2.59	 	 	 	- 11	%	
NGLs (per Bbl)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mont Belvieu blended index (1)	 	$	33.05	 	 	 	 	 	 	$	24.76	 	 	 	+33	%	 	$	28.99	 	 	 	 	 	 	$	23.49	 	 	 	+23	%	
Realized price, unhedged	 	$	29.59	 	 	 	90%	 	 	$	15.15	 	 	 	+95	%	 	$	25.60	 	 	 	88%	 	 	$	14.62	 	 	 	+75	%	
Cash settlements	 	$	(2.50	)	 	 	 	 	 	$	(0.03	)	 	 	 	 	 	$	(1.62	)	 	 	 	 	 	$	(0.02	)	 	 	 	 	
Realized price, with hedges	 	$	27.09	 	 	 	82%	 	 	$	15.12	 	 	 	+79	%	 	$	23.98	 	 	 	83%	 	 	$	14.60	 	 	 	+64	%	
Combined (per Boe)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	$	34.06	 	 	 	 	 	 	$	23.85	 	 	 	+43	%	 	$	32.16	 	 	 	 	 	 	$	24.44	 	 	 	+32	%	
Canada	 	$	31.24	 	 	 	 	 	 	$	31.59	 	 	 	- 1	%	 	$	26.79	 	 	 	 	 	 	$	28.50	 	 	 	- 6	%	
Realized price, unhedged	 	$	33.50	 	 	 	 	 	 	$	25.67	 	 	 	+30	%	 	$	31.00	 	 	 	 	 	 	$	25.41	 	 	 	+22	%	
Cash settlements	 	$	(1.89	)	 	 	 	 	 	$	0.52	 	 	 	 	 	 	$	(1.44	)	 	 	 	 	 	$	0.29	 	 	 	 	 	
Total	 	$	31.61	 	 	 	 	 	 	$	26.19	 	 	 	+21	%	 	$	29.56	 	 	 	 	 	 	$	25.70	 	 	 	+15	%	

 	(1)	Based upon composition of our NGL barrel.	
Hedging
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Cash settlements:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil derivatives	 	$	(66	)	 	$	11	 	 	$	(197	)	 	$	29	 	
Gas derivatives	 	 	1	 	 	 	13	 	 	 	33	 	 	 	14	 	
NGL derivatives	 	 	(26	)	 	 	—	 	 	 	(47	)	 	 	—	 	
Total cash settlements	 	 	(91	)	 	 	24	 	 	 	(211	)	 	 	43	 	
Valuation changes	 	 	(185	)	 	 	(168	)	 	 	(603	)	 	 	171	 	
Oil, gas and NGL derivatives	 	$	(276	)	 	$	(144	)	 	$	(814	)	 	$	214	 	
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Production Expenses
 	 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	 	2018	 	 	2017	 	 	Change	 	 	2018	 	 	2017	 	 	Change	 	
LOE	 	$	234	 	 	$	229	 	 	 	+2	%	 	$	744	 	 	$	691	 	 	 	+8	%	
Gathering, processing & transportation	 	 	219	 	 	 	162	 	 	 	+35	%	 	 	671	 	 	 	485	 	 	 	+38	%	
Production taxes	 	 	82	 	 	 	46	 	 	 	+81	%	 	 	208	 	 	 	142	 	 	 	+46	%	
Property taxes	 	 	19	 	 	 	11	 	 	 	+72	%	 	 	46	 	 	 	42	 	 	 	+9	%	
Total	 	$	554	 	 	$	448	 	 	 	+24	%	 	$	1,669	 	 	$	1,360	 	 	 	+23	%	
Per Boe:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
LOE	 	$	4.89	 	 	$	4.71	 	 	 	+4	%	 	$	5.09	 	 	$	4.67	 	 	 	+9	%	
Gathering, processing & transportation	 	$	4.55	 	 	$	3.34	 	 	 	+36	%	 	$	4.58	 	 	$	3.27	 	 	 	+40	%	
Percent of oil, gas and NGL sales:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production taxes	 	 	5.1	%	 	 	3.7	%	 	 	+37	%	 	 	4.6	%	 	 	3.8	%	 	 	+21	%	
 
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 $64 million and $191 million, respectively, during the three months and nine months ended 2018 with no impact to net earnings. Additionally, increases in the effective severance tax rates in Oklahoma contributed to higher production taxes during 2018.
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, 2018 and 2017.
 	 	Three months ended September 30,	 	 	Nine months ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Operating cash flow from continuing operations	 	$	807	 	 	$	501	 	 	$	1,686	 	 	$	1,656	 	
Effect of exchange rate and other	 	 	7	 	 	 	11	 	 	 	175	 	 	 	(45	)	
Divestitures of property and equipment	 	 	89	 	 	 	280	 	 	 	696	 	 	 	387	 	
Capital expenditures	 	 	(598	)	 	 	(467	)	 	 	(1,851	)	 	 	(1,298	)	
Acquisitions of property and equipment	 	 	(19	)	 	 	(6	)	 	 	(35	)	 	 	(39	)	
Debt activity, net	 	 	(21	)	 	 	—	 	 	 	(1,132	)	 	 	—	 	
Common stock dividends	 	 	(38	)	 	 	(30	)	 	 	(112	)	 	 	(95	)	
Repurchases of common stock	 	 	(1,698	)	 	 	—	 	 	 	(2,197	)	 	 	—	 	
Net change in cash, cash equivalents and restricted cash
   from discontinued operations	 	 	3,067	 	 	 	196	 	 	 	3,207	 	 	 	329	 	
Net change in cash, cash equivalents and restricted cash	 	$	1,596	 	 	$	485	 	 	$	437	 	 	$	895	 	
Cash, cash equivalents and restricted cash at end of period	 	$	3,121	 	 	$	2,854	 	 	$	3,121	 	 	$	2,854	 	
 
Operating Cash Flow
 
Net cash provided by operating activities continued to be a significant source of capital and liquidity during 2018.
 
Our operating cash flow increased $306 million or approximately 60% in the third quarter of 2018 as compared to the same time period of 2017. Additionally, our operating cash flow fully funded our capital expenditure program during the third quarter of 2018.
 
The nine months ended September 30, 2018 operating cash flows included a realized foreign exchange loss of $243 million relating to foreign currency denominated intercompany loan activity as described in Note 8 in “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.
 
Subsequent to the third quarter of 2018, market forces have widened Canadian heavy oil differentials beyond historical norms and negatively impacted the price we are realizing on our Canadian production. We currently have basis swaps for approximately half our forecasted fourth quarter 2018 production and approximately 20% of our forecasted 2019 production that mitigate the effect of the lower market price. To further mitigate the effects of the lower price, we reduced our Jackfish production in November 2018, which
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will impact fourth quarter production by approximately 8,000 Bbls/d. Should the price decline continue, we could extend production curtailments in future periods. We are also working to enter into firm transport and other agreements that would also mitigate the lower localized price effects.
Divestitures of Property and Equipment
During the first nine months of 2018, we sold non-core U.S. assets, including certain Barnett Shale assets, for approximately $700 million, net of customary purchase price adjustments. For additional information, please see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report. During the first nine months of 2017, we sold non-core U.S. assets for $387 million, net of customary purchase price adjustments.
Capital Expenditures and Acquisitions of Property and Equipment
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
 
 	 	Three months ended September 30,	 	 	Nine months ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Oil and gas	 	$	592	 	 	$	440	 	 	$	1,817	 	 	$	1,237	 	
Corporate and other	 	 	6	 	 	 	27	 	 	 	34	 	 	 	61	 	
Total capital expenditures	 	$	598	 	 	$	467	 	 	$	1,851	 	 	$	1,298	 	
Acquisitions	 	$	19	 	 	$	6	 	 	$	35	 	 	$	39	 	
 
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.
Debt Activity
During the first nine months of 2018, our debt decreased $828 million due to completed tender offers of certain long-term debt as well as the maturity of certain senior notes. In conjunction with the tender offers, we recognized a $312 million loss on the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Shareholder Distributions and Stock Activity
The following table summarizes our common stock dividends during the first nine months of 2018 and 2017. In the second quarter of 2018, we increased the quarterly dividend to $0.08 per share.
 	Amounts	 	 	Rate Per Share	 	
Quarter Ended 2018:	 	 	 	 	 	 	 	
First quarter 2018	$	32	 	 	$	0.06	 	
Second quarter 2018	 	42	 	 	$	0.08	 	
Third quarter 2018	 	38	 	 	$	0.08	 	
Total year-to-date	$	112	 	 	 	 	 	
Quarter Ended 2017:	 	 	 	 	 	 	 	
First quarter 2017	$	32	 	 	$	0.06	 	
Second quarter 2017	 	33	 	 	$	0.06	 	
Third quarter 2017	 	30	 	 	$	0.06	 	
Total year-to-date	$	95	 	 	 	 	 	
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 increased our program by an additional $3.0 billion, bringing the total to $4.0 billion. The share repurchase program expires December 31, 2019.
As discussed further in Note 19 in “Part I. Financial Information – Item 1. Financial Statements” in this report we entered into and completed an ASR transaction to repurchase $1.0 billion shares, during the third quarter of 2018. Including unsettled shares, we
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repurchased 54.5 million shares of common stock for $2.2 billion, or $40.94 per share, under the ASR agreement and through open-market share repurchases through September 30, 2018.
Cash Flows from Discontinued Operations
All cash flows in the following table relate to activities of EnLink and the General Partner.
 
 	 	Three months ended September 30,	 	 	Nine months ended September 30,	 	
 	 	2018	 	 	2017	 	 	2018	 	 	2017	 	
Cash flows from discontinued operations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	46	 	 	$	200	 	 	$	476	 	 	$	528	 	
Investing activities	 	 	2,950	 	 	 	(191	)	 	 	2,548	 	 	 	(475	)	
Financing activities	 	 	71	 	 	 	187	 	 	 	183	 	 	 	276	 	
Net change in cash, cash equivalents and
   restricted cash of discontinued operations:	 	$	3,067	 	 	$	196	 	 	$	3,207	 	 	$	329	 	
 
EnLink’s operating cash flow from the first nine months of 2018 decreased $52 million from the first nine months of 2017 as a result of the divestiture of our aggregate ownership interests in EnLink and the General Partner in July 2018.
 
Cash flows from investing activities includes $3.125 billion received from the divestiture of our aggregate ownership interests in EnLink and the General Partner, partially offset by capital expenditures and other items. 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 nine months of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.
Devon received $134 million and $199 million in distributions from EnLink and the General Partner during the first nine months of 2018 and 2017, respectively. During the first nine months of 2017, EnLink issued and sold 5 million common units and generated $92 million in net proceeds, through its “at the market” programs. During the third quarter of 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.
Liquidity
Our primary sources of capital and liquidity are our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidity also include, among other things, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. Additionally, the sale of our aggregate ownership interests 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.
Operating Cash Flow
Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, bitumen, gas and NGLs we produce and sell. 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 30, 2018, see Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Divestitures of Property and Equipment
To further focus our resource-rich portfolio, we are targeting $5 billion of asset divestiture proceeds. As noted below, we made significant progress to achieving this goal during the first nine months of 2018.
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In May 2018, we 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 separate transaction within the Barnett, we formed a partnership in April 2018 under which we will monetize half our working interest across 116 gross undrilled locations for an approximate $75 million payment spread over the next five years. With this agreement, we will also drill and operate up to 24 wells per year.
During the third quarter of 2018, we closed the largest portion of our divestiture program by selling our aggregate ownership interests in EnLink and the General Partner for $3.125 billion.
Additionally, during the third quarter of 2018, we entered into definitive agreements to sell non-core Delaware Basin and Barnett Shale assets for approximately $320 million in the aggregate, before purchase price adjustments. These transactions subsequently closed in the fourth quarter of 2018.
Subsequent to September 30, 2018, we reached an agreement to sell a portion of our non-core U.S. assets for $100 million, before purchase price adjustments. The transaction is expected to close in the first quarter of 2019.
 
Overall, the transactions noted above, combined with other previously disclosed asset sales, generated approximately $4.7 billion of total divestiture proceeds. We also expect to monetize additional minor, non-core assets across our U.S. portfolio as we progress toward the $5 billion target.
Capital Expenditures
Our capital expenditures for the fourth quarter of 2018 are expected to range from $555 million to $665 million, inclusive of upstream capital ranging from $550 million to $650 million.
Credit Availability
As of September 30, 2018, we had approximately $2.9 billion of available borrowings under our 2012 Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At September 30, 2018, there were no borrowings under our commercial paper program, and we were in compliance with the facility’s financial covenant.
On October 5, 2018, we terminated our 2012 Senior Credit Facility and subsequently entered into a new $3.0 billion revolving 2018 Senior Credit Facility. The 2018 Senior Credit Facility contains similar terms as our 2012 Senior Credit Facility and matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items, including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Ba1 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
Share Repurchase Program
During March 2018, our Board of Directors authorized a $1.0 billion share repurchase program of our 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. Through October 31, 2018, we have executed $2.6 billion of the authorized $4.0 billion program. We expect to complete the $4.0 billion share repurchase program by early 2019.

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Critical Accounting Estimates
Income Taxes
As discussed in our 2017 Annual Report on Form 10-K , in December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a measurement period not to extend beyond one year after the enactment date of the Tax Reform Legislation. The 2017 U.S. federal tax return was filed subsequent to the end of the third quarter of 2018. With the completion of the 2017 federal return, Devon considers the accounting of the transition tax, deferred tax remeasurements and other items to now be substantially complete .
Absent unexpected events and unexpected effects of the Tax Reform Legislation, Devon expects a positive impact on its future after-tax earnings, primarily due to the lower federal statutory tax rate.
Non-GAAP Measures
We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2018 Results” in this Item 2 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our financial results. 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 20 in “Part I. Financial Information – Item 1. Financial Statements” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded relate to asset dispositions, the gain on the sale of Devon’s aggregate ownership interests in EnLink and the General Partner, noncash asset impairments (including noncash unproved asset impairments), deferred tax asset valuation allowance, costs associated with early retirement of debt, fair value changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with the 2018 workforce reduction and 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.
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Below are reconciliations of our core earnings and core earnings per share attributable to Devon to their comparable GAAP measures.
 	Three Months Ended September 30,	 	 	Nine Months Ended September 30,	 	
 	Before tax	 	 	After tax	 	 	After Noncontrolling Interests	 	 	Per Diluted Share	 	 	Before tax	 	 	After tax	 	 	After Noncontrolling Interests	 	 	Per Diluted Share	 	
2018	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) attributable to Devon (GAAP)	$	162	 	 	$	300	 	 	$	300	 	 	$	0.61	 	 	$	(564	)	 	$	(385	)	 	$	(385	)	 	$	(0.76	)	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset dispositions	 	(6	)	 	 	(5	)	 	 	(5	)	 	 	(0.01	)	 	 	5	 	 	 	4	 	 	 	4	 	 	 	0.01	 	
Asset and exploration impairments	 	20	 	 	 	17	 	 	 	17	 	 	 	0.03	 	 	 	237	 	 	 	183	 	 	 	183	 	 	 	0.36	 	
Deferred tax asset valuation allowance	 	—	 	 	 	(130	)	 	 	(130	)	 	 	(0.27	)	 	 	—	 	 	 	(51	)	 	 	(51	)	 	 	(0.10	)	
Early retirement of debt	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	312	 	 	 	240	 	 	 	240	 	 	 	0.47	 	
Fair value changes in financial
   instruments and foreign currency	 	158	 	 	 	119	 	 	 	119	 	 	 	0.25	 	 	 	595	 	 	 	470	 	 	 	470	 	 	 	0.91	 	
Restructuring and transaction costs	 	11	 	 	 	8	 	 	 	8	 	 	 	0.02	 	 	 	105	 	 	 	80	 	 	 	80	 	 	 	0.16	 	
Core earnings attributable to
   Devon (Non-GAAP)	$	345	 	 	$	309	 	 	$	309	 	 	$	0.63	 	 	$	690	 	 	$	541	 	 	$	541	 	 	$	1.05	 	
Discontinued Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings attributable to Devon (GAAP)	$	2,650	 	 	$	2,263	 	 	$	2,237	 	 	$	4.53	 	 	$	2,863	 	 	$	2,460	 	 	$	2,300	 	 	$	4.47	 	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gain on sale of EnLink and the General Partner	 	(2,607	)	 	 	(2,222	)	 	 	(2,222	)	 	 	(4.51	)	 	 	(2,607	)	 	 	(2,222	)	 	 	(2,222	)	 	 	(4.32	)	
Fair value changes, and minimum
   volume commitment settlement	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(34	)	 	 	(28	)	 	 	(10	)	 	 	(0.02	)	
Core earnings attributable to
   Devon (Non-GAAP)	$	43	 	 	$	41	 	 	$	15	 	 	$	0.02	 	 	$	222	 	 	$	210	 	 	$	68	 	 	$	0.13	 	
Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings attributable to Devon (GAAP)	$	2,812	 	 	$	2,563	 	 	$	2,537	 	 	$	5.14	 	 	$	2,299	 	 	$	2,075	 	 	$	1,915	 	 	$	3.71	 	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	183	 	 	 	9	 	 	 	9	 	 	 	0.02	 	 	 	1,254	 	 	 	926	 	 	 	926	 	 	 	1.81	 	
Discontinued Operations	 	(2,607	)	 	 	(2,222	)	 	 	(2,222	)	 	 	(4.51	)	 	 	(2,641	)	 	 	(2,250	)	 	 	(2,232	)	 	 	(4.34	)	
Core earnings attributable to Devon (Non-GAAP)	$	388	 	 	$	350	 	 	$	324	 	 	$	0.65	 	 	$	912	 	 	$	751	 	 	$	609	 	 	$	1.18	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2017	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings attributable to Devon (GAAP)	$	207	 	 	$	194	 	 	$	194	 	 	$	0.37	 	 	$	727	 	 	$	714	 	 	$	714	 	 	$	1.35	 	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset dispositions	 	(170	)	 	 	(108	)	 	 	(108	)	 	 	(0.21	)	 	 	(200	)	 	 	(127	)	 	 	(127	)	 	 	(0.24	)	
Asset and exploration impairments	 	18	 	 	 	11	 	 	 	11	 	 	 	0.02	 	 	 	80	 	 	 	50	 	 	 	50	 	 	 	0.10	 	
Deferred tax asset valuation allowance	 	—	 	 	 	(23	)	 	 	(23	)	 	 	(0.04	)	 	 	—	 	 	 	(178	)	 	 	(178	)	 	 	(0.34	)	
Fair value changes in financial
   instruments and foreign currency	 	99	 	 	 	35	 	 	 	35	 	 	 	0.07	 	 	 	(290	)	 	 	(231	)	 	 	(231	)	 	 	(0.44	)	
Core earnings attributable to
   Devon (Non-GAAP)	$	154	 	 	$	109	 	 	$	109	 	 	$	0.21	 	 	$	317	 	 	$	228	 	 	$	228	 	 	$	0.43	 	
Discontinued Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) attributable to Devon (GAAP)	$	20	 	 	$	18	 	 	$	(1	)	 	$	0.00	 	 	$	69	 	 	$	60	 	 	$	1	 	 	$	0.00	 	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset dispositions, impairments, fair value
   changes and early retirement of debt	 	9	 	 	 	7	 	 	 	4	 	 	$	0.00	 	 	 	(2	)	 	 	(1	)	 	 	(1	)	 	$	(0.00	)	
Core earnings attributable to
   Devon (Non-GAAP)	$	29	 	 	$	25	 	 	$	3	 	 	$	0.00	 	 	$	67	 	 	$	59	 	 	$	0	 	 	$	0.00	 	
Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings attributable to Devon (GAAP)	$	227	 	 	$	212	 	 	$	193	 	 	$	0.37	 	 	$	796	 	 	$	774	 	 	$	715	 	 	$	1.35	 	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	(53	)	 	 	(85	)	 	 	(85	)	 	 	(0.16	)	 	 	(410	)	 	 	(486	)	 	 	(486	)	 	 	(0.92	)	
Discontinued Operations	 	9	 	 	 	7	 	 	 	4	 	 	 	0.00	 	 	 	(2	)	 	 	(1	)	 	 	(1	)	 	 	(0.00	)	
Core earnings attributable to
   Devon (Non-GAAP)	$	183	 	 	$	134	 	 	$	112	 	 	$	0.21	 	 	$	384	 	 	$	287	 	 	$	228	 	 	$	0.43	 	
 
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
As of September 30, 2018, we have commodity derivatives that pertain to a portion of our production for the last three months of 2018, as well as for 2019 and 2020. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At September 30, 2018, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately $500 million.
Interest Rate Risk
As of September 30, 2018, we had total debt of $6.0 billion. All of this debt was based on fixed interest rates averaging 5.4%.
As of September 30, 2018, we had an open interest rate swap position that is presented in Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report. The fair value of our interest rate 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 30, 2018.
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our September 30, 2018 balance sheet.
Devon engages in intercompany loan activity between subsidiaries with different functional currencies. The value of these foreign currency denominated intercompany loans increases or decreases from the remeasurement into the subsidiaries’ functional currency. Based on the amount of the intercompany loans as of September 30, 2018, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of September 30, 2018 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. Other Information
Item 1. Legal Proceedings
We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.
 
Please see our 2017 Annual Report on Form 10-K for additional information.
Item 1A. Risk Factors
There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2017 Annual Report on Form 10-K .
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information regarding purchases of our common stock that were made by us during the third quarter of 2018 (shares in thousands).
Period	 	Total Number of
Shares Purchased  (1)	 	 	Average Price
Paid per Share	 	 	Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (2)	 	 	Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs  (2)	 	
July 1 - July 31	 	 	10,474	 	 	$	44.53	 	 	 	10,438	 	 	$	3,014	 	
August 1 - August 31	 	 	18,324	 	 	$	43.05	 	 	 	18,278	 	 	$	2,227	 	
September 1 - September 30	 	 	12,109	 	 	$	37.95	 	 	 	12,106	 	 	$	1,767	 	
Total	 	 	40,907	 	 	$	41.92	 	 	 	40,822	 	 	 	 	 	

 	(1)	In addition to shares purchased under the share repurchase program described below, these amounts also included 85,000 shares received by us from employees for the payment of personal income tax withholding on vesting transactions.	
 	(2)	On March 7, 2018, we announced a $1.0 billion share repurchase program. On June 6, 2018, we announced the expansion of this program to $4.0 billion with a December 31, 2019 expiration date. In August 2018, we entered into an ASR transaction to repurchase $1.0 billion shares which was completed in the third quarter. As of September 30, 2018, we had repurchased 54.5 million common shares for $2.2 billion, or $40.94 per share, through the ASR and through open-market share repurchases program. Future purchases under the program will be made in open market or private transactions, or through the use of ASR programs.	
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 6,200 shares of our common stock in the third quarter of 2018, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Devon Plan through open-market purchases.
Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In the third quarter of 2018, there were no shares purchased by Canadian employees.
Item 3. Defaults Upon Senior Securities
Not applicable.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Not applicable.
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Item 6. E xhibits
 
Exhibit
Number	 	Description	

31.1	 	Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
 	 	
31.2	 	Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
 	 	
32.1	 	Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
 	 	
32.2	 	Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
 	 	
101.INS	 	XBRL Instance Document – the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.	
 	 	
101.SCH	 	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.

 
 
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 	 	 	 	DEVON ENERGY CORPORATION	
 	 	 	
Date: November 7, 2018	 	 	 	/s/ Jeremy D. Humphers	
 	 	 	 	Jeremy D. Humphers	
 	 	 	 	Senior Vice President and Chief Accounting Officer	

49

Exhibit 31.1
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, David A. Hager, certify that:
1.     I have reviewed this quarterly report on Form 10-Q of Devon Energy Corporation;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
Date: November 7, 2018	 	 	
 	 	 	
 	 	/s/ David A. Hager	
 	 	David A. Hager	
 	 	President and Chief Executive Officer	

Exhibit 31.2
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Jeffrey L. Ritenour, certify that:
1.     I have reviewed this quarterly report on Form 10-Q of Devon Energy Corporation;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
Date: November 7, 2018	 	 	
 	 	 	
 	 	/s/ Jeffrey L. Ritenour	
 	 	Jeffrey L. Ritenour	
 	 	Executive Vice President and Chief Financial Officer	

Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Report of Devon Energy Corporation (“Devon”) on Form 10-Q for the period ended September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David A. Hager, President and Chief Executive Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
 	(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

 	
/s/ David A. Hager	
David A. Hager	
President and Chief Executive Officer	
November 7, 2018	

Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Report of Devon Energy Corporation (“Devon”) on Form 10-Q for the period ended September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey L. Ritenour, Executive Vice President and Chief Financial Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
 	(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

 	
/s/ Jeffrey L. Ritenour	
Jeffrey L. Ritenour	
Executive Vice President and Chief Financial Officer	
November 7, 2018