UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): November 6, 2018

DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)

 
					
DELAWARE	 	001-32318	 	73-1567067	
(State or Other Jurisdiction
of Incorporation)	 	(Commission
File Number)	 	(IRS Employer
Identification Number)	
		
333 W. SHERIDAN AVE., OKLAHOMA CITY,
OKLAHOMA	 	73102-5015	
(Address of Principal Executive Offices)	 	(Zip Code)	
Registrant’s telephone number, including area code: (405) 235-3611
Not Applicable
(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instructions A-2. Below):
 
 	☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)	
 
 	☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)	
 
 	☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))	
 
 	☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).
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.  ☐

 

Item 2.02	Results of Operations and Financial Condition.	
On November 6, 2018, Devon Energy Corporation (the “Company”) issued a press release announcing its financial and operational results for the quarter ended September 30, 2018. In connection with the earnings release, the Company also provided its operations report for the third quarter of 2018. Copies of the earnings release and third quarter 2018 operations report are furnished as Exhibits 99.1 and 99.2, respectively, to this report and will be available on the Company’s website at www.devonenergy.com.
The information contained in this report and the exhibits hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing.
 
Item 7.01	Regulation FD Disclosure.	
The information in Item 2.02 above is incorporated herein by reference.
 
Item 9.01	Financial Statements and Exhibits.	
(d)  Exhibits

	Exhibit
No.	  		Description of Exhibits	
			
99.1	  	Earnings release, dated November 6, 2018.		
			
99.2	  	Third quarter 2018 operations report.		

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 hereunto duly authorized.

DEVON ENERGY CORPORATION	
		
By:	 	/s/ Jeffrey L. Ritenour	
	 	Jeffrey L. Ritenour	
	 	Executive Vice President and Chief Financial Officer	
Date: November 6, 2018

Exhibit 99.1

NEWS RELEASE
Devon Energy Reports Third-Quarter 2018 Results
Highlights
 
 	•	 	Delaware Basin and Eagle Ford drive U.S. production outperformance	
 
 	•	 	Third-quarter upstream capital expenditures were 9 percent below guidance	
 
 	•	 	Operating cash flow expands 61 percent year over year to $807 million	
 
 	•	 	Free cash flow generation reaches $249 million in third quarter	
 
 	•	 	Stock-repurchase program on pace to decrease share count by 20 percent	
OKLAHOMA CITY – Nov. 6, 2018 – Devon Energy Corp. (NYSE: DVN) today reported operational and financial results for the third quarter of 2018. Also included within the release is the company’s guidance outlook for the fourth quarter of 2018.
“Devon continued to execute at a high level on its U.S.-focused growth initiatives,” said Dave Hager, president and CEO. “Our third-quarter performance was highlighted by improving well productivity and capital efficiency that drove U.S. production above the high end of guidance with a total capital investment well below forecast. Furthermore, our unwavering commitment to capital discipline allowed us to comfortably fund our drilling programs and generate free cash flow in the quarter.
“In addition to our strong operational and financial results, we also made significant progress building per-share value through our industry-leading $4 billion share-repurchase program,” Hager said. “Given the value proposition of our current share price, we opportunistically accelerated the buyback of our shares and are on track to repurchase approximately 20 percent of the company’s outstanding shares by the time we complete the program in the first quarter of 2019.”
Delaware Basin and Eagle Ford Drive U.S. Production Outperformance
Devon’s total companywide production averaged 522,000 oil-equivalent barrels (Boe) per day in the third quarter. With the company’s capital programs focused on expanding higher-margin production, oil and natural gas liquids (NGLs) volumes increased to 67 percent of the product mix.
Third-quarter production was highlighted by results from Devon’s U.S. resource plays, which are attaining the highest returns in the company’s portfolio. U.S. production averaged 418,000 Boe per day in the quarter, exceeding the company’s third-quarter guidance range, adjusted for asset sales, of 398,000 to 417,000 Boe per day.
Within Devon’s diversified U.S. portfolio, the strongest asset-level performance was achieved by the company’s Delaware Basin operations in southeast New Mexico. Oil production from this world-class asset increased 45 percent year over year, driving volumes in the Delaware to 79,000 Boe per day. A key driver of growth was seven prolific Wolfcamp wells around the state-line area that averaged initial 30-day rates of 4,000 Boe per day per well.
 
1

Devon’s Eagle Ford assets in south Texas also delivered strong results, with production advancing 12 percent compared to the second quarter of 2018. The growth was driven by 20 high-rate wells brought online during the quarter that averaged initial 30-day rates of approximately 3,000 Boe per day per well.
With the strong well productivity Devon has achieved year to date in the U.S., light-oil production growth from retained assets is on track to advance 17 percent in 2018. This growth rate is trending at approximately 200 basis points above the company’s original budget expectations, adjusted for asset sales.
For additional details on Devon’s E&P operations and preliminary 2019 outlook, please refer to the company’s third-quarter 2018 operations report at www.devonenergy.com .
Capital Spending Below Q3 Guidance; No Change to 2018 Outlook
In addition to the strong U.S. production performance, the company maintained discipline with its capital program. Devon’s upstream capital spending was $523 million in the third quarter, which was $52 million, or 9 percent below the company’s midpoint guidance.
For the full year, Devon has made no modifications to its capital outlook and expects its upstream capital spending to be approximately $2.4 billion in 2018.
Premium Gulf Coast Pricing Drives Upstream Revenue Higher
Devon’s upstream revenue, excluding commodity derivatives, totaled $1.6 billion in the third quarter, a 29 percent improvement compared to the year-ago quarter. Contributing factors to revenue growth were higher commodity price realizations and growth in higher-margin, liquids production.
Revenue associated with NGLs production delivered the highest growth, advancing 134 percent year over year. The company’s NGLs volumes are benefitting from direct access to premium Mont Belvieu pricing through fixed, low-cost transportation and fractionation agreements.
Also contributing to higher revenues were firm transport and marketing agreements that provide the majority of Devon’s U.S. oil production direct access to advantaged Gulf Coast pricing. Combined with price protection provided by regional basis swaps, oil realizations in the U.S. averaged approximately 97 percent of the West Texas Intermediate (WTI) benchmark.
The company’s heavy-oil business in Canada continues to benefit from Western Canadian Select (WCS) basis swaps on approximately 50 percent of its estimated oil production in 2018. These attractive WCS basis swaps are locked in at $15 off WTI pricing and have generated cash settlements of $193 million year to date.
Operating Costs Improve and Field-Level Margins Expand
Devon’s largest field-level cost, lease operating expense and transportation, totaled $453 million, or $9.45 per Boe in the third quarter. This represents a $40 million improvement compared to the previous quarter and was 2 percent below guidance. The field-level cost savings were achieved in both the U.S. and Canada.
The improving operating costs coupled with the benefits of improved price realizations and higher-margin liquids production resulted in margin expansion for Devon. Field-level cash margin reached $22 per Boe in the third quarter, a 34 percent increase compared to the year-ago period. Field-level cash margin is computed as upstream revenues, excluding commodity derivatives, less production expenses with the result divided by oil-equivalent production volumes.
 
2

Corporate Cost Savings Initiatives Enhancing Profitability
Further enhancing Devon’s profitability is its improving general and administrative (G&A) cost structure. G&A expenses totaled $147 million in the third quarter, which was below the low end of guidance and represents a 13 percent improvement compared to the third quarter of 2017. The lower overhead costs were driven by reduced personnel expenses.
With the retirement of $828 million of debt year to date, the company expects to reduce net financing costs by $66 million on an annual basis. With reduced debt balances, Devon’s net borrowing costs (net financing costs plus capitalized interest) improved 17 percent year over year to $81 million.
The aforementioned cost savings, combined with the financial benefits related to the sale of EnLink Midstream, position Devon’s go-forward G&A and interest expense to improve by approximately $475 million annually.
Earnings Exceeds Wall Street Consensus
The company reported net earnings attributable to Devon of $2.5 billion or $5.14 per diluted share in the third quarter. Adjusting for items securities analysts typically exclude from their published estimates, the company’s core earnings totaled $324 million or $0.65 per diluted share, exceeding the consensus estimates of analysts.
With the closing of the EnLink transaction, EnLink’s financial results are no longer consolidated with Devon’s upstream business, and historical results related to EnLink are presented as discontinued operations in the company’s consolidated financial statements.
Operating Cash Flow Increases 61 Percent; Free Cash Flow Reaches $249 Million
Devon’s operating cash flow from continuing operations totaled $807 million in the third quarter, a 61 percent increase compared to the same period a year ago. This level of operating cash flow fully funded the company’s total capital investments and generated $249 million of free cash flow in the quarter.
The company also generated additional cash inflows through its ongoing divestiture activity. With the closing of the EnLink transaction in July, asset sale proceeds exceeded $3 billion in the third quarter. To date, total proceeds from Devon’s divestiture program have now reached $4.7 billion, and the company expects to achieve its $5 billion divestiture target around year-end.
Industry-Leading $4 Billion Share-Repurchase Program Advances
The company’s $4 billion share-repurchase authorization represents the largest in the upstream industry when measured as a percentage of market capitalization. To date, Devon has repurchased 67 million shares, or nearly 13 percent of outstanding shares, at a total cost of approximately $2.7 billion. The company expects to complete its $4 billion share-repurchase program during the first quarter of 2019.
Devon exited the third quarter with $3.1 billion of cash on hand and an undrawn credit facility of $3 billion. Devon has a debt balance of $6.0 billion and no significant debt maturities until mid-2021. Overall, Devon’s financial position remains exceptionally strong, with investment-grade credit ratings and excellent liquidity.
 
3

Conference Call Webcast and Supplemental Earnings Materials
Also provided with today’s release is the company’s detailed operations report that is available on the company’s website at www.devonenergy.com . The company’s third-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Nov. 7, 2018, and will serve primarily as a forum for analyst and investor questions and answers.
Non-GAAP Disclosures
This release may include non-GAAP (generally accepted accounting principles) financial measures. Such non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Reconciliations of these non-GAAP measures and other disclosures are provided below in this release.
Forward-Looking Statements
This release includes “forward-looking statements” as defined by the Securities and Exchange Commission (SEC). Such statements include those concerning strategic plans, expectations and objectives for future operations, 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. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the company. Statements regarding our business and operations are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are 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 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 identified in our Form 10-K and our other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this release are made as of the date of this release, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This release may contain certain terms, such as resource potential, potential locations, risked and unrisked locations, estimated ultimate recovery (or EUR), exploration target size and other similar terms. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com . You can also obtain this form from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov .
 
4

About Devon Energy
Devon Energy is a leading independent energy company engaged in finding and producing oil and natural gas. Based in Oklahoma City and included in the S&P 500, Devon operates in several of the most prolific oil and natural gas plays in the U.S. and Canada with an emphasis on achieving strong returns and capital-efficient cash-flow growth. For more information, please visit www.devonenergy.com .

Investor Contacts	  	Media Contact	
Scott Coody, 405-552-4735	  	John Porretto, 405-228-7506	
Chris Carr, 405-228-2496	  		
 
5

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
PRODUCTION NET OF ROYALTIES

 	  	Quarter Ended	 	  	Nine Months Ended	 	
 	  	September 30,	 	  	September 30,	 	
 	  	2018	 	  	2017	 	  	2018	 	  	2017	 	
Oil and bitumen (MBbls/d)	  				  				  				  				
U. S.	  	 	125	 	  	 	101	 	  	 	121	 	  	 	106	 	
Heavy Oil	  	 	102	 	  	 	121	 	  	 	113	 	  	 	127	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	227	 	  	 	222	 	  	 	234	 	  	 	233	 	
U.S. divested assets	  	 	8	 	  	 	11	 	  	 	9	 	  	 	11	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	235	 	  	 	233	 	  	 	243	 	  	 	244	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				
U. S.	  	 	107	 	  	 	82	 	  	 	97	 	  	 	84	 	
U.S. divested assets	  	 	6	 	  	 	12	 	  	 	9	 	  	 	12	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	113	 	  	 	94	 	  	 	106	 	  	 	96	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				
U. S.	  	 	990	 	  	 	967	 	  	 	966	 	  	 	966	 	
Heavy Oil	  	 	11	 	  	 	16	 	  	 	12	 	  	 	17	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	1,001	 	  	 	983	 	  	 	978	 	  	 	983	 	
U.S. divested assets	  	 	45	 	  	 	218	 	  	 	139	 	  	 	229	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	1,046	 	  	 	1,201	 	  	 	1,117	 	  	 	1,212	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				
U. S.	  	 	396	 	  	 	343	 	  	 	379	 	  	 	349	 	
Heavy Oil	  	 	104	 	  	 	124	 	  	 	115	 	  	 	130	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	500	 	  	 	467	 	  	 	494	 	  	 	479	 	
U.S. divested assets	  	 	22	 	  	 	60	 	  	 	42	 	  	 	63	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	522	 	  	 	527	 	  	 	536	 	  	 	542	 	

6

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
PRODUCTION TREND

 	  	2017	 	  	2018	 	
 	  	Quarter 3	 	  	Quarter 4	 	  	Quarter 1	 	  	Quarter 2	 	  	Quarter 3	 	
Oil and bitumen (MBbls/d)	  				  				  				  				  				
STACK	  	 	26	 	  	 	29	 	  	 	34	 	  	 	34	 	  	 	29	 	
Delaware Basin	  	 	30	 	  	 	30	 	  	 	34	 	  	 	45	 	  	 	44	 	
Rockies Oil	  	 	9	 	  	 	12	 	  	 	15	 	  	 	13	 	  	 	15	 	
Heavy Oil	  	 	121	 	  	 	132	 	  	 	129	 	  	 	109	 	  	 	102	 	
Eagle Ford	  	 	28	 	  	 	27	 	  	 	23	 	  	 	28	 	  	 	31	 	
Barnett Shale	  	 	1	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
Other	  	 	7	 	  	 	6	 	  	 	6	 	  	 	7	 	  	 	6	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	222	 	  	 	236	 	  	 	241	 	  	 	236	 	  	 	227	 	
U.S. divested assets	  	 	11	 	  	 	10	 	  	 	10	 	  	 	9	 	  	 	8	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	233	 	  	 	246	 	  	 	251	 	  	 	245	 	  	 	235	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				  				
STACK	  	 	31	 	  	 	34	 	  	 	35	 	  	 	37	 	  	 	40	 	
Delaware Basin	  	 	10	 	  	 	12	 	  	 	11	 	  	 	15	 	  	 	19	 	
Rockies Oil	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	  	 	2	 	
Eagle Ford	  	 	12	 	  	 	13	 	  	 	8	 	  	 	13	 	  	 	15	 	
Barnett Shale	  	 	26	 	  	 	33	 	  	 	29	 	  	 	31	 	  	 	30	 	
Other	  	 	2	 	  	 	2	 	  	 	1	 	  	 	1	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	82	 	  	 	95	 	  	 	85	 	  	 	98	 	  	 	107	 	
U.S. divested assets	  	 	12	 	  	 	11	 	  	 	12	 	  	 	11	 	  	 	6	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	94	 	  	 	106	 	  	 	97	 	  	 	109	 	  	 	113	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				  				
STACK	  	 	304	 	  	 	307	 	  	 	324	 	  	 	329	 	  	 	337	 	
Delaware Basin	  	 	86	 	  	 	84	 	  	 	93	 	  	 	94	 	  	 	103	 	
Rockies Oil	  	 	6	 	  	 	8	 	  	 	12	 	  	 	13	 	  	 	18	 	
Heavy Oil	  	 	16	 	  	 	15	 	  	 	12	 	  	 	12	 	  	 	11	 	
Eagle Ford	  	 	86	 	  	 	87	 	  	 	63	 	  	 	74	 	  	 	84	 	
Barnett Shale	  	 	484	 	  	 	453	 	  	 	458	 	  	 	447	 	  	 	447	 	
Other	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	983	 	  	 	955	 	  	 	963	 	  	 	970	 	  	 	1,001	 	
U.S. divested assets	  	 	218	 	  	 	220	 	  	 	214	 	  	 	158	 	  	 	45	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	1,201	 	  	 	1,175	 	  	 	1,177	 	  	 	1,128	 	  	 	1,046	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				  				
STACK	  	 	108	 	  	 	114	 	  	 	123	 	  	 	125	 	  	 	126	 	
Delaware Basin	  	 	55	 	  	 	57	 	  	 	61	 	  	 	76	 	  	 	79	 	
Rockies Oil	  	 	11	 	  	 	14	 	  	 	18	 	  	 	16	 	  	 	19	 	
Heavy Oil	  	 	124	 	  	 	134	 	  	 	131	 	  	 	111	 	  	 	104	 	
Eagle Ford	  	 	54	 	  	 	55	 	  	 	41	 	  	 	54	 	  	 	60	 	
Barnett Shale	  	 	107	 	  	 	109	 	  	 	105	 	  	 	105	 	  	 	105	 	
Other	  	 	8	 	  	 	7	 	  	 	7	 	  	 	8	 	  	 	7	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	467	 	  	 	490	 	  	 	486	 	  	 	495	 	  	 	500	 	
U.S. divested assets	  	 	60	 	  	 	58	 	  	 	58	 	  	 	46	 	  	 	22	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	527	 	  	 	548	 	  	 	544	 	  	 	541	 	  	 	522	 	

7

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
BENCHMARK PRICES
(average prices)

 	  	Quarter 3	 	  	September YTD	 	
 	  	2018	 	  	2017	 	  	2018	 	  	2017	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	69.60	 	  	$	48.14	 	  	$	66.79	 	  	$	49.48	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	2.91	 	  	$	2.99	 	  	$	2.90	 	  	$	3.17	 	
REALIZED PRICES

 	  	Quarter Ended September 30, 2018	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	  	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	  	(Per Boe)	 	
United States	  	$	64.80	 	 	$	29.59	 	 	$	2.19	 	  	$	34.06	 	
Canada	  	$	31.77	 	 	 	N/M	 	 	 	N/M	 	  	$	31.24	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	50.47	 	 	$	29.59	 	 	$	2.19	 	  	$	33.50	 	
Cash settlements	  	$	(3.04	) 	 	$	(2.50	) 	 	$	0.01	 	  	$	(1.89	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	47.43	 	 	$	27.09	 	 	$	2.20	 	  	$	31.61	 	

 	  	Quarter Ended September 30, 2017	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	  	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	  	(Per Boe)	 	
United States	  	$	47.12	 	 	$	15.15	 	 	$	2.45	 	  	$	23.85	 	
Canada	  	$	32.25	 	 	 	N/M	 	 	 	N/M	 	  	$	31.59	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	39.36	 	 	$	15.15	 	 	$	2.45	 	  	$	25.67	 	
Cash settlements	  	$	0.54	 	 	$	(0.03	) 	 	$	0.12	 	  	$	0.52	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	39.90	 	 	$	15.12	 	 	$	2.57	 	  	$	26.19	 	

 	  	Nine Months Ended September 30, 2018	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	  	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	  	(Per Boe)	 	
United States	  	$	64.09	 	 	$	25.60	 	 	$	2.21	 	  	$	32.16	 	
Canada	  	$	27.22	 	 	 	N/M	 	 	 	N/M	 	  	$	26.79	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	46.95	 	 	$	25.60	 	 	$	2.21	 	  	$	31.00	 	
Cash settlements	  	$	(2.97	) 	 	$	(1.62	) 	 	$	0.10	 	  	$	(1.44	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	43.98	 	 	$	23.98	 	 	$	2.31	 	  	$	29.56	 	

 	  	Nine Months Ended September 30, 2017	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	  	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	  	(Per Boe)	 	
United States	  	$	47.84	 	 	$	14.62	 	 	$	2.54	 	  	$	24.44	 	
Canada	  	$	29.10	 	 	 	N/M	 	 	 	N/M	 	  	$	28.50	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	38.08	 	 	$	14.62	 	 	$	2.54	 	  	$	25.41	 	
Cash settlements	  	$	0.45	 	 	$	(0.02	) 	 	$	0.05	 	  	$	0.29	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	38.53	 	 	$	14.60	 	 	$	2.59	 	  	$	25.70	 	

8

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED STATEMENTS OF EARNINGS
(in millions, except per share amounts)

 	  	Quarter Ended	 	 	Nine Months Ended	 	
 	  	September 30,	 	 	September 30,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
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	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average common shares outstanding:	  				 				 				 				
Basic	  	 	491	 	 	 	526	 	 	 	513	 	 	 	525	 	
Diluted	  	 	494	 	 	 	529	 	 	 	516	 	 	 	528	 	
UPSTREAM REVENUES
(in millions)

 	  	Quarter Ended	 	 	Nine Months Ended	 	
 	  	September 30,	 	 	September 30,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
Oil, gas and NGL sales	  	$	1,608	 	 	$	1,245	 	 	$	4,534	 	 	$	3,760	 	
Derivative cash settlements	  	 	(91	) 	 	 	24	 	 	 	(211	) 	 	 	43	 	
Derivative valuation changes	  	 	(185	) 	 	 	(168	) 	 	 	(603	) 	 	 	171	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream revenues	  	$	1,332	 	 	$	1,101	 	 	$	3,720	 	 	$	3,974	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
PRODUCTION EXPENSES
(in millions)

 	  	Quarter Ended	 	  	Nine Months Ended	 	
 	  	September 30,	 	  	September 30,	 	
 	  	2018	 	  	2017	 	  	2018	 	  	2017	 	
Lease operating expense	  	$	234	 	  	$	229	 	  	$	744	 	  	$	691	 	
Gathering, processing & transportation	  	 	219	 	  	 	162	 	  	 	671	 	  	 	485	 	
Production taxes	  	 	82	 	  	 	46	 	  	 	208	 	  	 	142	 	
Property taxes	  	 	19	 	  	 	11	 	  	 	46	 	  	 	42	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Production expense	  	$	554	 	  	$	448	 	  	$	1,669	 	  	$	1,360	 	

9

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

 	  	Quarter Ended	 	 	Nine Months Ended	 	
 	  	September 30,	 	 	September 30,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
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	 	

10

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED BALANCE SHEETS
(in millions)

 	  	September 30,	 	 	December 31,	 	
 	  	2018	 	 	2017	 	
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	 	
	  	 	 	 	 	 	 	 	
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	  	 	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	 	
	  	 	 	 	 	 	 	 	
Common shares outstanding	  	 	474	 	 	 	525	 	
CAPITAL EXPENDITURES
(in millions)

 	  	Quarter Ended	 	  	Nine Months Ended	 	
 	  	September 30, 2018	 	  	September 30, 2018	 	
Upstream capital	  	$	523	 	  	$	1,794	 	
Land and other acquisitions	  	 	22	 	  	 	39	 	
	  	 	 	 	  	 	 	 	
Exploration and production (E&P) capital	  	 	545	 	  	 	1,833	 	
Capitalized interest	  	 	6	 	  	 	41	 	
Other	  	 	7	 	  	 	30	 	
	  	 	 	 	  	 	 	 	
Devon capital expenditures	  	$	558	 	  	$	1,904	 	

11

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
NON-GAAP FINANCIAL MEASURES
This press release includes non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-GAAP measures used in this press release, including reconciliations to their most directly comparable GAAP measure.
CORE EARNINGS
Devon’s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the company’s financial results. Accordingly, the company also uses the measures of core earnings and core earnings per share attributable to Devon. Devon believes these non-GAAP measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believes these non-GAAP measures can facilitate comparisons of its performance between periods and to the performance of its peers. The following table summarizes the effects of these items on third-quarter 2018 earnings.

(in millions, except per share amounts)	  	Quarter Ended September 30, 2018	 	
 	  	Before-tax	 	  	After-tax	 	  	After
Noncontrolling
Interests	 	  	Per Diluted
Share	 	
Continuing Operations	  				  				  				  				
Earnings attributable to Devon (GAAP)	  	$	162	 	  	$	300	 	  	$	300	 	  	$	0.61	 	
Adjustments:	  				  				  				  				
Asset dispositions	  	 	(6	) 	  	 	(5	) 	  	 	(5	) 	  	 	(0.01	) 	
Asset and exploration impairments	  	 	20	 	  	 	17	 	  	 	17	 	  	 	0.03	 	
Deferred tax asset valuation allowance	  	 	—  	 	  	 	(130	) 	  	 	(130	) 	  	 	(0.27	) 	
Fair value changes in financial instruments and foreign currency	  	 	158	 	  	 	119	 	  	 	119	 	  	 	0.25	 	
Restructuring and transaction costs	  	 	11	 	  	 	8	 	  	 	8	 	  	 	0.02	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings attributable to Devon (Non-GAAP)	  	$	345	 	  	$	309	 	  	$	309	 	  	$	0.63	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Discontinued Operations	  				  				  				  				
Earnings attributable to Devon (GAAP)	  	$	2,650	 	  	$	2,263	 	  	$	2,237	 	  	$	4.53	 	
Adjustments:	  				  				  				  				
Gain on sale of EnLink and the General Partner	  	 	(2,607	) 	  	 	(2,222	) 	  	 	(2,222	) 	  	 	(4.51	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings attributable to Devon (Non-GAAP)	  	$	43	 	  	$	41	 	  	$	15	 	  	$	0.02	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  				  				  				  				
Earnings attributable to Devon (GAAP)	  	$	2,812	 	  	$	2,563	 	  	$	2,537	 	  	$	5.14	 	
Adjustments:	  				  				  				  				
Continuing Operations	  	 	183	 	  	 	9	 	  	 	9	 	  	 	0.02	 	
Discontinued Operations	  	 	(2,607	) 	  	 	(2,222	) 	  	 	(2,222	) 	  	 	(4.51	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings attributable to Devon (Non-GAAP)	  	$	388	 	  	$	350	 	  	$	324	 	  	$	0.65	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
NET DEBT
Devon defines net debt as debt less cash and cash equivalents. Devon believes that netting these sources of cash against debt provides a clearer picture of the future demands on cash from Devon to repay debt.

(in millions)	  	 	 	
 	  	September 30, 2018	 	
Total debt (GAAP)	  	$	6,048	 	
Less cash and cash equivalents	  	 	(3,102	) 	
	  	 	 	 	
Net debt (Non-GAAP)	  	$	2,946	 	

12

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
FREE CASH FLOW
Devon defines free cash flow as operating cash flow from continuing operations less capital expenditures. Devon believes that free cash flow provides a useful measure of available cash generated by operating activities for other investing and financing activities.

(in millions)	  	Quarter Ended
September 30, 2018	 	
Operating cash flow from continuing operations	  	$	807	 	
Less capital expenditures:	  				
Upstream capital	  	 	(523	) 	
Land and other acquisitions	  	 	(22	) 	
Capitalized interest	  	 	(6	) 	
Other	  	 	(7	) 	
	  	 	 	 	
Free cash flow	  	$	249	 	

13

DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
 
PRODUCTION GUIDANCE

 	  	Quarter 4	 	
 	  	Low	 	 	High	 	
Oil and bitumen (MBbls/d)	  	 	 	 	 	 	
U.S.	  	 	127	 	 	 	131	 	
Heavy Oil (1)	  	 	110	(1)   	 	 	115	(1)   	
	  	 	 	 	 	 	 	 	
Retained assets	  	 	237	 	 	 	246	 	
U.S. divested assets	  	 	6	 	 	 	8	 	
	  	 	 	 	 	 	 	 	
Total	  	 	243	 	 	 	254	 	
	  	 	 	 	 	 	 	 	
Natural gas liquids (MBbls/d)	  				 				
Retained assets	  	 	106	 	 	 	110	 	
U.S. divested assets	  	 	3	 	 	 	5	 	
	  	 	 	 	 	 	 	 	
Total	  	 	109	 	 	 	115	 	
	  	 	 	 	 	 	 	 	
Gas (MMcf/d)	  				 				
U.S.	  	 	950	 	 	 	1,000	 	
Heavy Oil	  	 	5	 	 	 	10	 	
	  	 	 	 	 	 	 	 	
Retained assets	  	 	955	 	 	 	1,010	 	
U.S. divested assets	  	 	25	 	 	 	35	 	
	  	 	 	 	 	 	 	 	
Total	  	 	980	 	 	 	1,045	 	
	  	 	 	 	 	 	 	 	
Total oil equivalent (MBoe/d)	  				 				
U.S.	  	 	391	 	 	 	408	 	
Heavy Oil	  	 	111	 	 	 	116	 	
	  	 	 	 	 	 	 	 	
Retained assets	  	 	502	 	 	 	524	 	
U.S. divested assets	  	 	13	 	 	 	19	 	
	  	 	 	 	 	 	 	 	
Total	  	 	515	 	 	 	543	 	

(1)	Guidance assumes Jackfish complex curtailments continue throughout December	
PRICE REALIZATIONS GUIDANCE

 	  	Quarter 4	 	
 	  	Low	 	 	High	 	
Oil and bitumen - % of WTI	  				 				
U.S.	  	 	90	% 	 	 	100	% 	
Canada	  	 	10	% 	 	 	20	% 	
NGL - realized price	  	$	23	 	 	$	28	 	
Natural gas - % of Henry Hub	  	 	70	% 	 	 	80	% 	
OTHER GUIDANCE ITEMS

 	  	Quarter 4	 	
($ millions, except Boe and %)	  	Low	 	 	High	 	
Marketing & midstream operating profit	  	$	20	 	 	$	30	 	
LOE & GP&T per BOE	  	$	9.50	 	 	$	9.75	 	
Production & Property Tax	  	$	85	 	 	$	95	 	
Exploration expenses	  	$	25	 	 	$	35	 	
Depreciation, depletion and amortization	  	$	420	 	 	$	460	 	
General & administrative expenses	  	$	140	 	 	$	160	 	
Financing costs, net	  	$	75	 	 	$	85	 	
Other expenses	  	$	15	 	 	$	20	 	
Current income tax rate	  	 	0	% 	 	 	5	% 	
Deferred income tax rate	  	 	20	% 	 	 	25	% 	
	  	 	 	 	 	 	 	 	
Total income tax rate	  	 	20	% 	 	 	30	% 	
	  	 	 	 	 	 	 	 	
Average basic share count outstanding (MM)	  	 	450	 	 	 	460	 	

CAPITAL EXPENDITURES GUIDANCE

 	  	Quarter 4	 	
(in millions)	  	Low	 	  	High	 	
Upstream capital	  	$	550	 	  	$	650	 	
Other	  	 	5	 	  	 	15	 	
	  	 	 	 	  	 	 	 	
Devon capital expenditures	  	$	555	 	  	$	665	 	

14

DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
 
Oil Commodity Hedges

 	  	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	 	  	 	85,904	 	  	$	54.72	 	  	$	64.72	 		
Q1-Q4 2020	  	 	1,740	 	  	$	62.88	 	  	 	4,973	 	  	$	59.94	 	  	$	69.94	 		
Oil Basis Swaps

 	  	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	  	Western Canadian Select	  	 	62,109	 	  	$	(16.41	) 	 	 	1,000	 	  	$	(15.50	) 	 	$	(13.93	) 		
Q1-Q4 2019	  	Midland Sweet	  	 	28,000	 	  	$	(0.46	) 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q1-Q4 2019	  	Argus LLS	  	 	15,000	 	  	$	4.88	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q1-Q4 2019	  	Argus MEH	  	 	16,000	 	  	$	2.84	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q1-Q4 2019	  	Western Canadian Select	  	 	10,647	 	  	$	(23.39	) 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Natural Gas Commodity Hedges - Henry Hub

 	  	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	  	 	220,129	 	  	$	2.81	 	  	 	205,241	 	  	$	2.65	 	  	$	3.03	 		
Q1-Q4 2020	  	 	9,075	 	  	$	2.81	 	  	 	14,545	 	  	$	2.66	 	  	$	2.96	 		
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	  	 	137,637	 	  	$	0.01	 		
Q1-Q4 2019	  	Transco Zone 4	  	 	7,397	 	  	$	(0.03	) 		
Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price. Devon’s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index. Commodity hedge positions are shown as of November 1, 2018.
 
15

Q3 2018 Operations Report Key Messages 2 Outlook 3 Modeling Stats 7 Q3 Results 8 Delaware Basin 11 STACK15 Rockies 18 Eagle Ford & Barnett Shale 19 Heavy Oil 20 NYSE: DVN devonenergy.com Exhibit 99.2

Disciplined Growth Strategy U.S. oil growth ahead of plan (+200 basis point vs. budget) No change to capital spending outlook Corporate cost savings: ~$475 million/year Operating cash flow accelerates in Q3 (+61% YoY) Reduced consolidated debt by >40% Repurchasing ~20% of outstanding stock Raised quarterly dividend 33% KEY ACCOMPLISHMENTS IN 2018 ü ü ü ü ü ü KEY STRATEGIC OBJECTIVES Fund high-return projects Maintain financial strength Return cash to shareholders Generate free cash flow 1 2 3 4 ü

2018 Outlook: U.S. Growth Initiatives Ahead of Plan U.S. growth exceeding expectations YTD 2018e oil production growth rates (retained assets) U.S. Oil Production (MBOD) 2018e 2017 % Delaware Basin 42 30 STACK 32 25 Rockies 15 10 Eagle Ford 28 34 Other 6 6 Total retained assets 123 105 +17% Divested assets (sold or to be sold) 9 11 Total reported oil production 132 116 +13% Basis Points +200 FOR ADDITIONAL DETAILS ON ASSET DIVESTITURES – SEE PAGE 10 No change to capital spending plans 2018e E&P capital $2.4B 10% 90% U.S. ASSETS 2018e E&P CAPITAL CANADA KEY MESSAGES U.S. oil growth to accelerate into 2019 No change to activity with higher pricing Generating free cash flow ($249 million in Q3)

OUTSTANDING SHARES U.S. RETAINED ASSETS E&P CAPITAL PROGRAM 2019 Preview: Keeping Our Discipline 15%-19% Growth $2.4-$2.7 Billion OPTIMIZED FOR RETURNS POSITIONED FOR FREE CASH FLOW ~20% Reduction DRIVEN BY LOW-RISK DEVELOPMENT PROGRAM OIL GROWTH SHARE REDUCTION $ ENHANCING PER-SHARE CASH FLOW GROWTH KEY MESSAGES U.S. resource plays account for ~90% of capital Delaware Basin top-funded asset in portfolio STACK & Rockies key contributors to oil growth

2018e Executing the Multi-Year Business Plan +15% – 17% CAGR Multi-Year Targets (2017-2020) 17% YoY growth 9% YoY growth in U.S. G&A/interest: ↓$475 MM Trending above 3-year plan ~$5 billion by year end >40% decrease in debt Note: Assumes $65 WTI, $3 Henry Hub and current WCS strip pricing U.S. oil production (retained assets) Total BOE production (retained assets) Per-unit cost savings (G&A, interest & LOE) Cash flow growth Excess cash inflow (Free cash flow + divestiture proceeds) Net debt to EBITDA ratio Exceeding 2018 plan On track with 2018 plan +5% – 7% CAGR >20% by 2020 $6 – $8 billion ~1.0x – 1.5x >20% CAGR (on a per-share basis)

Strategic Deployment of Excess Cash $4 billion share-repurchase program underway Represents ~20% of outstanding shares $2.7 billion repurchased to date Expect program to be completed by Q1 2019 Raised quarterly dividend by 33% in 2018 Target cash flow payout ratio: 5% - 10% Expect to deliver sustainable dividend growth Retired $828 million of upstream debt year to date Reduces interest expense by $66 million annually EnLink sale further deleverages balance sheet Plan to retire maturing debt of $257 million by early 2019 Industry leading share-repurchase program Average outstanding shares (MM) ~20% REDUCTION 527 ~420 Aggressively deleveraging the balance sheet Consolidated debt ($B) >40% REDUCTION YEAR TO DATE $6.0 (net debt: $2.9)

KEY METRICS Q3 ACTUALS U.S. oil – retained (MBbls/d) 125 Canada oil (MBbls/d) 102 NGLs – retained (MBbls/d) 107 Gas - retained (MMcf/d) 1,001 Total retained assets (MBoe/d) 500 U.S. divested assets (MBoe/d) 22 Total (MBoe/d) 522 LOE & GP&T ($/BOE) $9.45 General & administrative expenses ($MM) $147 Financing costs, net ($MM) $75 Upstream capital ($MM) $523 Q3 2018 - ASSET DETAIL DELAWARE STACK ROCKIES EAGLE FORD BARNETT HEAVY OIL RETAINED PRODUCTION Oil (MBbl/d) 44 29 15 31 - 102 NGL (MBbl/d) 19 40 2 15 30 - Gas (MMcf/d) 103 337 18 84 447 11 Total (MBoe/d) 79 126 19 60 105 104 ASSET MARGIN (per Boe) Realized price $46.80(2) $31.48 $55.83 $49.44 $17.78 $39.99(3) Lease operating expenses ($4.90) ($2.16) ($6.90) ($2.34) ($2.14) ($9.61) Gathering, processing & transportation ($2.01) ($5.05) ($1.68) ($4.92) ($7.53) ($3.93) Production & property taxes ($3.37) ($1.71) ($6.81) ($2.72) ($1.24) ($0.83) Cash margin $36.52 $22.56 $40.44 $39.46 $6.87 $25.62 CAPITAL ACTIVTY (Q3 avg.) Upstream capital ($MM) $198 $167 $29 $35 $15 $60 Operated development rigs 8 8 2 1 Operated frac crews 2 2 0.5 1 Operated spuds 25 26 6 9 Operated wells tied-in 27 26 7 10 Average lateral length 7,000’ 9,800’ 8,700’ 5,200’ GUIDANCE Q4 2018e U.S. oil – retained (MBbls/d) 127 – 131 Canada oil (MBbls/d)(2) 110 – 115(1) NGLs – retained (MBbls/d) 106 – 110 Gas – retained (MMcf/d) 955 – 1,010 Total retained assets (MBoe/d) 502 – 524 U.S. divested assets (MBoe/d) 13 – 19 Total (MBoe/d) 515 – 543 Lease operating expense & GP&T ($/BOE) $9.50 – $9.75 Production & property taxes ($MM) $85 – $95 General & administrative expenses ($MM) $140 – $160 Financing costs, net ($MM) $75 – $85 Upstream capital ($MM) $550 – $650 Avg. basic share count outstanding (MM) 450 – 460 Guidance assumes Jackfish complex curtailments continue throughout December. Includes benefits of regional basis swaps and firm transport in the Delaware totaling $42 million. Includes benefits of regional basis swaps in Canada totaling $84 million. Q3 2018 – Key Modeling Stats & Outlook

Corporate cost structure continues to improve G&A declines 42% vs. peak rates Borrowing costs reduced 17% vs. Q3 2017 Capital discipline accelerates free cash flow growth Q3 capital 9% below midpoint guidance Generated $249 million of free cash flow in Q3 Q3 Results Headlined by Free Cash Flow Generation Total U.S. production exceeds guidance Driven by Delaware Basin & Eagle Ford Firm transport and basis swaps protect pricing Light-oil has access to Gulf Coast markets Secured NGLs access to Mt. Belvieu (pg. 9) WCS swaps protect Canadian cash flow Achieving improved capital efficiency Upstream capital Strong oil realizations across U.S. U.S. oil realizations as % of WTI Light-oil growth advances U.S. oil production – retained assets (MBOD) (2) Includes benefits of basis swaps & firm transport 97% of WTI(2) BASIS SWAPS & FIRM TRANSPORT FIELD-LEVEL REALIZATIONS INCREASE 24% $523 million Q3 CAPITAL INVESTMENT 9% BELOW GUIDANCE (1) Excludes divesture assets (see pg. 3 for asset detail)

One of the largest NGLs producers in the U.S. Q3 retained NGLs production: 107 MBbls per day Represents ~20% of production mix 98% of NGLs have access to Mont Belvieu markets(1) >30% premium to Conway pricing (see chart) Margins to benefit from contractual rights to recover operated ethane production Legacy contracts lock in below-market fees with no exposure to rising spot rates Firm sales contractually guarantee flow assurance Devon possesses excess capacity at Mont Belvieu ~10 MBbls/day of excess fractionating capacity Supports NGL growth plans through end of decade Capturing the Benefit of Higher NGLs Pricing (1) Represents percentage of operated production Mont Belvieu Flow Assurance to Premium NGLs Markets STACK Delaware Basin Advantaged Pricing at Mont Belvieu $/Barrel (Mont Belvieu vs. Conway Pricing) Mont Belvieu Conway Mont Belvieu >30% premium to Conway markets North Texas 98% of Devon’s volumes access Mont Belvieu(1)

Divestiture Program Accelerates Value Creation SALES PRICE: $3.125 Billion ACCRETIVE MULTIPLE: 12x Cash Flow TRANSACTION DETAILS CLOSED Resource quality & depth allows for high-grading of portfolio Announced $4.7 billion of divestitures to date Closed EnLink transaction in July ($3.125 billion) Upstream asset sales: $1.6 billion No incremental cash taxes from transactions Expect to exceed $5 billion divestiture target around year end Rockies CO2 projects (bids by year end) Central Basin Platform assets (bids by year end) Continuously evaluating options to further high-grade upstream portfolio Next Steps in High-Grading Portfolio Rockies CO2 Central Basin Platform Production: 4 MBOED (~80% oil) Data room: Open Production: 4 MBOED (~45% oil) Data room: Open

Delaware Basin – Q3 2018 Results 79 (Q3 Guide: 70-75)(1) 45% GROWTH YEAR OVER YEAR Q3 Production Outperforms Guidance(1) Retained production (MBOED) Delaware Well Productivity Reaching Record Highs Average Cumulative Oil Production Per Well (MBOD) 2018 2015-2017 avg. Months Online >70% IMPROVEMENT 2018 VERSUS 3-YEAR AVERAGE Production increased 45% year over year(1) 4,000 BOE per day above top end of guidance Oil and liquids reach 78% of product mix “Step-change” improvement in 2018 well results >70% improvement in productivity vs. 3-year avg. Driven by focused program in state-line area Q3 performance driven by strong well productivity Top 10 wells achieved IP30: ~3,400 BOED (60% oil) Driven by prolific Wolfcamp results (see pg. 12) Effectively mitigating inflation pressures Per-unit LOE declined 8% vs. Q2 2018 Capital in line with budget expectations YTD (1) Production and guidance range adjusted for “Mi Vida” and other non-core asset divestitures (~3 MBOED impact).

Delaware – Wolfcamp Program Delivers Prolific Results WOLFCAMP DEVELOPMENT PROGRAM BUILDING MOMENTUM Current Projects COTTON DRAW RATTLESNAKE New Mexico Texas Development Areas ~4,000 Q3 WOLFCAMP WELLS(1) BOED AVG. 30-DAY IPs Lusitano 2 Wolfcamp wells online Avg. IP 30: 4,600 BOED/well Seawolf 5 of 12 Wolfcamp wells online Avg. IP 30: 3,700 BOED/well(1) Fighting Okra Completing Peak rates: 1H 2019 BONE SPRING 3rd WOLFCAMP XY A UPPER MIDDLE LOWER Seawolf Development - Rattlesnake Area Avg. IP30: 3,700 BOED(1) Peak Rates: Q4 2018 Well productivity at Seawolf trending above plan Wolfcamp sweet spot in southern Lea County Avg. IP30: 3,700 BOED(1) (represents 5 of 12 wells) Peak rates for remaining 7 wells expected in Q4 Lusitano derisks Cotton Draw Wolfcamp potential 6-well project testing Leonard and Wolfcamp Wolfcamp wells avg. IP30: 4,600 BOED (50% oil) Flagler Drilling Peak rates: mid-2019 (1) Includes two appraisal wells (avg. lateral 5,700’) that were normalized for 10,000’ at a 1.75 multiplier.

Delaware – Infrastructure Supports Profitable Growth Premium oil pricing and flow assurance Q3 oil realizations: 97% of WTI(1) Swaps & firm transport protect ~75% of 2019 oil Firm oil sales contracts guarantee in basin flow assurance (100 MBOD of contractual capacity in basin) NGLs have firm transport to Mont Belvieu (see pg. 9) Revenue improves ~30% vs. Q2 2018 Swaps protect gas production through 2019 Infrastructure drives sustainable cost savings Operating costs improved ~60% vs. peak rates Oil and produced water gathered on pipe (avoids trucking) Operate ~50 disposal wells and 8 water reuse facilities 80% of water used in operations is recycled Includes benefits of basis swaps and firm transport to Gulf Coast Long-term guaranteed contractual capacity with firm transport partners Positioned for flow assurance & premium pricing Firm transport: ~20 MBOD on Longhorn Firm sales(2): 100 MBOD in basin Established local refinery relationships ~85% of oil gathered on pipe >90% of produced water on pipe FLOW ASSURANCE PLAN STRONG PRICE REALIZATIONS 97% OF WTI(1) BASIS SWAPS FIELD-LEVEL PRICING LONGHORN (FIRM TRANSPORT) Q3 RESULTS Note: 2015-2017 costs are pro forma for revenue recognition accounting rules recently implemented. ~60% IMPROVEMENT Improved infrastructure driving lower costs LOE & Transportation Expense ($/BOE)

Delaware Basin – Raising Growth Outlook Raising 2018 production growth estimates Increasing 2018 exit rate growth: ~90 MBOED(1) Non-core divestitures: 3 MBOED impact to Q4 Activity to reach 10 operated rigs around year end Ramping-up capital investment in 2019 Delaware is top-funded asset by a wide margin Capital investment: up to $1.0 billion Oil production growth: ~40% vs. 2018 Per-unit LOE to decline 10% to 15% Accelerating Todd 2nd Bone Spring program Two Boundary Raider wells delivered highest rates in Delaware history (IP24: 24 MBOED) Drill >20 wells in focus area over next year (see map) Todd 2018 Activity Focus Area Bone Spring Focus Area (Drill >20 wells next year) Eddy Lea Two Boundary Raider Wells IP24: 24,000 BOED 2019 PREVIEW: ACCELERATING TODD 2ND BONE SPRING PROGRAM Upcoming wells (vs. 2018) High-return oil growth positioned to accelerate Retained production (MBOED) ~90(1) >5 MBOED vs. plan(1) RAISING GUIDANCE (1) Production and guidance range adjusted for “Mi Vida” and other minor non-core asset divestitures (~3 MBOED impact).

STACK – Initial Infill Spacing Results Initial Infill Spacing Results Showboat 12 wells/unit (avg. lateral: 7,000’) Avg. 90-Day IP: 800 BOED Horsefly 10 wells per drilling unit Avg. 30-Day IP: 1,475 BOED Coyote 7-well development project Avg. 90-Day IP: 3,100 BOED Bernhardt 8 wells per drilling unit Avg. 30-Day IP: 1,300 BOED BLACK OIL WINDOW OVER- PRESSURED OIL WINDOW Devon Acreage Current Projects ~35 Days 19 16 COMPLETIONS (68% of well cost) DRILLING (32% of well cost) SAVINGS PER WELL Drilling Days Reduced Extended reach laterals >30% >50% DECREASE Significant Capital Savings Bernhardt D&C costs vs. parent well Q3 net production up 16% year over year Dewey County assets sold in Q3 (~7 MBOED) NGLs up ~30% with benefits of Mont Belvieu pricing Total volume growth limited by infill pilot performance Capital efficiency improves (spending 31%↓ vs. 1H 2018 avg.) Infill activity accelerates D&C capital efficiencies Horsefly costs reduced to ~$7.5 million per well Bernhardt achieves >30% savings vs. parent (~$7MM/well) Pilots testing higher-density spacing not optimized Showboat upside test underperforms vs. plan (12 wells/unit) Horsefly delivered improved results (10 wells/unit) Bernhardt rates limited by flowback strategy (8 wells/unit) Lighter-spaced Coyote project delivers best results

STACK – Next Steps to Optimize Development Returns Learnings from high-density infill tests Initial results indicate spacing was too tight Flowback approach key for oil recoveries Upper Meramec delivered best well results Vertical communication observed Substantial D&C savings achieved (pg. 15) Reverting to “base case” spacing to optimize returns Upcoming activity targeting 4-8 wells per unit Well placement focused in Upper Meramec Flowback adjusted to improve performance Project IRRs to benefit from less capital intensity Utilizing tailored, more capital efficient completions Projects to benefit from less infrastructure capital on centralized facilities Pony Express 4 wells per unit Online Q4 2018 ML Block 8 wells per unit 2019 project Kingfisher Canadian Custer Blaine Upcoming Developments BLACK OIL WINDOW OVER- PRESSURED OIL WINDOW UPCOMING STACK DEVELOPMENT ACTIVITY 1 5 9 Geis 7 wells per unit Flowing Back Shangri-La 5 wells per unit Online Q4 2018 Showboat 12 wells per unit 1 2 3 2 6 10 Safari 4 wells per unit Online Q4 2018 Doppelganger/Kraken 8 & 7 wells per unit 2019 project 3 7 11 Scott 6 wells per unit 2019 project 4 8 12 4-8 wells UPCOMING ACTIVITY PER UNIT Developments Online Horsefly 10 wells per unit Bernhardt 8 wells per unit 4 6 7 9 Coyote 7-well project 8 10 11 12 5 Whiskey Jack 5 wells per unit Online Q4 2018 Northwoods 4 wells per unit 2019 project Brachiosaurus 4 wells per unit 2019 project Minnie Ha Ha 6 wells per unit 2019 project Morning Thunder 4 wells per unit 2019 project

STACK – Outlook Upcoming activity highly accretive to corporate return targets Q4 activity: 20 to 25 new wells online Re-establishes growth trajectory by year end Positioned for production growth in 2019 2nd highest funded asset in portfolio Capital investment: $500-$700 million Expect to bring online 70-90 wells Targeting 4-8 wells per drilling unit Significant growth inventory remaining 130,000 net acres in over-pressured oil window Acreage position >90% undeveloped Meramec inventory risked at 6 wells per unit High-quality Woodford optionality 120 - 125 Asset sales: ~7 MBOED Spacing pilots: ~5 MBOED 125(1) 104(1) KEY ITEMS IMPACTING Q4 (1) Production adjusted for recent Dewey County asset sale. KEY MESSAGES Growth trajectory re-established by year end Upcoming infill projects recalibrated to optimize IRRs D&C costs expected to further decline in 2019 PRODUCTION GROWTH TO RESUME IN 2019 Retained production (MBOED)

Rockies – An Emerging Growth Opportunity Net production increased 17% vs. Q2 2018 Oil production ~75% of product mix Powder River barrels receive WTI pricing Accelerating capital activity in 2019 Expect to operate 4 rigs by early next year Represents 2x increase in activity from 2018 No permitting or infrastructure constraints Shifting Super Mario area into development ~35 Turner wells planned to spud in 2019 Multi-year Turner inventory (~200 wells) Niobrara provides significant upside potential Initial 3 wells successful (product mix: ~90% oil) >10 additional tests scheduled in 2019 Net acres: ~200,000 in oil fairway 2019 Outlook: Accelerating Activity Drilling activity by zone Niobrara Other 2019 DRILLING ACTIVITY 25 (wells) 45-50 (wells) Turner RECENT POWDER RIVER BASIN ACTIVITY Super Mario Area Turner Niobrara OIL Converse FAIR WAY RU DILTS Fed 1X & 3X Avg. 30-Day IP: 1,050 BOED per well RU JFW Fed 13 3X & 4X Avg. 30-Day IP: 1,500 BOED per well Conley Draw 1X Avg. 30-Day IP: 1,300 BOED (~90% oil) SDU Tillard 1X Avg. 30-Day IP: 1,200 BOED (~90% oil) PDU WJ Ranch 22 Avg. 30-Day IP: 1,100 BOED (~90% oil) RU State Fed 2X & 4X Avg. 30-Day IP: 1,450 BOED per well SDU Tillard 2X Avg. 30-Day IP: 1,650 BOED (~90% oil)

Eagle Ford and Barnett Shale Q3 Results 20 Eagle Ford Wells Avg. 30-Day IP: ~3,000 BOED/Well EAGLE FORD OVERVIEW Q3 production averaged 60 MBOED (51% oil) Strong well results drive 10% growth vs. Q2 20 new wells : IP30 ~3,000 BOED (50% oil) Completion design contributes to performance Free cash flow accelerates (~$500 million in 2018e) Q4 outlook: ~60 MBOED (15 new wells online) BARNETT SHALE OVERVIEW Sale price: ~$50 million Production: ~4 MBOED Denton Wise Dewitt Divest Details 2018 Dow JV Activity FREE CASH FLOW 500 $ Q3 production averaged 105 MBOED (~30% NGLs) Dow JV and refrac activity stabilizing production NGL pricing drives margin expansion GP&T expense to decline by ~$90 million in 2019 Wise County package sold for ~$50 million (Q4 close) MILLION IN 2018e SOLD ~ 10% OIL GROWTH (VS Q2 2018)

Heavy Oil – Overview & Outlook Q3 net production: 104,000 Boe per day Jackfish 1 maintenance impact: ~15 MBOD Jackfish 2&3 produced at nameplate capacity LOE per Boe declined 16% vs. Q2 2018 Full-scale operations restored at Jackfish complex Rates reach ~110% of nameplate capacity in October Adjusted November production rates at Jackfish due to market conditions (~8 MBOD impact to Q4) Previously incorporated in Q4 oil production outlook (press release issued 10/16/18) Potential to continue curtailing barrels in December Decision based on real-time pricing WCS basis swaps protect Q4 cash flow (~$150 MM benefit) SAGD Sweet Spot 1 $ INCREASE PER BBL FOR EVERY INCREMENTAL 40 MM $ ANNUALIZED CASH FLOW Q3 PRODUCTION GROSS NET Jackfish 1 (MBOD) 20.4 19.4 Jackfish 2 (MBOD) 34.9 33.1 Jackfish 3 (MBOD) 34.8 33.0 Lloydminster (MBOED) 20.7 18.3 Total Heavy Oil (MBOED) 110.8 103.8

Heavy Oil – Mitigating Pricing Pressures in 2019 Actively adding WCS financial swaps in 2019 (21 MBOD at ~$23 off WTI in 1H 2019) Secured firm transport to Gulf Coast (Agreements cover ~10% of production) Seeking accretive rail contracts (Targeting up to 20% of production) Directly connected to Northwest upgrader (Limits impact of future apportionments) Line 3 expansion in Q4 2019 (+370 MBOD capacity) PADD 2 Houston Edmonton Jackfish Enbridge Mainline Flanagan South ~$30 off WTI in 2019 WCS Pricing Pipelines Rail Seaway Cushing ~$2 off WTI in 2019 Gulf Coast WCS Pricing All in cost: ~$20/BBL Rail Opportunities Canadian Heavy Oil Marketing Opportunities Differentials Narrowing into 2019 $/Barrel Differential (WCS vs. WTI) WCS differential to WTI Further improvements expected as industry adds incremental rail activity

Investor Contacts & Notices Investor Relations Contacts Scott CoodyChris Carr VP, Investor RelationsSupervisor, Investor Relations 405-552-4735405-228-2496 Email: investor.relations@dvn.com Forward-Looking Statements This presentation includes "forward-looking statements" as defined by the Securities and Exchange Commission (the “SEC”). Such statements include those concerning strategic plans, expectations and objectives for future operations, 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. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. Statements regarding our business and operations are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are 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 Investor Notices 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 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 identified in our Form 10-K and our other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this presentation are made as of the date of this presentation, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. Use of Non-GAAP Information This presentation may include non-GAAP financial measures. Such non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. For additional disclosure regarding such non-GAAP measures, including reconciliations to their most directly comparable GAAP measure, please refer to Devon’s third-quarter 2018 earnings release at www.devonenergy.com. Cautionary Note to Investors The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This presentation may contain certain terms, such as resource potential, potential locations, risked and unrisked locations, estimated ultimate recovery (EUR), exploration target size and other similar terms. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.