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): July 31, 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	
(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 July 31, 2018, Devon Energy Corporation (the “Company”) issued a press release announcing its financial and operational results for the quarter ended June 30, 2018. In connection with the earnings release, the Company also provided its operations report for the second quarter of 2018. Copies of the earnings release and second 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 July 31, 2018.		
			
99.2	  	Second 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: July 31, 2018

Exhibit 99.1

	 		 	Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102-5015	
	 				
NEWS RELEASE
Devon Energy Reports Second-Quarter 2018 Results
Highlights
 
 	•	 	Delaware Basin and STACK drive U.S oil production beat	
 
 	•	 	Light-oil production growth on track to expand 16 percent in 2018	
 
 	•	 	EnLink ownership interests monetized at 12 times cash flow	
 
 	•	 	Industry-leading share-repurchase program increased to $4 billion	
 
 	•	 	Field-level cash margins expand by 31 percent year over year	
 
 	•	 	Corporate cost structure to improve by $475 million annually	
OKLAHOMA CITY – July  31, 2018 – Devon Energy Corp. (NYSE: DVN) today reported operational and financial results for the second quarter of 2018. Also included within the release is the company’s guidance outlook for the third quarter and full-year 2018.
“Devon is executing at a very high level on our 2020 Vision,” said Dave Hager, president and CEO. “Operationally, our second-quarter performance was headlined by strong well productivity in the Delaware Basin and STACK, which drove light-oil production above the high end of our guidance expectations. Importantly, we converted this volume growth into higher profits with our access to premium pricing in advantaged markets and through our success in driving both field-level and corporate costs lower.
“With the strong well productivity we’ve achieved year to date in the U.S., light-oil production growth is on track to advance 16 percent in 2018, which is 200 basis points above our original budget expectations,” said Hager. “We expect to deliver this improved outlook without any increase to our planned activity, and this disciplined investment program positions us to generate substantial amounts of free cash flow at today’s market prices.
“In addition to our strong operating results, we took a significant step forward in achieving our 2020 Vision by further simplifying our asset portfolio through our monetization of EnLink,” said Hager. “This highly accretive transaction provides a strategic exit from EnLink at a value of 12 times cash flow, and we’re returning the sales proceeds to our shareholders through our industry-leading $4 billion share-repurchase program.”
Delaware Basin and STACK Drive U.S. Oil Production Beat
Production results in the quarter were highlighted by oil growth from Devon’s U.S. resource plays, which are attaining the highest margins and returns in Devon’s portfolio. In the quarter, light-oil production in the U.S. averaged 136,000 barrels per day, a 12 percent increase compared to the first quarter of 2018. This result exceeded the top end of guidance by 2,000 barrels per day.
The strongest asset-level performance during the second quarter was from the company’s Delaware Basin assets. Light-oil production increased 54 percent year over year in the quarter, driving total volumes in the Delaware to 79,000 oil-equivalent barrels (Boe) per day. Growth in the Delaware was driven by prolific well productivity, where the top 10 wells in the quarter averaged initial 30-day rates of approximately 3,000 Boe per day.
 
1

Devon’s STACK assets also delivered strong results during the quarter. Total production in the STACK advanced 26 percent compared to the second quarter of 2017. Driven by several strong wells across the play, oil production delivered the highest growth rate, increasing 41 percent year over year.
In Canada, net oil production averaged 109,000 barrels per day in the second quarter. Scheduled maintenance at the company’s Jackfish facility curtailed production by approximately 15,000 barrels per day. Also contributing to lower production was a 2 percentage point increase in royalty rates because of higher commodity prices and improved profitability.
Overall, total companywide production averaged 541,000 Boe per day in the second quarter. Oil accounted for the largest component of the product mix at 45 percent of total volumes. For additional details on Devon’s E&P operations in the quarter, please refer to the company’s second-quarter 2018 operations report at www.devonenergy.com .
Light-Oil Production Growth on Track to Increase 16 Percent in 2018
With the strong well productivity Devon has achieved year to date in the U.S., light-oil production growth is on track to advance 16 percent in 2018. This growth rate is trending at approximately 200 basis points above the company’s original budget expectations.
The incremental oil growth in the U.S. is expected to be delivered without an increase to Devon’s capital activity. This disciplined investment program positions the company to generate free cash flow in the second half of 2018 at today’s market prices.
EnLink Ownership Interests Monetized at 12 Times Cash Flow
In mid-July, Devon completed the sale of its ownership interests in EnLink Midstream Partners, LP (NYSE: ENLK) and EnLink Midstream, LLC (NYSE: ENLC) for $3.125 billion. The company’s interests in EnLink generated $265 million of cash distributions over the past year, valuing the investment at approximately 12 times cash flow. Devon expects no incremental corporate cash taxes resulting from this sale.
With the closing of the EnLink transaction, combined with other minor asset sales achieved to date, total proceeds from Devon’s divestiture program have now reached $4.2 billion. The company expects to monetize an additional $1 billion of minor, non-core assets across the United States by year-end. These divestiture packages include undeveloped leasehold in the southern Delaware Basin, enhanced oil recovery projects in the Rockies and Midland Basin along with Wise County acreage in the Barnett Shale. Data rooms are open for the majority of these packages and bids are expected throughout the second half of 2018.
Industry-Leading Share-Repurchase Program Increased to $4 Billion
In conjunction with closing the EnLink transaction, Devon’s board of directors authorized an increase in the company’s share-repurchase program to $4 billion. This authorization represents the largest share-repurchase program in the upstream industry when measured as a percentage of market capitalization. At the end of July, Devon had repurchased 24 million shares, or nearly 5 percent of outstanding shares, at a total cost of approximately $1 billion.
For the remaining share-repurchase authorization, the company plans to utilize a series of accelerated stock repurchase programs (ASR) that are expected to commence in early August. With these ASR programs, Devon expects to complete its $4 billion share-repurchase program during the first half of 2019. Detailed forward-looking guidance on share count is provided later in this release.
 
2

Financial Reporting Impact of EnLink Monetization
With the closing of the EnLink transaction, the financial results of EnLink Midstream will no longer be consolidated with Devon’s upstream business, and historical results related to EnLink will be presented as discontinued operations in the company’s consolidated financial statements.
To assist with this financial reporting transition, Devon has provided pro forma financial statements for its upstream business in a Form 8-K filing in July. Additionally, updated detailed forward-looking guidance for financial statement line items impacted by this transaction in 2018 is provided later in this release.
Upstream Revenue Benefits from Premium Gulf Coast Pricing
Devon’s upstream revenue, excluding commodity derivatives, totaled $1.6 billion in the second quarter, a 15 percent improvement compared to the previous quarter. The strong growth in revenue was driven by growth in higher-margin, light-oil production coupled with improved price realizations across the company’s asset portfolio.
Also contributing to the improving price realizations in the quarter were Devon’s firm transport and marketing agreements that provide the majority of U.S. oil production direct access to premium Gulf Coast markets. Combined with the price protection provided by regional basis swaps, second-quarter oil realizations in the U.S. averaged approximately 98 percent of the West Texas Intermediate benchmark. Importantly, the company is positioned to maintain these strong U.S. oil price realizations through the end of the decade.
In Canada, Devon 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 the WTI benchmark price and have generated cash settlements of $109 million year to date.
U.S. Operating Costs Improve and Field-Level Margins Expand
Devon continued to effectively manage operating costs during the second quarter. Production expense, which represents field-level operating costs, totaled $572 million in the second quarter. The largest components of production expense are lease operating expense and transportation, which totaled $493 million in the quarter. Taxes also contributed $79 million to production expense during the second quarter.
The company’s U.S. resource plays delivered the strongest cost performance, where lease operating expense and transportation costs declined 3 percent on a per-unit basis compared to the first quarter. In Canada, production expense in the quarter was impacted by $21 million of non-recurring costs associated with maintenance work at the Jackfish complex.
Overall, the benefits of higher-margin oil production, improved price realizations and a lower cost structure resulted in expanded margins for Devon. Field-level cash margin reached $20.19 per Boe in the second quarter, a 31 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.
 
3

Corporate Cost Structure to Improve by $475 Million Annually
Further expanding Devon’s profitability is its improving general and administrative (G&A) cost structure. Upstream-related G&A expenses totaled $153 million, a 22 percent improvement compared to the first quarter. The significantly lower overhead costs were driven by reduced personnel expenses.
The company has also reduced financing costs. With the early retirement of $807 million of debt early in the year, the company expects to reduce net financing costs by approximately $64 million on an annual basis.
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.
Investment-Grade Financial Position Continues to Strengthen
Devon’s financial position remains exceptionally strong, with investment-grade credit ratings and excellent liquidity. The company exited the second quarter with $1.5 billion of cash on hand. Adjusted for the sale of EnLink Midstream in July, pro forma cash balances reached $4.6 billion and the company’s consolidated debt declined by 40 percent to $6.1 billion.
Second-Quarter Earnings and Cash-Flow Results
The company reported a net loss attributable to Devon of $425 million or $0.83 per diluted share in the second quarter. Excluding the impact of noncontrolling interests, the company reported a net loss of $335 million. Devon’s results were impacted by certain items securities analysts typically exclude from their published estimates. After excluding adjusting items, the company’s core earnings totaled $177 million or $0.34 per diluted share. Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) reached $1.0 billion in the quarter.
Devon’s operating cash flow from continuing operations totaled $269 million in the second quarter. Operating cash flow in the quarter was impacted by several non-recurring or unusual items, including a non-cash foreign exchange loss, restructuring charges, EnLink’s reclassification to discontinued operations and working capital changes. The most significant item was related to a non-cash, foreign exchange loss. This impact was driven by foreign currency denominated intercompany loan activity resulting in a realized loss of $244 million as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. For more understanding of the company’s cash flow performance during the quarter please refer to the explanations and reconciliations provided later in this release.
Pursuant to regulatory disclosure requirements, Devon is required to reconcile non-GAAP (generally accepted accounting principles) financial measures to the related GAAP information. Reconciliations of these non-GAAP measures are provided within the tables of this release.
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 second-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Aug. 1, 2018, and will serve primarily as a forum for analyst and investor questions and answers.
 
4

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 .
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
June 30,	 	  	Six Months Ended
June 30,	 	
 	  	2018	 	  	2017	 	  	2018	 	  	2017	 	
Oil and bitumen (MBbls/d)	  				  				  				  				
U. S. - Core	  	 	136	 	  	 	113	 	  	 	129	 	  	 	117	 	
Heavy Oil	  	 	109	 	  	 	122	 	  	 	119	 	  	 	130	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	245	 	  	 	235	 	  	 	248	 	  	 	247	 	
Divested assets	  	 	—  	 	  	 	3	 	  	 	—  	 	  	 	2	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	245	 	  	 	238	 	  	 	248	 	  	 	249	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				
U. S. - Core	  	 	105	 	  	 	90	 	  	 	98	 	  	 	89	 	
Divested assets	  	 	4	 	  	 	7	 	  	 	5	 	  	 	8	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	109	 	  	 	97	 	  	 	103	 	  	 	97	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				
U. S. - Core	  	 	1,013	 	  	 	1,010	 	  	 	1,007	 	  	 	1,012	 	
Heavy Oil	  	 	12	 	  	 	14	 	  	 	12	 	  	 	18	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	1,025	 	  	 	1,024	 	  	 	1,019	 	  	 	1,030	 	
Divested assets	  	 	103	 	  	 	184	 	  	 	133	 	  	 	188	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	1,128	 	  	 	1,208	 	  	 	1,152	 	  	 	1,218	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				
U. S. - Core	  	 	409	 	  	 	371	 	  	 	395	 	  	 	375	 	
Heavy Oil	  	 	111	 	  	 	124	 	  	 	121	 	  	 	133	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	520	 	  	 	495	 	  	 	516	 	  	 	508	 	
Divested assets	  	 	21	 	  	 	41	 	  	 	27	 	  	 	42	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	541	 	  	 	536	 	  	 	543	 	  	 	550	 	

6

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION

PRODUCTION TREND

 	  	2017	 	  	2018	 	
 	  	Quarter 2	 	  	Quarter 3	 	  	Quarter 4	 	  	Quarter 1	 	  	Quarter 2	 	
Oil and bitumen (MBbls/d)	  				  				  				  				  				
STACK	  	 	25	 	  	 	27	 	  	 	30	 	  	 	35	 	  	 	35	 	
Delaware Basin	  	 	30	 	  	 	31	 	  	 	32	 	  	 	36	 	  	 	46	 	
Rockies Oil	  	 	13	 	  	 	12	 	  	 	15	 	  	 	18	 	  	 	16	 	
Heavy Oil	  	 	122	 	  	 	121	 	  	 	132	 	  	 	129	 	  	 	109	 	
Eagle Ford	  	 	34	 	  	 	28	 	  	 	27	 	  	 	23	 	  	 	28	 	
Barnett Shale	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	
Other	  	 	10	 	  	 	11	 	  	 	9	 	  	 	9	 	  	 	10	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	235	 	  	 	231	 	  	 	246	 	  	 	251	 	  	 	245	 	
Divested assets	  	 	3	 	  	 	2	 	  	 	—	 	  	 	—	 	  	 	—	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	238	 	  	 	233	 	  	 	246	 	  	 	251	 	  	 	245	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				  				
STACK	  	 	31	 	  	 	32	 	  	 	34	 	  	 	37	 	  	 	38	 	
Delaware Basin	  	 	10	 	  	 	11	 	  	 	13	 	  	 	11	 	  	 	16	 	
Rockies Oil	  	 	1	 	  	 	1	 	  	 	1	 	  	 	2	 	  	 	2	 	
Eagle Ford	  	 	10	 	  	 	12	 	  	 	13	 	  	 	8	 	  	 	13	 	
Barnett Shale	  	 	35	 	  	 	29	 	  	 	36	 	  	 	31	 	  	 	34	 	
Other	  	 	3	 	  	 	2	 	  	 	3	 	  	 	2	 	  	 	2	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	90	 	  	 	87	 	  	 	100	 	  	 	91	 	  	 	105	 	
Divested assets	  	 	7	 	  	 	7	 	  	 	6	 	  	 	6	 	  	 	4	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	97	 	  	 	94	 	  	 	106	 	  	 	97	 	  	 	109	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				  				
STACK	  	 	298	 	  	 	313	 	  	 	316	 	  	 	344	 	  	 	352	 	
Delaware Basin	  	 	94	 	  	 	90	 	  	 	89	 	  	 	97	 	  	 	100	 	
Rockies Oil	  	 	17	 	  	 	13	 	  	 	14	 	  	 	18	 	  	 	18	 	
Heavy Oil	  	 	14	 	  	 	16	 	  	 	15	 	  	 	12	 	  	 	12	 	
Eagle Ford	  	 	92	 	  	 	86	 	  	 	87	 	  	 	63	 	  	 	74	 	
Barnett Shale	  	 	496	 	  	 	498	 	  	 	466	 	  	 	470	 	  	 	460	 	
Other	  	 	13	 	  	 	10	 	  	 	13	 	  	 	10	 	  	 	9	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	1,024	 	  	 	1,026	 	  	 	1,000	 	  	 	1,014	 	  	 	1,025	 	
Divested assets	  	 	184	 	  	 	175	 	  	 	175	 	  	 	163	 	  	 	103	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	1,208	 	  	 	1,201	 	  	 	1,175	 	  	 	1,177	 	  	 	1,128	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				  				
STACK	  	 	105	 	  	 	111	 	  	 	117	 	  	 	129	 	  	 	132	 	
Delaware Basin	  	 	55	 	  	 	57	 	  	 	60	 	  	 	64	 	  	 	79	 	
Rockies Oil	  	 	17	 	  	 	16	 	  	 	19	 	  	 	23	 	  	 	21	 	
Heavy Oil	  	 	124	 	  	 	124	 	  	 	134	 	  	 	131	 	  	 	111	 	
Eagle Ford	  	 	60	 	  	 	54	 	  	 	55	 	  	 	41	 	  	 	54	 	
Barnett Shale	  	 	118	 	  	 	113	 	  	 	114	 	  	 	110	 	  	 	111	 	
Other	  	 	16	 	  	 	14	 	  	 	13	 	  	 	13	 	  	 	12	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	495	 	  	 	489	 	  	 	512	 	  	 	511	 	  	 	520	 	
Divested assets	  	 	41	 	  	 	38	 	  	 	36	 	  	 	33	 	  	 	21	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	536	 	  	 	527	 	  	 	548	 	  	 	544	 	  	 	541	 	

7

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

 	  	Quarter 2	 	  	June YTD	 	
 	  	2018	 	  	2017	 	  	2018	 	  	2017	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	67.83	 	  	$	48.32	 	  	$	65.38	 	  	$	50.16	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	2.80	 	  	$	3.19	 	  	$	2.90	 	  	$	3.25	 	
REALIZED PRICES

		
 	  	Quarter Ended June 30, 2018	 	
 	  	Oil /Bitumen
(Per Bbl)	 	 	NGL
(Per Bbl)	 	 	Gas
(Per Mcf)	 	  	Total
(Per Boe)	 	
United States	  	$	65.41	 	 	$	24.10	 	 	$	2.01	 	  	$	31.97	 	
Canada	  	$	31.70	 	 	 	N/M	 	 	 	N/M	 	  	$	31.17	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	50.43	 	 	$	24.10	 	 	$	2.01	 	  	$	31.81	 	
Cash settlements	  	$	(5.80	) 	 	$	(1.66	) 	 	$	0.13	 	  	$	(2.68	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	44.63	 	 	$	22.44	 	 	$	2.14	 	  	$	29.13	 	

 	  	Quarter Ended June 30, 2017	 	
 	  	Oil /Bitumen
(Per Bbl)	 	 	NGL
(Per Bbl)	 	 	Gas
(Per Mcf)	 	  	Total
(Per Boe)	 	
United States	  	$	46.65	 	 	$	13.26	 	 	$	2.50	 	  	$	23.58	 	
Canada	  	$	29.05	 	 	 	N/M	 	 	 	N/M	 	  	$	28.50	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	37.63	 	 	$	13.26	 	 	$	2.50	 	  	$	24.72	 	
Cash settlements	  	$	0.29	 	 	$	(0.03	) 	 	$	0.04	 	  	$	0.22	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	37.92	 	 	$	13.23	 	 	$	2.54	 	  	$	24.94	 	

 	  	Six Months Ended June 30, 2018	 	
 	  	Oil /Bitumen
(Per Bbl)	 	 	NGL
(Per Bbl)	 	 	Gas
(Per Mcf)	 	  	Total
(Per Boe)	 	
United States	  	$	63.71	 	 	$	23.38	 	 	$	2.21	 	  	$	31.20	 	
Canada	  	$	25.24	 	 	 	N/M	 	 	 	N/M	 	  	$	24.84	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	45.25	 	 	$	23.38	 	 	$	2.21	 	  	$	29.79	 	
Cash settlements	  	$	(2.93	) 	 	$	(1.13	) 	 	$	0.16	 	  	$	(1.23	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	42.32	 	 	$	22.25	 	 	$	2.37	 	  	$	28.56	 	

 	  	Six Months Ended June 30, 2017	 	
 	  	Oil /Bitumen
(Per Bbl)	 	 	NGL
(Per Bbl)	 	 	Gas
(Per Mcf)	 	  	Total
(Per Boe)	 	
United States	  	$	48.18	 	 	$	14.36	 	 	$	2.59	 	  	$	24.72	 	
Canada	  	$	27.60	 	 	 	N/M	 	 	 	N/M	 	  	$	27.03	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price without hedges	  	$	37.48	 	 	$	14.36	 	 	$	2.59	 	  	$	25.28	 	
Cash settlements	  	$	0.39	 	 	$	(0.02	) 	 	$	—  	 	  	$	0.19	 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	37.87	 	 	$	14.34	 	 	$	2.59	 	  	$	25.47	 	

8

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

 	    	Quarter Ended
June 30,	 	  	Six Months Ended
June 30,	 	
 	    	2018	 	  	2017	 	  	2018	 	  	2017	 	
Upstream revenues	    	$	1,069	 	  	$	1,332	 	  	$	2,388	 	  	$	2,873	 	
Marketing revenues	    	 	1,180	 	  	 	833	 	  	 	2,059	 	  	 	1,692	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total revenues	    	 	2,249	 	  	 	2,165	 	  	 	4,447	 	  	 	4,565	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Production expenses	    	 	572	 	  	 	455	 	  	 	1,115	 	  	 	912	 	
Exploration expenses	    	 	68	 	  	 	57	 	  	 	101	 	  	 	152	 	
Marketing expenses	    	 	1,160	 	  	 	849	 	  	 	2,033	 	  	 	1,728	 	
Depreciation, depletion and amortization	    	 	420	 	  	 	369	 	  	 	819	 	  	 	769	 	
Asset impairments	    	 	154	 	  	 	—  	 	  	 	154	 	  	 	—  	 	
Asset dispositions	    	 	23	 	  	 	(22	) 	  	 	11	 	  	 	(30	) 	
General and administrative expenses	    	 	153	 	  	 	181	 	  	 	352	 	  	 	376	 	
Financing costs, net	    	 	62	 	  	 	77	 	  	 	449	 	  	 	160	 	
Restructuring and transaction costs	    	 	94	 	  	 	—  	 	  	 	94	 	  	 	—  	 	
Other expenses	    	 	24	 	  	 	(8	) 	  	 	45	 	  	 	(22	) 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total expenses	    	 	2,730	 	  	 	1,958	 	  	 	5,173	 	  	 	4,045	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Earnings (loss) from continuing operations before income taxes	    	 	(481	) 	  	 	207	 	  	 	(726	) 	  	 	520	 	
Income tax benefit	    	 	(7	) 	  	 	(5	) 	  	 	(41	) 	  	 	—  	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net earnings (loss) from continuing operations	    	 	(474	) 	  	 	212	 	  	 	(685	) 	  	 	520	 	
Net earnings from discontinued operations, net of income tax expense	    	 	139	 	  	 	33	 	  	 	197	 	  	 	42	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net earnings (loss)	    	 	(335	) 	  	 	245	 	  	 	(488	) 	  	 	562	 	
Net earnings attributable to noncontrolling interests	    	 	90	 	  	 	26	 	  	 	134	 	  	 	40	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net earnings (loss) attributable to Devon	    	$	(425	) 	  	$	219	 	  	$	(622	) 	  	$	522	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Basic net earnings (loss) per share:	    				  				  				  				
Basic earnings (loss) from continuing operations per share	    	$	(0.92	) 	  	$	0.40	 	  	$	(1.33	) 	  	$	0.99	 	
Basic earnings from discontinued operations per share	    	 	0.09	 	  	 	0.01	 	  	 	0.13	 	  	 	—  	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Basic net earnings (loss) per share	    	$	(0.83	) 	  	$	0.41	 	  	$	(1.20	) 	  	$	0.99	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Diluted net earnings (loss) per share:	    				  				  				  				
Diluted earnings (loss) from continuing operations per share	    	$	(0.92	) 	  	$	0.40	 	  	$	(1.33	) 	  	$	0.99	 	
Diluted earnings from discontinued operations per share	    	 	0.09	 	  	 	0.01	 	  	 	0.13	 	  	 	—  	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Diluted net earnings (loss) per share	    	$	(0.83	) 	  	$	0.41	 	  	$	(1.20	) 	  	$	0.99	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Weighted average common shares outstanding:	    				  				  				  				
Basic	    	 	521	 	  	 	526	 	  	 	524	 	  	 	525	 	
Diluted	    	 	524	 	  	 	529	 	  	 	527	 	  	 	528	 	
UPSTREAM REVENUES
(in millions)

 	    	Quarter Ended
June 30,	 	    	Six Months Ended
June 30,	 	
 	    	2018	 	  	2017	 	    	2018	 	  	2017	 	
Oil, gas and NGL sales	    	$	1,566	 	  	$	1,206	 	    	$	2,926	 	  	$	2,515	 	
Derivative cash settlements	    	 	(131	) 	  	 	11	 	    	 	(120	) 	  	 	19	 	
Derivative valuation changes	    	 	(366	) 	  	 	115	 	    	 	(418	) 	  	 	339	 	
	    	 	 	 	  	 	 	 	    	 	 	 	  	 	 	 	
Upstream revenues	    	$	1,069	 	  	$	1,332	 	    	$	2,388	 	  	$	2,873	 	
	    	 	 	 	  	 	 	 	    	 	 	 	  	 	 	 	
PRODUCTION EXPENSES
(in millions)

 	    	Quarter Ended
June 30,	 	    	Six Months Ended
June 30,	 	
 	    	2018	 	    	2017	 	    	2018	 	    	2017	 	
Lease operating expense	    	$	269	 	    	$	239	 	    	$	510	 	    	$	462	 	
Gathering, processing & transportation	    	 	224	 	    	 	160	 	    	 	452	 	    	 	323	 	
Production taxes	    	 	67	 	    	 	41	 	    	 	126	 	    	 	96	 	
Property taxes	    	 	12	 	    	 	15	 	    	 	27	 	    	 	31	 	
	    	 	 	 	    	 	 	 	    	 	 	 	    	 	 	 	
Production expense	    	$	572	 	    	$	455	 	    	$	1,115	 	    	$	912	 	

9

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

 	    	Quarter Ended
June 30,	 	  	Six Months Ended
June 30,	 	
 	    	2018	 	  	2017	 	  	2018	 	  	2017	 	
Cash flows from operating activities:	    				  				  				  				
Net earnings (loss)	    	$	(335	) 	  	$	245	 	  	$	(488	) 	  	$	562	 	
Adjustments to reconcile net earnings to net cash
from operating activities:	    				  				  				  				
Earnings from discontinued operations, net of tax	    	 	(139	) 	  	 	(33	) 	  	 	(197	) 	  	 	(42	) 	
Depreciation, depletion and amortization	    	 	420	 	  	 	369	 	  	 	819	 	  	 	769	 	
Asset impairments	    	 	154	 	  	 	—  	 	  	 	154	 	  	 	—  	 	
Leasehold impairments	    	 	53	 	  	 	22	 	  	 	61	 	  	 	64	 	
Accretion on discounted liabilities	    	 	15	 	  	 	15	 	  	 	31	 	  	 	32	 	
Total (gains) losses on commodity derivatives	    	 	497	 	  	 	(126	) 	  	 	538	 	  	 	(358	) 	
Cash settlements on commodity derivatives	    	 	(131	) 	  	 	11	 	  	 	(120	) 	  	 	19	 	
(Gains) and losses on asset dispositions	    	 	23	 	  	 	(22	) 	  	 	11	 	  	 	(30	) 	
Deferred income tax expense (benefit)	    	 	20	 	  	 	(17	) 	  	 	(18	) 	  	 	(32	) 	
Share-based compensation	    	 	58	 	  	 	45	 	  	 	96	 	  	 	81	 	
Early retirement of debt	    	 	—  	 	  	 	—  	 	  	 	312	 	  	 	—  	 	
Total (gains) losses on foreign exchange	    	 	31	 	  	 	(49	) 	  	 	81	 	  	 	(64	) 	
Settlements of intercompany foreign denominated assets/liabilities	    	 	(244	) 	  	 	1	 	  	 	(243	) 	  	 	10	 	
Other	    	 	(20	) 	  	 	23	 	  	 	(50	) 	  	 	11	 	
Changes in assets and liabilities, net	    	 	(133	) 	  	 	102	 	  	 	(108	) 	  	 	133	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net cash from operating activities - continuing operations	    	 	269	 	  	 	586	 	  	 	879	 	  	 	1,155	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Cash flows from investing activities:	    				  				  				  				
Capital expenditures	    	 	(602	) 	  	 	(434	) 	  	 	(1,253	) 	  	 	(831	) 	
Acquisitions of property and equipment	    	 	(10	) 	  	 	(13	) 	  	 	(16	) 	  	 	(33	) 	
Divestitures of property and equipment	    	 	560	 	  	 	75	 	  	 	607	 	  	 	107	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net cash from investing activities - continuing operations	    	 	(52	) 	  	 	(372	) 	  	 	(662	) 	  	 	(757	) 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Cash flows from financing activities:	    				  				  				  				
Repayments of long-term debt principal	    	 	—  	 	  	 	—  	 	  	 	(807	) 	  	 	—  	 	
Early retirement of debt	    	 	—  	 	  	 	—  	 	  	 	(304	) 	  	 	—  	 	
Repurchases of common stock	    	 	(428	) 	  	 	—  	 	  	 	(499	) 	  	 	—  	 	
Dividends paid on common stock	    	 	(42	) 	  	 	(33	) 	  	 	(74	) 	  	 	(65	) 	
Shares exchanged for tax withholdings	    	 	(6	) 	  	 	(3	) 	  	 	(44	) 	  	 	(56	) 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net cash from financing activities - continuing operations	    	 	(476	) 	  	 	(36	) 	  	 	(1,728	) 	  	 	(121	) 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Effect of exchange rate changes on cash:	    				  				  				  				
Settlements of intercompany foreign denominated assets/liabilities	    	 	244	 	  	 	(1	) 	  	 	243	 	  	 	(10	) 	
Other	    	 	(17	) 	  	 	9	 	  	 	(31	) 	  	 	10	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total effect of exchange rate changes on cash – continuing operations	    	 	227	 	  	 	8	 	  	 	212	 	  	 	—  	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net change in cash, cash equivalents and restricted cash of
continuing operations	    	 	(32	) 	  	 	186	 	  	 	(1,299	) 	  	 	277	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Cash flows from discontinued operations:	    				  				  				  				
Operating activities	    	 	236	 	  	 	151	 	  	 	430	 	  	 	328	 	
Investing activities	    	 	(222	) 	  	 	(215	) 	  	 	(402	) 	  	 	(284	) 	
Financing activities	    	 	73	 	  	 	128	 	  	 	112	 	  	 	89	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net change in cash, cash equivalents and restricted cash of
discontinued operations	    	 	87	 	  	 	64	 	  	 	140	 	  	 	133	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Net change in cash, cash equivalents and restricted cash	    	 	55	 	  	 	250	 	  	 	(1,159	) 	  	 	410	 	
Cash, cash equivalents and restricted cash at beginning of period	    	 	1,470	 	  	 	2,119	 	  	 	2,684	 	  	 	1,959	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Cash, cash equivalents and restricted cash at end of period	    	$	1,525	 	  	$	2,369	 	  	$	1,525	 	  	$	2,369	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Reconciliation of cash, cash equivalents and restricted cash:	    				  				  				  				
Cash and cash equivalents	    	$	1,460	 	  	$	2,358	 	  	$	1,460	 	  	$	2,358	 	
Restricted cash included in other current assets	    	 	28	 	  	 	—  	 	  	 	28	 	  	 	—  	 	
Cash and cash equivalents included in current assets held for sale	    	 	37	 	  	 	11	 	  	 	37	 	  	 	11	 	
	    	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total cash, cash equivalents and restricted cash	    	$	1,525	 	  	$	2,369	 	  	$	1,525	 	  	$	2,369	 	

10

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

 	    	June 30,	 	  	December 31,	 	
 	    	2018	 	  	2017	 	
Current assets:	    				  				
Cash and cash equivalents	    	$	1,460	 	  	$	2,642	 	
Accounts receivable	    	 	1,141	 	  	 	989	 	
Current assets held for sale	    	 	10,764	 	  	 	760	 	
Other current assets	    	 	455	 	  	 	400	 	
	    	 	 	 	  	 	 	 	
Total current assets	    	 	13,820	 	  	 	4,791	 	
Oil and gas property and equipment, based on successful efforts accounting, net	    	 	12,957	 	  	 	13,318	 	
Other property and equipment, net	    	 	1,164	 	  	 	1,266	 	
	    	 	 	 	  	 	 	 	
Total property and equipment, net	    	 	14,121	 	  	 	14,584	 	
Goodwill	    	 	841	 	  	 	841	 	
Other long-term assets	    	 	377	 	  	 	296	 	
Long-term assets held for sale	    	 	—  	 	  	 	9,729	 	
	    	 	 	 	  	 	 	 	
Total assets	    	$	29,159	 	  	$	30,241	 	
	    	 	 	 	  	 	 	 	
Current liabilities:	    				  				
Accounts payable	    	$	771	 	  	$	633	 	
Revenues and royalties payable	    	 	959	 	  	 	748	 	
Short-term debt	    	 	277	 	  	 	115	 	
Current liabilities held for sale	    	 	5,291	 	  	 	991	 	
Other current liabilities	    	 	1,079	 	  	 	828	 	
	    	 	 	 	  	 	 	 	
Total current liabilities	    	 	8,377	 	  	 	3,315	 	
	    	 	 	 	  	 	 	 	
Long-term debt	    	 	5,790	 	  	 	6,749	 	
Asset retirement obligations	    	 	1,088	 	  	 	1,099	 	
Other long-term liabilities	    	 	624	 	  	 	549	 	
Long-term liabilities held for sale	    	 	—  	 	  	 	3,936	 	
Deferred income taxes	    	 	432	 	  	 	489	 	
Equity:	    				  				
Common stock	    	 	51	 	  	 	53	 	
Additional paid-in capital	    	 	6,888	 	  	 	7,333	 	
Retained earnings	    	 	6	 	  	 	702	 	
Accumulated other comprehensive earnings	    	 	1,091	 	  	 	1,166	 	
Treasury stock, at cost, 0.5 million shares in 2018	    	 	(22	) 	  	 	—  	 	
	    	 	 	 	  	 	 	 	
Total stockholders’ equity attributable to Devon	    	 	8,014	 	  	 	9,254	 	
Noncontrolling interests	    	 	4,834	 	  	 	4,850	 	
	    	 	 	 	  	 	 	 	
Total equity	    	 	12,848	 	  	 	14,104	 	
	    	 	 	 	  	 	 	 	
Total liabilities and equity	    	$	29,159	 	  	$	30,241	 	
	    	 	 	 	  	 	 	 	
Common shares outstanding	    	 	515	 	  	 	525	 	
CAPITAL EXPENDITURES
(in millions)

 	    	Quarter Ended
June 30, 2018	 	    	Six Months Ended
June 30, 2018	 	
Upstream capital	    	$	607	 	    	$	1,271	 	
Land and other acquisitions	    	 	12	 	    	 	18	 	
	    	 	 	 	    	 	 	 	
Exploration and production (E&P) capital	    	 	619	 	    	 	1,289	 	
Capitalized interest	    	 	17	 	    	 	35	 	
Other	    	 	9	 	    	 	22	 	
	    	 	 	 	    	 	 	 	
Devon capital expenditures	    	$	645	 	    	$	1,346	 	

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 second-quarter 2018 earnings.

 	  	Quarter Ended June 30, 2018	 	
(in millions, except per share amounts)	  	Before-tax	 	  	After-tax	 	  	After
Noncontrolling
Interests	 	  	Per Diluted
Share	 	
Continuing Operations	  				  				  				  				
Loss attributable to Devon (GAAP)	  	$	(481	) 	  	$	(474	) 	  	$	(474	) 	  	$	(0.92	) 	
Adjustments:	  				  				  				  				
Asset dispositions	  	 	23	 	  	 	18	 	  	 	18	 	  	 	0.03	 	
Asset and exploration impairments	  	 	207	 	  	 	159	 	  	 	159	 	  	 	0.31	 	
Deferred tax asset valuation allowance	  	 	—  	 	  	 	73	 	  	 	73	 	  	 	0.14	 	
Fair value changes in financial instruments and foreign currency	  	 	376	 	  	 	291	 	  	 	291	 	  	 	0.56	 	
Restructuring and transaction costs	  	 	94	 	  	 	72	 	  	 	72	 	  	 	0.14	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings attributable to Devon (Non-GAAP)	  	$	219	 	  	$	139	 	  	$	139	 	  	$	0.26	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Discontinued Operations	  				  				  				  				
Earnings attributable to Devon (GAAP)	  	$	149	 	  	$	139	 	  	$	49	 	  	$	0.09	 	
Adjustments:	  				  				  				  				
Fair value changes and minimum volume commitment settlement	  	 	(36	) 	  	 	(30	) 	  	 	(11	) 	  	 	(0.01	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings attributable to Devon (Non-GAAP)	  	$	113	 	  	$	109	 	  	$	38	 	  	$	0.08	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  				  				  				  				
Loss attributable to Devon (GAAP)	  	$	(332	) 	  	$	(335	) 	  	$	(425	) 	  	$	(0.83	) 	
Adjustments:	  				  				  				  				
Continuing Operations	  	 	700	 	  	 	613	 	  	 	613	 	  	 	1.18	 	
Discontinued Operations	  	 	(36	) 	  	 	(30	) 	  	 	(11	) 	  	 	(0.01	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings attributable to Devon (Non-GAAP)	  	$	332	 	  	$	248	 	  	$	177	 	  	$	0.34	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
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)	  	June 30,
2018	 	
Total debt (GAAP) (1)	  	$	6,067	 	
Less cash and cash equivalents	  	 	(1,460	) 	
	  	 	 	 	
Net debt (Non-GAAP)	  	$	4,607	 	

(1)	Excludes EnLink since its debt-related amounts are included in liabilities held for sale.	
 
12

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
ADJUSTED EBITDA
We define Adjusted EBITDA, a non-GAAP financial measure, as EBITDA adjusted for certain items presented in the accompanying reconciliation. We believe that EBITDA is widely used by investors to measure a company’s performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. In addition, Adjusted EBITDA generally excludes certain other items that management believes affect the comparability of operating results or are not related to Devon’s ongoing operations. Management uses Adjusted EBITDA to evaluate the company’s operational trends and performance relative to other oil and gas companies.
ADJUSTED EBITDA
(in millions)

 	  	Quarter Ended June 30, 2018	 	
 	  	Continuing	 	  	Discontinued	 	  	 	 	
 	  	Operations	 	  	Operations	 	  	Total	 	
Net earnings (loss)	  	$	(474	) 	  	$	139	 	  	$	(335	) 	
Financing costs, net	  	 	62	 	  	 	45	 	  	 	107	 	
Income tax expense (benefit)	  	 	(7	) 	  	 	10	 	  	 	3	 	
Depreciation, depletion and amortization	  	 	420	 	  	 	106	 	  	 	526	 	
Accretion of discounted liabilities	  	 	15	 	  	 	—  	 	  	 	15	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
EBITDA	  	$	16	 	  	$	300	 	  	$	316	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Non-cash stock compensation	  	 	32	 	  	 	10	 	  	 	42	 	
Asset and leasehold impairments	  	 	207	 	  	 	—  	 	  	 	207	 	
Asset disposition losses	  	 	23	 	  	 	—  	 	  	 	23	 	
Restructuring and transaction costs	  	 	94	 	  	 	—  	 	  	 	94	 	
Derivative and financial instrument valuation changes	  	 	376	 	  	 	12	 	  	 	388	 	
EnLink minimum volume commitment settlement	  	 	—  	 	  	 	(48	) 	  	 	(48	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Adjusted EBITDA	  	$	748	 	  	$	274	 	  	$	1,022	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
PRO FORMA CASH & CASH EQUIVALENTS
Devon defines pro forma cash and cash equivalents as cash and cash equivalents plus proceeds from the recently closed EnLink Midstream sale. Devon believes adjusting for this item provides a clearer picture of Devon’s financial position.

(in millions)	  	June 30,
2018	 	
Cash and cash equivalents (GAAP)	  	$	1,460	 	
Proceeds from EnLink Midstream monetization that closed in mid-July	  	 	3,125	 	
	  	 	 	 	
Pro forma cash and cash equivalents (Non-GAAP)	  	$	4,585	 	

13

DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
 
PRODUCTION GUIDANCE

 	  	Quarter 3	 	  	Full Year	 	
 	  	Low	 	  	High	 	  	Low	 	  	High	 	
Oil and bitumen (MBbls/d)	  				  				  				  				
U.S. – retained assets	  	 	132	 	  	 	137	 	  	 	130	 	  	 	135	 	
Heavy Oil	  	 	115	 	  	 	120	 	  	 	120	 	  	 	125	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total – retained assets	  	 	247	 	  	 	257	 	  	 	250	 	  	 	260	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				
Total – retained assets	  	 	100	 	  	 	105	 	  	 	100	 	  	 	104	 	
Gas (MMcf/d)	  				  				  				  				
U.S. – retained assets	  	 	1,010	 	  	 	1,060	 	  	 	1,000	 	  	 	1,050	 	
Heavy Oil	  	 	11	 	  	 	13	 	  	 	11	 	  	 	13	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total – retained assets	  	 	1,021	 	  	 	1,073	 	  	 	1,011	 	  	 	1,063	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				
U.S. – retained assets	  	 	400	 	  	 	419	 	  	 	397	 	  	 	414	 	
Heavy Oil	  	 	117	 	  	 	122	 	  	 	122	 	  	 	127	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total – retained assets	  	 	517	 	  	 	541	 	  	 	519	 	  	 	541	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
PRICE REALIZATIONS GUIDANCE

 	  	Quarter 3	 	 	Full Year	 	
 	  	Low	 	 	High	 	 	Low	 	 	High	 	
Oil and bitumen - % of WTI	  				 				 				 				
U.S. (1)	  	 	88	% (1)  	 	 	93	% (1)  	 	 	92	% (1)  	 	 	97	% (1)  	
Canada (1)	  	 	40	% (1)  	 	 	50	% (1)  	 	 	37	% (1)  	 	 	42	% (1)  	
NGL - realized price	  	$	23	 	 	$	28	 	 	$	22	 	 	$	27	 	
Natural gas - % of Henry Hub	  	 	70	% 	 	 	80	% 	 	 	70	% 	 	 	80	% 	
 
(1)	Does not include benefits from basis swaps and firm transportation agreements.	
OTHER GUIDANCE ITEMS

 	  	Quarter 3	 	 	Full Year	 	
($ millions, except Boe and %)	  	Low	 	 	High	 	 	Low	 	 	High	 	
Marketing & midstream operating profit	  	$	5	 	 	$	15	 	 	$	40	 	 	$	50	 	
LOE & GP&T per BOE	  	$	9.50	 	 	$	9.75	 	 	$	9.40	 	 	$	9.90	 	
Production & Property Tax (% of upstream sales)	  	 	5.20	% 	 	 	5.40	% 	 	 	5.20	% 	 	 	5.40	% 	
Exploration expenses	  	$	20	 	 	$	30	 	 	$	90	 	 	$	100	 	
Depreciation, depletion and amortization	  	$	420	 	 	$	470	 	 	$	1,700	 	 	$	1,800	 	
General & administrative expenses	  	$	150	 	 	$	170	 	 	$	650	 	 	$	700	 	
Financing costs, net (2)	  	$	70	(2)  	 	$	80	(2)  	 	$	285	(2)  	 	$	295	(2)  	
Other expenses	  	$	15	 	 	$	20	 	 	$	60	 	 	$	80	 	
Current income tax rate	  	 	0	% 	 	 	5	% 	 	 	0	% 	 	 	5	% 	
Deferred income tax rate	  	 	20	% 	 	 	25	% 	 	 	20	% 	 	 	25	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax rate	  	 	20	% 	 	 	30	% 	 	 	20	% 	 	 	30	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average basic share count outstanding (MM)	  	 	493	 	 	 	496	 	 	 	500	 	 	 	505	 	
 
(2)	On a go-forward basis interest expense that had been historically capitalized will now be included in financing costs, net.	
CAPITAL EXPENDITURES GUIDANCE

 	  	Quarter 3	 	  	Full Year	 	
(in millions)	  	Low	 	  	High	 	  	Low	 	  	High	 	
Upstream capital	  	$	550	 	  	$	600	 	  	$	2,200	 	  	$	2,400	 	
Capitalized interest and other (2)	  	 	20	 	  	 	30	 	  	 	100	 	  	 	150	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	$	570	 	  	$	630	 	  	$	2,300	 	  	$	2,550	 	

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)	 	
Q3-Q4 2018	  	 	91,300	 	  	$	58.15	 	  	 	100,700	 	  	$	52.27	 	  	$	62.87	 		
Q1-Q4 2019	  	 	54,225	 	  	$	59.34	 	  	 	65,875	 	  	$	52.76	 	  	$	62.76	 		
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)	 	
Q3-Q4 2018	  	Midland Sweet	  	 	23,000	 	  	$	(1.02	) 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q3-Q4 2018	  	Argus LLS	  	 	12,000	 	  	$	3.95	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q3-Q4 2018	  	Argus MEH	  	 	15,832	 	  	$	2.82	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q3-Q4 2018	  	NYMEX Roll	  	 	21,315	 	  	$	0.63	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q3-Q4 2018	  	Western Canadian Select	  	 	78,000	 	  	$	(14.91	) 	 	 	2,000	 	  	$	(15.50	) 	 	$	(13.93	) 		
Q1-Q4 2019	  	Midland Sweet	  	 	28,000	 	  	$	(0.46	) 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q1-Q4 2019	  	Argus LLS	  	 	1,000	 	  	$	4.60	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q1-Q4 2019	  	Argus MEH	  	 	16,000	 	  	$	2.84	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q1-Q4 2019	  	NYMEX Roll	  	 	24,000	 	  	$	0.51	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
Q1-Q4 2020	  	NYMEX Roll	  	 	24,000	 	  	$	0.31	 	 	 	—  	 	  	$	—  	 	 	$	—  	 		
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)	 	
Q3-Q4 2018	  	 	278,750	 	  	$	2.91	 	  	 	246,500	 	  	$	2.76	 	  	$	3.09	 		
Q1-Q4 2019	  	 	194,000	 	  	$	2.81	 	  	 	155,750	 	  	$	2.64	 	  	$	3.03	 		
Natural Gas Basis Swaps

	Period	  	Index	  	Volume
(MMBtu/d)	 	  	Weighted Average
Differential to
Henry Hub
($/MMBtu)	 	
Q3-Q4 2018	  	Panhandle Eastern Pipe Line	  	 	120,000	 	  	$	(0.51	) 		
Q3-Q4 2018	  	El Paso Natural Gas	  	 	100,000	 	  	$	(1.25	) 		
Q3-Q4 2018	  	Houston Ship Channel	  	 	115,000	 	  	$	0.01	 		
Q3-Q4 2018	  	Transco Zone 4	  	 	15,000	 	  	$	(0.03	) 		
Q1-Q4 2019	  	Panhandle Eastern Pipe Line	  	 	62,500	 	  	$	(0.77	) 		
Q1-Q4 2019	  	El Paso Natural Gas	  	 	120,000	 	  	$	(1.48	) 		
Q1-Q4 2019	  	Houston Ship Channel	  	 	100,000	 	  	$	(0.01	) 		
Q1-Q4 2019	  	Transco Zone 4	  	 	7,500	 	  	$	(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 July 27, 2018.
 
15

Q2 2018 Operations Report Key Messages 2 Modeling Stats 3 Q2 Results 4 Outlook 6 Delaware Basin 12 STACK17 Eagle Ford 21 Rockies 22 Barnett Shale 23 Heavy Oil 24 NYSE: DVN devonenergy.com Exhibit 99.2

Q2 light-oil production exceeds high end of guidance Driven by strong well productivity in Delaware and STACK U.S. light-oil growth running ahead of original budget YTD No change to full-year capital spending budget Free cash flow positioned to rapidly expand Majority of U.S. oil has access to premium Gulf Coast pricing G&A and interest savings to reach ~$475 MM annually(1) Per-unit LOE on track to improve by ~10% by 1H 2019 Divestiture program accelerates value creation Ownership in EnLink Midstream monetized for 12x cash flow Expect to exceed $5 billion divestiture target around year end (pg. 10) Shareholder-friendly initiatives underway Recently increased share-repurchase program to $4 billion Consolidated debt has declined by ~40% YTD(1) Executing the 2020 Vision Focus on capital efficiency Portfolio simplification Improve financial strength Return cash to shareholders Maximize cash flow DEVON’S 2020 VISION (1) Includes the pro forma benefits related to the sale of EnLink Midstream in mid-July.

KEY METRICS Q2 ACTUALS(1) Q2 GUIDANCE U.S. oil (MBbls/d) 136 129 - 134 Canada oil (MBbls/d) 109 110 - 115 NGLs (MBbls/d) 105 97 - 100 Gas (MMcf/d) 1,025 1,001 – 1,053 Total retained (MBoe/d) 520 503 - 525 Production expenses ($MM) $572 $530 - $580 General & administrative expenses ($MM) $153 $150 - $170(2) Financing costs, net ($MM) $62 $60 - $70(3) Upstream capital ($MM) $607 $550 - $650 Q2 2018 - ASSET DETAIL DELAWARE STACK ROCKIES EAGLE FORD BARNETT(1) HEAVY OIL PRODUCTION Oil (MBbl/d) 46 35 16 28 1(1) 109 NGL (MBbl/d) 16 38 2 13 34(1) - Gas (MMcf/d) 100 352 18 74 460(1) 12 Total (MBoe/d) 79 132 21 54 111(1) 111 ASSET MARGIN (per Boe) Realized price $45.05(5) $29.77 $55.46 $47.03 $16.05 $32.38(7) Lease operating expenses ($5.48) ($2.62) ($10.29)(6) ($2.41) ($2.45) ($11.38) Gathering, processing & transportation ($1.95) ($4.73) ($1.23) ($5.22) ($7.39) ($4.35) Production & property taxes ($3.50) ($0.88) ($6.79) ($2.45) ($0.58) ($0.75) Cash margin $34.12 $21.54 $37.15 $36.95 $5.63 $15.90 CAPITAL ACTIVTY (Q2 avg.) Upstream capital ($MM) $178 $252 $35 $58 $19 $40 Operated development rigs 7.5 9 2 1 Operated frac crews 2 3.5 1 1 Operated spuds 22 31 2 8 Operated wells tied-in 14 37 3 2 Average lateral length 9,600’ 6,700’ 9,000’ 5,200’ UPDATED GUIDANCE Q3 2018e FY 2018e U.S. oil (MBbls/d) 132 - 137 130 - 135 Canada oil (MBbls/d) 115 - 120 120 - 125 NGLs (MBbls/d) 100 - 105 100- 104 Gas (MMcf/d) 1,021 – 1,073 1,011 - 1,063 Total retained (MBoe/d) 517 - 541 519 - 541 Lease operating expense & GP&T (per BOE) $9.50 - $9.75 $9.40 - $9.90 Production taxes (% of upstream sales) 5.2% - 5.4% 5.2% - 5.4% General & administrative expenses ($MM) $150 - $170 $650 - $700 Financing costs, net ($MM)(4) $70 - $80(4) $285 - $295(4) Upstream capital ($MM) $550 - $600 $2,200 - $2,400 Capitalized interest & other capital ($MM)(4) $20 - $30(4) $100 - $150(4) Avg. basic share count outstanding (MM) 493 – 496 500 – 505 Key Modeling Stats Production results exclude Johnson County divestiture. General & administrative expense guidance range was adjusted by $30 million to exclude EnLink Midstream. Net financing costs guidance range was adjusted by $45 million to exclude EnLink Midstream. On a go-forward basis, interest expense that had been historically capitalized will now be included in financing costs, net. Includes benefits of regional basis swaps and firm transport in the Delaware totaling $15 million. Includes higher cost enhanced oil recovery properties that are currently being marketed. Includes benefits of regional basis swaps in Canada totaling $12 million.

Q2 2018 Results – U.S. Oil Growth Accelerates U.S. oil production exceeds guidance 2,000 barrels per day above top end of range 12% increase in oil production vs. Q1 2018 Delaware & STACK continue to deliver strong growth Delaware oil production 54% higher year over year STACK oil volumes increase 41% vs. Q2 2017 Multi-zone developments building momentum Prolific wells brought online drive Q2 oil beat 4-well Cotton Draw package IP30: 14 MBOED (pg. 12) Top 10 STACK wells avg. IP30 2,400 BOED per well Capital spending reduced 9% vs. Q1 2018 Driven by reduced seasonal drilling in Canada and timing of Eagle Ford activity IP30: 14,000 BOED (70% oil) (Total rate from 4-well package in Cotton Draw area) Top Delaware Well Results Top 10 STACK Well Results HIGH-RATE WELLS DRIVE Q2 OIL BEAT Avg. IP30: 2,400 BOED (~50% oil) (Top well: Porcupine 1H w/ IP30 of 3,700 BOED) High-returning U.S. oil production exceeds guidance MBOD 136 (Q2 Guide: 129-134) 2,000 ABOVE GUIDANCE U.S. OIL PRODUCTION 122 BARRELS PER DAY

Q2 2018 Results - Margins Continue to Expand Production shifting to higher-value product mix Light-oil production is highest growth product Liquids reach 67% of retained asset volumes Majority of light-oil production has access to premium Gulf Coast pricing Q2 2018 U.S. oil realizations: 98% of WTI(1) Field-level cash flow expands in U.S. resource plays 53% higher compared to Q2 2017 Per-unit LOE improves ~3% vs. last quarter Corporate cost structure continues to significantly improve G&A and interest declines 21% vs. Q1 2018 With declining corporate costs Upstream G&A & interest ($MM) Resulting in margin expansion U.S. field-level operating margin (retained assets) Strong oil realizations across U.S. U.S. oil realizations as % of WTI 53% OPERATING MARGIN YEAR OVER YEAR DECLINE 21% INCREASE (2) Q2 2018 U.S. field-level operating margin for retained assets was $830 million. (1) Includes benefits of basis swaps & firm transport 98% of WTI(1) BASIS SWAPS & FIRM TRANSPORT FIELD-LEVEL REALIZATIONS

2018 Outlook U.S. oil production growth exceeding budget YTD On track to deliver 16% growth vs. 2017 ~200 basis points above original budget expectations Q3 volumes impacted by timing of completions Canada production to increase to ~120 MBOED in Q3 Jackfish 1 turnaround extends into Q3 (pg. 24) Cost structure to improve throughout the year G&A/interest savings to reach ~$475 MM annually(1) Per-unit LOE to improve by ~10% by 1H 2019 No change to 2018 capital spending outlook Capital trending toward around top end of guidance Positioned to generate free cash flow in 2H 2018 U.S. oil growth exceeding expectations YTD U.S. oil production growth rates (retained assets) Basis Points +200 ~$475 MILLION Significantly improving corporate cost structure G&A and interest(1)(2)(3) ($MM) (1) Includes the pro forma benefits related to the sale of EnLink Midstream in mid-July (2) Includes EnLink Midstream G&A and interest for 2017 and 1H of 2018 (3) Includes capitalized interest for each period

Supply Chain Strategy Effectively Mitigating Inflation Devon expects low-to-mid single-digit inflation (vs. 2017) No change to 2018 capital spending outlook Minimal inflation expected in 2H 2018 Development efficiencies offsetting cost pressures YTD Multi-year development plans allow for longer-term commitments at below-market rates Decoupling historically bundled services across supply chain Expanded vendor universe to achieve LOE and capital savings Vast majority of services and supplies secured through 2019 Innovative contracting strategy is delivering strong results 75% of rigs price protected at below market rates Long-term dedicated frac crews in Delaware & STACK at significant discounts to market rates Regional sand strategy delivering 30% savings SERVICES & SUPPLIES SECURED SERVICES & SUPPLIES SECURED

Protecting Price & Flow Assurance Majority of U.S. oil production has access to Gulf Coast markets (premium to WTI pricing) Delaware Basin positioned for attractive oil pricing (pg. 13) Basis swaps & firm transport protect ~90% of oil volumes Firm transport secured for 2019 gas growth expectations Basis swaps protect gas production STACK volumes have access to advantaged markets (pg. 18) Pipeline access to premium Gulf Coast oil pricing Firm transport covers vast majority of gas production ~60% of gas volumes price protected (~$0.50 off HH) Basis hedges protecting cash flow in Canada WCS swaps protect ~50% of oil volumes in 2018 ($15 off WTI) Gulf Coast Access to Premium Gulf Coast Markets Firm transport: 30 MBOD (Marketlink) Gas protected by swaps & firm transport STACK Delaware Basin Firm transport: ~20 MBOD (Longhorn) Firm sales: 100 MBOD (guaranteed flow) Basis swaps protect in-basin sales

EnLink Sale Drives $4 Billion Share-Buyback Program SALES PRICE: $3.125 Billion ACCRETIVE MULTIPLE: 12x Cash Flow ENLC ENLK 115 MM Units 95 MM Units TRANSACTION DETAILS Devon exits EnLink position for $3.125 billion Accretive transaction at 12x cash flow No tax leakage associated with sale Transaction closed in mid-July Board increases share-buyback program to $4 billion Largest authorization of any E&P company to date(1) ~$1 billion repurchased through July (24 million shares) Utilizing ASR programs to execute authorization(2) Initial ASR program to begin in August $4 billion authorization to be completed by 1H 2019 Financial reporting benefits of EnLink sale Reduces consolidated debt by $3.9 billion G&A and interest savings of ~$300 million annually Measured as a % of market capitalization ASR is an acronym for “accelerated share repurchase” $4 Billion Share-Repurchase Program Underway $1 BILLION Repurchased To Date Repurchased to date (~$1 billion or ~5% of shares) Remaining program $3 BILLION REMAINING

Resource quality & depth allows for high-grading of portfolio Announced $4.2 billion of divestitures to date Closed EnLink transaction in July ($3.125 billion) Upstream asset sales: $1.1 billion No incremental cash taxes from transactions Marketing additional ~$1 billion of assets Southern Delaware “Mi Vida” acreage (~9k acres) Barnett Shale: Western Wise County (~100k acres) Minor legacy oil assets across U.S. (~10 MBOD)(1) Expect to exceed $5 billion divestiture target by around year end Continuously evaluating options to high-grade portfolio Asset Divestiture Update Ward Reeves Key Stats Non-Operated Acreage Operated Acreage Production: ~3 MBOED Net acres: ~9,000 Bids due: Q3 2018 “Mi Vida” Acreage SOUTHERN DELAWARE – “MI VIDA” ASSET PACKAGE (1) Minor legacy oil assets include: Rockies and Midland CO2 assets and various Central Basin Platform properties. Note: Not shown on map are ~6k net acres for sale across the S. Delaware Divest Acreage BARNETT SHALE ASSET PACKAGE Key Stats Net acres: ~100k Data rooms: Open Production: ~5 MBOED Bids due: Q3 2018 Denton Wise Jack

2020 Vision: Next Steps Expand per-unit margins Maintain capital discipline Portfolio simplification Shareholder-friendly initiatives NEXT STEPS TO FURTHER OPTIMIZE RETURNS & CAPITAL-EFFICIENCY FOR SHAREHOLDERS Maintain strong pricing through basis swaps & firm transport Maintain discipline: no change to multi-year development plans Expect to exceed $5 billion divestiture target by around year end Retire ~$280 million of maturing debt by early next year Positioned to sustainably grow quarterly dividend rate Currently marketing ~$1 billion of non-core assets across the U.S. Execute on light-oil growth plans (mid-teens CAGR through 2020) Concentrate activity in economic core of Delaware & STACK Improve per-unit cash costs by ~10% by 1H 2019(1) Complete $4 billion share-repurchase program by 1H 2019 Generate free cash flow in 2H 2018(2) Continuously evaluating options to high-grade portfolio (1) Cash costs include LOE, G&A and interest expense. (2) Assumes $65 WTI & $2.75 Henry Hub pricing

Delaware Basin – Q2 2018 Results Production increased 42% year over year Driven by focused activity in economic core of play Oil volumes achieve highest growth (54% vs. Q2 17) Prolific Bone Spring well results achieved in Q2 Top 10 new wells: avg. IP30 ~3,000 BOED (75% oil) Record results in Cotton Draw area (see graphic) Multi-zone development success continues Boomslang online (Last 3 wells avg: IP30 of 2,400 BOED) Lusitano Wolfcamp wells now flowing back Seawolf expected to be online by the end of Q3 Field-level cash flow expands 119% year over year Per-unit costs improve 15% vs. Q1 2018 $66 million of free cash flow generated in Q2 42% GROWTH YEAR OVER YEAR High-returning production growth MBOED Record Well Results (Cotton Draw acreage) Generating Free Cash Flow Asset level cash flow (in $MM) Q2 2018 Revenue $322(1) Production Expenses $78 Cash Margin $244 Capital Expenditures $178 Free Cash Flow $66 (1) Includes benefits of regional basis swaps and firm transport. Cotton Draw Unit 506-509H (4-well package) IP30: ~14 MBOED (70% oil) (Note: IP30 represents cumulative rate of the 4 wells)

Delaware – Infrastructure Supports Profitable Growth Positioned for flow assurance and premium pricing Q2 oil realizations: 97% of WTI(1) Swaps & firm transport protect ~90% of oil volumes Firm oil sales contracts guarantee in basin flow assurance (100 MBOD of contractual capacity in basin) Firm transport secured for 2019 gas growth expectations Historic infrastructure investment drives sustainable cost savings Operating costs improved by >50% vs. peak rates Nearly all oil and produced water on pipe (avoids trucking) 80% of water used in operations is recycled Operate ~50 disposal wells and 8 water reuse facilities Bottom line impact: per-unit margins expanded by >60% year over year Note: 2015-2017 costs are pro forma for revenue recognition accounting rules recently implemented. >50% IMPROVEMENT 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 Improved infrastructure driving lower costs LOE & Transportation Expense ($/BOE) FLOW ASSURANCE PLAN Positioned for flow assurance & premium pricing Includes benefits of basis swaps and firm transport to Gulf Coast Long-term guaranteed contractual capacity with firm transport partners PROTECTING PRICE ~90% PRICE PROTECTED BASIS SWAPS FIELD-LEVEL PRICING LONGHORN (FIRM TRANSPORT)

DEVELOPMENT STRATEGY BUILDING MOMENTUM Delaware Development Projects Advancing on Plan Boomslang project reaches peak rates (Avg. IP30 across 11 wells: ~1,650 BOED) Wolfcamp development program builds momentum in 2H 2018 (see pg. 15) Q2-2018a Q3-2018e Q4-2018e Q1-2019e Completion Production Completion Production Completion Fighting Okra (9 well pattern across 3 intervals in the Wolfcamp) Production Seawolf (12 well pattern across 4 Wolfcamp intervals) Lusitano (6 well pattern across multiple intervals in the Leonard, Bone Spring and Wolfcamp) Completion Medusa (12 well pattern across 3 intervals in the Leonard Shale and Bone Spring) Production Snapping (5 well pattern across 2 intervals in the Leonard) Drilling Completion North Thistle 34 (6 well pattern across 1 interval in the Leonard) Drilling Completion Drilling Drilling Drilling DELAWARE BASIN DEVELOPMENT ACTIVITY Developments online Projects underway Seawolf Completing Fighting Okra Completing Van Doo Dah Potato Basin Tomb Raider Cobra Flagler Lusitano Completing Boomslang (11 wells) Avg. IP30: ~1,650 BOED Medusa Completing North Thistle 34 2018 spud Future projects Snapping 2018 spud

Delaware – Wolfcamp Program Building Momentum Seawolf project to deliver 1st production in Q3 Developing Wolfcamp sweet spot in Lea County 12 wells across multiple Wolfcamp landing zones Average working interest: 50% Peak project rates expected by Q4 2018 Drilling operations completed at Fighting Okra Project developing 9 Wolfcamp wells Parent well achieved IP30 of 3,000 BOED Initial Wolfcamp wells at Lusitano project online Appraising Wolfcamp potential in Cotton Draw area RATTLESNAKE DEVELOPMENT ACTIVITY Rattlesnake Fighting Okra Drilling completed Peak rates: 1H 2019 New Mexico Texas Lea Current Project Lease Acreage Seawolf Completing Peak rates: Q4 2018 LEONARD B C BONE SPRING 2nd 3rd WOLFCAMP XY A UPPER Located in Cotton Draw area (see map pg. 14) 6-well appraisal project testing multiple intervals WOLFCAMP WELLS FLOWING BACK AT LUSITANO PROJECT INITIAL WOLFCAMP WELLS NOW ONLINE (PEAK RATES IN Q3)

Delaware Basin – Outlook 2018 capital & production plan on track Q3 volumes impacted by timing of completions Multi-zone projects to accelerate production growth in Q4 2018 Mitigating inflation: no change to $725 MM capital budget Franchise asset provides multi-decade oil growth opportunity ~300k net surface acres (>1.3 million net effective acres) SIGNIFICANT RESOURCE OPPORTUNITY Net surface acreage ~300,000 (90% in SE New Mexico) Stacked-pay opportunity >15 landing zones Net effective acres >1.3 million Risked inventory >6,500 locations 2018 Capital Program Remains on Track Leonard Bone Spring Wolfcamp $725 MM 2018 E&P CAPITAL Delivering Prolific Growth (MBOED) ~50% EXIT RATE GROWTH 73 - 78

STACK – Q2 2018 Results Production increases 26% year over year Driven by oil volumes (up 41% vs. Q2 2017) Showboat project a key contributor to growth Liquids volumes account for ~80% of revenue STACK play continues to deliver high-rate wells Top 10 new wells in Q2: avg. IP30 2,400 BOED Highlighted by Porcupine 1HX (IP30: 3,700 BOED) Four infill development projects to achieve first production by year-end 2018 Coyote wells attain average IP30 of 4,400 BOED Showboat achieves peak 30-day rates (pg. 19) Horsefly & Bernhardt online in August High-returning production growth (MBOED) 117 132 105 111 26% GROWTH YEAR OVER YEAR KEY Q2 2018 STACK WELL RESULTS WELL NAME 30-DAY IP (BOED) % LIQUID Porcupine 1HX 3,700 70% Ladybug 27-1HX 3,200 50% Mosasaurus 16-12H 2,800 81% C-Farm 23-1H 2,600 76% C-Farm 23-2H 2,400 71% Willow 12-1HX 2,200 62%

STACK – Access to Premium Markets Expands Margins (1) Includes benefits of Marketlink firm transport to Gulf Coast Oil production has access to premium gulf coast pricing Marketlink firm transport (30 MBOD): covers ~75% of oil In-basin sales have cost-effective access to Cushing Strong oil realizations: 99% of WTI(1) in Q2 2018 Firm transport and basis swaps protect gas prices ~60% of gas volumes price protected (~$0.50 off HH) Firm transport agreements to diversified sales points guarantees flow assurance Anchor customer on Midship pipeline (in service in 2019) Local infrastructure in place to support growth plans Oil gathering buildout reducing trucking requirements Per-unit costs to trend lower through end of decade Bottom line impact: Per-unit margins expand 30% year over year Access to Premium Gulf Coast Markets Firm transport on Marketlink to Gulf Coast: 30 MBOD STACK Cushing $16.58 $21.54 Driving higher margins ($ per BOE) Advantaged pricing (% STACK oil volumes) 75% GULF COAST 25% CUSHING

STACK – Infill Development Strategy Next 3 projects designed to inform future infill decisions Testing 8, 10 & 12 Meramec wells per drilling unit All wells now online at Showboat (12 wells per drilling unit) Average 30-day rates: ~1,800 BOED(1) (56% oil) Undeveloped upper Meramec zones delivered best results Early flow rates indicate higher declines than parent well Expect 1st production at Horsefly and Bernhardt in August Peak project flow rates expected by end of Q3 Horsefly D&C costs improved to ~$7.5 million per well Additional cost savings expected at Bernhardt project Leveraging learnings to optimize future developments Initial data suggests Showboat infill spacing not optimized Continue to deliver cost efficiencies (>20% savings vs. legacy wells) Upside initiatives: working to mitigate parent well impact Devon Acreage Current Projects Current Projects to Inform Future Infill Decisions MERAMEC RESOURCE Over-pressured oil acreage 130,000 net surface acres Stacked-pay opportunity 5 Meramec landing zones Risked inventory 6 wells per surface section Infill spacing tests 8 to 12 wells per surface section (1) Normalized for 10,000’ laterals at a 1.75 multiplier. Horsefly 10 wells per drilling unit Completing Showboat 12 wells per drilling unit Avg. 30-Day IP: 1,800 BOED(1) Bernhardt 8 wells per drilling unit Completing OVER- PRESSURED OIL WINDOW BLACK OIL WINDOW

STACK – Centralized Facilities to Drive Returns Higher Centralized facilities designed to support future regional development projects (see map) Central tank battery connected to gathering systems Designed to support multiple development projects Project IRRs to benefit from less capital intensity Improves avg. project economics by up to 20% Future projects benefit from less infrastructure capital Expect significant operating synergies over the development life cycle Oil and water connected to gathering systems (avoids trucking, driving per-unit costs lower) Less labor requirements in the field drives lower LOE Centralized facilities to have less maintenance & downtime SHARED INFRASTRUCTURE PROVIDES STRATEGIC COST ADVANTAGE Showboat 12 wells per unit Flowing back North Star Central Tank Battery Cascade Privott Chisolm Scott Flowlines to tank battery Development projects Existing Devon lease acreage Oil Gathering Water Gathering

MILLION Eagle Ford Q2 Results 8 Lower Eagle Ford Avg. 30-Day IP: 3,100 BOED Q2 Results 15 Lower Eagle Ford Avg. 30-Day IP: 3,300 BOED EAGLE FORD OVERVIEW 25% Oil Prolific well results drive strong Q2 oil growth Net production 31% higher vs. Q1 2018 23 wells average IP30 of ~3,200 BOED (60% oil) High-rates driven by improved completion design Margins benefit from premium LLS oil pricing Q2 oil realizations 103% of WTI (gas 104% of HH) Per-unit LOE declines 20% from prior quarter Expect stable production in 2H 2018 15 – 20 wells tied-in per quarter Austin Chalk delineation work underway (vs. Q1 2018) Premium Oil Pricing (103% of WTI) Growth Production Profile to Stabilize MBOED (in $MM) 2018e Revenue $850 Production Expenses $200 Cash Margin $650 Capital Expenditures $250 Free Cash Flow $400 31% GROWTH QUARTER OVER QUARTER $ 400 Significant Free Cash Flow Generation (1) Assumes $65 WTI & $2.75 Henry Hub for 2H 2018. 2018e FREE CASH FLOW(1)

Rockies Parkman Turner Niobrara 2018 ACTIVITY ~20 WELLS 14 17 Growth plans on track MBOD Teapot Powder River Basin activity Activity by zone Oil production increased 22% vs. Q2 2017 Two Turner wells brought online in Q2 (8k laterals) Avg. IP30: 1,450 BOED (75% oil) Powder River barrels receive WTI pricing Light, sweet crude with ~40 degree API Majority sold to in-basin refiners Niobrara exploration work progressing Significant upside potential (~200k acres) Initial two wells flowing back (results in 2H18) Preparing for higher activity levels in 2019 Preparing to run up to 4 rigs next year Potential for 2x increase in activity from 2018 Shifting Super Mario area into development Select appraisal work to expand inventory Q2 POWDER RIVER BASIN ACTIVITY Super Mario Area RU JFW Fed 13-24s Completing 2 wells Niobrara #1 Flowing Back Turner Niobrara OIL Converse FAIR WAY RU State Fed 4X Avg. 30-Day IP: 1,400 Niobrara #2 Flowing Back RU State Fed 2X Avg. 30-Day IP: 1,500

Barnett Shale Johnson County sale completed in May Gross proceeds: $553 million Q2 production: 21 MBOED (80% gas) Stable production outlook for remainder of year Driven by Dow JV and refrac program Minimum volume commitments to expire in 2018 ~$100 million cash flow benefit in 2019 BARNETT SHALE OVERVIEW New Drills RETAINED ASSET OVERVIEW Net acres: 400k Production: 111 BOED 2018 activity: 20 new drills / 50 refracs Denton Refracs Wise Tarrant 2018 ACTIVITY Stable Production Outlook Retained Assets MBOED

Heavy Oil Q2 PRODUCTION GROSS NET Jackfish 1 (MBOD) 21.7 19.1 Jackfish 2 (MBOD) 39.2 37.5 Jackfish 3 (MBOD) 36.3 34.8 Lloydminster (MBOED) 21.5 19.3 Total Heavy Oil (MBOED) 118.7 110.7 SAGD Sweet Spot (1) Assumes $65 WTI and $25 differential for 2H 2018 and includes benefits of basis swaps. Q2 volumes impacted by turnaround and royalties Jackfish maintenance impact: ~15 MBOD Royalties ~2 percentage points higher than Q1 18 Net production increases to ~120 MBOED in Q3 Turnaround efforts at Jackfish identified additional maintenance requirements Maintenance extends facility ramp-up into Q3 Peak production rates expected in Q4 Significant free cash flow generation in 2018 WCS basis swaps continue to protect pricing ~50% hedged at $15 off WTI 2018 free cash flow: ~$500 million(1) Higher pricing accelerates Jackfish 2 payout Potential to occur as early as first half of 2019 ~3-4 MBOD impact at current strip pricing 1 $ INCREASE IN WCS PER BBL FOR EVERY INCREMENTAL 40 MM $ ANNUALIZED CASH FLOW

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 second-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.