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): April 30, 2019

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 April 30, 2019, Devon Energy Corporation (the “Company”) announced its financial and operational results for the quarter ended March 31, 2019. In connection with this announcement, the Company provided an earnings release, its operations report for the first quarter of 2019 and certain supplemental financial information. Copies of these documents are furnished as Exhibits 99.1, 99.2 and 99.3, 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 April 30, 2019.		
			
99.2	  	First quarter 2019 operations report.		
			
99.3	  	Supplemental financial information.		

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: April 30, 2019

Exhibit 99.1

NEWS RELEASE
Devon Energy Reports First-Quarter 2019 Results
Highlights
 
 	•	 	Light-oil production advances 24 percent year over year	
 
 	•	 	Raising full-year 2019 light-oil production outlook	
 
 	•	 	Upstream capital 9 percent below guidance	
 
 	•	 	Operating and G&A costs savings ahead of plan	
 
 	•	 	Stock repurchase program decreases share count by more than 20 percent	
OKLAHOMA CITY – April  30, 2019 – Devon Energy Corp. (NYSE: DVN) today reported operational and financial results for the first quarter of 2019. Supplemental financial tables for first-quarter results and updated guidance for the second quarter and full-year 2019 are available on the company’s website at www.devonenergy.com .
“Devon’s tremendous first-quarter operating results showcase the world-class capabilities of our U.S. oil business,” said Dave Hager, president and CEO. “Our quarterly performance was highlighted by improving well productivity and capital efficiency that drove our light-oil production above guidance with a total capital investment below forecast. Furthermore, we made substantial progress improving our corporate cost structure with G&A expenses declining 23 percent year over year.
“With these strong first-quarter results, we are raising the full-year growth outlook for our U.S. oil business,” Hager said. “We now expect 2019 light-oil production growth to reach 17 percent, a 200 basis point improvement from our previous guidance. Importantly, we are delivering this incremental production growth without any increase in capital spending and our margins will benefit from operating and G&A cost-saving initiatives that are tracking ahead of plan.”
Delaware Basin Drives U.S. Oil Production Outperformance
First-quarter production was highlighted by results from Devon’s retained U.S. oil business. Light-oil production from these assets averaged 138,000 barrels per day, a 24 percent increase compared to the first quarter of 2018. This result exceeded the high-end of guidance by 8,000 barrels per day.
The strongest asset-level performance during the first quarter was from the company’s Delaware Basin properties that delivered prolific growth in high-margin production. Net production increased 76 percent year over year, driving total volumes in the Delaware to 107,000 oil-equivalent barrels (Boe) per day. First-quarter operating results in the Delaware were highlighted by five prolific Cat Scratch Fever wells targeting a second Bone Spring interval in southwest Lea County, New Mexico. These wells averaged initial 24-hour production rates in excess of 10,000 Boe per day per well, of which approximately 80 percent was oil.
Overall, net production for retained U.S. assets averaged 308,000 Boe per day during the first quarter, exceeding midpoint guidance by 27,000 Boe per day. Of this total, oil and liquids production accounted for nearly 70 percent of total volumes.

Raising 2019 Light-Oil Production Outlook
Based on the strong year-to-date results, Devon is raising the oil production outlook for its retained U.S. business in 2019. The midpoint of the company’s full-year guidance now represents an estimated oil growth rate of 17 percent compared to 2018, up from the previous guidance of 15 percent.
The improved outlook is driven by strong well productivity associated with development projects in the Delaware Basin. For additional details on Devon’s E&P operating results and key upcoming projects, please refer to the company’s first-quarter 2019 operations report at www.devonenergy.com .
Capital Spending Below First-Quarter Guidance; No Change to 2019 Outlook
In addition to the strong production performance, the company maintained discipline with its capital program. Devon’s upstream capital spending for its retained U.S. oil business was $457 million in the first quarter, which was $43 million, or 9 percent below the company’s midpoint guidance. This level of capital investment represents 24 percent of Devon’s 2019 upstream budget.
For the full-year 2019, Devon has made no modifications to its capital outlook and expects upstream capital spending for retained assets to range between $1.8 billion and $2.0 billion.
Oil and Gas Revenue Advances 24 Percent
Devon’s upstream revenue, excluding commodity derivatives, totaled $1.4 billion in the first quarter of 2019, a 24 percent increase compared to the fourth quarter of 2018. The strong revenue growth was primarily attributable to higher oil price realizations.
First-quarter revenue associated with the company’s retained U.S. oil business benefited from its firm transportation agreements and hedge position. Cash settlements associated with these activities increased revenue in the U.S. by nearly $48 million.
Field-Level Operating Costs and G&A Reductions Ahead of Plan
Devon continued to make progress improving its operating and corporate cost structure in the first quarter. The company’s largest field-level cost, lease operating expense, improved to $4.63 per Boe in the quarter. On a per-unit basis, lease operating expense declined 10 percent compared to the fourth quarter of 2018 and was below the low end of guidance.
Another key contributor to the company’s improving cost performance was lower general and administrative (G&A) expenses. First-quarter G&A costs totaled $153 million, a 23 percent improvement from the first quarter of 2018. This result was $12 million below the company’s midpoint guidance due to lower personnel related expenses. Due to the cost performance achieved year to date, the company is lowering its full-year 2019 outlook for G&A by $30 million.
Earnings Exceed Wall Street Consensus
In the first quarter, Devon reported a net loss of $317 million, or $0.74 per diluted share. The loss was attributable to a $670 million non-cash charge related to fair value changes in the company’s derivative position. Adjusting for items securities analysts typically exclude from published estimates, Devon’s core earnings totaled $0.36 per diluted share, exceeding analyst consensus estimates by a wide margin.

Devon’s operating cash flow totaled $377 million in the first quarter. The timing of working capital changes largely related to the Canadian business, driven by weak heavy-oil prices in the fourth quarter of 2018, reduced operating cash flow by $302 million in the quarter. First-quarter EBITDAX reached $779 million, a 26 percent improvement compared to the fourth quarter of 2018.
Industry-Leading $5 Billion Share Repurchase Program Advances
The company’s $5 billion share-repurchase authorization represents the largest in the upstream industry when measured as a percentage of market capitalization. To date, Devon has repurchased 114 million shares, or greater than 20 percent of outstanding shares, at a total cost of $4 billion. The company expects its repurchase program to reach $5 billion by year end.
The company is also rewarding shareholders with its quarterly common stock dividend. Earlier this year the company’s board of directions increased the quarterly dividend by 13 percent to $0.09 per share. The new quarterly dividend is effective in the second quarter of 2019.
Devon’s financial position remains exceptionally strong, with investment-grade credit ratings and excellent liquidity. The company exited the first quarter with $1.3 billion of cash on hand and an undrawn credit facility of $3 billion. At the end of March, Devon had an outstanding debt balance of $5.8 billion with no significant debt maturities until mid-2021.
Divestiture Program Accelerates Value Creation
Devon announced earlier this year its plan to transform to a high-return U.S. oil growth company by exiting Canada and the Barnett Shale by the end of 2019. The company is evaluating multiple methods of separating the assets, including a potential sale or spin-off. Data rooms for Canada and the Barnett Shale open in the second quarter of 2019.
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 first-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, May 1, 2019, 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 results as reported under GAAP. Reconciliations of these non-GAAP measures and other disclosures are provided within the supplemental financial tables that are available on the company’s website at www.devonenergy.com and see our related Form 10-Q.
Forward-Looking Statements
This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission (the “SEC”). Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that

Devon 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 our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to: the volatility of oil, gas and NGL prices; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; the uncertainties, costs and risks involved in oil and gas operations; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to regulatory, social and market efforts to address climate change; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate some of our oil and gas properties; midstream capacity constraints and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for assets, materials, people and capital; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our Form 10-K and 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 press release are made as of the date of this press 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. with an emphasis on achieving strong corporate-level returns and capital-efficient cash-flow growth. For more information, please visit www.devonenergy.com and see our related Form 10-Q.

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

Q1 2019 Operations Report April 30, 2019 Exhibit 99.2

Defining the “New Devon” World-class U.S. oil company Unrivaled acreage position in top basins Multi-decade inventory to drive sustainable growth Resource depth allows for high-grading of portfolio (exiting Canada & Barnett positions) Focused on operational excellence Aggressively reducing costs Shifting to higher-margin production Positioned for mid-teens oil growth and free cash flow generation above $46 WTI Delivering value to shareholders Committed to return of capital Capital-efficient per-share growth 21 MBOED (76% OIL) STACK 123 MBOED (55% LIQUIDS) POWDER RIVER EAGLE FORD 50 MBOED (50% OIL) 107 MBOED (56% OIL) DELAWARE Production: 308 MBOED (Q1 2019) Revenue: 84% oil & liquids Oil growth rate: 17% in 2019 Multi-decade growth platform New Devon Overview

Efficiently Advancing the Business RAISING U.S. OIL GUIDANCE (Q1 2019 +8 MBOD vs. top-end of guidance range) WORLD-CLASS DELAWARE RESULTS (Cat Scratch Fever wells drive Q1 production 76% higher) PRIORITIZING CASH RETURNS FOR SHAREHOLDERS (Returned >$4 billion to shareholders over past year) COST SAVINGS TRENDING AHEAD OF PLAN (LOE, G&A & capital below guidance) PORTFOLIO HIGH-GRADING PROGRESSING (See page 11 for details)

“New Devon” Delivers Strong Q1 Outperformance “New Devon” oil production exceeds guidance 8,000 barrels per day above top end of range 24% increase in oil production vs. Q1 2018 Delaware well productivity drives Q1 oil beat Results headlined by cat scratch fever wells (pg. 14) High-rate Wolfcamp wells at Rattlesnake (pg. 14) Per-unit operating costs continue to improve Operating costs decline 12% vs. Q1 ‘18 G&A cost reductions ahead of plan (pg. 8) Capital discipline accelerates free cash flow growth Capital spend 9% below midpoint guidance (pg. 5) Q1 spending represents 24% of full-year budget Generating free cash flow above $46 WTI (pg. 10) Light-oil production exceeds guidance New Devon (MBOD) 138 (Q1 Guide: 125-130) 111 G&A LOE & GP&T Interest Improving cost structure expands margins Per-unit cost ($/BOE) YEAR OVER YEAR DECLINE 12% $13.63 $15.50 8,000 ABOVE GUIDANCE U.S. OIL PRODUCTION BARRELS PER DAY

Committed to Capital Discipline Focused on top-tier oil development opportunities New Devon 2019e E&P capital $1.8-$2.0 E&P CAPITAL 50% DELAWARE 20% STACK 15% POWDER RIVER 15% EAGLE FORD BILLION 15% MORE WELLS FOR ~10% LESS CAPITAL (VS. 2018) 2019 outlook reflects $200 million of D&C efficiencies Structural improvements driving capital efficiency: Wolfcamp cycle times and costs improving STACK infill spacing design optimized Dedicated frac crew to lower PRB costs Facility cost savings up to 40% across U.S. by year-end Capital activity unchanged with higher pricing Capital efficiency showcased with Q1 results New Devon upstream capital (Q1 2019 result: $457 million) 9% Q1 2019 CAPITAL SPENDING REPRESENTS 24% OF 2019 CAPITAL BUDGET BELOW GUIDANCE

Raising Our 2019 Growth Outlook HIGH-RATE WELLS DRIVE Q2 OIL BEAT ~17% OIL GROWTH 2018 vs 2019 midpoint Raising “New Devon” 2019 oil production outlook New Devon U.S oil production (MBOD) Repurchase program accelerates per-share growth Outstanding shares (MM) >25% SHARE COUNT 527 ~390(1) 521 491 459 434 (1) Assumes an incremental $1 billion of shares are repurchased at current share price. 417 +200 BASIS POINTS (VS ORIGINAL GUIDANCE) Raising “New Devon” oil production guidance Increasing midpoint to 17% growth vs. 2018 Guidance increased by ~200 basis points no change to capital spending outlook Oil growth to accelerate in second half of 2019 Driven by timing of wells in Delaware & Powder River Q2 oil production outlook: 134-141 MBOD Cost savings initiatives ahead of plan (pg. 7) Lowering full-year outlook for G&A expense (pg. 8) Per-unit LOE to decline by 5% to 10% by year-end Structural improvements with capital efficiency prioritizing cash returns to shareholders Repurchased $4 billion of shares to date Increased quarterly dividend by 13% in Q1 REDUCTION >25% (2019 exit rate vs. FY 2018)

Cost savings initiatives trending ahead of plan Estimated cost savings by area as of 4/30/19 ($MM) Optimizing New Devon’s Cost Structure Aggressively pursuing improved cost structure New Devon expected cost savings by area vs. 2018 results ($MM) $780 ANNUAL COST SAVINGS BY 2021 MILLION G&A $300 MM Interest $130 MM Per-Unit Recurring LOE $50 MM D&C Efficiencies $300 MM (2) (1) 65% BY YEAR-END 2019 50% BY YEAR-END 2019 (1) ~$100 MM associated with the exit of Canada and Barnett. (2) Assumes $3 billion of debt repayments with the exit of Canada and Barnett. (3) Run-rate saving achieved as of 4/30/19 (Run-rate as of 4/30/19) CURRENTLY ACHIEVED (Based on decisions made) UPCOMING 2019 SAVINGS (Expected during 2020 & 2021) FUTURE COST INITIATIVES Cost savings designed to be front-end weighted >70% of savings achieved by year-end 2019 G&A run-rate savings YTD: ~$110 million(3) (pg. 8) D&C efficiencies reflected in 2019 outlook (pg. 5) (1) (2)

G&A Cost Savings: Path to Completion G&A cost savings: 3-year performance targets Annualized G&A expense ($MM) $650 ~$350 (YE 2021) $300 MM TARGETED SAVINGS Cost savings initiatives outperforming plan YTD G&A expense ($MM) Targeting >$200 million of G&A savings by year-end Q1 results 8% below midpoint of guidance G&A run-rate savings achieved YTD ~$110 million Exit of Canada and Barnett to eliminate ~$100 million (Canada represents ~80% of total) Cost savings momentum driving an improved outlook Q2 2019 G&A costs to decline >10% vs. Q1 reducing guidance by $30 million in 2019(1) Driven by lower personnel-related expenses Additional cost synergies expected beyond 2019 Primarily due to non-workforce related costs PV10 of G&A savings plan: ~$2 billion (over next 10 years) $153 (Q1 Guide: $155-$175) $199 G&A RUN-RATE 110 $ ACHIEVED YTD SAVINGS MM (1) 2019 guidance assumes Canada and Barnett G&A burden for the full year. Guidance will be revised once assets exit portfolio.

New Devon: 3-Year Performance Targets CUMULATIVE FREE CASH FLOW OIL GROWTH COST SAVINGS DEBT TARGET CAPITAL PROGRAM RETURN ON CAPITAL TARGET: >15%(1) $2.3 At $60 WTI 12% – 17% CAGR (FY2018 – 2021) Light-Oil Production $780 MM By 2021 See page 7 for update 1.0x to 1.5x Debt to EBITDA ratio Funded See page 10 for update At $46 WTI Opportunistically repurchase shares Sustainably pay and grow dividend Improve financial strength and flexibility Free Cash Flow Priorities (See page 10 for FCF sensitivities) Internal rate of return on capital investment after burdening for G&A and corporate costs. Metric further detailed in proxy and driver of management compensation. Assumes cost savings detailed on page 7 are fully realized at the beginning of 2019. BILLION (2)

New Devon: Free Cash Flow Yield to Investors ($55 WTI) ($60 WTI) Cumulative Free Cash Flow $3.0B Cumulative Free Cash Flow ($B) Cumulative Free Cash Flow $2.3B Free Cash Yield (Annual Avg.) Cumulative Free Cash Flow $1.6B Note: Free cash flow yield assumes market capitalization based on current share price multiplied by expected shares outstanding at year-end 2019 (~390 mm shares). Cumulative free cash flow represents the aggregate operating cash flow less total capital requirements before dividend. Assumes $3 HH price. Cumulative Free Cash Flow Free Cash Flow Yield (Annual Avg.) (1) Assumes cost savings are fully realized at the beginning of 2019. OIL CAGR: 12%-17% BREAKEVEN: $46 WTI (CALCULATION INCLUSIVE OF ALL CAPEX) 3-YEAR CAPITAL PLAN (1) (1) (1)

Divestiture Program Accelerates Value Creation Resource quality & depth allows for high-grading of portfolio Pursuing strategic alternatives for Barnett Shale and Canadian assets Outright sale or spin-off Data rooms: open Q2 2019 Expect to complete by year end Proceeds will be utilized for debt repayment Targeted debt-to-EBITDA ratio: 1.0x-1.5x Expect up to $3 billion of debt repayments Rockies CO2 asset sale expected in 2019 New Devon Assets Divestiture Assets POWDER RIVER STACK DELAWARE BASIN EAGLE FORD CANADA Production: 113 MBOED Data room: Open in Q2 Rockies CO2 Barnett Shale Production: 103 MBOED Data room: Open in Q2 Production: 3 MBOED Sales process: Ongoing

Q1 2019 - ASSET DETAIL NEW DEVON DELAWARE STACK POWDER RIVER EAGLE FORD(3) OTHER NEW DEVON PRODUCTION Oil (MBbl/d) 138 60 32 15 25 6 NGL (MBbl/d) 73 23 35 2 12 1 Gas (MMcf/d) 581 146 333 18 83 1 Total (MBoe/d) 308 107 123 21 50 7 ASSET MARGIN (per Boe) Realized price $32.60 $35.89(2) $26.65 $41.69 $39.41 $42.03 Lease operating expenses ($3.72) ($4.58) ($1.87) ($8.00) ($2.81) ($15.89) Gathering, processing & transportation ($3.92) ($2.23) ($5.18) ($1.70) ($5.84) ($0.01) Production & property taxes ($2.25) ($2.72) ($1.33) ($4.97) ($2.23) ($3.30) Cash margin $22.71 $26.36 $18.27 $27.02 $28.53 $22.83 CAPITAL ACTIVITY Upstream capital ($MM) $457 $240 $112 $48 $48 $9 Operated development rigs (avg.) 21 11 5 3 3 Operated frac crews (avg.) 6 2 2 0 2 Operated spuds 78 39 18 9 12 Operated wells tied-in 75 25 29 3 18(4) Average lateral length 8,000’ 8,500’ 9,000’ 10,000’ 6,000’ OTHER KEY STATS General & administrative expenses ($MM) $153(1) Financing costs, net ($MM) $73 Share count (MM) (avg.) 434 Includes Canada and Barnett until assets are divested. Includes benefits of regional basis swaps and firm transport in the Delaware totaling $19 million. Includes partner activity. Includes all wells brought online during the quarter, of which 9 reached 30-day peak rates. Q1 2019 - Key Modeling Stats For additional modeling stats and updated guidance see our Q1 earnings release tables

Delaware Basin – Capital-Efficient Growth Engine Net production increased 76% year over year Q1 oil realizations: 97% of WTI (details on pg. 15) Minimal exposure to West Texas Light crude Swaps protect >90% of gas volumes ($1.46 off HH) Cat Scratch Fever wells deliver top Q1 highlight Five 2nd Bone Spring wells in Todd area (10k lateral) Initial 24-hour IP: 10 MBOED per well (~80% oil) Infrastructure drives sustainable savings (pg. 15) LOE rates decline 60% from peak Incremental improvements expected in 2019 No change to activity levels with higher pricing Diversified activity across 5 core areas 11 rigs supported by 2 dedicated frac crews 125 spuds planned in 2019 (>100 new wells online) World-class wells in Todd and Rattlesnake areas (pg. 14) Well productivity & flow assurance (pg. 15) Inventory provides multi-decade growth platform (pg. 16) Key Delaware Basin Highlights Outstanding well productivity drives Q1 outperformance Production (MBOED) YEAR OVER YEAR GROWTH Gas NGL Oil 107 76% 61

Delaware Basin – Prolific Wells Drive Q1 Results Todd Area Eddy Boundary Raider (2 wells) Avg. IP24 hr: 12 MBOED/well RATTLESNAKE DEVELOPMENT AREA Rattlesnake Area Lea ACCELERATING TODD DEVELOPMENT PROGRAM Flagler (Phase 1) Completing Peak rates: 2H 2019 Lea Ko Lanta (2 Leonard wells) Avg. IP30: 2,600 BOED/well Tomb Raider (3 Wolfcamp wells) Avg. IP30: 3,500 BOED/well Other Key Activity Bone Spring Wells Fighting Okra 9 Wolfcamp wells Avg. IP30: ~3,200 BOED/well Arena Roja 2H 2019 Spud Mean Green 2H 2019 Spud Jayhawk Drilling Seawolf 12 Wolfcamp wells Avg. IP30: 3,300 BOED/well Developments Online Upcoming Developments Cat Scratch Fever (Phase 1) 10 wells online IP24 hr: 10 MBOED/well(1) (Top 5 wells) (1) Peak 24-hour production rates achieved to understand well deliverability. Current production rates constrained due to facility capacity. Wolfcamp program ramping up (~40% of 2019 activity) Six key projects underway in Rattlesnake area Fighting Okra wells online (IP30: ~3,200 BOED/well) next catalyst: Flagler project (Phase one: 7 wells) New facility design to lower costs (up to $250k/well) Developing 2nd Bone Spring sweet spot at Todd Cat Scratch Fever wells delivering prolific results Phase one consists of 10 wells (flowing back) Top 5 wells avg. IP24 hr: 10 MBOED(1) (facility constrained) next catalyst: Phase two online by year-end (10 wells) Cat Scratch Fever (Phase 2) 10 wells (online by YE 2019)

Delaware Basin – Positioned for High-Return Growth Well productivity reaching record highs Average cumulative oil production per well (MBO) Months Online 2018 average 2015-2017 average BONE SPRING & WOLFCAMP (SEE PG. 14 FOR Q1 2019 RESULTS) FOCUS IN 2019 2018 Boundary Raider wells (>90% improvement vs. 3-year avg.) (targeting Bone Spring) Positioned for flow assurance & premium pricing Firm oil transport: ~20 MBOD Firm oil sales: 100 MBOD in basin Swaps protect >90% of gas volumes Gas sold under LT contracts to West Coast FLOW ASSURANCE & PRICING STRONG OIL PRICE REALIZATIONS 97% OF WTI BASIS SWAPS (~25 MBOD) FIELD-LEVEL PRICING FIRM OIL SALES GULF COAST FIRM TRANSPORT (~20 MBOD) Q1 RESULTS Operating scale drives per-unit costs lower Delaware Basin LOE & GP&T expense ($/BOE) 60% IMPROVEMENT

Delaware Basin – A Multi-Decade Growth Platform Bone Spring Wolfcamp Leonard High-return inventory at $50 WTI Gross operated inventory locations generating IRR >20%(1) 2,000 locations (Avg. lateral length: 7,500’) 16-YEAR INVENTORY (AT CURRENT ACTIVITY PACE) Weighted Avg. IRR: >50% (1) IRR on E&P capital investment (includes drilling, completion and well-site facilities and flow back). Delaware Leonard Bone Spring Wolfcamp Thistle Cotton Draw Todd Potato Basin Rattlesnake ~5,000 feet of pay Massive stacked-pay resource opportunity Potential landing zones by core operating region 125 wells drilled (Avg. lateral length: 8,000’)

STACK – Optimizing Infill-Development Results Lighter-spaced projects delivering optimized results Average cumulative production per well (MBOE) Type Curve (10K LATERAL) 30-DAY IP (BOED) 1,300 – 1,600 EUR (MBOE) 1,200 – 1,400 D&C COST ~$7.5 MM Type Well Pony Express(1) Scott(1) Q1 production averaged 123 MBOED (55% liquids) Volumes YTD trending ahead of budget Weather impact: ~3 MBOED in the first-quarter Lighter-spaced projects delivering improved results Well productivity tracking at or above type curve Expect 15% lower D&C costs per well vs. 2018 next steps: Transition all activity to 4-6 wells per unit Drilling focused in best part of play (volatile oil window) Activity primarily targeting Upper Meramec interval Prioritizing free cash flow over volume growth Expect stable production profile in 2019 Significant inventory remaining (850 high-return locations) Kingfisher Canadian Blaine Key Q1 2019 Results STACK DEVELOPMENT ACTIVITY Upcoming Developments (1) Normalized for 10,000’ laterals Scott (5 wells/DSU) Avg. IP30: 2,500 BOED(1) Northwoods (5 wells/DSU) Avg. IP30: 1,500 BOED Pony Express (4 wells/DSU) Avg. IP30: 1,600 BOED(1) 2019 Focus Area 4-6 wells TARGETED SPACING PER DSU Kraken (7 wells/DSU) Currently flowing back

Powder River Basin – Oil Growth Set to Accelerate Net production increased 15% vs. Q4 2018 Activity increasing: 4 rigs & dedicated frac crew Expect >50% oil exit rate growth (Q4’ 19 vs. Q4’ 18) Oil volume growth to accelerate in 2H 2019 High-return growth to benefit from improving margins Light-oil volumes >75% of production mix Operating scale to drive LOE ~20% lower by year-end Structural improvements to drive capital efficiency 2019 program focused on Turner development drilling Expect savings of >$1 million per well (see chart) Niobrara possesses scalable growth potential 200,000 net acres of stacked pay in oil fairway Initial 3 operated wells successful (avg. IP30 >1,000 BOD) next catalyst: Initial spacing test spud in Q1 Operating scale driving D&C costs lower Turner formation drilling and completion costs ($MM) $6.5 $8.0 >$1 MILLION EXPECTED SAVINGS Super Mario Area SDU Tillard 1XPH (Parkman) Avg. 30-Day IP: 1,800 BOED (~95% oil) (12,500’ lateral) Madsen FED 36-1 (Turner) Avg. 30-Day IP: 1,300 BOED (~80% oil) (9,600’ lateral) Initial Niobrara spacing test Q1 2019 Spud POWDER RIVER BASIN ACTIVITY Upcoming Activity Converse (Turner focused)

Eagle Ford – Expanding Resource Opportunity (in $MM) Last 12 months Revenue $930 Production Expenses $215 Cash Margin $715 Capital Expenditures $172 Free Cash Flow $543 Substantial free cash flow Q1 production averaged 50 MBOED (~50% oil) 9 wells achieved IP30s in Q1 (avg. 3,100 BOED) Activity increased to 3 drilling rigs in January 70 spuds planned in 2019 (~50 new wells online) Program supported by dedicated frac crew Production to average ~50 MBOED in 2019 Horizontal oil refrac program creating value Initial results achieve 12x increase in well productivity Current-year program to appraise 20 locations 200 refrac candidates identified (>700 potential) 10-year drilling inventory at 2019 activity levels 700 “high-return” undrilled locations identified(1) next catalyst: Appraisal activity underway (see map) 700 Eagle Ford locations 10-year drilling inventory ~ Upside potential Austin Chalk locations Q1 2019 Results 9 Lower Eagle Ford Wells Avg. 30-Day IP: 3,100 BOED/Well EAGLE FORD ACTIVITY Eagle Ford Redevelopment Well Flowing Back Initial Austin Chalk Well Flowing Back 2019 Refrac Activity FREE CASH FLOW ($MM) 543 $ LAST 12 MONTHS Initial Eagle Ford Refracs Avg. 30-Day Uplift: 1,300 BOED/Well High-return inventory represents locations generating >20% IRR. Returns based on all-in E&P capital investment, which includes drilling, completion and well-site facilities and flow back. High-Return Locations (With Upside)

Investor Contacts & Notices Investor Relations Contacts Scott CoodyChris Carr VP, Investor RelationsManager, 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, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Devon 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 our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to: the volatility of oil, gas and NGL prices; uncertainties inherent in estimating oil, gas and NGL Investor Notices 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 regulatory, social and market efforts to address climate change; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate some of our oil and gas properties; midstream capacity constraints and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for assets, materials, people and capital; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our Form 10-K and 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 first-quarter 2019 earnings release at www.devonenergy.com and Form 10-Q filed with the SEC. 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 high-return inventory, 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.

Exhibit 99.3
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
PRODUCTION NET OF ROYALTIES

 	  	Quarter Ended	 	
 	  	March 31,	 	
 	  	2019	 	  	2018	 	
Oil and bitumen (MBbls/d)	  				  				
New Devon	  	 	138	 	  	 	111	 	
Canada divest assets	  	 	112	 	  	 	129	 	
U.S. divest assets	  	 	4	 	  	 	11	 	
	  	 	 	 	  	 	 	 	
Total	  	 	254	 	  	 	251	 	
	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				
New Devon	  	 	73	 	  	 	56	 	
U.S. divest assets	  	 	31	 	  	 	41	 	
	  	 	 	 	  	 	 	 	
Total	  	 	104	 	  	 	97	 	
	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				
New Devon	  	 	581	 	  	 	493	 	
Canada divest assets	  	 	4	 	  	 	12	 	
U.S. divest assets	  	 	439	 	  	 	672	 	
	  	 	 	 	  	 	 	 	
Total	  	 	1,024	 	  	 	1,177	 	
	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				
New Devon	  	 	308	 	  	 	249	 	
Canada divest assets	  	 	113	 	  	 	131	 	
U.S. divest assets	  	 	108	 	  	 	164	 	
	  	 	 	 	  	 	 	 	
Total	  	 	529	 	  	 	544	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
PRODUCTION TREND

 	  	2018	 	  	2019	 	
 	  	Quarter 1	 	  	Quarter 2	 	  	Quarter 3	 	  	Quarter 4	 	  	Quarter 1	 	
Oil and bitumen (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	34	 	  	 	45	 	  	 	44	 	  	 	45	 	  	 	60	 	
STACK	  	 	34	 	  	 	34	 	  	 	29	 	  	 	31	 	  	 	32	 	
Powder River Basin	  	 	15	 	  	 	13	 	  	 	15	 	  	 	13	 	  	 	15	 	
Eagle Ford	  	 	23	 	  	 	28	 	  	 	31	 	  	 	30	 	  	 	25	 	
Other	  	 	5	 	  	 	6	 	  	 	5	 	  	 	6	 	  	 	6	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	111	 	  	 	126	 	  	 	124	 	  	 	125	 	  	 	138	 	
Canada divest assets	  	 	129	 	  	 	109	 	  	 	102	 	  	 	120	 	  	 	112	 	
U.S. divest assets	  	 	11	 	  	 	10	 	  	 	9	 	  	 	8	 	  	 	4	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	251	 	  	 	245	 	  	 	235	 	  	 	253	 	  	 	254	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	11	 	  	 	15	 	  	 	19	 	  	 	18	 	  	 	23	 	
STACK	  	 	35	 	  	 	37	 	  	 	40	 	  	 	37	 	  	 	35	 	
Powder River Basin	  	 	1	 	  	 	1	 	  	 	2	 	  	 	2	 	  	 	2	 	
Eagle Ford	  	 	8	 	  	 	13	 	  	 	15	 	  	 	15	 	  	 	12	 	
Other	  	 	1	 	  	 	2	 	  	 	1	 	  	 	1	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	56	 	  	 	68	 	  	 	77	 	  	 	73	 	  	 	73	 	
U.S. divest assets	  	 	41	 	  	 	41	 	  	 	36	 	  	 	32	 	  	 	31	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	97	 	  	 	109	 	  	 	113	 	  	 	105	 	  	 	104	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				  				
Delaware Basin	  	 	93	 	  	 	94	 	  	 	103	 	  	 	127	 	  	 	146	 	
STACK	  	 	324	 	  	 	329	 	  	 	337	 	  	 	343	 	  	 	333	 	
Powder River Basin	  	 	12	 	  	 	13	 	  	 	18	 	  	 	20	 	  	 	18	 	
Eagle Ford	  	 	63	 	  	 	74	 	  	 	84	 	  	 	95	 	  	 	83	 	
Other	  	 	1	 	  	 	3	 	  	 	2	 	  	 	2	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	493	 	  	 	513	 	  	 	544	 	  	 	587	 	  	 	581	 	
Canada divest assets	  	 	12	 	  	 	12	 	  	 	11	 	  	 	6	 	  	 	4	 	
U.S. divest assets	  	 	672	 	  	 	603	 	  	 	491	 	  	 	457	 	  	 	439	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	1,177	 	  	 	1,128	 	  	 	1,046	 	  	 	1,050	 	  	 	1,024	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				  				
Delaware Basin	  	 	61	 	  	 	76	 	  	 	79	 	  	 	84	 	  	 	107	 	
STACK	  	 	123	 	  	 	125	 	  	 	126	 	  	 	126	 	  	 	123	 	
Powder River Basin	  	 	18	 	  	 	16	 	  	 	19	 	  	 	18	 	  	 	21	 	
Eagle Ford	  	 	41	 	  	 	54	 	  	 	60	 	  	 	61	 	  	 	50	 	
Other	  	 	6	 	  	 	8	 	  	 	7	 	  	 	6	 	  	 	7	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	249	 	  	 	279	 	  	 	291	 	  	 	295	 	  	 	308	 	
Canada divest assets	  	 	131	 	  	 	111	 	  	 	104	 	  	 	121	 	  	 	113	 	
U.S. divest assets	  	 	164	 	  	 	151	 	  	 	127	 	  	 	116	 	  	 	108	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	544	 	  	 	541	 	  	 	522	 	  	 	532	 	  	 	529	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
BENCHMARK PRICES

(average prices)	  	Quarter 1	 	
 	  	2019	 	  	2018	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	54.88	 	  	$	62.93	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	3.15	 	  	$	3.01	 	
REALIZED PRICES

 	  	Quarter Ended March 31, 2019	 	
 	  	Oil /Bitumen	 	  	NGL	 	  	Gas	 	  	Total	 	
 	  	(Per Bbl)	 	  	(Per Bbl)	 	  	(Per Mcf)	 	  	(Per Boe)	 	
United States	  	$	51.83	 	  	$	18.64	 	  	$	2.53	 	  	$	28.58	 	
Canada	  	$	34.60	 	  	 	N/M	 	  	 	N/M	 	  	$	34.42	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price without hedges	  	$	44.20	 	  	$	18.64	 	  	$	2.53	 	  	$	29.83	 	
Cash settlements	  	$	(1.18	) 	  	$	0.48	 	  	$	(0.17	) 	  	$	(0.82	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	43.02	 	  	$	19.12	 	  	$	2.36	 	  	$	29.01	 	

 	  	Quarter Ended March 31, 2018	 	
 	  	Oil /Bitumen	 	  	NGL	 	  	Gas	 	  	Total	 	
 	  	(Per Bbl)	 	  	(Per Bbl)	 	  	(Per Mcf)	 	  	(Per Boe)	 	
United States	  	$	61.79	 	  	$	22.56	 	  	$	2.41	 	  	$	30.39	 	
Canada	  	$	19.74	 	  	 	N/M	 	  	 	N/M	 	  	$	19.45	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price without hedges	  	$	40.15	 	  	$	22.56	 	  	$	2.41	 	  	$	27.75	 	
Cash settlements	  	$	(0.10	) 	  	$	(0.53	) 	  	$	0.17	 	  	$	0.23	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	40.05	 	  	$	22.03	 	  	$	2.58	 	  	$	27.98	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED STATEMENTS OF EARNINGS
									
(in millions, except per share amounts)	  	Quarter Ended
March 31,	 	
 	  	2019	 	 	2018	 	
Upstream revenues	  	$	710	 	 	$	1,319	 	
Marketing revenues	  	 	791	 	 	 	879	 	
	  	 	 	 	 	 	 	 	
Total revenues	  	 	1,501	 	 	 	2,198	 	
	  	 	 	 	 	 	 	 	
Production expenses	  	 	506	 	 	 	543	 	
Exploration expenses	  	 	13	 	 	 	33	 	
Marketing expenses	  	 	759	 	 	 	873	 	
Depreciation, depletion and amortization	  	 	459	 	 	 	399	 	
Asset dispositions	  	 	(44	) 	 	 	(12	) 	
General and administrative expenses	  	 	153	 	 	 	199	 	
Financing costs, net	  	 	73	 	 	 	387	 	
Restructuring and transaction costs	  	 	54	 	 	 	—  	 	
Other expenses	  	 	(45	) 	 	 	21	 	
	  	 	 	 	 	 	 	 	
Total expenses	  	 	1,928	 	 	 	2,443	 	
	  	 	 	 	 	 	 	 	
Loss from continuing operations before income taxes	  	 	(427	) 	 	 	(245	) 	
Income tax benefit	  	 	(110	) 	 	 	(34	) 	
	  	 	 	 	 	 	 	 	
Net loss from continuing operations	  	 	(317	) 	 	 	(211	) 	
Net earnings from discontinued operations, net of income tax expense	  	 	—  	 	 	 	58	 	
	  	 	 	 	 	 	 	 	
Net loss	  	 	(317	) 	 	 	(153	) 	
Net earnings attributable to noncontrolling interests	  	 	—  	 	 	 	44	 	
	  	 	 	 	 	 	 	 	
Net loss attributable to Devon	  	$	(317	) 	 	$	(197	) 	
	  	 	 	 	 	 	 	 	
Basic net loss per share:	  				 				
Basic loss from continuing operations per share	  	$	(0.74	) 	 	$	(0.41	) 	
Basic earnings from discontinued operations per share	  	 	—  	 	 	 	0.03	 	
	  	 	 	 	 	 	 	 	
Basic net loss per share	  	$	(0.74	) 	 	$	(0.38	) 	
	  	 	 	 	 	 	 	 	
Diluted net loss per share:	  				 				
Diluted loss from continuing operations per share	  	$	(0.74	) 	 	$	(0.41	) 	
Diluted earnings from discontinued operations per share	  	 	—  	 	 	 	0.03	 	
	  	 	 	 	 	 	 	 	
Diluted net loss per share	  	$	(0.74	) 	 	$	(0.38	) 	
	  	 	 	 	 	 	 	 	
Weighted average common shares outstanding - basic and diluted	  	 	434	 	 	 	527	 	
UPSTREAM REVENUES

(in millions)	  	Quarter Ended
March 31,	 	
 	  	2019	 	 	2018	 	
Oil, gas and NGL sales	  	$	1,419	 	 	$	1,360	 	
Derivative cash settlements	  	 	(39	) 	 	 	11	 	
Derivative valuation changes	  	 	(670	) 	 	 	(52	) 	
	  	 	 	 	 	 	 	 	
Upstream revenues	  	$	710	 	 	$	1,319	 	
	  	 	 	 	 	 	 	 	
PRODUCTION EXPENSES

(in millions)	  	Quarter Ended
March 31,	 	
 	  	2019	 	  	2018	 	
Lease operating expense	  	$	220	 	  	$	241	 	
Gathering, processing & transportation	  	 	203	 	  	 	228	 	
Production taxes	  	 	68	 	  	 	59	 	
Property taxes	  	 	15	 	  	 	15	 	
	  	 	 	 	  	 	 	 	
Production expenses	  	$	506	 	  	$	543	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
									
(in millions)	  	Quarter Ended
March 31,	 	
 	  	2019	 	 	2018	 	
Cash flows from operating activities:	  				 				
Net loss	  	$	(317	) 	 	$	(153	) 	
Adjustments to reconcile net loss to net cash from operating activities:	  				 				
Net earnings from discontinued operations, net of income tax expense	  	 	—  	 	 	 	(58	) 	
Depreciation, depletion and amortization	  	 	459	 	 	 	399	 	
Leasehold impairments	  	 	1	 	 	 	8	 	
Accretion on discounted liabilities	  	 	17	 	 	 	16	 	
Total losses on commodity derivatives	  	 	709	 	 	 	41	 	
Cash settlements on commodity derivatives	  	 	(43	) 	 	 	11	 	
Gains on asset dispositions	  	 	(44	) 	 	 	(12	) 	
Deferred income tax benefit	  	 	(107	) 	 	 	(38	) 	
Share-based compensation	  	 	48	 	 	 	38	 	
Early retirement of debt	  	 	—  	 	 	 	312	 	
Total (gains) losses on foreign exchange	  	 	(34	) 	 	 	50	 	
Other	  	 	(10	) 	 	 	(29	) 	
Changes in assets and liabilities, net	  	 	(302	) 	 	 	25	 	
	  	 	 	 	 	 	 	 	
Net cash from operating activities - continuing operations	  	 	377	 	 	 	610	 	
	  	 	 	 	 	 	 	 	
Cash flows from investing activities:	  				 				
Capital expenditures	  	 	(548	) 	 	 	(651	) 	
Acquisitions of property and equipment	  	 	(11	) 	 	 	(6	) 	
Divestitures of property and equipment	  	 	311	 	 	 	47	 	
	  	 	 	 	 	 	 	 	
Net cash from investing activities - continuing operations	  	 	(248	) 	 	 	(610	) 	
	  	 	 	 	 	 	 	 	
Cash flows from financing activities:	  				 				
Repayments of long-term debt principal	  	 	(162	) 	 	 	(807	) 	
Early retirement of debt	  	 	—  	 	 	 	(304	) 	
Repurchases of common stock	  	 	(999	) 	 	 	(71	) 	
Dividends paid on common stock	  	 	(34	) 	 	 	(32	) 	
Shares exchanged for tax withholdings	  	 	(26	) 	 	 	(38	) 	
	  	 	 	 	 	 	 	 	
Net cash from financing activities - continuing operations	  	 	(1,221	) 	 	 	(1,252	) 	
	  	 	 	 	 	 	 	 	
Effect of exchange rate changes on cash - continuing operations	  	 	1	 	 	 	(15	) 	
	  	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of continuing operations	  	 	(1,091	) 	 	 	(1,267	) 	
	  	 	 	 	 	 	 	 	
Cash flows from discontinued operations:	  				 				
Operating activities	  	 	—  	 	 	 	194	 	
Investing activities	  	 	—  	 	 	 	(180	) 	
Financing activities	  	 	—  	 	 	 	39	 	
	  	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of discontinued operations	  	 	—  	 	 	 	53	 	
	  	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash	  	 	(1,091	) 	 	 	(1,214	) 	
Cash, cash equivalents and restricted cash at beginning of period	  	 	2,446	 	 	 	2,684	 	
	  	 	 	 	 	 	 	 	
Cash, cash equivalents and restricted cash at end of period	  	$	1,355	 	 	$	1,470	 	
	  	 	 	 	 	 	 	 	
Reconciliation of cash, cash equivalents and restricted cash:	  				 				
Cash and cash equivalents	  	$	1,327	 	 	$	1,407	 	
Restricted cash included in other current assets	  	 	28	 	 	 	46	 	
Cash and cash equivalents included in current assets held for sale	  	 	—  	 	 	 	17	 	
	  	 	 	 	 	 	 	 	
Total cash, cash equivalents and restricted cash	  	$	1,355	 	 	$	1,470	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED BALANCE SHEETS

(in millions)	  	March 31,
2019	 	 	December 31,
2018	 	
Current assets:	  				 				
Cash and cash equivalents	  	$	1,327	 	 	$	2,414	 	
Accounts receivable	  	 	1,038	 	 	 	885	 	
Current assets held for sale	  	 	—  	 	 	 	197	 	
Other current assets	  	 	338	 	 	 	941	 	
	  	 	 	 	 	 	 	 	
Total current assets	  	 	2,703	 	 	 	4,437	 	
Oil and gas property and equipment, based on successful efforts accounting, net	  	 	12,766	 	 	 	12,813	 	
Other property and equipment, net	  	 	1,098	 	 	 	1,122	 	
	  	 	 	 	 	 	 	 	
Total property and equipment, net	  	 	13,864	 	 	 	13,935	 	
Goodwill	  	 	841	 	 	 	841	 	
Right-of-use assets	  	 	365	 	 	 	—  	 	
Other long-term assets	  	 	304	 	 	 	353	 	
	  	 	 	 	 	 	 	 	
Total assets	  	$	18,077	 	 	$	19,566	 	
	  	 	 	 	 	 	 	 	
Current liabilities:	  				 				
Accounts payable	  	$	603	 	 	$	662	 	
Revenues and royalties payable	  	 	850	 	 	 	898	 	
Short-term debt	  	 	—  	 	 	 	162	 	
Current liabilities held for sale	  	 	—  	 	 	 	69	 	
Other current liabilities	  	 	515	 	 	 	435	 	
	  	 	 	 	 	 	 	 	
Total current liabilities	  	 	1,968	 	 	 	2,226	 	
	  	 	 	 	 	 	 	 	
Long-term debt	  	 	5,786	 	 	 	5,785	 	
Lease liabilities	  	 	298	 	 	 	—  	 	
Asset retirement obligations	  	 	938	 	 	 	1,030	 	
Other long-term liabilities	  	 	458	 	 	 	462	 	
Deferred income taxes	  	 	772	 	 	 	877	 	
Stockholders’ equity:	  				 				
Common stock	  	 	42	 	 	 	45	 	
Additional paid-in capital	  	 	3,518	 	 	 	4,486	 	
Retained earnings	  	 	3,280	 	 	 	3,650	 	
Accumulated other comprehensive earnings	  	 	1,064	 	 	 	1,027	 	
Treasury stock, at cost, 1.5 million and 1.0 million shares in 2019 and 2018, respectively	  	 	(47	) 	 	 	(22	) 	
	  	 	 	 	 	 	 	 	
Total stockholders’ equity	  	 	7,857	 	 	 	9,186	 	
	  	 	 	 	 	 	 	 	
Total liabilities and stockholders’ equity	  	$	18,077	 	 	$	19,566	 	
	  	 	 	 	 	 	 	 	
Common shares outstanding	  	 	417	 	 	 	450	 	
CAPITAL EXPENDITURES
					
(in millions)	  	Quarter Ended
March 31, 2019	 	
New Devon upstream capital	  	$	457	 	
Divest assets upstream capital	  	 	59	 	
Land and other acquisitions	  	 	7	 	
	  	 	 	 	
Exploration and production (E&P) capital	  	 	523	 	
Other	  	 	7	 	
	  	 	 	 	
Devon capital expenditures	  	$	530	 	

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 first-quarter 2019 earnings.

( in millions, except per share amounts)	  	Quarter Ended March 31, 2019	 	
 	  	Before-tax	 	  	After-tax	 	  	Per Diluted
Share	 	
Net loss (GAAP)	  	$	(427	) 	  	$	(317	) 	  	$	(0.74	) 	
Adjustments:	  				  				  				
Asset dispositions	  	 	(44	) 	  	 	(34	) 	  	 	(0.08	) 	
Asset and exploration impairments	  	 	1	 	  	 	1	 	  	 	—  	 	
Deferred tax asset valuation allowance	  	 	—  	 	  	 	(18	) 	  	 	(0.04	) 	
Fair value changes in financial instruments and foreign currency	  	 	635	 	  	 	484	 	  	 	1.12	 	
Restructuring and transaction costs	  	 	54	 	  	 	42	 	  	 	0.10	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings (Non-GAAP)	  	$	219	 	  	$	158	 	  	$	0.36	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
EBITDAX
Devon believes EBITDAX provides information useful in assessing operating and financial performance across periods. Devon computes EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; depreciation, depletion and amortization; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to normal operations. EBITDAX as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.

(in millions)	  	Q1 2019	 	  	Q4 2018	 	
Net earnings (loss) from continuing operations (GAAP)	  	$	(317	) 	  	$	1,149	 	
Financing costs, net	  	 	73	 	  	 	70	 	
Income tax expense (benefit)	  	 	(110	) 	  	 	335	 	
Exploration expenses	  	 	13	 	  	 	44	 	
Depreciation, depletion and amortization	  	 	459	 	  	 	423	 	
Asset disposition gains	  	 	(44	) 	  	 	(268	) 	
Share-based compensation	  	 	26	 	  	 	27	 	
Derivative and financial instrument non-cash valuation changes	  	 	635	 	  	 	(1,209	) 	
Restructuring and transaction costs	  	 	54	 	  	 	9	 	
Accretion on discounted liabilities and other	  	 	(10	) 	  	 	40	 	
	  	 	 	 	  	 	 	 	
EBITDAX (Non-GAAP)	  	$	779	 	  	$	620	 	
	  	 	 	 	  	 	 	 	
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)	  	March 31, 2019	 	
Total debt (GAAP)	  	$	5,786	 	
Less cash and cash equivalents	  	 	(1,327	) 	
	  	 	 	 	
Net debt (Non-GAAP)	  	$	4,459	 	

DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE

																	
PRODUCTION GUIDANCE	  				  				  				  				
			
 	  	Quarter 2	 	  	Full Year	 	
 	  	Low	 	  	High	 	  	Low	 	  	High	 	
Oil and bitumen (MBbls/d)	  				  				  				  				
New Devon	  	 	134	 	  	 	141	 	  	 	140	 	  	 	145	 	
Assets to be sold - Canada	  	 	95	 	  	 	100	 	  	 	108	 	  	 	112	 	
Assets to be sold - U.S.	  	 	2	 	  	 	4	 	  	 	3	 	  	 	5	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	231	 	  	 	245	 	  	 	251	 	  	 	262	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				
New Devon	  	 	72	 	  	 	76	 	  	 	72	 	  	 	77	 	
Assets to be sold - U.S.	  	 	27	 	  	 	32	 	  	 	26	 	  	 	30	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	99	 	  	 	108	 	  	 	98	 	  	 	107	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				
New Devon	  	 	530	 	  	 	580	 	  	 	540	 	  	 	580	 	
Assets to be sold - Canada	  	 	2	 	  	 	4	 	  	 	2	 	  	 	4	 	
Assets to be sold - U.S.	  	 	420	 	  	 	440	 	  	 	400	 	  	 	440	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	952	 	  	 	1,024	 	  	 	942	 	  	 	1,024	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				
New Devon	  	 	295	 	  	 	314	 	  	 	302	 	  	 	319	 	
Assets to be sold - Canada	  	 	95	 	  	 	101	 	  	 	108	 	  	 	113	 	
Assets to be sold - U.S.	  	 	99	 	  	 	109	 	  	 	96	 	  	 	108	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	489	 	  	 	524	 	  	 	506	 	  	 	540	 	

																	
PRICE REALIZATIONS GUIDANCE	  				 				 				 				
			
 	  	Quarter 2	 	 	Full Year	 	
 	  	Low	 	 	High	 	 	Low	 	 	High	 	
Oil and bitumen - % of WTI	  				 				 				 				
U.S.	  	 	90	% 	 	 	100	% 	 	 	90	% 	 	 	100	% 	
Canada	  	 	65	% 	 	 	75	% 	 	 	55	% 	 	 	65	% 	
NGL - realized price	  	$	16	 	 	$	20	 	 	$	16	 	 	$	20	 	
Natural gas - % of Henry Hub	  	 	70	% 	 	 	80	% 	 	 	70	% 	 	 	80	% 	
OTHER GUIDANCE ITEMS - Expense line items include full-year impact of assets that are currently in the process of being sold.

 	  	Quarter 2	 	 	Full Year	 	
($ millions, except Boe and %)	  	Low	 	 	High	 	 	Low	 	 	High	 	
Marketing & midstream operating profit	  	$	10	 	 	$	20	 	 	$	50	 	 	$	70	 	
LOE & GP&T per BOE	  	$	9.30	 	 	$	9.55	(1)  	 	$	8.80	 	 	$	9.05	 	
Production & property tax	  	$	80	 	 	$	90	 	 	$	340	 	 	$	380	 	
Exploration expenses	  	$	10	 	 	$	15	 	 	$	40	 	 	$	60	 	
Depreciation, depletion and amortization	  	$	440	 	 	$	490	 	 	$	1,800	 	 	$	1,900	 	
General & administrative expenses	  	$	130	 	 	$	140	 	 	$	520	 	 	$	540	 	
Financing costs, net	  	$	75	 	 	$	85	 	 	$	300	 	 	$	340	 	
Other expenses	  	$	10	 	 	$	20	 	 	$	30	 	 	$	40	 	
Current income tax rate	  	 	0	% 	 	 	0	% 	 	 	0	% 	 	 	0	% 	
Deferred income tax rate	  	 	20	% 	 	 	25	% 	 	 	20	% 	 	 	25	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax rate	  	 	20	% 	 	 	25	% 	 	 	20	% 	 	 	25	% 	
 
(1)	Included in the Q2 LOE & GP&T guidance is the expected impact from a turnaround at the company’s Jackfish facility within its Canadian operations.	
CAPITAL EXPENDITURES GUIDANCE

 	  	Quarter 2	 	  	Full Year	 	
(in millions)	  	Low	 	  	High	 	  	Low	 	  	High	 	
New Devon upstream capital	  	$	500	 	  	$	550	 	  	$	1,800	 	  	$	2,000	 	
Assets to be sold upstream capital (assumes full year)	  	 	60	 	  	 	80	 	  	 	225	 	  	 	275	 	
Corporate	  	 	5	 	  	 	10	 	  	 	25	 	  	 	35	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Devon capital expenditures	  	$	565	 	  	$	640	 	  	$	2,050	 	  	$	2,310	 	

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)	 	
Q2-Q4 2019	 	 	46,891	 	 	$	 59.97	 	 	 	87,484	 	 	$	54.60	 	 	$	 64.62	 	
Q1-Q4 2020	 	 	3,238	 	 	$	60.13	 	 	 	19,186	 	 	$	 52.23	 	 	$	62.36	 	
			
 	 	Three-Way Price Collars	 	 	 	 	
Period	 	Volume (Bbls/d)	 	 	Weighted
Average Floor
Sold Price
($/Bbl)	 	 	Weighted
Average Floor
Purchased
Price ($/Bbl)	 	 	Weighted
Average Ceiling
Price ($/Bbl)	 	 	 	 	
Q2-Q4
2019	 	 	5,000	 	 	$	50.00	 	 	$	63.00	 	 	$	74.80	 	 				
Oil Basis Swaps

Period	 	Index	 	Volume (Bbls/d)	 	 	Weighted Average
Differential to WTI
($/Bbl)	 	
Q2-Q4 2019	 	Midland Sweet	 	 	24,945	 	 	$	(0.46	) 	
Q2-Q4 2019	 	Argus LLS	 	 	8,900	 	 	$	 5.10	 	
Q2-Q4 2019	 	Argus MEH	 	 	20,945	 	 	$	3.24	 	
Q2-Q4 2019	 	NYMEX Roll	 	 	38,000	 	 	$	0.45	 	
Q2-Q4 2019	 	Western Canadian Select	 	 	62,762	 	 	$	(19.21	) 	
Q1-Q4 2020	 	Argus MEH	 	 	3,000	 	 	$	3.43	 	
Q1-Q4 2020	 	NYMEX Roll	 	 	42,000	 	 	$	0.32	 	
Q1-Q4 2020	 	Western Canadian Select	 	 	4,577	 	 	$	(20.80	) 	
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)	 	
 	Q2-Q4 2019	 	 	 	262,525	 	 	$	 2.81	 	 	 	213,884	 	 	$	2.64	 	 	$	 3.02	 	
 	Q1-Q4 2020	 	 	 	51,409	 	 	$	2.86	 	 	 	40,071	 	 	$	 2.73	 	 	$	3.03	 	
Natural Gas Basis Swaps

Period	 	Index	 	Volume (MMBtu/d)	 	 	Weighted Average
Differential to Henry
Hub ($/MMBtu)	 	
Q2-Q4 2019	 	Panhandle Eastern Pipe Line	 	 	63,018	 	 	$	(0.71	) 	
Q2-Q4 2019	 	El Paso Natural Gas	 	 	130,000	 	 	$	(1.46	) 	
Q2-Q4 2019	 	Houston Ship Channel	 	 	162,500	 	 	$	0.01	 	
Q1-Q4 2020	 	Panhandle Eastern Pipe Line	 	 	30,000	 	 	$	(0.47	) 	
Q1-Q4 2020	 	El Paso Natural Gas	 	 	40,000	 	 	$	(0.67	) 	
Q1-Q4 2020	 	Houston Ship Channel	 	 	10,000	 	 	$	0.02	 	
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 April 25, 2019.