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.