Q1 2018 Operations Report Key Messages 2 Modeling Stats 3 Q1 Results 4 Outlook 5 Delaware Basin 9 STACK15 Rockies 21 Heavy Oil 22 Eagle Ford 23 Barnett Shale 24 NYSE: DVN devonenergy.com Exhibit 99.2

Executing the 2020 Vision Raising U.S. oil production guidance for 2018 Q1 production at high end of guide Record-setting well productivity driving strong returns Executing multi-zone projects ahead of plan Marketing & supply chain provides certainty of execution Services and supplies secured at competitive pricing Firm transport and basis swaps protect regional pricing Cash flow & margins positioned to expand Driven by U.S. oil growth and improved WCS pricing G&A and interest savings to reach ~$175 MM annually Shareholder-friendly initiatives underway $1 billion share-repurchase program Quarterly dividend raised 33% Divestiture program brings forward value in the Barnett Focus on capital efficiency Portfolio simplification Improve financial strength Return cash to shareholders Maximize cash flow Devon’s 2020 Vision

KEY METRICS Q1 ACTUALS(1) Q1 GUIDANCE U.S. oil (MBbls/d) 122 117 - 122 Canada oil (MBbls/d) 129 125 - 130 NGLs (MBbls/d) 97 98 - 103 Gas (MMcf/d) 1,177 1,139 - 1,191 Total (MBoe/d) 544 530 - 554 Production expenses ($MM) $543 $500 - $550 General & administrative expenses ($MM) $226 $210 - $230 Financing costs, net ($MM)(2) $119 $115 - $125 Upstream capital ($MM) $664 $550 - $650 Q1 2018 - ASSET DETAIL DELAWARE STACK ROCKIES EAGLE FORD BARNETT(1) HEAVY OIL PRODUCTION Oil (MBbl/d) 36 35 18 23 1 129 NGL (MBbl/d) 11 37 2 8 37 0 Gas (MMcf/d) 97 344 18 63 633 12 Total (MBoe/d) 64 129 23 41 143 131 ASSET MARGIN (per Boe) Realized price $41.95 $29.57 $51.76 $46.68 $16.50 $27.68(4) Lease operating expenses ($6.09) ($2.54) ($10.45) ($3.00) ($2.66) ($7.92) Gathering, processing & transportation ($2.59) ($4.93) ($1.15) ($6.06) ($6.51) ($3.94) Production & property taxes ($3.37) ($0.95) ($6.27) ($2.48) ($0.76) ($0.65) Cash margin $29.90 $21.15 $33.89 $35.14 $6.57 $15.17 CAPITAL ACTIVTY (Q1 avg.) Upstream capital ($MM) $192 $230 $41 $78 $12 $71 Operated development rigs 8 9 2 n/a 0.5 Operated frac crews 2 3.5 0.5 n/a 0.5 Operated spuds 20 30 7 n/a 1 Operated wells tied-in 26 20 6 n/a 2 Average lateral length 7,800’ 9,000’ 9,700’ n/a 3,200’ UPDATED GUIDANCE Q2 2018e FY 2018e U.S. oil (MBbls/d) 129 - 134 130 - 135 Canada oil (MBbls/d) 110 - 115 125 - 130 NGLs - retained (MBbls/d) 97 - 100 99 - 102 Gas - retained (MMcf/d) 1,001 - 1,053 1,011 - 1,063 Total retained (MBoe/d) 503 - 525 523 - 544 Divested assets (MBoe/d)(3) 21 - 24 13 - 16 Total (MBoe/d) 524 - 549 536 - 560 Production expenses ($MM) $530 - $580 $2,100 - $2,200 General & administrative expenses ($MM) $180 - $200 $775 - $825 Financing costs, net ($MM) $105 - $115 $440 - $470 Upstream capital ($MM) $550 - $650 $2,200 - $2,400 Corporate capital ($MM) $20 - $30 $50 - $70 Capitalized interest ($MM) $15 - $20 $50 - $80 Key Modeling Stats Q1 2018 actuals include recently announced Johnson County divestiture. Excludes $312 million one-time charge for early retirement of debt. Divested assets represents production for recently announced Johnson County sale through May 2018. Cash settlements related to regional basis hedges in Canada were $97 million, or $8.23 per Boe. Note: Items in bold with italics have updated full-year guidance ranges.

Q1 2018 Results U.S. oil production at top end of guidance Delaware & STACK deliver strong growth Delaware March oil production 30% higher vs. Q4 2017 STACK oil production increases 20% vs. Q4 2017 Massive record-setting wells brought online Two Boundary Raider wells IP24: 24 MBOED (~80% oil) Coyote development: avg. IP30 ~4,400 BOED per well Executing multi-zone projects ahead of plan Drove capital 2% above guidance in Q1 Showboat online ~40 days ahead of plan Record drill times set at Boomslang & Seawolf 32 41 30 35 Delaware oil growth MBOD STACK oil growth MBOD 30% GROWTH IP24: 12,868 BOED (82% oil) Boundary Raider 6-7 Com 212H Boundary Raider 6-7 Com 213H BEST WELLS IN DELAWARE BASIN HISTORY IP24: 11,149 BOED (76% oil)

2018 Outlook Raising 2018 U.S. oil production guidance Expect 16% growth vs. 2017 (~30% exit-rate growth) Guidance increased by ~200 basis points Cost structure to improve throughout 2018 G&A and interest savings: ~$175 MM annually (~65% of 2020 Vision target) Per-unit LOE to decline 5% to 10% by year end Positioned for significant cash flow expansion Canadian WCS pricing improving Eagle Ford volumes to grow from Q1 levels Firm transport and basis swaps protect cash flow Efficiencies expected to pull forward capital activity Benefits 2018 & 2019 production profile Capital trending toward top half of guidance Improving 2018 oil production outlook U.S. oil production (retained assets) (MBOD) 129 - 134 145 - 150 ~30% EXIT-RATE INCREASE VS. 2017 114 122 (1) Represents Devon upstream cash flow. Assumes $65 WTI & $2.75 Henry Hub for Q2 – Q4 2018. Growing upstream cash flow(1) ($MM) ~35% GROWTH

2020 Vision: Driving Significant Cash Flow Growth G&A Op. Cost Interest Cost savings to expand margins Upstream Per-Unit Cash Cost ($/BOE) Growing higher-value production U.S. Oil Production (MBOD) MID-TEENS CAGR DRIVEN BY >25% CAGR IN DELAWARE & STACK 15% COST SAVINGS $2.2 CAGR >25% Driving upstream cash flow expansion $ Billions ($60 WTI & $2.75 HH) Significant free cash flow generation Through 2020 ($60 WTI & $2.75 HH) Note: 2017 operating costs been restated under the current accounting methodology. CUMULATIVE FREE CASH FLOW 2.5 Billion

$1 billion share-repurchase program underway $204 million repurchased to date (6.2 million shares) Average price: $33 per share Expect to be completed by year end Raised quarterly dividend by 33% New quarterly rate: $0.08 per share (effective Q2 2018) Target cash flow payout ratio: 5% - 10% Positioned for sustainable annual dividend growth Successfully tendered $807 million of debt in Q1 Reduces interest by $64 million annually Plan to retire $277 million of maturing upstream debt (next 9 months) Shareholder-Friendly Initiatives $1 Billion share repurchase program initiated KEY INITIATIVES UNDERWAY 33% Increase in quarterly cash dividend $1 Billion debt reduction plan

Portfolio Simplification Strategy Resource quality & depth allows for high-grading of portfolio Potential for >$5 billion of asset disposals Divest proceeds to date: $1.1 billion Committed to bringing forward appropriate value as market conditions allow Optionality to monetize oil or gas Multiple initiatives underway to further focus portfolio footprint Actively pursuing larger asset transactions Concurrently marketing ~$1 billion of non-core asset packages across U.S. (high-multiple properties) POTENTIAL ASSET SALE PROCEEDS Portfolio Simplification >$5 Billion STACK Delaware Basin Rockies Heavy Oil Barnett Eagle Ford

Delaware Basin – Q1 2018 Results March production averages 73 MBOED Oil volumes 30% higher vs. Q4 2017 Driven by focused development program Generating best returns in portfolio Two Boundary Raider wells achieve highest flow rates in Delaware Basin history B. Raider 212H - IP24: 12,868 BOED (82% oil) B. Raider 213H - IP24: 11,149 BOED (76% oil) Landed in 2nd Bone Spring interval (Todd area) 25 wells planned in sweet spot over next 18 months Cash margin expands 27% YoY ($30 per BOE) Oil increases to 56% of mix (54% in prior qtr.) Per-unit operating costs to decline by >10% in 2018 High-returning production growth (MBOED) DELAWARE BASIN Q1 18 Q4 17 Net production (MBOED) 64 60 Upstream capital ($MM) $192 $153 Operated rigs / Frac crews (average) 8/2 8/2 Operated spuds / Wells tied-in 20/26 22/20 Average lateral length 7,800’ 9,000’ 35% GROWTH YEAR OVER YEAR

Initial Multi-Zone Projects Delivering Strong Results Frac efficiencies reaching up to 15 stages/day Anaconda project savings: $1 MM per well Average well cost declined to ~$5.5 million Project EUR trending toward 8 MMBOE Boomslang project attains 1st production 11 wells across 3 intervals (Leonard & Bone Spring) Avg. IP30: ~1,400 BOED (represents 7 of 11 wells) Record drill time: 1,350 ft/day Project cycle time: ~6 months New play type derisked at Boomslang/Thistle area Two 2nd Bone Siltstone wells (Avg. IP24: ~1,700 BOED) Potential across state-line area 1,350 1,200 1,050 6.0 5.8 THISTLE/GAUCHO Lea Eddy ANACONDA: $1 MM SAVINGS PER WELL Drilling Completions Facilities 25% 50% 25% Feet Drilled Per Day Short Cycle Times Spud to first production (months) Anaconda 10 wells online Avg. IP-30: 1,600 BOED Boomslang 11 wells flowing back Peak rates in Q2 2018

World-Class Rattlesnake Developments Advancing Completion work underway at Seawolf project 12 wells targeting multiple Wolfcamp intervals Drilling efficiency improved 67% vs. prior activity Avg. drilling savings: ~$800,000 per well Fighting Okra infill drilling program progressing Developing 9 Wolfcamp wells Key contributor to production growth in 1H 2019 BONE SPRING 3rd WOLFCAMP XY A UPPER MIDDLE LOWER Seawolf Development - Rattlesnake Area Initial Development Future Potential Fighting Okra Drilling 9 wells Peak rates: 1H 2019 Seawolf Completing 12 wells Peak rates: Q4 2018 RATTLESNAKE Condor 9 wells Avg. IP-30: 2,000 BOED Endurance 2 wells Avg. IP-30: 1,925 BOED Calm Breeze 4 wells Avg. IP-30: 2,500 BOED PROLIFIC WOLFCAMP RESULTS ACROSS RATTLESNAKE AREA Devon Activity Industry Activity Audacious 4 wells Avg. IP-30: 3,225 BOED Whirling Wind 4 wells Avg. IP-30: 3,900 BOED Lomas Rojas 8 wells Avg. IP-30: 2,000 BOED

Q1-2018a Q2-2018e Q3-2018e Q4-2018e Boomslang (11 well pattern across 3 intervals in the Leonard and Bone Spring) Drilling Completion Production Drilling Completion Production Drilling Completion Fighting Okra (9 well pattern across 3 intervals in the Wolfcamp) Completion Production Production Seawolf (12 well pattern across 4 Wolfcamp intervals ) Lusitano (6 well pattern across multiple intervals in the Leonard, Bone Spring and Wolfcamp) Drilling Completion Medusa (12 well pattern across 3 intervals in the Leonard Shale and Bone Spring) Production North Thistle 34 (7 well pattern across 1 interval of the Leonard Shale) Drilling Completion DEVELOPMENT STRATEGY BUILDING MOMENTUM DELAWARE BASIN DEVELOPMENT ACTIVITY Current Developments Future Projects (Timing TBD) Seawolf Completing Fighting Okra Drilling Van Doo Dah Potato Basin Tomb Raider Cobra Flagler Lusitano Completing Boomslang Flowing back Anaconda 10 wells online Medusa Drilling North Thistle 34 2018 spud Snapping Delaware Development Projects Advancing on Plan 70% of 2018 capital activity associated with multi-zone developments 6 multi-zone projects expected to contribute to 1st production by YE 2018

Firm transport and basis swaps protect price realizations Midland basis swaps protect ~50% of oil production ~40% of oil delivered on firm transport to Gulf Coast Term gas sales in place to flow to West Coast (avoids WAHA hub) Gas basis swaps protect ~40% of production Field-level infrastructure in place to support growth plans >90% of produced water piped to disposal wells or recycling facilities ~80% of total water used in operations is recycled (DVN: 8 facilities) >80% of oil gathering on pipe by 2H 2018 Excess gas processing capacity projected through 2022 Services and supplies requirements secured through 2019 Rig requirements secured to complete current program (~8 rigs) Dedicated frac crews secured to execute capital plans (~2.5 crews) 30% savings on self-sourced regional sand Houston ~40% of 2018 Delaware volumes transported on Longhorn Protecting Price & Flow Assurance Longhorn (Firm transport) In-basin sales protected by basis swaps OIL BASIS SWAPS PROTECT PRICE 2018 2019 Midland oil swaps (MBbls/d) 23 28 Avg. differential to WTI ($/Bbl) ($1.02) ($0.46) Delaware Basin – Certainty of Execution

Delaware Basin – Outlook Significant resource opportunity (~300,000 net surface acres with >15 development targets) >15% sequential quarter production growth expected in Q2 Capital spending on track with 2018 budget (~$725 million) Production exit-rate growth: >40% by year end Franchise asset provides multi-decade oil growth opportunity ~300k net surface acres (>15 different development targets) >1.3 million net effective acres Production forecast on track (MBOED) >40% EXIT RATE GROWTH

STACK – Q1 2018 Results Oil production increases 68% from Q1 17 Coyote development delivering record flow rates Top wells average IP30 of ~3,500 BOED Field-level cash flow expands 60% year over year Liquids volumes account for ~80% of revenue Per-unit operating costs to decline >10% by Q4 2018 Showboat project online ~40 days ahead of plan Efficiencies accelerated capital spend in Q1 (33% of budget) 8 Bonsai IP 30: 3,900 BOED Coyote 1X IP 30: 3,800 BOED Cottontail IP 30: 4,400 BOED 1 2 3 4 Chipmunk IP 30: 5,900 BOED Sonoyta 2HX IP 30: 3,500 BOED Otter IP 30: 3,400 BOED Coyote 3HX IP 30: 4,400 BOED 5 6 7 Coyote 2HX IP 30: 3,400 BOED 10 Sonoyta 3HX IP 30: 3,500 BOED Hydra IP 30: 2,150 BOED 9 11 Grizzly IP 30: 2,000 BOED 12 Rhino IP 30: 2,100 BOED RECORD-SETTING STACK WELL PRODUCTIVITY Blaine 5 6 11 8 7 10 9 12 ~3,500 Q1 2018 KEY WELLS BOED 30-DAY IPs Canadian Kingfisher Coyote Development 68% OIL GROWTH 1 2 3 4 YEAR-OVER-YEAR KEY STATS Q1 18 Q4 17 Net production (MBOED) 129 117 Upstream capital ($MM) $230 $230 Operated rigs / Frac crews (average) 9/3.5 10/3.5 Operated spuds / Wells tied-in 30/20 32/24 Average lateral length 9,000’ 8,600’

Next 3 projects designed to inform future infill decisions Testing 9, 10 & 12 Meramec wells per drilling unit Program to deliver attractive returns (Showboat/Horsefly/Bernhardt) Burdened wellhead IRRs projected at ~40%(1) (at strip pricing) Low-risk appraisal objectives (testing spacing & secondary targets) Conservatively risked performance within our 2018 outlook Infill projects to deliver improved capital efficiency Projected IRRs superior to historical appraisal drilling results Driven by optimized subsurface planning, significantly lower capital costs and improved LOE costs per well Positioned for significant resource & inventory upside 130k surface acres in over-pressured oil window Economic core of play with up to 5 different landing zones Infill spacing to de-risk upside (currently risked at 6 wells/section) STACK – Infill Development Strategy Drilling Unit Current Projects Showboat 12 wells per drilling unit Flowing back 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 9 to 12 wells per surface section (1) Returns are burdened for corporate overhead costs Bernhardt 9 wells per drilling unit Drilling Horsefly 10 wells per drilling unit Completing

STACK Development Activity Progressing 60% of capital activity in 2018 associated with multi-zone developments 4 multi-zone projects expected to contribute to 1st production by YE 2018 DEVELOPMENT STRATEGY BUILDING MOMENTUM STACK DEVELOPMENT ACTIVITY Kingfisher Canadian Dewey Custer Blaine 2018 Developments Coyote 4 of 7 wells online Avg. 30-Day IP 4,400 BOED Showboat Flowing back 12 wells per unit Kraken 2018 spud Geis 2018 spud Bernhardt Drilling 9 wells per unit Horsefly Completing 10 wells per unit ML Block 2018 spud Cascade 2018 spud Q1-2018a Q2-2018e Q3-2018e Q4-2018e Coyote (7 well development in the Meramec) Completion Production Drilling Completion Production Drilling Completion Geis (7 wells per drilling unit across 2 intervals in the Meramec) Completion Production Showboat (Testing 12 wells per drilling unit across 3 intervals in the Meramec and 1 Woodford zone) Horsefly (Testing 10 wells per drilling unit across 3 Meramec intervals) Drilling Completion Bernhardt (Testing 9 wells per drilling unit across 3 Meramec intervals) Production Kraken (7 wells per drilling unit across 3 intervals in the Meramec and 1 Woodford zone) Drilling Completion

STACK Infill Projects Delivering Efficiencies Record flow rates achieved at Coyote project Project developing Lower Meramec sweet spot Average IP30: 4,400 BOED (4 of 7 wells online) Drilling time improved by up to 25% vs. offsetting Faith Marie well ($1 MM savings per well) Completion costs reduced by ~10% vs. previous activity Showboat cost savings: ~$1.5 million per well 30% drilling efficiencies ($500k savings per well) 2x improvement in frac stages per day 1st production achieved in April (~40 days ahead of plan) Well tie-ins staggered over next two months Peak project rates expected by mid-year Spud-to-1st production cycle time: ~7 months Faith Marie Parent Well Online Q4 17 IP30: 4,700 BOED Cottontail Parent Well Online Q1 18 IP30: 4,400 BOED Coyote Project 4 of 7 wells online Avg. 30-day IP: 4,400 BOED Online in 2018 Flowing Back 16N 12W 17N 12W Coyote Area: A Lower Meramec Sweet Spot $1.5 MM Savings Per Well Drilling Completions Facilities Cost Savings By Area Frac Stages Per Day

STACK – Certainty of Execution Improved oil takeaway infrastructure boosts pricing (~$1/Bbl uplift) Majority of oil planned to be connected to gathering systems (Black Coyote online in April) Reliable and cost-effective pipeline access to Cushing (see map) Gas flow assurance: Devon holds firm transportation Covers vast majority of estimated STACK gas production Access to premium pricing outside of Mid-Con (covers 1/3 of volumes) Basis swaps protect ~25% of gas production (~$0.45 off HH) Sufficient gas processing capacity to support growth plans Thunderbird plant increases EnLink capacity to 1.2 BCFD Services and supplies requirements secured through 2019 Rig requirements secured to complete current program (~8 rigs) Dedicated frac crews secured to execute capital plans (~3 crews) 30% savings on self-sourced regional sand Protecting Price and Flow Assurance Cushing BASIS SWAPS PROTECT PRICE REALIZATIONS 2018 MidCon basis swaps (MMBtu/d) 94,370 Avg. differential to Henry Hub ($/MMBtu) ($0.45) Basis swaps protect 25% of in-basin gas pricing Navigator Glass Mountain Pipeline Firm gas transportation moves 1/3 of volumes to premium markets

STACK – Outlook Activity concentrated in over-pressured oil window (best returns in play) >100 new operated wells online in 2018 Targeting higher-return Meramec formation Accelerated capital spend in Q1 due to completion efficiencies (32% of budget) 2018 production plan on track Q2 oil volumes flat due to timing of development projects Multi-zone projects to accelerate production growth in 2H 2018 Year-end 2018 exit rates: >40% oil growth Activity shifting to economic core >95% WOODFORD 2018 E&P ACTIVITY MERAMEC ACTIVITY High-returning production growth Production (MBOED) >140 (>40% oil growth) 117 129

Rockies Oil production increased 17% vs. Q4 2017 Parkman/Teapot activity drives growth Low costs drive strong returns (~$5 MM per well) Testing Niobrara potential (~400k prospective acres) Initial well flowing back Completion work underway at 2nd appraisal well “Super Mario” Turner activity accelerating ~10 wells scheduled for remainder of 2018 KEY POWDER RIVER BASIN ACTIVITY Q1 2018 Activity Key Wells to Date Upcoming Turner Wells T Cosner Fed 29-1XPH Parkman 30-Day IP: 1,850 BOED T Cosner Fed 29-3XPH Parkman 30-Day IP: 2,400 BOED T Cosner Fed 29-4XPH Parkman 30-Day IP: 2,550 BOED T Cosner Fed 29-2XPH Parkman 30-Day IP: 2,100 BOED Super Mario Area Turner 4-well test Avg. 30-Day IP: 2,100 BOED/well 1st Niobrara Test Flowing back 2nd Niobrara Test Completing 4 Parkman Wells Avg. 30-Day IP: 1,200 BOED/well Avg. well cost: ~$5mm Teapot Well Avg. 30-Day IP: 1,700 BOED Well cost: ~$5mm Moore Land Trust 21 1TH Teapot 30-Day IP: 2,500 BOED Moore Land Trust 21 2TH Teapot 30-Day IP: 2,300 BOED KEY STATS Q1 18 Q4 17 Net production (MBOED) 23 19 Upstream capital ($MM) $41 $66 Operated rigs / Frac crews (average) 2/0.5 3/0.5 Operated spuds / Wells tied in 7/6 7/11 Average lateral length 9,700’ 8,000’

Heavy Oil Oil production at high end of guidance in Q1 Q2 volumes impacted by turnaround and royalties Jackfish turnaround impact: ~15 MBOD Higher royalties: ~3 MBOD WCS hedges protecting cash flow in 2018 ~50% hedged at $15 off WTI Free cash flow in 2018: $550 million(1) Heavy Oil 2018e Free Cash Flow ($MM) $550 ($275) ($650) $250 $1,225 (1) Assumes $65 WTI & $25 differential for remainder of 2018. Q1 PRODUCTION GROSS NET Jackfish 1 (MBOD) 35.0 31.8 Jackfish 2 (MBOD) 41.7 40.3 Jackfish 3 (MBOD) 40.0 38.7 Lloydminster (MBOED) 21.8 20.3 Total Heavy Oil (MBOED) 138.5 131.1 SAGD Sweet Spot 1 $ INCREASE IN WCS PER BBL FOR EVERY INCREMENTAL 40 MM $ ANNUALIZED CASH FLOW

Stabilizing High-Margin Production Eagle Ford Strong production growth in Q2 (chart below) Two frac crews currently on site 25 wells to be tied-in Plan in place to stabilize production 35 to 40 new wells online in 2H 2018 Free cash flow in 2018: >$400 million(1) 10 Staggered laterals Lower Eagle Ford Tied In: Q2 2018 15 Staggered laterals Lower Eagle Ford Tied In: Q2 2018 EAGLE FORD HIGHLIGHTS Two Completion Crews 25 Wells Expected Online in Q2 ~30% GROWTH (1) Assumes $65 WTI & $2.75 Henry Hub for remainder of 2018. KEY STATS Q1 18 Q4 17 Net production (MBOED) 41 55 Upstream capital ($MM) $78 $41

Barnett Shale Johnson County divestiture announced Proceeds: $553 million (closing late May) Q1 production: 33 MBOED (18% liquids) Partnership formed with DowDupont Selling ½ working interest in 116 locations Devon to receive ~$75 million over 5 yrs Drilling commitment of up to 24 wells/year No restrictions on exiting Barnett ~50 horizontal refracs planned in 2018 Capital program to stabilize production for retained Barnett assets (table right) 2018 BARNETT SHALE ACTIVITY OUTLOOK Dow JV Acreage 2018e activity: ~20 wells drilled Refrac Focus Area 2018e activity: ~50 horizontal refracs PRODUCTION (MBOED) Q1 18 Q2 18e 2H 18e Retained Barnett assets 110 105 - 115 110- 115 Johnson County divestiture 33 22 0 Total Barnett production 143 127 - 137 110 - 115

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 first-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.