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NYSE: DVNdevonenergy.com

UBS Global Oil and Gas Conference

May 23, 2018

2| Investor Presentation

Investor Contacts & Notices

Investor Relations Contacts

Scott Coody Chris CarrVP, Investor Relations Supervisor, Investor Relations405-552-4735 405-228-2496

Email: [email protected]

Forward-Looking StatementsThis 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 InformationThis 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 InvestorsThe 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.

mailto:[email protected]


Investment Thesis

DELAWARE & STACKPOTENTIAL LOCATIONS>30,000

Multi-decade growth platform

Delaware & STACK focused

Rapidly expanding cash flow

Disciplined capital allocation

Significant financial strength


Devon’s 2020 Vision

Enhance returns through disciplined capital investment

High-grade resource-rich asset portfolio

Net debt to EBITDA target: 1.0x – 1.5x

$1 billion share repurchase program underway

Focus on capital efficiency

Portfolio simplification

Improve financial strength

Return cash to shareholders

TOP OBJECTIVE: OPTIMIZE RETURNS & DELIVER CAPITAL-EFFICIENT, CASH-FLOW GROWTH

Consistently grow and sustain dividend

Further improve investment-grade credit ratings

>$5 billion of divestiture potential

Improve margins by aggressively lowering cost structure

Leverage technology to optimize base production Maximize cash flow

Concentrated activity in economic core of Delaware & STACK


2017 2018e 2019e 2020e

2020 Vision: Driving Significant Cash Flow Growth

114

100

125

150

175

200

2017 2018e 2019e 2020e $-

$6

$12

$18

2017 2018e 2019e 2020e

G&AOp. Cost

Interest

Cost savings to expand marginsUpstream Per-Unit Cash Cost ($/BOE)

Growing higher-value productionU.S. Oil Production (MBOD)

MID-TEENS CAGRDRIVEN BY >25% CAGR INDELAWARE & STACK

15% COST SAVINGS

$2.2

CAGR >25%

Driving upstream cash flow expansion $ Billions ($60 WTI & $2.75 HH)

Significant free cash flow generationThrough 2020 ($60 WTI & $2.75 HH)

CUMULATIVE FREE CASH FLOW2.5Billion

Note: 2017 costs are pro forma for revenue recognition accounting rules recently implemented.


$1 billion share-repurchase program underway

— $204 million repurchased (as of 4/30/18)

— Average price: $33 per share

— Expect program to be completed by year end

Raised quarterly dividend by 33%

— Target cash flow payout ratio: 5% - 10%

— Positioned for sustainable dividend growth

Recently tendered $807 million of debt

— Plan to retire $277 million of maturing debt (next 9 months)

Shareholder-Friendly Initiatives

$1 Billion share repurchase program initiated

KEY INITIATIVES UNDERWAY

33% Increasein quarterly cash dividend

$1 Billion debt reduction plan


Portfolio Simplification Strategy

POTENTIAL ASSETSALE PROCEEDS

Portfolio Simplification

>$5 BillionSTACK

Delaware Basin

Rockies

Heavy Oil

Barnett

Eagle Ford

Resource quality & depth allows for high-grading of portfolio

Potential for >$5 billion of asset disposals

— Divest proceeds to date: $1.1 billion

— Optionality to monetize oil or gas

Multiple initiatives underway to further focus portfolio footprint

— Actively pursuing larger asset divestitures

— Marketing ~$1 billion of non-core asset packages


Significant Financial Strength

Investment-grade credit ratings

Net debt to EBITDA target: 1.0x to 1.5x

Significant investment in EnLink Midstream

Disciplined hedging program

— ~60% of 2018 oil & gas volumes protected

— Attractive WCS & Midland basis swaps

PROTECTING OUR ABILITY TO EXECUTE

INVESTMENT-GRADECREDIT RATINGS

EnLink InvestmentMarket Value: ~$3.5B(as of May 2018)

ExcellentLiquidityCash: $1.4B

Disciplined Hedging2018: ~60%

For additional information on hedges see the appendix


Operational Excellence

Maximize base production

Minimize controllable downtime

Enhance well productivity

Leverage midstream operations

Control operating costs

Optimize capital program

Disciplined project execution

Perform premier technical work

Focus on development drilling

Accelerate operational efficiencies

CaptureFULL VALUE

ImproveRETURNS


Updated 2018 Outlook

Raised 2018 U.S. oil production guidance— 16% growth vs. 2017 (~30% exit-rate growth)

— Guidance increased by ~200 basis points— Driven by efficiencies and well productivity

FY 2017 Q1 2018 Q2 2018e 2H 2018e 2018e Exit Rate

135 - 142

Improving 2018 oil production outlookU.S. oil production (retained assets) (MBOD)

129 - 134

145 - 150

~30% EXIT-RATEINCREASE VS. 2017

114

122

(1) Represents Devon upstream cash flow. Assumes $65 WTI and $2.75 Henry Hub for Q2 – Q4 2018.

$400

$600

$800

Q1 2018 Q2 2018e Q3 2018e Q4 2018e

Growing upstream cash flow(1)

($MM)

~35%GROWTH

Positioned for significant cash flow expansion— Driven by high-margin U.S. oil growth— Canadian WCS pricing improving— G&A and interest savings: ~$175 MM annually


The Next Frontier Of Efficiency Gains

Multi-zone projects to drive returns higher— Increase rig & frac crew efficiencies

— Centralized facilities improve cost structure

— Higher recoveries from stacked pay

— Focused activity maintains short cycle times

Initial Delaware & STACK development highlights:— Capital savings of up to $1.5 MM per well

— Record drill times (~30% improvement)

— Frac efficiencies reaching as high as 15 stages/day

For additional information see our Q1 operations report

>20%COST SAVINGS

PER WELL

TARGETING


Securing The Supply Chain

Services and supplies secured through 2019

— Dedicated frac crews in Delaware & STACK

— Development efficiencies driving rig reductions

— Self-sourcing regional sand (~30% savings)

— Industry leader in water recycling

Attaining top-tier services at below-market rates

— Decoupling historically bundled services

— Securing longer-term relationships

— Development efficiencies offsetting inflation

SERVICES & SUPPLIES SECUREDSERVICES & SUPPLIES SECURED


Protecting Price & Flow Assurance

Houston~40% of 2018 Delaware volumes

transported on Longhorn

Delaware gas volumes flow to west coast markets

Waha

In-basin oil sales protected by basis swaps

DELAWARE BASIN: OIL BASIS SWAPS2018 2019

Midland oil swaps (MBbls/d) 23 28

Avg. differential to WTI ($/Bbl) ($1.02) ($0.46)

Delaware Basin positioned for premium oil pricing— Swaps & firm transport protect ~90% of oil volumes— Gas flows to West Coast (avoids WAHA hub)

— Basis swaps protect ~40% of gas production

STACK volumes have access to advantaged markets— WTI pricing with pipeline access to Cushing— Firm transport covers vast majority of gas production— ~60% of gas volumes price protected (~$0.50 off HH)

Basis hedges protecting cash flow in Canada— WCS swaps protect ~50% of oil volumes in 2018 ($15 off WTI)

For additional information on hedges see the appendix

Premium Pricing in the Delaware Basin


Delaware Basin – Franchise Asset

World-class oil opportunity


Up to 15 target intervals

Accelerating development activity

Future Projects (Timing TBD)

Current Developments

Core Development Area

POTATO BASIN

TODD

THISTLE/GAUCHOCOTTON DRAW

RATTLESNAKE

LusitanoCompleting

BoomslangFlowing Back

SeawolfCompleting

MedusaDrilling

Anaconda10 Wells Online

Potato Basin

Flagler

CobraTomb Raider

Eddy

Loving

Lea

Fighting OkraDrilling

Van Doo Dah

Snapping

North Thistle 342018 Spud


Activity targeting the most prolific zones

Delaware Basin – Advantaged State-Line Area

Q4 2017 March 2018 2018e Exit Rate

>85

60

73

Leonard

Bone Spring

Wolfcamp

Improving cost structure to boost marginsLOE & Transportation Expense ($/BOE)

Positioned for high-return production growthProduction (MBOED)

2018E&P

ACTIVITY

Delivered the top wells in Delaware Basin history

IP24: 12,868 BOED (82% oil)Boundary Raider 6-7 Com 212H

Boundary Raider6-7 Com 213H IP24: 11,149 BOED (76% oil)

$9.10 $8.97$8.68

~$7.50

1H 2017 2H 2017 Q1 2018 Year End 2018e

Note: 2017 costs are pro forma for revenue recognition accounting rules recently implemented.


Delaware Basin – Significant Growth Opportunity

Massive stacked-pay potential Multi-decade oil growth opportunity

─ ~300k net surface acres focused in state-line area

─ >1.3 million net effective acres (up to 15 target intervals)

─ Significant resource upside with Wolfcamp delineation

DELAWARE BASIN RESOURCE

FORMATION NET EFFECTIVEACRES

GROSS RISKED LOCATIONS

GROSS UNRISKEDLOCATIONS

Leonard Shale 160,000 1,000 3,500

Bone Spring 530,000 3,200 6,000

Wolfcamp 460,000 1,500 8,500

Other Targets 180,000 800 2,500

Total >1,300,000 6,500 >20,000


STACK – Franchise Asset

Canadian

KingfisherBlaine

Caddo

CoyoteAvg. 30-Day IP 4,400 BOED

ShowboatFlowing back

HorseflyCompleting

BernhardtDrilling

Best-in-class acreage position

>600k net acres by formation

Up to 4 target intervals per unit

Accelerating development activity Geis2018 Spud

Cascade2018 Spud

Kraken2018 Spud

ML Block2018 Spud

Minnie Haha

Northwoods

Centaur

Future Projects (Timing TBD)

2018 Developments

Projects Online


STACK – Infill Projects Delivering Efficiencies

Record flow rates achieved at Coyote project─ Project developing Lower Meramec sweet spot

─ Average IP30: 4,400 BOED (60% oil)

─ Drilling times improved by ~25%

─ Completion costs reduced by ~10% vs. prior activity

Showboat cost savings: ~$1.5 million per well─ 30% faster drill times vs. prior activity

─ 2x improvement in frac stages per day

─ 1st production achieved 40 days ahead of plan

─ Peak project flow rates expected by mid-year

Faith Marie Parent WellOnline Q4 17IP30: 4,700 BOED

Cottontail Parent WellOnline Q1 18IP30: 4,400 BOEDCoyote Project

4 of 7 wells onlineAvg. 30-day IP: 4,400 BOED

Online in 2018Flowing Back

16N 12W

17N 12W

Coyote Area: A Lower Meramec Sweet Spot

$1.5 MMSavingsPer Well

Drilling Completions Facilities

Showboat 2017 Avg.

~8 avg.(up to 11 per day)

4

Showboat Cost Savings Frac Stages Per Day (Showboat)


STACK – Meramec Drives Strong Oil Growth

Activity concentrated in over-pressured oil window (best returns in play)

Multi-zone projects to accelerate production growth

Positioned for significant resource & inventory upside

Activity shifting to economic core

>95%WOODFORD

2018E&P

ACTIVITY

MERAMEC ACTIVITY

Q4 2017 Q1 2018 2018e Exit Rate

High-returning production growthProduction (MBOED)

>140(>40% oil growth)

117

129 SIGNIFICANT MERAMEC RESOURCE UPSIDE

Over-pressured oil acreage 130,000 net surface acres

Stacked-pay opportunity Up to 5 Meramec landing zones

Risked inventory 6 wells per surface section

Current infill spacing tests 9 to 12 wells per surface section


Investment Thesis

DELAWARE & STACKPOTENTIAL LOCATIONS>30,000


Delaware & STACK focused

Rapidly expanding cash flow

Disciplined capital allocation

Significant financial strength

Thank you.

Thank you. For additional information see ourQ1 Operations Report


Rockies – An Emerging Oil Growth Asset

Premier Powder River Basin position— Q1 net production: 23 MBOED — Stacked pay: >10 prospective intervals

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 Tests

T Cosner Fed 29-1XPHParkman30-Day IP: 1,850 BOED




Super Mario Area

Turner 4-well testAvg. 30-Day IP: 1,500 BOED/well

1st Niobrara Test30-Day rates in Q2

2nd Niobrara Test30-Day rates in 2H18

4 Parkman WellsAvg. 30-Day IP: 1,200 BOED/wellAvg. Well cost: ~$5mm Teapot Appraisal Well

Avg. 30-Day IP: 1,700 BOED/wellWell cost: ~$5mm

Moore Land Trust 21 1THTeapot30-Day IP: 2,500 BOED

Moore Land Trust 21 2THTeapot30-Day IP: 2,300 BOED


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)

UpstreamRevenues

WCS Hedges ProductionExpenses

Capex Free Cash Flow

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 NETJackfish 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 BBLFOR EVERY INCREMENTAL

40MM$ANNUALIZED CASH FLOW


Q1 2018 Q2 2018e 2H 2018e

41

52 - 57

(MBOED)

50 - 55

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 lateralsLower Eagle FordTied In: Q2 2018

15 Staggered lateralsLower Eagle FordTied In: Q2 2018

EAGLE FORD HIGHLIGHTS

Two Completion Crews

25 WellsExpected Online in Q2

(1) Assumes $65 WTI & $2.75 Henry Hub for remainder of 2018.

KEY STATS Q1 18 Q4 17Net 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 Acreage2018e activity: ~20 wells drilled

Refrac Focus Area2018e activity: ~50 horizontal refracs

PRODUCTION (MBOED) Q1 18 Q2 18e 2H 18eRetained Barnett assets 110 105 - 115 110- 115

Johnson County divestiture 33 22 0

Total Barnett production 143 127 - 137 110 - 115


Innovation Momentum - Technology Projects In Flight

Improved 3D seismic interpretation

High-graded location selection

Optimized landing zones

Well productivity predictions

Depletion analysis

Geospatial optimization

Cyber-geosteering

Flat, in-zone wells

Fiber-optic sensing

Prolonged drill-bit life

Coiled-tubing drill-outs

Efficient flowbacks

Cutting-edge frac modeling

Accounting process automation

World-class partnerships in digital innovation platforms

Enterprise dashboards for information

Accessible mobile applications across all aspects of the business

Water-treatment options

Frac fluid chemistry

Data acquisition and management systems

Leak detection in piping systems

Water transfer and storage safety

Predictive pump failures

Field-issue prioritization

Optimized compressors

Production monitoring

Flood optimization

Inter-well communication (data analytics)

Gas lift for EOR

Targeting hundreds of millions in value creation annually

S U B S U R F A C ED R I L L I N G &C O M P L E T I O N S

P R O D U C T I O NO P E R A T I O N S

W A T E R M A N A G E M E N T C O R P O R A T E


Hedge Position

NATURAL GAS DERIVATIVESSWAPS COLLARS BASIS SWAPS

PERIODVOLUME

(MMBTU/D)

WEIGHTEDAVG. PRICE($/MMBTU)

VOLUME(MMBTU/D)

WEIGHTED AVG. FLOOR PRICE ($/MMBTU)

WEIGHTED AVG. CEILING PRICE

($/MMBTU) INDEXVOLUME

(MMBTU/D)

WTD. AVG.DIFF to

HENRY HUB ($/MMBTU) INDEX

VOLUME(MMBTU/D)

WTD. AVG.DIFF to

HENRY HUB ($/MMBTU)

Q2-Q4 2018 357.3 $2.96 194.8 $2.77 $3.10 PANHANDLE EASTERN 93.5 ($0.48) EL PASO 53.5 ($1.17)

FY 2019 118.6 $2.83 87.8 $2.69 $3.06 PANHANDLE EASTERN 5.0 ($0.81) EL PASO 60.0 ($1.58)

OIL DERIVATIVESSWAPS COLLARS MIDLAND BASIS SWAPS WCS BASIS SWAPS

PERIOD VOLUMEWEIGHTED AVG. PRICE VOLUME

WEIGHTED AVG. FLOOR PRICE

WEIGHTED AVG. CEILING PRICE VOLUME

WEIGHTED AVG. DIFF. to WTI VOLUME

WEIGHTED AVG. DIFF. to WTI

(MBPD) ($/BBL) (MBPD) ($/BBL) ($/BBL) (MBPD) ($/BBL) (MBPD) ($/BBL)

Q2-Q4 2018 75.6 $56 92.8 $51 $61 20 ($1.02) 69 ($14.91)

FY 2019 40.1 $58 54.8 $52 $62 28 ($0.46) — —

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