NYSE: DVNdevonenergy.com

Barclays CEO Energy-Power Conference

September 7, 2016

Investor Contacts & Notices

2

Investor Relations Contacts

Howard J. Thill, Senior Vice President, Communications & Investor Relations(405) 552-3693 / howard.thill@dvn.com

Scott Coody, Director, Investor Relations(405) 552-4735 / scott.coody@dvn.com

Chris Carr, Supervisor, Investor Relations(405) 228-2496 / chris.carr@dvn.com

Forward-Looking StatementsThis presentation includes "forward-looking statements" as defined by the Securities and Exchange Commission (the “SEC”). Such statements are subject to a variety of risks and uncertainties that could cause actual results or developments to differ materially from those projected in the forward-looking statements. Please refer to the slide entitled “Forward-Looking Statements” included in this presentation for other important information regarding such statements.

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 most recent 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, risked or unrisked resource, potential locations, risked or unrisked locations, 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.

Devon TodayA Leading North American E&P

3

Key Messages

Premier asset portfolio

— Top-tier N.A. resource plays

— Deep inventory of opportunities

Significant financial strength

Delivering best-in-class results

Disciplined capital allocation

— Focused on value and returns

Heavy Oil

Rockies Oil

Barnett Shale

STACK

Oil44%

NGL19%

Gas37%

Retained Asset Production Forecasted 2016: 558 - 578 MBOED

Delaware Basin

Eagle Ford

Approach To The Current Environment

4

Achieve additional operating cost savings

Further increase capital productivity

Focused on value and returns

Accelerate activity in STACK and Delaware Basin

Preserve continuity in other U.S. resource plays

Invest within cash flow

Divestitures to enhance financial strength

Successful Asset Divestiture ProgramEnhancing Financial Strength

5

Midland Basin$1.0 BillionClosed

San Juan BasinUndisclosed ValueClosed

Access Pipeline$1.1 BillionExpected close: Q3 2016

Granite Wash$0.3 BillionClosed

Divestiture program complete

Total proceeds: $3.2 billion

― E&P asset sales: $2.1 billion

― Access pipeline sale: $1.1 billion

Minimal cash taxes expected

Majority of proceeds to reduce debt

Mississippian$0.2 BillionClosed

East Texas$0.5 BillionClosed

Significant Financial Strength

6

Investment-grade balance sheet

― Adjusted cash balance: $4.6 billion(1)

― Undrawn $3 billion credit facility

Net debt(2) reduced >45% from early 2016

Debt reduction program underway

― $1.3 billion tendered to date

No significant debt maturities until mid-2021

$8.7

$4.7

Jan. 2016 Current

Net Debt(2)

$ Billions

>45%DECLINE

(1) Cash balance at 6/30/16 adjusted for asset divestitures expected to close in Q3 2016.(2) Net debt is a non-GAAP measure defined as total debt less cash and cash equivalents and

debt attributable to the consolidation of EnLink Midstream. Net debt is adjusted for assetdivestitures that have closed and those expected to close in Q3 2016.

P RO- FORMA L IQUID ITY

BILLION

Advantaged Midstream Business

7

Devon’s equity ownership interest

― 24% of MLP (ENLK: 95 million units)

― 64% of GP (ENLC: 115 million units)

Eliminates midstream capital requirements

Improves midstream growth potential

Provides visible cash flow stream

― Annual distributions: ≈$270 million

EnLink Overview

DVN’S ENLINK OWNERSHIP

BILLION

MARKET VALUE ON AUGUST 30th

Operating Strategy For Success

8

Maximize base production

— Minimize controllable downtime

— Enhance well productivity

— Leverage midstream operations

— Reduce operating costs

Optimize capital program

— Disciplined project execution

— Perform premier technical work

— Focus on development drilling

— Reduce capital costs

Delivering Best-In-Class Well Results

9

Devon delivered best well results of any U.S. producer during 2015

Key drivers of success:

— Enhanced completion designs and improved well placement

— Development drilling focused in top N.A. resource plays

0

150

300

450

600

2015 Avg. 90-Day Wellhead IPsBOED, 20:1

0

150

300

450

600

2012 2013 2014 2015 Top U.S. Producers

Source: IHS/Devon. Operators with more than 100 wells.

Devon’s Avg. 90-Day Wellhead IPsBOED, 20:1

≈250%INCREASE

Achieving Significant Cost Savings

10

D&C Well Cost DeclinesPeak cost to Q2 2016

S A V I N G S

Declining D&C costs across portfolio

― Up to 40% lower than peak rates

― Driven by efficiencies and supply chain costs

― More than offsetting larger completions

Delivering significant operating cost savings

― LOE and G&A reduced >30% from peak levels

― Operating costs to decline by ≈$1 billion in 2016

UP TO

2015 2016e

2016e Field-Level Operating Costs and G&A(1)

$ Billions

≈$1BSAVINGS

$3.7

$2.7 - $2.9

LOE

Prod. Taxes

G&A

(1) Includes capitalized G&A.

Disciplined Capital AllocationYielding Strong Results

11

37%

21%

17%

15%

10%

STACK

DelawareBasin

Eagle Ford

Heavy Oil

Other

2016 E&P Capital Budget$1.1 Billion - $1.3 Billion

Capital program focused on top U.S. resource plays

Accelerating activity in STACK and Delaware Basin

― Adding up to 7 operated rigs by year-end 2016

― Preparing for full-field development in 2017

Raised 2016 production targets

― Driven by strong base production results

― Retained Midland assets boost U.S. oil guidance

Positioned to stabilize and grow production by mid-2017

Strong Returns At Lower Prices

12

IRR

–B

TAX

no

G&

A

IRR

–A

TAX

w/G

&A

Other Properties

Assets in best U.S. resource plays

Inventory attractively positioned on cost curve

>10,000 risked locations in STACK and Delaware

Prepared to further accelerate activity

Incremental Well EconomicsAt $50 Oil & $2.50 Gas

Delaware BasinSTACK – MeramecEagle FordRockies

STACK – WoodfordBarnett (hz. refracs)

Note: The capital component of the IRR calculation includes the cost to drill and complete an incremental well. Seismic and G&G costs are excluded from this calculation.

30%+

30%to

15%

15%to

0%

20%+

20%to

10%

10%to

0%

STACKBest-In-Class Position

13

Canadian

Kingfisher

Blaine

Hunton

Woodford

Mis

siss

ipp

ian

Chester

Springer

Morrow

De

von

ian

Pe

nn

.

Osage

Atoka

Meramec

Custer

Caddo

Meramec – Best Results - Strong flow rates- Oil-weighted production- Low well costs

Woodford – Core Area - Repeatable development- High liquids production

STACK Play

World-class development opportunity

— 430,000 net surface acres

— Top targets: Meramec & Woodford

— Q2 net production: ≈91 MBOED

Acreage concentrated in core of play

— Deep inventory of low-risk projects

Accelerating activity in 2H 2016

— Up to 6 operated rigs by year end

— 2016 capital ≈$450 million

— Drilling focused in Meramec formation

Dewey

STACKA Multi-Decade Growth Opportunity

14

Largest leasehold position of any operator

Advantaged cost structure

Strong production growth

Significant resource

430,000

265,000203,000 171,000

130,00083,000

STACK AcreageNet Acres

Peers

Source: Company reports.

59

91

Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016

54%INCREASE

STACK ProductionMBOED

$5.88 $5.96

$4.42 $4.48

$3.78

Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016

36%IMPROVEMENT

STACK Field-Level Operating Costs(1)

$/BOE

R I S K E D L O C A T I ON S

STACK DRILLING INVENTORY

(1) Includes LOE and production taxes.

STACKMeramec Results Validate Core Position

15

OverPressuredOil

LiquidsRich

Dry GasPlay Windows NormalPressuredOil

Pressure Gradient (psi/ft.) >0.75 0.75 – 0.6 0.7 – 0.45 0.45 or less

Oil-Weighted Production30-Day IPs: ≈60% oil

EURs: ≈40% oil

Custer

Dewey

Canadian

Kingfisher

Blaine

Favorable characteristics ofcore oil window:

1. Attractive reservoir properties (thickness, permeability, porosity)

2. Strong flow rates due to high pressure gradients

3. Returns enhanced by oil-weighted production

4. Low well costs

Pony Express 27-1H30-Day IP: 2,100 BOED Born Free Staggered Pilot

30-Day IP: 2,200 BOED

Scheffler 1H-9X30-Day IP: 2,000 BOED

Blurton 1-7-6XH30-Day IP: 1,800 BOED

Otto 1H30-Day IP: 1,900 BOED

Maybel 1H-13X30-Day IP: 1,900 BOED

Meramec Core

Cows Face 0805-4AH30-Day IP: 2,200 BOED

Stiles 1407 2-4MH30-Day IP: 1,900 BOED

Pump House 7-well Pattern15-Day IP: 2,200 BOED

Wort 1-21H30-Day IP: 2,400 BOEDAlma 5-Well Pilot

30-Day IP: 1,400 BOED

Parker 1-33H30-Day IP: 2,000 BOED

Compton 1-2-35XH30-Day IP: 2,200 BOED

Blue Ox 3130 -4AH24-Hour IP: 4,000 BOED

Marmot 19-1HX24-Hour IP: 3,400 BOED

Meramec ResourceBest Emerging Development Play in North America

16

Meramec inventory conservatively risked (4 wells per surface section)

>10 spacing tests underway to drive risked location count higher

― First three Devon operated spacing pilots successful (Born Free, Alma and Pump House tests)

― Testing up to 8 wells per section across 1 interval in Meramec

― Staggered lateral pilots underway could further expand potential in Meramec

(1) Does not include upside potential from other target intervals within Meramec.

RISKED LOCATIONS

MERAMEC INVENTORYRisked

MER

AM

EC Pri

mar

ySe

con

dar

y

Upside

Meramec Inventory(1)

Up to 8 wells/section3 wells/section

Up to 6 wells/section1 well/section≈4,000 UNRISKED

Woodford ShaleA Top-Tier Liquids-Rich Development

17

Well productivity improved by >100%

— Recent wells averaging up to 1,900 BOED

— Results driven by enhanced completion design

5-section Hobson row development underway

— Completion activity begins in Q3 2016

— Higher oil rates expected

Future development to leverage long laterals

Deep inventory of lower risk projects

— 3,700 risked locations

— Acreage concentrated in liquids-rich window

Custer

Dewey

Canadian

Kingfisher

Blaine

Hobson Row30-Day IPs: Expected early 2017

Woodford Core

Golden RowAvg. 30-Day IP: 1,500 BOED

Chiles RowAvg. 30-Day IP: 1,500 BOED

Gordon RowAvg. 30-Day IP: 1,600 BOED

Haley PadAvg. 30-Day IP: 1,900 BOED

Delaware BasinA World-Class Oil Play

18

Industry leader in basin

— Net risked acres by formation: 585,000

— Q2 net production: 65 MBOED

Delivering top-tier well results

Deep inventory of low-risk oil projects

— >5,000 risked locations

Accelerating activity in 2H 2016

— Up to 3 operated rigs by year end

— 2016 capital ≈$250 million

EddyLea

Bone Spring

Wolfcamp

Leonard Shale

Delaware Sands

S L O P E

B A S I N

Delaware BasinIndustry Leading Well Productivity

19

Acreage position concentrated in basin of southeast New Mexico

Delivering the most productive wells in world-class field

90-day IP rates ≈20% higher than industry average

68

3828

14 10 7 6 6 6 5 4 4 2 2

Peers

Top 200 Delaware Basin WellsBased on 90-Day IP Rates, Number of Wells

Source: IHS/Devon. Data limited to wells with 90-day rates in southeast New Mexico (as of 6/30/16). Natural gas adjusted to BOE on a 20-to-1 basis.

Delaware BasinAchieving Significant Cost Savings

20

Record-low LOE costs reduced by ≈50%

Majority of cost savings are sustainable

— Improved electrical infrastructure

— Enhanced water handling infrastructure

Drilling and completion efficiencies accelerate

— 75% increase in feet drilled per day

— Completion costs reduced ≈60%

— Well costs as low as $5 million

$16.87

$14.80

$12.62$12.00

$10.76

$8.82

Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016

≈50%IMPROVEMENT

Delaware Basin Unit LOE$/BOE

C O S T R E D U C T I O N

Bone Spring Basin Completion CostsQ4 2014 to 1H 2016

Delaware BasinSignificant Resource Opportunity

21

Identified 5,200 risked locations (>16,000 unrisked)

— Bone Spring ≈65% of risked inventory

— Wolfcamp has massive upside potential

Appraisal work evaluating resource upside

— Evaluating tighter Bone Spring spacing

— Leonard Shale has staggered lateral potential

— Wolfcamp appraisal activity to increase in 2017

Results to optimize master development plan

Note: Graphic for illustrative purposes only and not necessarily representative across Devon’s entire acreage position.

Basin Slope

DEL

AW

AR

E SA

ND

S Madera

Lower Brushy

LEO

NA

RD A

B

C

BO

NE

SPR

ING

1st

2nd

(Upper &Lower)

3rd

WO

LFC

AM

P

X/Y

A, B, C & D

Risked Location Unrisked Location

1 Section 1 Section

Delaware Basin Master Development PlanTotal Reservoir Access Concept (TRAC)

22

A disciplined development approach

— Develop up to 9 intervals of stacked-pay

— Utilizes integrated surface facilities

— Leverages simultaneous operations

— Flexibility to add/defer development zones

Efficiencies gains to drive returns higher

TRAC project progressing

— Planning complete

— Permits submitted to BLM

— Initial drilling expected in 2H 2017

Premier Asset PortfolioPlatform For Value Creation

23

Asset Risked Opportunity Upside Potential

STACK 5,300 undrilled locations

>10 spacing tests underway

Delaware Basin

>5,000 undrilled locations

Spacing tests and appraisal work ongoing

Heavy Oil 1.4 billion barrels of risked resource

Technology to improve facility performance and increase future recovery rates

Eagle Ford ≈1,000 potential locations

Upper EF delineation and staggered lateral development of Lower EF

Barnett Shale

5,000-plus producing wells

Horizontal refrac testing underway

Rockies Oil >1,000 potential locations

Further de-risking of oil fairway

Heavy Oil

Rockies Oil

Barnett Shale

STACK

Delaware Basin

Eagle Ford

Devon EnergyA Leading North American E&P

24

Thank you.

25

Forward-Looking Statements

26

This presentation includes "forward-looking statements" as defined by 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, including the currently depressed commodity price environment; 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 exploration and development activities; risks related to our hedging activities; counterparty credit risks; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks relating to our indebtedness; our ability to successfully complete mergers, acquisitions and divestitures; the extent to which insurance covers any losses we may experience; our limited control over third parties who operate our oil and gas properties; midstream capacity constraints and potential interruptions in production; competition for leases, materials, people and capital; cyberattacks targeting our systems and infrastructure; 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.

NYSE: DVNdevonenergy.com

Appendix

Canadian Heavy Oil

28

Top-tier thermal oil position

— High reservoir quality: <2.5 SOR(1)

— Massive risked resource: 1.4 BBO

Significant leverage to higher prices

— Profitable at ≈$35 WTI

— $1 increase in WTI ≈$40 MM of annualized cash flow

Jackfish complex oil production up 36% YoY

65% decline in LOE from peak rates

(1) Current steam-to-oil ratio for Jackfish complex.

Eagle Ford

29

Top-tier acreage position

— 66,000 net acres focused in DeWitt Co.

— Q2 net production: 75 MBOED (77% liquids)

Expect ≈$300 million of free cash flow in 2016

— Best-in-class well productivity

— Low-cost asset: LOE $4 per BOE

Staggered lateral development to expand inventory

Completion activity to resume in 2H 2016

— Reduce DUCs to ≈50 by year end

2 0 1 6 e F R E E C A S H F L O W

MILLION

CR

ETA

CEO

US

AUSTIN CHALK

UPPER EAGLEFORD SHALE

LOWER EAGLEFORD SHALE

BUDA

DEL RIO

Staggered Lateral Development(9-well pattern testing up to 18 wells per section)

880’440’

Rockies

30

Johnson

Campbell

Converse

Weston

Niobrara

Natrona

Premier Powder River position

— ≈470,000 net surface acres

— Q2 net production: 21 MBOED (70% oil)

Development programs delivering strong results

— Targeting Parkman, Teapot and Turner formations

Barnett Shale

31

Future Focus Area

2015/2016 RefracWise

Parker

Johnson

Hood

Tarrant

Ft. Worth

Denton

Denton Significant gas optionality

— Net acres: 610,000

— Q2 net production: 167 MBOED (26% liquids)

Focused on optimizing base production

— Concluded refrac appraisal program in 2016

— Identified 1,000 horizontal refrac locations