NYSE: DVN
devonenergy.com
Investor Presentation
July 2018

2| Investor Presentation
Investor Contacts & Notices
Investor Relations Contacts
Scott Coody Chris Carr
VP, Investor Relations Supervisor, Investor Relations
405-552-4735 405-228-2496
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.

3| Investor Presentation
Investment Thesis
DELAWARE & STACK
POTENTIAL LOCATIONS>30,000
Multi-decade growth platform
Delaware & STACK focused
Rapidly expanding cash flow
Disciplined capital allocation
Significant financial strength

4| Investor Presentation
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
 $4 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 asset divestiture target
 Improve margins by aggressively lowering cost structure
 Leverage technology to optimize base production
Maximize cash flow
 Concentrated activity in economic core of Delaware & STACK

5| Investor Presentation
2017 2018e 2019e 2020e
2020 Vision: Driving Significant Cash Flow Growth
114
100
125
150
175
200
2017 2018e 2019e 2020e
$-
$6
$12
$18
2017 2018e 2019e 2020e
G&A
Op. Cost
Interest
Cost savings to expand margins
Upstream Per-Unit Cash Cost ($/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)
CUMULATIVE FREE CASH FLOW
2.5Billion
Note: 2017 costs are pro forma for revenue recognition accounting rules recently implemented.

6| Investor Presentation
 Resource quality & depth allows for high-
grading of portfolio
 Announced >$4 billion of divestitures to date
— Monetized entire EnLink ownership ($3.125 billion)
— Upstream asset sales: $1.1 billion
— No incremental cash taxes from transactions
 Currently marketing additional ~$1 billion of
non-core asset packages
 Expect to reach >$5 billion divestiture target by
year-end
Portfolio Simplification Strategy
DIVESTITURE
TARGET
Portfolio Simplification
>$5 Billion
STACK
Delaware Basin
Rockies
Heavy Oil
Barnett
Eagle Ford

7| Investor Presentation
 $4 billion share-repurchase program underway
— Represents ~20% of shares outstanding
— Authorization in place through 2019
— Expect to utilize accelerated share-repurchase
program(1)
 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
$4 Billion
share-repurchase program initiated
KEY INITIATIVES UNDERWAY
33% Increase
in quarterly cash dividend
$1 Billion
debt reduction plan
(1) Accelerated share repurchase program expected to begin in the third quarter.

8| Investor Presentation
Significant Financial Strength
 Investment-grade credit ratings
 Substantial liquidity: $1.4 billion of cash
 Net debt to EBITDA target: 1.0x to 1.5x
 Disciplined hedging program
— ~60% of 2018 oil & gas volumes protected
— Attractive WCS & Midland basis swaps
PROTECTING OUR ABILITY
TO EXECUTE
INVESTMENT-
GRADE
CREDIT RATINGS
Low
Leverage
Net debt to EBITDA
target: <1.5x
Excellent
Liquidity
Cash: $1.4B
Disciplined
Hedging
2018: ~60%

9| Investor Presentation
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
Capture
FULL VALUE
Improve
RETURNS

10| Investor Presentation
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 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 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

11| Investor Presentation
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

12| Investor Presentation
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

13| Investor Presentation
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 SWAPS
2018 2019
Midland oil swaps (MBbls/d) 23 28
Avg. differential to WTI ($/Bbl) ($1.02) ($0.46)
 Majority of U.S. oil production has access to gulf coast
markets (significant premium to WTI pricing)
 Delaware Basin positioned for attractive 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
— Pipeline access to premium gulf coast oil pricing
— 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)
Premium Pricing in the Delaware Basin

14| Investor Presentation
Delaware Basin – Franchise Asset
World-class oil opportunity
Multi-decade growth platform
Up to 15 target intervals
Accelerating development activity
Future Projects (Timing TBD)
Current Developments
Core Development Area
POTATO BASIN
TODD
THISTLE/GAUCHOCOTTON DRAW
RATTLESNAKE
Lusitano
Completing
Boomslang
Flowing Back
Seawolf
Completing
Medusa
Drilling
Anaconda
10 Wells Online
Potato Basin
Flagler
Cobra
Tomb Raider
Eddy
Loving
Lea
Fighting Okra
Drilling
Van Doo Dah
Snapping
North Thistle 34
2018 Spud

15| Investor Presentation
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 margins
LOE & Transportation Expense ($/BOE)
Positioned for high-return production growth
Production (MBOED)
2018
E&P
ACTIVITY
Delivered the top wells in Delaware Basin history
IP24: 12,868 BOED (82% oil)
Boundary Raider
6-7 Com 212H
Boundary Raider
6-7 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.

16| Investor Presentation
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 EFFECTIVE
ACRES
GROSS RISKED
LOCATIONS
GROSS UNRISKED
LOCATIONS
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

17| Investor Presentation
STACK – Franchise Asset
Canadian
KingfisherBlaine
Caddo
Coyote
Avg. 30-Day IP 4,400 BOED
Showboat
Flowing back
Horsefly
Completing
Bernhardt
Drilling
Best-in-class acreage position
>600k net acres by formation
Up to 4 target intervals per unit
Accelerating development activity
Geis
2018 Spud
Cascade
2018 Spud
Kraken
2018 Spud
ML Block
2018 Spud
Minnie Haha
Northwoods
Centaur
Future Projects (Timing TBD)
2018 Developments
Projects Online

18| Investor Presentation
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 Well
Online Q4 17
IP30: 4,700 BOED
Cottontail Parent Well
Online Q1 18
IP30: 4,400 BOEDCoyote 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
Showboat 2017 Avg.
~8 avg.
(up to 11 per day)
4
Showboat Cost Savings Frac Stages Per Day
(Showboat)

19| Investor Presentation
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
2018
E&P
ACTIVITY
MERAMEC ACTIVITY
Q4 2017 Q1 2018 2018e Exit Rate
High-returning production growth
Production (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

20| Investor Presentation
Investment Thesis
DELAWARE & STACK
POTENTIAL LOCATIONS>30,000
Multi-decade growth platform
Delaware & STACK focused
Rapidly expanding cash flow
Disciplined capital allocation
Significant financial strength

Thank you.
Thank you. For additional information see our
Q1 Operations Report

22| Investor Presentation
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 29-1XPH
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: 1,500 BOED/well
1st Niobrara Test
30-Day rates in Q2
2nd Niobrara Test
30-Day rates in 2H18
4 Parkman Wells
Avg. 30-Day IP: 1,200 BOED/well
Avg. Well cost: ~$5mm Teapot Appraisal Well
Avg. 30-Day IP: 1,700 BOED/well
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

23| Investor Presentation
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: $550 million(1)
Upstream
Revenues
WCS Hedges Production
Expenses
Capex Free Cash Flow
Heavy Oil 2018e Free Cash Flow
($MM)
$550($275)
($650)
$250$1,225
(1) Assumes $65 WTI & $25 differential for remainder of 2018.
Q1 PRODUCTION GROSS NET
Jackfish 1 (MBOD) 35.0 31.8
Jackfish 2 (MBOD) 41.7 40.3
Jackfish 3 (MBOD) 40.0 38.7
Lloydminster (MBOED) 21.8 20.3
Total Heavy Oil (MBOED) 138.5 131.1
SAGD Sweet Spot
1$
INCREASE IN WCS
PER BBL
FOR EVERY INCREMENTAL
40MM
$
ANNUALIZED CASH FLOW

24| Investor Presentation
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 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 WellsExpected Online in Q2
(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

25| Investor Presentation
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

26| Investor Presentation
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 E
D 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 N
O 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

27| Investor Presentation
Hedge Position
NATURAL GAS DERIVATIVES
SWAPS COLLARS BASIS SWAPS
PERIOD
VOLUME
(MMBTU/D)
WEIGHTED
AVG. PRICE
($/MMBTU)
VOLUME
(MMBTU/D)
WEIGHTED AVG.
FLOOR PRICE
($/MMBTU)
WEIGHTED AVG.
CEILING PRICE
($/MMBTU) INDEX
VOLUME
(MMBTU/D)
WTD. AVG.
DIFF to
HENRY HUB
($/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 ($1.58)
OIL DERIVATIVES
SWAPS COLLARS MIDLAND BASIS SWAPS WCS BASIS SWAPS
PERIOD VOLUME
WEIGHTED
AVG. PRICE VOLUME
WEIGHTED AVG.
FLOOR PRICE
WEIGHTED AVG.
CEILING PRICE VOLUME
WEIGHTED AVG.
DIFF. to WTI VOLUME
WEIGHTED AVG.
DIFF. to WTI
(MBPD) ($/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) — —