August Investor Presentation

Investor Presentation

August 2014

NYSE: DVN www.devonenergy.com Slide 2

Investor Notices

Safe Harbor

Some of the information provided in this presentation includes “forward-looking statements” as defined by the Securities and Exchange Commission. Words such as “forecasts," "projections," "estimates," "plans," "expectations," "targets," and other comparable terminology often identify forward-looking statements. Such statements concerning future performance are subject to a variety of risks and uncertainties that could cause Devon’s actual results to differ materially from the forward-looking statements contained herein, including as a result of the items described under "Risk Factors" in our most recent Form 10-K; and the items described under "Information Regarding Forward-Looking Estimates" in our Form 8-K filed August 6, 2014.

Cautionary Note to Investors

The United States Securities and Exchange Commission 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 and exploration target size. 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 from us at Devon Energy Corporation, Attn. Investor Relations, 333 West Sheridan, Oklahoma City, OK 73102-5015. 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.

Slide 3

Devon TodaySharpening The Focus

Devon’s Core & Emerging Assets

Core

EmergingHeavy Oil

Rockies Oil

Mississippian-WoodfordBarnett Shale

Permian Basin

Anadarko Basin

Eagle Ford

• Q2 2014 net production:620 MBOED(1)

• Oil & NGLs ≈60% of production by year-end

• Deep inventory of oil opportunities

— Top-tier Eagle Ford development

— High-quality Permian Basin position

— World-class heavy oil projects

— Upside potential in emerging plays

• Strong liquids-rich gas optionality

• EnLink ownership valued at ≈$8 billion

— Additional midstream value in Accessand Victoria Express pipelines

(1) Excludes assets sold or contracted to sell.

NYSE: DVN www.devonenergy.com

Second-Quarter 2014 Highlights


0

20

40

60

80

100

120

140

Q2 2013 Q2 2014

Net

Pro

duct

ion

(MBO

PD)

71

128

U.S. Oil Production Growth(1)

Pre-Tax Cash Margin Per Boe(2)

• Completed portfolio transformation announcedlast year

— Closed on sale of Canadian gas business for $2.8 billion

— Added 50,000 net acres to Cana-Woodford play

— Contracted to sell U.S. non-core assets for $2.3 billion

• Delivered U.S. oil production growth of 79% YoY(1)

— Achieved excellent well results in the Delaware Basin

— Eagle Ford contributed full quarter of production

• Expanded pre-tax cash margin by 40% YoY

• Completed several major projects

— Jackfish 3

— Access and Victoria Express pipelines

(2) Pre-tax cash margin is defined as unhedged upstream revenues and midstream operating profit less LOE and production &property taxes, G&A and net financing costs, divided by BOE production.

$21.82

$30.47

$0.00

$10.00

$20.00

$30.00

$40.00

Q2 2013 Q2 2014


2014 Production Growth Targets

2013 2014e

73

124 - 136

Total Oil Production(1)

(MBOPD)


2013 2014e

539

579 - 622

U.S. Oil Production(1)

(MBOPD)BOE Production(1)

(MBOED)

U.S. Canada

2013 2014e

152

198 - 216

6:1 20:1

Slide 6

Accelerating Drilling Activity

• Delaware Basin— Currently: 12 operated rigs

— Expected by year-end 2015: up to 20 operated rigs

• Cana-Woodford— Currently: 1 operated rig

— Expected by Q1 2015: ≈10 total rigs (op and non-op)

• Powder River Basin— Currently: 3 operated rigs

— Expected by year-end 2014: 4 operated rigs


Slide 7

Preliminary 2015 Outlook

2014e 2015e

Oil

NGLs

Natural Gas

Total Oil Production(1)

(MBOPD)Key Highlights

• On track to deliver 2015 oil productiongrowth >20%(1)

— Driven by Eagle Ford, Permian and Jackfish 3

• Increased activity levels expected at Cana

• High-margin production growth expected

to expand operating margins

• Growing cash flow to comfortably fund

capital demands

198 - 216


Slide 8

Permian BasinDelaware Basin Delivering Outstanding Results

Loving

Winkler

WardReeves

Lea

Eddy

Central

New Mexico

Texas

Delaware Sands80,000 net acres

Leonard Shale60,000 net acres

Bone Spring285,000 net acres

Wolfcamp>100,000 net acres

TEXAS

NEW MEXICO OKLAHOMA

• Activity focused on repeatable, high-impact Bone Spring

— Brought 22 wells online in Q2

— 30-day IP rate: 660 BOED

• Recent Delaware Sands success— Two high-rate wells in Q2

— 30-day IP rate: ≈1,000 BOED (70% oil)

• Operated rig count: 12

• 2014 plans: Drill ≈150 wells


Delaware BasinSignificant Resource Opportunity

Net Risked Acres

Risked Wells Per Section

Gross Risked Undrilled Locations

2014e Activity

(Wells Drilled)

80,000 4 700 20

60,000 5 700 1

285,000 5 3,500 ≈120

>100,000 n/a UnderEvaluation 3

20,000 4 >200 4

>500,000 >5,000 ≈150

Delaware SandsDelaware Sands

Leonard ShaleLeonard Shale

Bone SpringBone Spring

WolfcampWolfcamp

Other (Yeso & Strawn)Other (Yeso & Strawn)

Formation

Total

• Evaluating larger, more focused frac design in the Delaware Basin

— Testing >2,000 lbs of proppant per lateral foot

— Delivering more complex fracturing network closer

to the wellbore

— Potential to improve recovery of oil in place

• Pursuing tighter well spacing in Bone Spring intervals

— Testing downspacing pilots with up to 8 wells per section

— Evaluating staggered lateral development scheme to further tighten well spacing

• Potential to significantly increase risked inventory

Slide 10

Delaware Basin UpsideEnhanced Completions & Tighter Spacing

-

500

1,000

1,500

2,000

2,500

Current Design Pilot

Poun

ds P

er F

oot

Up to 1,200

>2,000

Proppant Per Lateral Foot

Permian BasinDelivering Significant Oil Production Growth

0

10

20

30

40

50

60

2009 2010 2011 2012 2013 2014e

Net

Pro

duct

ion

(MBO

PD)


Slide 12

Eagle Ford OverviewWorld-Class Oil Asset

• Located in best part of Eagle Ford

• Net acreage: 82,000— Working interest: 50%

— Net revenue interest: 38%

• Q2 2014 net production: 65 MBOED

• 2014e net production: 70 – 80 MBOED(1)

— 57% Oil

— 19% NGLs

— 24% Gas

• Risked resource: ≈400 MMBOE

• Drilling inventory: ≈1,200 — 80% resides in DeWitt County

• 2014 capital: $1.1 billion

Karnes

Devon Acreage

Gonzales

DeWitt

Lavaca

TEXAS

OKLAHOMA

(1) Represents Devon’s average estimated net production from March through December.

2014 Results to Date (MBOED)

Slide 13

Eagle Ford Production Results and Outlook

March 2014 Q2 2014 June 2014

73

65

49

Multi-Year Production Outlook (MBOED)

2014e 2015e

70 – 80 (1)

>100

(1) Represents Devon’s estimated net production from March through December.


Lower Eagle Ford UpsideLavaca County

Gonzales

DeWitt

Lavaca

Zebra Hunter 3H24-Hr IP: 2,250 BOED

Zebra Hunter 2H24-Hr IP: 1,511 BOED

Welhausen B 1H24-Hr IP: 1,446 BOED

Ronyn 1H24-Hr IP: 1,585 BOED

Devon’s Lavaca County

• Net acres: 32,000

• Significant upside potential

• Early results exceeding

expectations

Pavlicek Un 2H24-Hr IP: 1,319 BOED

Pavlicek Un 5H24-HR IP: 1,411 BOED

Lower Eagle Ford Activity

Industry

Devon Operated

Devon acreage

Upper Eagle Ford PotentialDeWitt and Lavaca Counties

Recent Industry Results

Devon Operated Location

Upper Eagle Ford Activity

Devon acreage

TEXAS

OKLAHOMA

Fojtik #1H24-Hr IP: 1,209 BOED

Sustr #1H24-Hr IP: 1,054 BOED

Medina 2HDrilling

Targac #1H24-Hr IP: 1,398 BOED

Gonzales

Lavaca

DeWitt

Net Pay (ft.)

05

10152025303540

• Encouraging industry results

• Pay thickest in DeWitt County

• Spud first well in Q3

• Additional test planned forlater this year

Welhausen A 2H24-Hr IP: 2,165 BOED

Martinsen 2H24-Hr IP: 1,360 BOED

Heavy Oil DevelopmentsJackfish & Pike

Slide 16

Ft. McMurray

Edmonton

Calgary

ALBERTABRITISHCOLUMBIA

Jackfish & Pike

Jackfish 1Jackfish 2

Jackfish 3

Access Pipeline

R8 R7 R6 R5 R4

T76

T75

T74

T73

Jackfish Acreage (100% WI)

Pike Acreage (50% WI)

Access Pipeline(50% Ownership)

Pike Project Area

6 Miles

SAGD Characteristics:

• Low F&D

• Low geologic risk

• Flat production profile

• Long reserve life >20 years

Each SAGD Project:

• 300 MMBO gross EUR

• Proved reserves 12/31/13: 552 MMBO

• Risked resource: 1.4 BBO

Slide 17

Jackfish Heavy Oil Developments Delivering Visible Oil Growth


Jackfish Complex:

• Q2 2014 production:

— Gross production: 60 MBOPD (52 MBOPD net)

• Delivering top-tier operating results at J1

• Plant start-up began on July 13th at J3

— Expect ramp-up to 35,000 MBOPD over next 18 months

• Provides visible multi-year oil growth beginning in 2015

• Begins era of free cash flow generation from Jackfish complex


Jackfish Heavy Oil DevelopmentsSignificant Free Cash Flow Generation

Assumptions: 1) $90 WTI oil and $4.50 Henry Hub natural gas 2) Bitumen realizations at 65% of WTI 3) Non-fuel operating costs of $12 per barrel 4) Free cash flow is after maintenance capital (average of ≈$300 million per year) and before income tax.

$0

$200

$400

$600

$800

$1,000

$1,200

2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e 2023e 2024e 2025e

$ in

mill

ions

Free Cash Flow Outlook

Slide 19

Anadarko BasinCana-Woodford Acquisition & Upside

• Q2 2014 net production: 64 MBOED (>40% liquids)

• Workover activity yielding excellent results

— Acid treatments performed on 200+ wells

— Avg. rates per well increased 1 to 2+ MMCFED

— Payback period for treatment <3 months

— Identified >100 additional future locations

• Improved completion design enhancing returns

• Acquired 50,000 net acres (closed June 2014)

— Directly overlaps existing leasehold

— Increases Cana position to ≈280,000 net acres

• Significant undrilled well inventory

— Total Cana risked locations: >5,000

Custer

Dewey

Blaine

Caddo

Canadian

Grady

Existing Devon acreage Acquired acreage

TEXAS

OKLAHOMA

Kingfisher


Cana-Woodford Completion Improvements

Old Design:

Sand: 3.5 MM lbs.

New Design:

Fluid: 130k Bbls.

10 Frac Stages

40 Perf Clusters

Sand: 6.0 MM lbs.

Fluid: 140k Bbls.

20 Frac Stages

80 Perf Clusters

Slide 21

Cana-Woodford Q2 ResultsLiquids-Rich Core

920

1,250

2014 Type Curve Q2 Results

30-Day IP Rates(MBOED)

1.4

1.7+


$8.0 $8.0


Cost Per Well ($MM)

EURs(MMBOE)

Slide 22

Rockies Oil Powder River Basin

• Net acreage: 150,000

• Stacked oil targets (Parkman, Turner, Frontier & others)

• Activity focused on repeatable Parkmanformation

— Two high-rate wells in Q2

— 30-day IP rate: 950 BOED (95% light oil)

• Risked drilling inventory: ≈1,000 (75% Parkman)

• Expect to add 4th rig by year-end

• Accelerating development activity in 2015

Current Focus Area

MONTANA

WYOMING

CAMPBELL

Devon acreage

Financial Strength & Flexibility

• Investment-grade ratings

— Fitch: BBB — Moody’s: Baa1— S&P: BBB+

• Cash balances at 6/30/14: $1.7 billion

• Future divestiture proceeds to reduce debt

• Pro forma net debt at 6/30/14(1): ≈$9 billion (>$7B excluding EnLink)

• Cash flow protected by hedges

Note: Includes a non-GAAP measure, see appendix for required disclosures.

(1) Includes proceeds from the announced sale of U.S. assets in June 2014 .


Innovative Midstream CombinationEnLink Midstream Overview

• Devon retains majority ownership— General partner (ENLC 70%)

— MLP (ENLK 52%)

• EnLink transaction highly accretive toshareholders

• Market value of Devon’s EnLink ownershipinterest: ≈$8 billion

• Improves capital efficiency, diversification,scale and growth of midstream business

Potential Drop Down AssetsAccess & Victoria Express Pipelines

ExpressTo U.S. Rockies

JACKFISH & PIKE

SturgeonTerminal

Access Pipeline

EDMONTON

HARDISTY

16” Diluent Line(Edmonton to Jackfish Area)

Oil Pipelines

24” Diluent Line(Sturgeon to Jackfish Area)

42” Blend Line(Jackfish Area to Sturgeon)

30” Blend Line(Sturgeon to Edmonton)

• Three ≈180 mile pipelines from Sturgeon Terminal to Devon’s thermal acreage

• ≈30 miles of dual pipeline from Sturgeon Terminal to Edmonton

• Capacity net to Devon:— Blended bitumen: 170 MBOPD

• Devon ownership: 50% — ≈$1B invested to date

• ≈56 mile crude oil pipeline from Eagle Ford core to Port of Victoria terminal

• ≈300,000 barrels of storage available

• Capacity:— 50 MBOPD start-up capacity (expandable)

• Devon ownership: 100%— ≈$70 MM invested to date

Victoria Express Pipeline

Port of Victoria

Karnes

Gonzales

DeWitt

Lavaca

Victoria

Jackson

Goliad

Wharton

Colorado

Calhoun

Refugio

Aransas

Matagorda

Gulf ofMexico

Devon Acreage


Why Own Devon?

• Disciplined focus on returns

• Deep inventory of oil opportunities

— Top-tier Eagle Ford development

— Strong Permian Basin position

— World-class heavy oil projects

— Upside potential in emerging oil plays

• Visible, low-risk oil production growth

• Strong balance sheet

Thank You

Appendix A

Strategy & Operations


Disciplined Capital Allocation

• Investing in E&P capital projects

— Accelerating development of high-margin oil projects

— Leveraging JV drilling carries in emerging plays

• High-grading asset portfolio

• Returning capital to shareholders

— Reduced net share count by ≈20% over past decade

— Increased average annual dividend by 23% since 2004

• Reducing debt

Top objective: Maximize shareholder returns by

optimizing cash flow per share, adjusted for debt

Slide 30

Non-Core Asset SalesSharpening The Focus

• Sold Canadian conventional business for C$3.125 billion

— US$2.8 billion (after foreign exchange)

— Accretive transaction: 7 times 2013 EBITDA

— Closed April 1, 2014

• Announced U.S. non-core assets sale for $2.3 billion (June 30, 2014)

— Accretive transaction: 7 times 2013 EBITDA

— Expected to close in the third quarter of 2014


Slide 31

2014 E&P Capital ProgramDelivering Strong Oil Growth

Permian Basin

28%

21%21%

11%

7%5%

2% 5%

2014 E&P Capital Budget$5.0 - 5.4 Billion (1)

Eagle FordHeavy Oil

Anadarko BasinBarnett Shale

Emerging OilOtherNon-Core Assets

E&P CapitalSpent ($B) (1)

% of Budget

Q1 2014 $1.2 23%

Q2 2014 $1.3 24%

1st Half Total $2.5 47%

(1) Excludes Eagle Ford and Cana-Woodford acquisitions.

• Capital concentrated in oil development plays

— ≈80% directed toward oil opportunities

— Spending focused on high-margin U.S. oil assets

— Long-term investment in Canadian oil growth

• Total capital spend to remain within cash flow

• JV carries minimize capital costs in emerging

oil plays (>$1 billion of drilling carries in 2014)


Permian Basin Overview2014 Focus Areas

• Net acreage: 1.3 million basin-wide

with stacked-pay potential

• Q2 2014 net production: 95 MBOED(≈60% oil)

• Deep inventory of low-risk projects

• Delivering highly economic & robustproduction growth

— Expect ≈20% oil growth in 2014

• Operated rig count: 23

• 2014 capital: $1.5 billion


NYSE: DVN

MidlandBasin

NorthwesternShelf

Central BasinPlatform

Ozona ArchDiabloPlatform

New

Mex

ico

Texa

s

Midland

Wolfberry

Conventional WolfcampShale

EasternShelf

TEXAS

NEW MEXICO OKLAHOMA

Bone Spring& Delaware

Slide 32

Permian Basin Midland-Wolfcamp Shale Oil Development

Reagan Irion

Crockett

TX

NM

Overview


• Low-risk, high-margin light oil play

• Delivering consistent economic results

• Thick pay with multiple intervals (up to 1,100’)

• Multi-year drilling inventory (≈750 locations)

• Efficiencies achieved through pad drilling

— Drilling time down to <15 days

— >50% improvement in drilling time since 2012

— Recent well drilled in only 4 days

Current Development Plans

• 2014 capital: ≈$200 million




Pike OverviewSAGD Oil Development

Pike leasehold

• 50% operated working interest

• Similar reservoir characteristicsto Jackfish

• Up to five 35 MBOPD SAGD development phases

Potential Pike 1 development

• Single plant pad

• Up to three 35 MBOPD projects

• Developed concurrently

• Regulatory approval expected by year-end

Jackfish

Pike acreage (50% WI) >15m (≈50ft) continuous bitumen pay

Pike Project Area

Pike 1Development Area

Access Pipeline (50% Ownership)


SAGD UpsideSolvents

Potential Benefits

• Increases production rates per well andplant production capacity

• Lower steam-oil ratios (15% - 50% decrease)

• Reduces plant emissions

Risks

• Access to solvent

• Solvent recovery

Status Update

• 1st pilot program: Initiated in 2013


Small-Scale SAGD

• Reusable SAGD facilities designed to exploit smaller accumulations

of bitumen (4 prospects identified)

— Targeted resource: 35-70 MMBO per project

— Peak production rates up to 10 MBOPD per project

— Less upfront capital commitments(30% of the capital required for traditional SAGD projects)

— Earlier return on capital(1st oil sale ≈25 months after sanctioning)


Iron River

Manatokan

End Lake

Lloydminster

LloydminsterOil Development

• Net acreage: ≈700,000

• Low-risk development

• Strong operating margins


• 2014 plans: ≈180 wells

B. C.

Alberta

Sask.

Lloydminster

Mississippian-Woodford TrendEmerging Oil Opportunity

Pawnee

Payne

Logan

Garfield Noble

Joint Venture Acreage Nemaha Ridge

• Net acres to DVN in JV area: ≈200,000

• Drilling activity focused on joint venture acreage

• Multiple oil-bearing intervals

• Q2 2014 net production rate: 18,000 BOED

• 2014 plans: Drill >250 wells

• Risked inventory: 1,000 locations

• Best wells to-date: IP’s >1,000 BOED

• Integration of 3D seismic will optimize results


OK

Barnett ShaleLiquids-Rich Gas Development


• Low average royalty burden: 18%

• Q2 2014 net production: 1.3 BCFED

— Liquids 27% of total production

— Total liquids growth 2% YoY

• Expected to generate >$1 billion of free

cash flow in 2014

• Liquids-rich drilling inventory: >2,500 locations

ParkerPalo Pinto

Hood

Tarrant

JohnsonErath

Hill

Jack

Denton

Wise Denton

Ft. Worth

DRY GAS

LIQUIDS-RICH

TEXAS

OKLAHOMA

www.devonenergy.com Slide 39


Granite WashOil & Liquids-Rich Gas Development


• Legacy land position held by production

• Low average royalty burden: 19%


OKLAHOMAOklahoma City

TEXAS

Granite Wash

Hemphill

Wheeler


Mississippian

Rockies OilUtica Ohio

Michigan

Joint Venture TransactionsOil & Liquids Exploration

Sinopec Joint Venture

• $2.5 billion transaction ($900 million cash and $1.6 billion drilling carry)

• Drilling carry balance: $500 million (6/30/14)

• Sinopec receives 33% of Devon’s interest

• Net acreage in joint venture: >1 million

• Devon serves as operator

Sumitomo Joint Venture

• $1.4 billion transaction ($400 million cash and $1.0 billion drilling carry)

• Drilling carry balance: $350 million (6/30/14)

• Sumitomo receives 30% of Devon’s interest

• Net acreage in joint venture: >600,000

• Devon serves as operator

Sinopec joint venture assets

Cline Shale & Wolfcamp Shale

Sumitomo joint venture assets

Slide 42

Attractively Hedged

Oil Hedges

• ≈65% of “go-forward” oil production hedged (Q3-Q4 2014)

— 75 MBOPD swapped at $94 per BBL

— 65 MBOPD collared at $89 - $100 per BBL

— 30 MBOPD WCS basis swapped at $18 off WTI (Q3 2014 only)

• 138 MBOPD of oil production hedged in 2015

— 107 MBOPD swapped at $91 per BBL

— 31 MBOPD collared at $90 - $98 per BBL

Natural Gas Hedges

• ≈80% of “go-forward” gas production hedged (Q3-Q4 2014)

— 800 MMCFD swapped at $4.42 per MCF

— 460 MMCFD collared at $4.03 - $4.51 per MCF

Note: The pricing points referenced above are weighted average prices.


EnLink Midstream BusinessOwnership Structure

Devon Energy Corporation(NYSE: DVN)

General PartnerEnLink Midstream LLC (ENLC)

Master Limited PartnershipEnLink Midstream Partners LP (ENLK)

Devon Midstream Holdings, LP(“Devon Holdings”)

GPPublic

Unitholders

MLPPublic

Unitholders

≈30%

≈41% LP

≈52% LP (120 MM units)

General Partner,≈7% LP andIDRs

50% LP50% LP

100% Incentive Distribution Rights (IDRs)

Dist./Qtr Splits

≤ $0.2500 2% / 98%

≤ $0.3125 15% / 85%

≤ $0.3750 25% / 75%

> $0.3750 50% / 50%

≈70% (115 MM units)

Appendix B

Supply & Demand

Canadian OilSupply & System Export Capacity

Source: Canadian Association of Petroleum Producers and Devon estimates

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

2011 2012 2013 2014e 2015e 2016e 2017e 2018e

MM

BOD

Oil Supply Current Export & Local Demand CapacityRail Alberta Clipper - Flanagan SouthTrans Mountain Expansion Keystone XLEnergy East Northern GatewayEnbridge Line 3 Replacement


Canadian Oil Pipeline Capacity Additions

Flanagan South: Flanagan to USGC• Capacity: staged increments up to 0.6 MMBOPD• Estimated in service: Q4 2014

Alberta Clipper/Southern Access: Hardisty to Flanagan• Capacity: staged increments up to 0.8 MMBOPD• Estimated combined in service: Q3 2015

Enbridge Line 9B Reversal: Sarnia to Montreal• Capacity: 0.3 MMBOPD• Estimated in service: Q4 2014

Keystone XL: Hardisty to USGC• Capacity: 0.8 MMBOPD• Estimated in service: mid-2016

Trans Mountain: Edmonton to Vancouver• Capacity: 0.6 MMBOPD • Estimated in service: 2018

Enbridge Line 3 Replacement : Hardisty to Superior• Capacity: 0.8 MMBOPD• Estimated in service: Q3 2017

Energy East: Hardisty to St. John• Capacity: 1.1 MMBOPD• Estimated in service: 2018

Northern Gateway: Edmonton to Kitimat• Capacity: 0.5 MMBOPD• Estimated in service: 2018

U.S. Gulf Coast (USGC)

Cushing

Hardisty

Edmonton

Flanagan

Kitimat

St. JohnVancouver

Superior

Sarnia

Montreal

Canadian OilRail Transport Fees

Potential Rail Costs $ Per BBL

Trucking & Loading ≈$5.00

Rail Car Rental ≈$2.50

Transport Fee Variable (Mileage Based)

Offloading Fee ≈$2.00

Oil Sands

West Coast Refining

Gulf Coast Refining

East Coast Refining

www.devonenergy.com Slide 48

Heavy OilRefinery Expansions

Operator Location In-Service Date

Capacity Increase (BOPD)

Husky Lima, Ohio 2016 40,000

Northwest Upgrading Edmonton, Alberta 2017 80,000

Total Capacity Increase 120,000

NYSE: DVN


U.S. Natural Gas Demand Growth By Sector 2013-2018

Source: Wood Mackenzie, EIA, PIRA, Bloomberg, FERC, US DOE, and Devon estimates

BCFD

72

2.5

3.7

2.1

0.56.5

87

60

65

70

75

80

85

90

2013Baseline

Industrial Res/Com Electric Mex/CanExports

Other LNGExports

2018 Total

-0.5


U.S. Natural Gas Cumulative Coal Retirement Demand Forecast

Source: Wood Mackenzie, Bernstein, PIRA, and Devon estimates

BCFD

-0.20.0

1.6

2.9

3.7

-2

0

2

4

6

2014F 2015F 2016F 2017F 2018F

Renewable Generation Coal Retirements Fuel Switching Net Effect


U.S. Natural GasAnnual Industrial Demand

Source: Devon estimates

20.020.8

21.522.1

22.5 22.9

10

13

16

19

22

25

2008 2009 2010 2011 2012 2013A 2014F 2015F 2016F 2017F 2018F

BCFD

Base Y/Y Growth


U.S. Natural Gas LNG Projects

Facility Developer(s) LocationTotal Capacity FTA/Non-FTA

(BCFD)

Non-FTA Capacity(BCFD)

Start-Up Date DOE Approval Non-FTA

Approval FERC

Final Investment

Decision (FID)

Sabine Pass (phase 1 & 2)

Cheniere Cameron, LA 2.2 2.2 4Q 2015 Approved Approved July 2012

Freeport LNG(phase 1)

Freeport LNG Freeport, TX 1.4 1.4 4Q 2017 Approved Filed --

Lake Charles Lake Charles Exports/Trunkline

Lake Charles, LA

2.0 2.0 2Q 2019 Approved Pre-Filed --

Cove Point Dominion Lusby, MD 1.0 0.8 2017 Approved Filed --

Freeport LNG(phase 2)

Freeport LNG Freeport, TX 1.4 0.4 4Q 2018 Approved Pre-Filed `

Cameron Sempra Energy Hackberry, LA 1.7 1.7 2017 Approved Approved --

Jordan Cove Fort Chicago Coos Bay, OR 1.2 0.8 2017 Approved Filed --

Oregon LNG LNG Development Astoria, OR 1.3 1.3 4Q 2017 Pending Filed --

Corpus Christi Cheniere Corpus Christi, TX

2.1 2.1 2020 Pending Filed --

Excelerate LNG Excelerate Lavaca Bay, TX

1.4 1.4 2020 Pending Pre-Filed --

Gulf Coast LNG Freeport LNG Brownsville, TX

2.8 2.8 2020 Pending -- --

Others 16 – 18 15 – 17 2017 - 2026 -- -- --

TOTAL U.S. 34.5 – 36.5 31.9 – 33.9


Canadian Natural Gas LNG Projects

Facility Developer(s) Location Capacity (BCFD)

Start-UpDate

NEB Export License

Douglas Channel Energy LNG Partners, HaislaNation

Floating LNG,Kitimat, B.C.

0.1 2017 Approved

Kitimat LNG Apache, Chevron Kitimat, B.C. 0.7 2018 Approved

LNG Canada Shell, Mitsubishi, KOGAS, PetroChina

Kitimat, B.C. 1.6 2019 Approved

Pacific Northwest LNG Petronas, Japex Prince Rupert, B.C.(Lelu Island)

2.0 2019 Approved

Prince Rupert LNG BG Group Prince Rupert, B.C.(Ridley Island)

1.8 2020 Approved

WCC LNG Ltd Imperial/Exxon Grassy Point (Prince Rupert B.C.) 1.3 2022 Approved

Woodfibre LNG Pacific Oil & Gas Group Squamish, B.C. 0.3 2017 Approved

Goldboro LNG Pieridae Energy Nova Scotia 1.3 2019 Filed

Triton LNG Altagas, Idemitsu Kosan (Japan)

Floating LNG, Kitimat or Prince Rupert, B.C.

0.3 2017 Filed

Aurora LNG CNOOC-Nexen Grassy Point (Prince Rupert B.C.) 3.2 2022 Filed

TOTAL CANADA 12.6

Natural Gas Liquids Supply

Page 54

*Q4 Normal Butane volumes reflect excess refinery usage reported as negative production, which impacts reported total.** Product total includes imports and refinery surplus volumes

Source: EIA, IHS_CMAI, Wells Fargo, Morgan Stanley, Bentek, and Devon estimates

0.0

0.5

1.0

1.5

2.0

Jan-10 Jan-11 Jan-12 Jan-13 Jan-14

MM

BPD

Estimated Ethane Rejection

Ethane Extraction Ethane Rejection

Q1 Q2 Q3 Q4* Q1 Q2A+F Q3F Q4F*

2013 2014F 2014(A+F) 2014F

Ethane after rejection 0.9 0.9 1.0 1.0 1.0 1.2 1.2 1.2 1.2 1.2NG Propane 0.9 0.9 0.9 1.0 1.0 1.0 1.0 1.1 1.0 1.0Refinery Propane 0.5 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6Isobutane 0.2 0.2 0.3 0.2 0.2 0.2 0.3 0.3 0.3 0.3Normal Butane* 0.2 0.5 0.4 0.1 0.2 0.5 0.5 0.2 0.4 0.4Natural Gasoline 0.3 0.4 0.4 0.3 0.3 0.4 0.5 0.5 0.4 0.5Total US NGL Supply** 3.2 3.5 3.5 3.2 3.4 3.9 4.1 3.9 3.8 4.0

0.00.51.01.52.02.53.03.54.04.5

U.S. NGL Supply by Component (MMBPD)

U.S. Natural Gas Liquids Demand

Source: EIA, Hodson Report, IHS_CMAI, Wells Fargo, Bentek, and Devon forecasts

3.6

3.03.2

3.93.8

3.53.8

4.1

3.3

3.6

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Q1 Q2 Q3 Q4 Q1 Q2 A+F Q3F Q4F 2013YTD*

2014YTD*

2013 2014F

MM

BPD

Petchem Other End Use Refinery/Blender Exports

*2013 YTD – Actual data through June ’13 and 2014 YTD actual through April plus forecast for May through June

Natural Gas LiquidsDemand – LPG exports

Page 56

0

200

400

600

800

1,000

1,200

2007 2008 2009 2010 2011 2012 2013 2014 2015

MBP

D

Actual LPG Exports Current LPG Capacity Planned LPG Capacity

Source: EIA, Argus, Platts, Waterborne Energy, Bentek and Wells Fargo

Natural Gas LiquidsCracking Rates & Inventories

Page 57Source: EIA and Hodson Report

5

10

15

20

25

30

35

40

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

MM

Bbl

U.S. Ethane Inventories5 Yr. High/Low 2014 2013 5 Yr. AVG.

0.3

0.5

0.7

0.9

1.1

1.3


MM

Bbl

U.S. Ethane Cracking Rates

5 Yr. High/Low 2014 2013 5 Yr Avg.

1020304050607080


MM

Bbl

U.S. Propane Inventories5 yr High/Low 2014 2013 5 Yr. AVG.

0.0

0.1

0.2

0.3

0.4

0.5

0.6


MM

Bbl

U.S Propane Cracking Rates

5 Yr. High/Low 2014 2013 5 Yr Avg.

Appendix C

Key Modeling Statistics


Key Modeling StatisticsBased on 2014 Drilling Program

0%

15%

30%

45%

60%

75%

Yr 1 Yr 2 Yr 3 Yr 4 Yr 5

Decline Rates(1st month to 13th month)

Bone Spring (Permian Basin)

Working interest / royalty: 76% / 21%

Drill & complete costs: $6 MM

30-day IP rate: 550 - 600 BOED

EUR: 400 – 500 MBOE

Oil / NGLs as % of production: 65% / 20%

0%

15%

30%

45%

60%

75%



Midland-Wolfcamp Shale (Permian Basin)



30-day IP rate: 400 BOED

EUR: 450 MBOE




0%

15%

30%

45%

60%

75%



Eagle Ford (DeWitt County)


Drill & complete costs: $9 - $10 MM

30-day IP rate: 1,200 – 1,400 BOED

EUR: 850 – 950 MBOE


0%

15%

30%

45%

60%

75%

90%



Eagle Ford (Lavaca County)



30-day IP rate: 1,000 – 1,100 BOED

EUR: 400 – 500 MBOE




0%

15%

30%

45%

60%

75%



Mississippian Lime (Mississippian-Woodford Trend)




EUR: 300 – 400 MBOE


0%

15%

30%

45%

60%

75%



Woodford Oil Shale (Mississippian-Woodford Trend)




EUR: 300 – 400 MBOE




0%

15%

30%

45%

60%

75%



Cana-Woodford Shale



30-day IP rate: 920 MBOE

EUR: 1.4 MMBOE


0%

15%

30%

45%

60%

75%



Barnett Shale


Drill & complete costs: $3 - $3.5 MM

30-day IP rate: 3 MMCFED

EUR: 4 BCFE


Discussion of Risk Factors

Information provided in this presentation includes “forward-looking statements” as defined by the Securities and Exchange Commission. Forward-lookingstatements are identified in this presentation as “forecasts, projections, estimates, plans, expectations, targets, opportunities, potential, outlook, etc.” andare subject to a variety of risk factors. A discussion of risk factors that could cause Devon’s actual results to differ materially from the forward-lookingstatements contained herein are outlined below.

The forward-looking statements provided in this presentation are based on management’s examination of historical operating trends, the information whichwas used to prepare reserve reports and other data in Devon’s possession or available from third parties. Devon cautions that its future oil, natural gas andNGL production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development, productionand sale of oil, gas and NGLs. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmentalrisks, drilling risks, political changes; changes in laws or regulations, the uncertainty inherent in estimating future oil and gas production or reserves, andother risks identified in our Form 10-K and our other filings with the SEC.

Specific Assumptions and Risks Related to Price and Production Estimates Prices for oil, natural gas and NGLs are determined primarily by prevailingmarket conditions. Market conditions for these products are influenced by regional and worldwide economic conditions, weather and other local marketconditions. These factors are beyond Devon’s control and are difficult to predict. In addition to volatility in general, Devon’s oil, gas and NGL prices may varyconsiderably due to differences between regional markets, differing quality of oil produced (i.e., sweet crude versus heavy or sour crude), differing Btucontents of gas produced, transportation availability and costs and demand for the various products derived from oil, natural gas and NGLs. Substantially allof Devon’s revenues are attributable to sales, processing and transportation of these three commodities. Consequently, Devon’s financial results andresources are highly influenced by price volatility.

Estimates for Devon’s future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil, gas and NGLs willcontinue at levels that allow for profitable production of these products. There can be no assurance of such stability. Most of Devon’s Canadian production ofoil, natural gas and NGLs is subject to government royalties that fluctuate with prices. Thus, price fluctuations can affect reported production. Estimates forDevon’s future processing and transport of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil, gas and NGLs willcontinue at levels that allow for profitable processing and transport of these products. There can be no assurance of such stability.

The production, transportation, processing and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption due totransportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerousother factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions forDevon’s oil, natural gas and NGLs will be substantially similar to those of 2013, unless otherwise noted.

Assumptions and Risks Related to Capital Expenditures Estimates Devon’s capital expenditures budget is based on an expected range of future oil, naturalgas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from Devon’s price expectations forits future production, some projects may be accelerated or deferred and, consequently, may increase or decrease capital expenditures. In addition, if theactual material or labor costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially fromDevon’s estimates.

Assumptions and Risks Related to Marketing and Midstream Estimates Devon cautions that its future marketing and midstream revenues and expenses aresubject to all of the risks and uncertainties normally incident to the marketing and midstream business. These risks include, but are not limited to, pricevolatility, environmental risks, mechanical failures, regulatory changes, the uncertainty inherent in estimating future processing volumes and pipelinethroughput, cost of goods and services and other risks.

Non-GAAP ReconciliationNet Debt

Slide 64

Devon defines net debt as debt less cash and cash equivalents. Devon believes that netting these sources of cash against debt provides a clearer picture of the future demands on cash to repay debt.

Note: The United States Securities and Exchange Commission has adopted disclosure requirements for public companies such as Devon concerning Non-GAAP financial measures. (GAAP refers to generally accepted accounting principles). The company must reconcile the Non-GAAP financial measure to related GAAP information.

RECONCILIATION TO GAAP INFORMATION (in billions)

June 30, 2014

Total debt (GAAP) $12.4

Adjustments:

Cash and cash equivalents 1.7

Net debt (Non-GAAP) $10.7

Net debt associated with EnLink 1.7

Devon stand-alone net debt (Non-GAAP) $9.0

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