Devon Energy July Presentation

Investor Presentation

July 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 May 7, 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

• Proved reserves: 2.6 billion BOE(1)

• Q1 2014 net production:563 MBOED(1)

— Oil & NGLs >50% of production mix

— Expect multi-year oil growth >20%

• Deep inventory of oil opportunities

— Top-tier Eagle Ford development

— Strong Permian Basin position

— World-class SAGD oil projects

— Upside potential in emerging plays

• Midstream business valued at >$8 billion

• Enterprise Value: ≈$45 billion

(1) Excludes non-core assets identified for monetization.

First-Quarter 2014 Highlights

(1) Excludes non-core assets identified for monetization.

0

25

50

75

100

Q1 2013 Q1 2014

Net

Pro

duct

ion

(MBO

PD)

62.7

97.5

U.S. Oil Production Growth(1)

Unhedged Operating Margin Per Boe(2)

• Delivered U.S. oil production growth of 56% YoY(1)

— Achieved excellent well results in the Delaware Basin

— Eagle Ford contributed 1 month of production to Q1

• Expanded operating margins by 54% YoY

• Increased risked drilling inventory by >5,000 locations

— Driven by Delaware Basin, Eagle Ford, Cana & Rockies

• Closed Eagle Ford and EnLink Midstream transactions

• Monetized Canadian conventional gas business

• Added 50,000 net acres to core Cana-Woodford play (Announced May 2014)

(2) Unhedged operating margin is a non-GAAP measure. Represented above is unhedged upstream revenues andmidstream operating profit less LOE and production & property taxes, divided by BOE production.

$20.87

$32.23

$0.00

$10.00

$20.00

$30.00

$40.00

Q1 2013 Q1 2014

Slide 5

Non-Core Asset SalesSharpening The Focus

• Sold Canadian conventional business for C$3.125 billion

— US$2.7 billion after tax (≈5% effective tax rate after repatriation)

— Accretive transaction: 7 times 2013 EBITDA

— Closed April 1, 2014

• Announced U.S. non-core assets sale for $2.3 billion

— $1.8 billion after tax

— Accretive transaction: 7 times 2013 EBITDA

— Expected to close in the third quarter of 2014

NYSE: DVN www.devonenergy.com

Slide 6

Permian Basin

28%

21%21%

7%

5%

11%

2% 5%

Note: Capital figures exclude capitalized G&A and interest, midstream and other corporate capital. For 2014, this represents approximately $1.4 billion. Property acquisitions are also excluded.

Key Highlights

• 2014 E&P capital:

— “Go-forward” assets: $4.8 - $5.2 billion

— $260 million attributable to non-core properties

• Capital concentrated in oil development plays

— “Go-forward” assets delivering >70% growth in U.S. oil production

— Long-term investment in Canadian oil growth

— “Go-forward” assets growing top-line production ≈10%

• Total capital spend to remain within cash flow

• JV carries minimize capital costs in emerging

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

2014 Capital Budget$5.0 - 5.4 Billion

Eagle FordHeavy Oil

Anadarko Basin

Barnett ShaleEmerging OilOtherNon-Core Assets

2014 E&P Capital ProgramDelivering Strong Oil Growth


2014 Production Growth Targets

2013 2014e

73

124 - 136

Total Oil Production(1)

(MBOPD)

(1) Estimates exclude assets identified for monetization.

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 8

Preliminary 2015 Outlook

2014e 2015e

Oil

NGLs

Natural Gas

(1) Estimates exclude assets identified for monetization.

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

Devon Oil ProductionSignificant Oil Producer in North America

0

50

100

150

200

250

EOG CHK CLR WLL PXD CXO NFX OAS XEC SD MEG ECA LPI RRC FANG

Q4 2013 Oil Production Pro Forma New Devon(1) vs. N.A. Onshore Pure-Play Peers

Slide 9NYSE: DVN www.devonenergy.com

(1) Pro Forma for Eagle Ford assets and excluding assets identified for monetization.

MBO

PD

CanadaU.S.


Permian Basin Overview2014 Focus Areas

• Net acreage: 1.3 million basin-wide

with stacked-pay potential

• Q1 2014 net production: 91 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

• 2014 plans: Drill ≈350 wells

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 10

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

Delaware BasinSignificant Resource Opportunity

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

• Two recent high-rate Delaware Sandswells

— 30-day IP rate: >1,000 BOED (≈90% oil)

• Initial Wolfcamp well in Ward Countysuccessful

— 30-day IP rate: 950 BOED (85% oil)


Delaware BasinSignificant Resource Opportunity

Net AcresProducing

Wells

2014e Activity

(Wells Drilled)

Risked UndrilledLocations

80,000 78 20 700

60,000 40 1 700

285,000 233 ≈120 3,500

>100,000 12 3 UnderEvaluation

20,000 2 4 >200

>500,000 365 ≈150 >5,000

Delaware SandsDelaware Sands

Leonard ShaleLeonard Shale

Bone SpringBone Spring

WolfcampWolfcamp

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

Formation

Total

Slide 14

Eagle Ford OverviewWorld-Class Oil Asset

• Located in best part of Eagle Ford

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

— Net revenue interest: 38%

• Acquisition closed on February 28th

• Current daily rate: 64 MBOED

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

— 57% Oil

— 19% NGLs

— 24% Gas

• Risked resource: ≈400 MMBOE

• Drilling inventory: ≈1,200 locations

• 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.


Eagle FordLow-Risk Development Inventory

DeWitt

ExistingProducer

UndrilledInfill

DevonAcreage

TEXAS

OKLAHOMA

• Derisked and ready for development

• Risked resource: ≈400 MMBOE

— 80% resides in DeWitt County

• Risked undrilled locations: ≈1,200

2014e Production Outlook (MBOED)

Slide 16

Eagle Ford Production Outlook

March 2014 May 2014 Q2 2014e 2H 2014e

65 – 70

80 – 85

64

49

Multi-Year Production Outlook (MBOED)

2014e 2015e

70 – 80 (1)

>100

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


Eagle Ford UpsideRecent Industry Success - Lavaca County

Gonzales

DeWitt

Lavaca

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

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

Welhausen A2H24-Hr IP: 2,165 BOED

Welhausen B1H24-Hr IP: 1,536 BOED

Lower Eagle Ford

Upper Eagle Ford

Devon’s Lavaca County

• Net acres: 32,000

• <10% of acquisition valueassigned

• Significant upside potential

• 2014 plans: Drill >30 wells

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

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

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

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

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

Recent Industry Drilling

SAGD Oil DevelopmentsJackfish & Pike

Slide 18

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

• High reservoir quality

• Flat production profile

• Long reserve life >20 years

• Q1 2014 production from Jackfish projects

— Gross production: 62 MBOPD (9% increase YOY)

— Net production: 52 MBOPD

Each SAGD Project:

• 300 MMBO gross EUR

• Proved reserves 12/31/13: 552 MMBO

• Risked resource: 1.4 BBO


Jackfish SAGD DevelopmentsVisible Oil Growth

0

25

50

75

100

2014e 2015e 2016e

Net

Pro

duct

ion

(MBO

PD)

47 - 52

62 - 67

77 - 82

Oil Production Growth Outlook Jackfish 1• Facility running above name-plate capacity

— Q1 2014 production: 37 MBOPD gross (29 MBOPD net)

• Delivering top-tier operating results

• Solvent and gas co-injection pilots underway

Jackfish 2

• Q1 2014 production increased 8% YoY— Q1 2014 production: 25 MBOPD gross (23 MBOPD net)

• New well pad ramping up

Jackfish 3

• Commissioning underway

• Plant start-up expected in Q3 2014


Jackfish SAGD 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 21

Mississippian-Woodford & RockiesEmerging Oil Opportunities


OKLAHOMA

Mississippian-WoodfordNet Acres: ≈200,000 (Inside JV)Q1 Net Production: 19,000 BOEDOperated rigs: 82014 Capital: ≈$300 million

Rockies OilNet Acres: 150,000 (Powder River Basin) Q1 Net Production: 20,000 BOEDOperated rigs: 32014 Capital: ≈$300 million

WYOMING

Mississippian-Woodford

• Multiple oil-bearing intervals• Q1 2014 net production increased 35% sequentially • Drilling activity focused on JV acreage• Best wells to-date: IP’s >1,000 BOED• Integration of 3D seismic will optimize results

Rockies Oil

• Focused in Powder River Basin (Best wells IP’s >1 MBOED)

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

• Risked inventory: ≈1,000 locations and growing

0

10

20

30

40

Q1-13 Q2-13 Q3-13 Q4-13 Q1-14

Net

Pro

duct

ion

(MBO

ED)

Emerging Oil Production Growth


Liquids-Rich GasBarnett Shale & Anadarko Basin

Net risked resource: >25 TCFE

Risked locations: >10,000

• Net acreage: >900,000

• Low average royalty burden: <20%

• Q1 2014 net production: 1.8 BCFED (32% liquids)

• Significant free cash flow (>$1 billion in 2014)


• 2014 capital: $600 million


Basin

Wheeler

Hemphill

Canadian

Blaine

Caddo

Johnson

Tarrant

DentonWise

Parker Ft. Worth

Denton

Oklahoma City

Barnett ShaleNet Acres: >600,000 Q1 Net Production: 1.3 BCFEDOperated Rigs: 2

Anadarko Basin(Cana & Granite Wash)

Net Acres: ≈350,000 Q1 Net Production: 512 MMCFEDOperated Rigs: 2

Slide 23

Anadarko Basin Resource CaptureCana-Woodford Acquisition & Upside

• Acquired 50,000 net acres (announced May 2014)

— Directly overlaps existing leasehold

— Increases Cana position to ≈300,000 net acres

• Improved completion design enhancing returns

— Utilizing more proppant per well (70% higher)

— Increased frac stages (up to 20 stages)

• Workover activity yielding excellent results

— Chemical treatments performed on 70 wells

— Avg. rates per well increased from 1 to 3+ MMCFED

— Payback period for treatment <3 months

— Identified >200 additional future locations

• Significant undrilled well inventory

— Total Cana risked locations: >5,000

Custer

Dewey

Blaine

Caddo

Canadian

Grady

Cana Plant

Existing Devon acreage Acquired acreage

TEXAS

OKLAHOMA

Kingfisher


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

Financial Strength & Flexibility

• Investment-grade ratings

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

• Cash balances at 3/31/14: $2.0 billion

• Pro forma net debt at 3/31/14(1): $11 billion (≈$9B excluding EnLink)

• Future divestiture proceeds to reduce debt

• Cash flow protected by hedges

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

(1) Includes net proceeds from sale of Canadian conventional assets in April 2014 (US$2.7 billion).


Innovative Midstream CombinationEnLink Midstream Overview

AUSTIN CHALK

EAGLEFORD

PERMIANBASIN

CANA-WOODFORD

ARKOMA-WOODFORD

BARNETTSHALE

HAYNESVILLE & COTTON

VALLEY

UTICA

MARCELLUS

LA

TX

OK

OH

WV

PA

Gathering SystemProcessing PlantFractionation FacilityNorth Texas SystemsLIG SystemPNGL SystemCajun‐Sibon Expansion

Howard EnergyOhio River Valley PipelineStorageCrude & Brine Truck StationBrine Disposal WellBarge TerminalRail Terminal

• Devon retains majority ownership

— General partner (ENLC 70%)

— MLP (ENLK 52%)

• EnLink transaction highly accretiveto shareholders

• Market value of Devon’s EnLinkownership interest: >$8 billion

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

Slide 27

EDMONTON

HARDISTY

Express P/LTo U.S. Rockies

16” Diluent Line (Edmonton to Jackfish Area)

Oil Pipelines

JACKFISH & PIKE

Sturgeon Terminal

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 SturgeonTerminal to Devon’s thermal acreage

• ≈30 miles of dual pipeline from SturgeonTerminal to Edmonton

• Devon ownership: 50%

— ≈$1B invested to date

• Capacity net to Devon (after 2014 expansion):— Blended bitumen: 170 MBOPD

— Diluent: 95 MBPD

• Expandable with additional investment

• Access to Edmonton refining and rail, west coast waterborne and U.S. markets

• Flexibility enhances economics

Potential Drop Down AssetAccess Pipeline (SAGD Oil Midstream)


Why Own Devon?

• Disciplined focus on returns

• Deep inventory of oil opportunities

— Top-tier Eagle Ford development

— Strong Permian Basin position

— World-class SAGD oil projects

— Upside potential in emerging oil plays

• Visible, low-risk oil production growth

• Strong balance sheet

• Active portfolio management

Thank You

Appendix A

Strategy & Operations


Strategic Objective

Devon strives to maximize long-term

value for our shareholders by growing

cash flow per share, adjusted for debt.


We Pursue Our Strategic Objective By:

• Exercising capital discipline

• Maintaining a low-cost structure to maximize operating margins

• Focusing on high-return projects

• Improving performance through midstream business

• Preserving financial strength and flexibility


Advantaged Resource Base

• Low entry costs (acreage and royalties)

• Large, concentrated positions

• High-graded portfolio (capturing and divesting)

• Strategic midstream business


Portfolio Management

Goal: Optimize depth, diversity, and quality of drilling inventory

• Harvesting mature and lower-return assets

• New leasehold capture

• Joint ventures / farm-ins


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

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

• Q1 2014 net production: 30 MBOED

• 2014 plans: ≈150 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

• Q1 2014 net production rate: 19,000 BOED


• 2014 plans: Drill >200 wells

• Risked inventory: 1,000 locations and growing

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

• Integration of 3D seismic will optimize results


OK

Rockies Oil Powder River Basin

Slide 40

Sheridan

Campbell

Johnson

Converse

MT

WY

Natrona

• Net acreage: 150,000

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

• High impact wells (Best wells: IP’s >1,000 BOED)



Barnett ShaleLiquids-Rich Gas Development

• Net acreage: ≈600,000

• Low average royalty burden: 18%

• Q1 2014 net production: 1.3 BCFED

— Liquids 27% of total production

— Total liquids growth 5% YoY

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

ParkerPalo Pinto

Hood

Tarrant

JohnsonErath

Hill

Jack

Denton

Wise Denton

Ft. Worth

DRY GAS

Bridgeport Plant

LIQUIDS-RICH

TEXAS

OKLAHOMA

www.devonenergy.com Slide 41

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 (≈800 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

• 2014 plans: Drill 140 wells



Granite WashOil & Liquids-Rich Gas Development


• Legacy land position held by production

• Low average royalty burden: 19%

• Q1 2014 net production: 22 MBOED

OKLAHOMAOklahoma City

TEXAS

Granite Wash

Hemphill

Wheeler


Mississippian(≈300,000 JV acres)

Rockies Oil(323,000 JV acres) Utica Ohio

(≈200,000 JV acres)

Michigan(≈400,000 JV acres)

Joint Venture TransactionsOil & Liquids Exploration

Sinopec Joint Venture

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

• Drilling carry balance: $685 million (3/31/14)

• 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: $450 million (3/31/14)

• 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

(>600,000 JV acres)

Sumitomo joint venture assets

Slide 45

Attractively Hedged

Oil Hedges

• ≈70% of “go-forward” oil production hedged (Q2-Q4 2014)

— 75 MBOPD swapped at $94 per BBL

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

— 12 MBOPD swapped at an $18 differential to WTI (WCS basis swap)

• 80 MBOPD of oil production hedged in 2015

— 77 MBOPD swapped at $90 per BBL

— 3 MBOPD collared at $86 - $96 per BBL

Natural Gas Hedges

• ≈75% of “go-forward” gas production hedged (Q2-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%

≈40% 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)

Potential Drop Down AssetVictoria Express Pipeline (VEX) (Eagle Ford)

• ≈56 mile crude oil pipeline from Eagle

Ford core to Devon’s Port of Victoriaterminal

• 50 MBOPD start-up capacity (expandable)

• ≈300,000 barrels of storage available

• VEX commissioning to begin early Q3

• Provides additional market options for crude and condensate

• Devon ownership: 100%

• Total current project capital: $70 MM(≈1/2 of capital spent by GeoSouthern)

Point Comfort

Port of Victoria

Karnes

Gonzales

DeWitt

Lavaca

Victoria

Jackson

Goliad

Wharton

Colorado

Calhoun

Refugio

Aransas

Matagorda

VEX Potential Expansion

VEX Under Construction

Devon Acreage

Gulf ofMexico

Appendix B

Supply & Demand

Canadian Crude 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: Q3 2014

Alberta Clipper/Southern Access: Hardisty to Flanagan• Capacity: staged increments up to 0.8 MMBOPD• Estimated in service: mid-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: 2017

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 52

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

20.020.5

21.121.7

22.1 22.5

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 Filed --

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

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

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

Jan 2010 Jan 2011 Jan 2012 Jan 2013

MM

BPD

Estimated Ethane Rejection

Ethane Extraction Ethane Rejection

Natural Gas Liquids Supply

Page 58

Q1 Q2 Q3 Q4* Q1F Q2F Q3F Q4F*

2013 2014F 2012Final

2013Final

Ethane 0.9 0.9 1.0 1.0 1.1 1.2 1.2 1.2 1.0 1.0NG Propane 0.9 0.9 0.9 1.0 1.1 1.0 1.0 1.1 0.8 0.9Refinery Propane 0.5 0.6 0.6 0.6 0.5 0.6 0.6 0.6 0.6 0.6Isobutane 0.2 0.2 0.3 0.2 0.3 0.3 0.3 0.3 0.2 0.2Normal Butane* 0.2 0.5 0.4 0.1 0.5 0.6 0.5 0.2 0.3 0.3Natural Gasoline 0.3 0.4 0.4 0.3 0.5 0.5 0.5 0.5 0.3 0.4Total US NGL Supply 3.2 3.5 3.5 3.2 4.0 4.0 4.1 3.9 3.2 3.3

0.00.51.01.52.02.53.03.54.04.5

U.S. NGL Supply by Component** (MMBPD)

*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, Wells Fargo, Morgan Stanley, Bentek, and Devon estimates

0.4

0.40.5

0.6 0.8

0.8 0.8

0.8

0.30.5

3.6

3.03.2

3.94.1

3.7 3.8

4.1

3.13.4

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

Q1 Q2 Q3 Q4 Q1F Q2F Q3F Q4F 2012 2013

2013 2014F

MM

BPD

Petchem Other End Use Refinery/Blender Exports

U.S. Natural Gas Liquids Demand

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

Natural Gas LiquidsDemand – LPG exports

Page 60

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 LiquidsInventories & Cracking Rates

510152025303540

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

MM

Bbl

U.S. Ethane Inventories

5 Yr. High/Low 2013 2012 5 Yr. AVG.

0.3

0.5

0.7

0.9

1.1

1.3


MM

BPD

U.S. Ethane Cracking Rate

5 Yr. High/Low 2013 2012 5 Yr Average

0.0

0.1

0.2

0.3

0.4

0.5

0.6


MM

BPD

U.S. Propane Cracking Rate

5 Yr. High/Low 5 Yr Average 2013 2012

End of Month Weekly Total

20141020304050607080


MM

Bbl

U.S. Propane Inventories

5 yr High/Low 2013 2012 5 Yr. AVG.

Page 61Source: EIA and Hodson Report

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: 5.5 MMCFED

EUR: 8 BCFE


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 68

Devon defines net debt as debt less cash, cash equivalents and short-term investments. 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)

Total debt (GAAP) at 3/31/2014 $15.5

Adjustments:

Cash and short-term investments at 3/31/2014 2.0

Net debt (Non-GAAP) at 3/31/2014 $13.5

Net proceeds from Canadian conventional gas sale (April 2014) 2.8 Pro Forma Net Debt $10.7