ubs bus-less tour presentation
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UBS Bus-less Tour PresentationTRANSCRIPT
UBS Bus-less Tour
September 18, 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 TodayDelivering Shareholder Value
• A leading North American E&P
• Focused and balanced portfolio
• Oil driving production growth
• Expanding margins
• Strong financial position with growing cash flow
• Accelerating activity
NYSE: DVN www.devonenergy.com
Slide 4
Devon: Strong North American Pure Play
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)
• 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 non-core divestiture assets.
NYSE: DVN www.devonenergy.com
Slide 5
Focused & Balanced Portfolio
37%
20%
43%
Q4 2014e Product Mix (1)
Natural GasNGLsOil
(1) Excludes non-core divestiture assets.
• Positioned in top North American
basins
• Completed asset divestiture program
— >$5 billion in gas-weighted asset sales
• Oil & NGLs ≈60% by year-end
• Focused on oil and value growth
NYSE: DVN www.devonenergy.com
NYSE: DVN www.devonenergy.com Slide 6
2014 Production Growth Targets
2013 2014e
73
124 - 136
Total Oil Production(1)
(MBOPD)
(1) Excludes non-core divestiture assets.
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 7
Preliminary 2015 Outlook
2014e 2015e
Oil
NGLs
Natural Gas
Total Oil Production(1)
(MBOPD)Key Highlights
• On track to deliver 2015 oil productiongrowth of 20 - 25%(1)
— Driven by Eagle Ford, Permian and Jackfish 3
• Top-line BOE growth: mid-single digits(1)
• High-margin production expected to expandmargins and cash flow
• Cash flow to fund capital demands
198 - 216
(1) Excludes non-core divestiture assets.
Devon Oil ProductionSignificant Oil Producer in North America
0
50
100
150
200
250
300
EOG CLR CHK WLL PXD MEG CXO NFX XEC OAS ECA SD LPI FANG RRC
Q2 2014 Oil Production Devon(1) vs. N.A. Onshore Pure-Play Peers
Slide 8NYSE: DVN www.devonenergy.com
(1) Excludes non-core divestiture assets.
MBO
D
Expanding Margins
(1) 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
• High-margin oil growth
• Improved price realizations
• Effective cost management
• Non-core asset divestitures
Pre-Tax Cash Margin Per Boe(1)
Slide 9
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 sale of U.S. assets closed in August 2014 .
Slide 10
Slide 11
Accelerating 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
• Accelerating deployment of larger and morefocused completions
NYSE: DVN www.devonenergy.com
Asset Overview
Slide 13
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
NYSE: DVN www.devonenergy.com Slide 14
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
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)
NYSE: DVN www.devonenergy.com Slide 15
Slide 16
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 17
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.
NYSE: DVN www.devonenergy.com Slide 18
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 20
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 21
Jackfish Heavy Oil Developments Delivering Visible Oil Growth
NYSE: DVN www.devonenergy.com
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
Slide 22
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
NYSE: DVN www.devonenergy.com Slide 23
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 24
Cana-Woodford Q2 ResultsLiquids-Rich Core
920
1,250
2014 Type Curve Q2 Results
30-Day IP Rates(MBOED)
1.4
1.7+
2014 Type Curve Q2 Results
$8.0 $8.0
2014 Type Curve Q2 Results
Cost Per Well ($MM)
EURs(MMBOE)
Slide 25
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
NYSE: DVN www.devonenergy.com Slide 26
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 to drop down assets
NYSE: DVN www.devonenergy.com Slide 27
Why Own Devon?
• A leading North American E&P
• Focused and balanced portfolio
• Oil driving production growth
• Expanding margins
• Strong financial position with growingcash flow
• Accelerating activity
Thank You
Appendix A
Strategy & Operations
NYSE: DVN www.devonenergy.com Slide 30
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 31
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
• Sold U.S. non-core assets for $2.3 billion
— Accretive transaction: 7 times 2013 EBITDA
— Closed August 29, 2014
NYSE: DVN www.devonenergy.com
Slide 32
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)
NYSE: DVN www.devonenergy.com
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
• 2014 plans: Drill ≈400 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 33
Permian Basin Midland-Wolfcamp Shale Oil Development
Reagan Irion
Crockett
TX
NM
Overview
• Net acreage: 117,000
• 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
• 2014 plans: Drill ≈150 wells
NYSE: DVN www.devonenergy.com Slide 34
NYSE: DVN www.devonenergy.com Slide 35
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
NYSE: DVN www.devonenergy.com Slide 36
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)
NYSE: DVN www.devonenergy.com Slide 37
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
NYSE: DVN www.devonenergy.com Slide 38
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)
NYSE: DVN www.devonenergy.com Slide 39
Iron River
Manatokan
End Lake
Lloydminster
LloydminsterOil Development
• Net acreage: ≈700,000
• Low-risk development
• Strong operating margins
• Q2 2014 net production: 29 MBOED
• 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
NYSE: DVN www.devonenergy.com Slide 40
OK
Barnett ShaleLiquids-Rich Gas Development
• Net acreage: 625,000
• 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 41
NYSE: DVN www.devonenergy.com Slide 42
Granite WashOil & Liquids-Rich Gas Development
• Net acreage: 66,000
• Legacy land position held by production
• Low average royalty burden: 19%
• Q2 2014 net production: 24 MBOED
OKLAHOMAOklahoma City
TEXAS
Granite Wash
Hemphill
Wheeler
NYSE: DVN www.devonenergy.com Slide 43
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
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
NYSE: DVN www.devonenergy.com Slide 45
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)
Slide 46
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.
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
NYSE: DVN www.devonenergy.com Slide 49
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 51
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
NYSE: DVN www.devonenergy.com Slide 52
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
NYSE: DVN www.devonenergy.com Slide 53
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
NYSE: DVN www.devonenergy.com Slide 54
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
NYSE: DVN www.devonenergy.com
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
NYSE: DVN www.devonenergy.com
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 57
*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 59
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 60Source: 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
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
MM
Bbl
U.S. Ethane Cracking Rates
5 Yr. High/Low 2014 2013 5 Yr Avg.
1020304050607080
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
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
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
MM
Bbl
U.S Propane Cracking Rates
5 Yr. High/Low 2014 2013 5 Yr Avg.
Appendix C
Key Modeling Statistics
NYSE: DVN www.devonenergy.com Slide 62
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%
Yr 1 Yr 2 Yr 3 Yr 4 Yr 5
Decline Rates(1st month to 13th month)
Midland-Wolfcamp Shale (Permian Basin)
Working interest / royalty: 62% / 24%
Drill & complete costs: $6 MM
30-day IP rate: 400 BOED
EUR: 450 MBOE
Oil / NGLs as % of production: 55% / 25%
NYSE: DVN www.devonenergy.com Slide 63
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)
Eagle Ford (DeWitt County)
Working interest / royalty: 50% / 25%
Drill & complete costs: $9 - $10 MM
30-day IP rate: 1,200 – 1,400 BOED
EUR: 850 – 950 MBOE
Oil / NGLs as % of production: 60% / 20%
0%
15%
30%
45%
60%
75%
90%
Yr 1 Yr 2 Yr 3 Yr 4 Yr 5
Decline Rates(1st month to 13th month)
Eagle Ford (Lavaca County)
Working interest / royalty: 50% / 25%
Drill & complete costs: $9 MM
30-day IP rate: 1,000 – 1,100 BOED
EUR: 400 – 500 MBOE
Oil / NGLs as % of production: 75% / 10%
NYSE: DVN www.devonenergy.com Slide 64
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)
Mississippian Lime (Mississippian-Woodford Trend)
Working interest / royalty: 35% / 19%
Drill & complete costs: $3 - $4 MM
30-day IP rate: 250 - 350 BOED
EUR: 300 – 400 MBOE
Oil / NGLs as % of production: 40% / 20%
0%
15%
30%
45%
60%
75%
Yr 1 Yr 2 Yr 3 Yr 4 Yr 5
Decline Rates(1st month to 13th month)
Woodford Oil Shale (Mississippian-Woodford Trend)
Working interest / royalty: 42% / 22%
Drill & complete costs: $3 - $4 MM
30-day IP rate: 250 - 350 BOED
EUR: 300 – 400 MBOE
Oil / NGLs as % of production: 35% / 35%
NYSE: DVN www.devonenergy.com Slide 65
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)
Cana-Woodford Shale
Working interest / royalty: 51% / 21%
Drill & complete costs: $8 MM
30-day IP rate: 920 MBOE
EUR: 1.4 MMBOE
Oil / NGLs as % of production: 10% / 30%
0%
15%
30%
45%
60%
75%
Yr 1 Yr 2 Yr 3 Yr 4 Yr 5
Decline Rates(1st month to 13th month)
Barnett Shale
Working interest / royalty: 89% / 18%
Drill & complete costs: $3 - $3.5 MM
30-day IP rate: 3 MMCFED
EUR: 4 BCFE
Oil / NGLs as % of production: 5% / 45%
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 67
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