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Jefferies Global Energy Conference
November 12, 2014
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 furnished November 4, 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-SEC0330 or from the SEC’s website at www.sec.gov.
NYSE: DVN
www.devonenergy.com
Slide 2
Devon Today
Delivering Shareholder Value
• A leading North American E&P
• Focused and balanced portfolio
• Oil driving production growth
• Expanding margins
• Strong financial position
• Accelerating activity
NYSE: DVN
www.devonenergy.com
Slide 3
Devon Today
Strong North American Pure Play
• Q3 2014 net production: 640 MBOED(1)
Devon’s Core & Emerging Assets
• Deep inventory of oil opportunities
— Top-tier Eagle Ford development
Heavy Oil
Core
Emerging
— High-quality Permian Basin position
— World-class heavy oil projects
— Upside potential in emerging plays
Rockies Oil
• Strong liquids-rich gas optionality
• EnLink ownership valued at ≈$8 billion
— Additional midstream value in Access
and Victoria Express pipelines
Anadarko Basin
Permian Basin
Eagle Ford
(1) Excludes non-core divestiture assets.
NYSE: DVN
www.devonenergy.com
Slide 4
MississippianWoodford
Barnett Shale
Focused & Balanced Portfolio
• Positioned in top North American
Q3 2014 Product Mix(1)
basins
• Completed asset divestiture program
— >$5 billion in gas-weighted asset sales
34%
45%
• Oil & NGL: 55% of production
21%
• Focused on oil and value growth
Oil
(1) Excludes non-core divestiture assets.
NYSE: DVN
www.devonenergy.com
Slide 5
NGLs
Natural Gas
2014 Production Growth Targets
U.S. Oil Production(1)
Total Oil Production(1)
BOE Production(1)
(MBOPD)
(MBOPD)
(MBOED)
614 - 620
206 - 209
539
152
127 - 128
73
2013
2014e
2013
U.S.
2013
2014e
6:1
Canada
(1) Excludes non-core divestiture assets.
NYSE: DVN
www.devonenergy.com
Slide 6
2014e
20:1
Preliminary 2015 Outlook
Total Oil Production(1)
Key Highlights
(MBOPD)
• On track to deliver 2015 oil production
growth of 20 - 25%(1)
— Driven by Eagle Ford, Permian and Jackfish 3
Oil (1)
• Top-line BOE growth: mid-single digits
206 - 209
Natural
Gas
• Growth achievable with similar spend rate
to 2014
NGLs
2014e
2015e
(1) Excludes non-core divestiture assets.
Slide 7
Devon Oil Production
Significant Oil Producer in North America
Q2 2014 Oil Production
Devon(1) vs. N.A. Onshore Pure-Play Peers
300
250
MBOD
200
150
100
50
0
EOG
CLR
CHK
WLL
PXD
MEG
CXO
NFX
XEC
OAS
(1) Excludes non-core divestiture assets.
NYSE: DVN
www.devonenergy.com
Slide 8
ECA
SD
LPI
FANG
RRC
Expanding Margins
Pre-Tax Cash Margin Per Boe(1)
• High-margin oil growth
(September Year to Date)
$29.51
• Improved price realizations
$21.47
• Effective cost management
• Non-core asset divestitures
2013 YTD
2014 YTD
(1) Pre-tax cash margin is defined as unhedged upstream revenues and midstream operating profit less LOE and production &
property taxes, cash-based G&A and net financing costs, divided by BOE production.
Slide 9
Financial Strength & Flexibility
• Strong investment-grade ratings
—
Cash balances: $3.4 billion
—
Net debt(1): $6.8 billion (excluding EnLink)
(9/30/14)
• Cash flow protected by hedges
—
Majority of Q4 production hedged above current pricing levels
—
>50% of 2015 oil protected at $91 per barrel
• Significant midstream drop-down optionality
—
Victoria Express and Access Pipeline operational
—
Candidates for drop down as early as next year
—
>$1 billion invested in these pipelines
(1) Net debt is a Non-GAAP measure defined as total debt less cash and cash
equivalents and debt attributable to the consolidation of EnLink Midstream.
Slide 10
Asset Overview
Permian Basin
Delaware Basin Delivering Outstanding Results
• Activity focused on repeatable,
high-impact Bone Spring
— Brought 13 wells online in Q3
Central
Eddy
— 30-day IP rate: ≈900 BOED (80% oil)
— Results >50% higher than type curve
• New completion design provides
further upside
— Testing sand volumes up 4x historical
design
Lea
New Mexico
— Preliminary results positive
Texas
• Operated rigs: 14 by year-end
Loving
NEW MEXICO
Winkler
OKLAHOMA
Reeves
TEXAS
Ward
Bone Spring
285,000 net acres
Delaware Sands
80,000 net acres
Leonard Shale
60,000 net acres
Wolfcamp
>100,000 net acres
Slide 12
Bone Spring
Raising Type Curve
Key Modeling Stats
30-Day IP Rates
(MBOED)
750+
575
30-Day IP (BOED)
750+
EUR
450+
(MMBOE)
D&C Cost
Previous
Revised
(in millions)
$6 - $7
Oil / NGL (% of Production)
65% / 20%
WI / NRI
71% / 56%
LOE
($/BOE)
Slide 13
$14
Delaware Basin
Significant Resource Opportunity
Net Risked
Acres
Risked Wells
Per Section
Gross Risked
Undrilled
Locations
Delaware Sands
80,000
4
700
20
Leonard Shale
60,000
5
700
1
Bone Spring
285,000
5
3,500
>100
Wolfcamp
>100,000
n/a
Under
Evaluation
3
20,000
4
>200
4
>5,000
>130
Formation
Other
Total
NYSE: DVN
(Yeso & Strawn)
>500,000
www.devonenergy.com
Slide 14
2014e
Activity
(Wells Drilled)
Permian Basin
Delivering Significant Oil Production Growth
60
Net Production (MBOPD)
50
40
30
20
10
0
2009
NYSE: DVN
2010
2011
www.devonenergy.com
2012
2013
Slide 15
2014e
Eagle Ford Overview
World-Class Oil Asset
• Located in best part of Eagle Ford
• Net acreage: 82,000
OKLAHOMA
TEXAS
— DeWitt: 48% WI / 36% NRI
(50,000 net acres)
— Lavaca: 81% WI / 63% NRI
(32,000 net acres)
• September exit rate: 87 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
(1) Represents Devon’s average estimated net production from March through December.
Slide 16
Eagle Ford
Production Results and Outlook
2014 Results to Date
Multi-Year Production Outlook
(MBOED)
(MBOED)
>100
87
70 – 80(1)
49
March 2014
September 2014
(1) Represents Devon’s estimated net production from March through December.
2014e
Slide 17
2015e
Lower Eagle Ford Upside
Lavaca County
Devon’s Lavaca County
• Net acreage: 32,000
Bock Unit (3 wells)
Berger 1H
Non-operated
Lower Eagle Ford
24-Hr IP: 2,401 BOED Avg.
• Q3 results highlighted by 7
Lower Eagle Ford
24-Hr IP: 1,291 BOED
high-rate wells (see map)
Gonzales
• Significant upside potential
Lavaca
Amber Unit (2 wells)
Non-operated
Lower Eagle Ford
24-Hr IP: 2,068 BOED Avg.
Marcia 1H
Lower Eagle Ford
24-Hr IP: 1,343 BOED
OKLAHOMA
TEXAS
DeWitt
NYSE: DVN
www.devonenergy.com
Slide 18
Upper Eagle Ford Potential
DeWitt and Lavaca Counties
OKLAHOMA
• Encouraging industry results
TEXAS
• Pay thickest in DeWitt County
Robin 1H
Q4 Spud
Medina 2H
Q4 Completion
• Spud first well in Q3
Angela 1H
Q4 Spud
• 5 additional tests planned for
2014
Gonzales
Nancy 1H
Q4 Completion
Pargmann 1H
Q4 Completion
DeWitt
Lavaca
Net Pay (ft.)
40
35
30
25
20
15
10
5
0
Heavy Oil Developments
Jackfish & Pike
SAGD Characteristics:
Jackfish 1
• Low F&D
Jackfish 2
T75
Jackfish 3
• Flat production profile
T74
Pike Project Area
• Long reserve life >20 years
Each SAGD Project:
Access Pipeline
T73
6 Miles
R8
• Low geologic risk
R7
Jackfish Acreage (100% WI)
Pike Acreage (50% WI)
Access Pipeline
(50% Ownership)
R6
R5
BRITISH
COLUMBIA
R4
• Proved reserves 12/31/13: 552 MMBO
• Risked resource: 1.4 BBO
ALBERTA
Jackfish & Pike
• 300 MMBO gross EUR
Ft. McMurray
Edmonton
Calgary
Slide 20
Jackfish Heavy Oil Developments
Delivering Visible Oil Growth
Jackfish Complex:
• Q3 2014 production:
— Gross production: 64 MBOPD (20% higher YoY)
— Net production: 53 MBOPD
• Delivering top-tier operating results at J1
• Plant start-up began on July 13th at J3
— 2014e exit rate: 10 MBOPD
— Expect to reach 35 MBOPD by year-end 2015
• Provides visible multi-year oil growth beginning
in 2015
• Begins era of free cash flow generation from
Jackfish complex
NYSE: DVN
www.devonenergy.com
Slide 21
Anadarko Basin
Cana-Woodford Accelerating Activity
Cana-Woodford Overview:
• Net acreage: 280,000
— Stacked-pay potential
— 200,000 net acres in oil and liquids window
• Q3 2014 net production: 71 MBOED
— Production increased 25% YoY
— Oil and NGL 45% of production
• Improved completion design enhancing returns
— Q2 wells averaged 1,440 BOE per day
OKLAHOMA
• Drilling first two STACK wells
TEXAS
(Targeting Meramec)
• Accelerating activity to >10 rigs by Q1 2015
Slide 22
Raising Cana-Woodford Type Curve
Liquids-Rich Core
EURs
(MMBOE)
30-Day IP Rates
1.7
(BOED)
1,200
1.4
920
Previous
Revised
Cost Per Well
($MM)
Previous
$8.0
$8.2
Previous
Revised
Revised
Rockies Oil
Powder River Basin
•
Net acreage: 150,000
•
Stacked oil targets
•
Activity focused on repeatable Parkman
formation
(Parkman, Turner, Frontier & others)
— Six high-rate development wells in Q3
— 30-day IP rate: 1,080 BOED (85% light oil)
•
Risked drilling inventory: ≈1,000
•
Accelerating development activity in 2015
•
Operated rig count: 4
MONTANA
WYOMING
Slide 24
(75% Parkman)
Innovative Midstream Combination
EnLink Midstream Overview
• Devon retains majority ownership
— General partner (ENLC 70%)
— MLP (ENLK 52%)
• EnLink transaction highly accretive to
shareholders
• Market value of Devon’s EnLink ownership
interest: ≈$8 billion
• Improves capital efficiency, diversification,
scale and growth of midstream business
• Potential to drop down assets
NYSE: DVN
www.devonenergy.com
Slide 25
Why Own Devon?
• A leading North American E&P
• Focused and balanced portfolio
• Oil driving production growth
• Expanding margins
• Strong financial position
• Accelerating activity
NYSE: DVN
www.devonenergy.com
Slide 26
Thank You
Appendix A
Strategy & Operations
Disciplined Capital Allocation
Top objective: Maximize shareholder returns by
optimizing cash flow per share, adjusted for debt
• 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
NYSE: DVN
www.devonenergy.com
Slide 29
Non-Core Asset Sales
Sharpening 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 30
2014 E&P Capital Program
Delivering Strong Oil Growth
2014 E&P Capital Budget
$5.0 - $5.4 Billion(1)
2%
5%
5%
7%
28%
11%
E&P Capital
Spent ($B)(1)
% of
Budget
Q1 2014
$1.2
23%
Q2 2014
$1.3
23%
Q3 2014
$1.3
25%
Sept YTD
$3.8
72%
• Capital concentrated in oil development plays
21%
Permian Basin
Eagle Ford
Heavy Oil
Emerging Oil
21%
Anadarko Basin
Barnett Shale
Other
Non-Core Assets
(1) Excludes Eagle Ford and Cana-Woodford acquisitions.
— ≈80% directed toward oil opportunities
— Spending focused on high-margin U.S. oil assets
— Long-term investment in Canadian oil growth
• JV carries minimize capital costs in emerging
oil plays (>$1 billion of drilling carries in 2014)
Slide 31
Permian Basin Overview
2014 Focus Areas
OKLAHOMA
• Net acreage: 1.3 million basin-wide
with stacked-pay potential
Texas
New Mexico
NEW MEXICO
Northwestern
Shelf
TEXAS
Midland
Basin
Eastern
Shelf
• Q3 2014 net production: 98 MBOED
(≈60% oil)
• Deep inventory of low-risk projects
Wolfberry
• Delivering highly economic & robust
production growth
Bone Spring
& Delaware
Central
Basin
Platform
Midland
— Expect ≈20% oil growth in 2014
• Operated rig count: 21
Conventional
Diablo
Platform
NYSE: DVN
Wolfcamp
Shale
Ozona Arch
www.devonenergy.com
• 2014 capital: $1.5 billion
• 2014 plans: Drill >350 wells
Slide 32
Permian Basin
Midland-Wolfcamp Shale Oil Development
• Net acreage: 122,000
• Low-risk, high-margin light oil play
• Thick pay with multiple intervals
Reagan
Irion
• Q3 2014 net production: 15 MBOED (>150% higher YoY)
• 2014 capital: ≈$200 million
Crockett
NM
• 2014 plans: Drill ≈150 wells
TX
NYSE: DVN
www.devonenergy.com
(up to 1,100’)
Slide 33
Pike Overview
SAGD Oil Development
Jackfish
Pike leasehold
Pike 1 Development Area
• 50% operated working interest
• Similar reservoir characteristics
to Jackfish
• Up to five 35 MBOPD SAGD
development phases
Pike
Potential Pike 1 development
• Single plant pad
• Up to three 35 MBOPD projects
Pike Acreage (50% WI)
>15m (≈50ft) Continuous
Bitumen Pay
Pike Project Area
Access Pipeline
(50% Ownership)
BRITISH
COLUMBIA
ALBERTA
Jackfish & Pike
Ft. McMurray
• Developed concurrently
Edmonton
Calgary
Slide 34
Lloydminster
Oil Development
Iron River
Manatokan
•
Net acreage: ≈700,000
•
Low-risk development
•
Strong operating margins
•
Q3 2014 net production: 31 MBOED
•
2014 plans: ≈150 wells
End Lake
Lloydminster
Alberta
Lloydminster
B. C.
NYSE: DVN
Sask.
www.devonenergy.com
Slide 35
Mississippian-Woodford Trend
Emerging Oil Opportunity
OKLAHOMA
TEXAS
• Net acres to DVN in JV area: ≈180,000
• Drilling activity focused on joint venture acreage
• Multiple oil-bearing intervals
• Q3 2014 net production rate: 21,000 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 36
Barnett Shale
Liquids-Rich Gas Development
Jack
Wise
Denton
Denton
• Net acreage: 625,000
• Low average royalty burden: 18%
• Q3 2014 net production: 1.2 BCFED
Palo Pinto
DRY GAS
Parker
LIQUIDS-RICH
— Liquids 27% of total production
• Expected to generate >$1 billion of free
Ft. Worth
cash flow in 2014
Tarrant
Hood
Johnson
Erath
OKLAHOMA
Hill
TEXAS
www.devonenergy.com
Slide 37
Anadarko Basin
Granite Wash
• Net acreage: 66,000
• Legacy land position held by production
• Low average royalty burden: 19%
Hemphill
• Q3 2014 net production: 21 MBOED
Wheeler
Granite Wash
OKLAHOMA
Oklahoma City
TEXAS
NYSE: DVN
www.devonenergy.com
Slide 38
Joint Venture Transactions
Oil & Liquids Exploration
Sinopec Joint Venture
• $2.5 billion transaction
($900 million cash and $1.6 billion drilling carry)
• Drilling carry balance: $280 million
(9/30/14)
• Sinopec receives 33% of Devon’s interest
• Net acreage in joint venture: ≈700,000
Michigan
Rockies Oil
Utica Ohio
• Devon serves as operator
Sumitomo Joint Venture
• $1.4 billion transaction
Mississippian
($400 million cash and $1.0 billion drilling carry)
Cline Shale &
Wolfcamp Shale
• Drilling carry balance: $165 million
(9/30/14)
• Sumitomo receives 30% of Devon’s interest
Sinopec joint venture assets
• Net acreage in joint venture: >500,000
Sumitomo joint venture assets
• Devon serves as operator
NYSE: DVN
www.devonenergy.com
Slide 39
Potential Drop Down Assets
Access & Victoria Express Pipelines
Access Pipeline
Victoria Express Pipeline
JACKFISH & PIKE
Colorado
Gonzales
Lavaca
16” Diluent Line
Wharton
(Edmonton to Jackfish Area)
24” Diluent Line
DeWitt
(Sturgeon to Jackfish Area)
42” Blend Line
Sturgeon
Terminal
EDMONTON
(Jackfish Area to Sturgeon)
Jackson
Karnes
30” Blend Line
Goliad
(Sturgeon to Edmonton)
Calhoun
Oil Pipelines
Port of Victoria
HARDISTY
Refugio
Express
To U.S. Rockies
Matagorda
Victoria
Devon Acreage
Aransas
Gulf of
Mexico
• Three ≈180 mile pipelines from Sturgeon Terminal
to Devon’s thermal acreage
• ≈56 mile crude oil pipeline from Eagle Ford
core to Port of Victoria terminal
• ≈30 miles of dual pipeline from Sturgeon Terminal
to Edmonton
• ≈300,000 barrels of storage available
• Capacity net to Devon:
—
Blended bitumen: 170 MBOPD
• Devon ownership: 50%
— ≈$1B invested to date
• Capacity:
— 50 MBOPD operational capacity (expandable)
• Devon ownership: 100%
— ≈$70 MM invested to date
EnLink Midstream Business
Ownership Structure
Devon Energy Corporation
GP
Public Unitholders
≈30%
(NYSE: DVN)
≈70% (115 MM units)
General Partner
EnLink Midstream LLC (ENLC)
General Partner,
≈7% LP and
IDRs
≈52% LP (120 MM units)
100% Incentive Distribution Rights (IDRs)
MLP
Public Unitholders
Master Limited Partnership
EnLink Midstream Partners LP (ENLK)
50% LP
Dist./Qtr
≈41% LP
50% LP
Devon Midstream
Holdings, LP
(“Devon Holdings”)
NYSE: DVN
www.devonenergy.com
Slide 41
Splits
≤ $0.2500
2% / 98%
≤ $0.3125
15% / 85%
≤ $0.3750
25% / 75%
> $0.3750
50% / 50%
Attractively Hedged
Oil Hedges
• ≈60% of oil production hedged
(Q4 2014)
— 75 MBOPD swapped at $94 per BBL
— 65 MBOPD collared at $89 - $100 per BBL
— 50 MBOPD WCS basis swapped at $17 off WTI
• 138 MBOPD of oil production hedged in 2015
— 107 MBOPD swapped at $91 per BBL
— 31 MBOPD collared at $90 - $98 per BBL
— 18 MBOPD WCS basis swapped at $19 off WTI
Natural Gas Hedges
• ≈80% of gas production hedged
(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.
Slide 42
Appendix B
Supply & Demand
Canadian Oil
Supply & System Export Capacity
9.0
8.0
7.0
MMBOD
6.0
5.0
4.0
3.0
2.0
1.0
0.0
2011
2012
2013
2014e
2015e
2016e
2017e
2018e
Oil Supply
Current Export & Local Demand Capacity
Rail
Alberta Clipper - Flanagan South
Trans Mountain Expansion
Keystone XL
Energy East
Enbridge Line 3 Replacement
Source: Canadian Association of Petroleum Producers and Devon estimates
Canadian Oil
Pipeline Capacity Additions
Flanagan South: Flanagan to USGC
• Capacity: staged increments up to 0.6 MMBOPD
• Estimated in service: Q4 2014
Kitimat
Alberta Clipper/Southern Access: Hardisty to Flanagan
• Capacity: staged increments up to 0.8 MMBOPD
• Estimated combined in service: Q3 2015
Edmonton
Hardisty
St. John
Vancouver
Superior
Montreal
Sarnia
Flanagan
Keystone XL: Hardisty to USGC
• Capacity: 0.8 MMBOPD
• Estimated in service: mid-2017
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
Cushing
U.S. Gulf Coast
(USGC)
NYSE: DVN
Enbridge Line 9B Reversal: Sarnia to Montreal
• Capacity: 0.3 MMBOPD
• Estimated in service: Q4 2014
www.devonenergy.com
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: 2019
Slide 45
Canadian Oil
Rail Transport Fees
Oil Sands
West Coast
Refining
Potential Rail
Costs
$ Per BBL
Trucking & Loading
≈$5.00
Rail Car Rental
≈$2.50
Transport Fee
Variable
Offloading Fee
East Coast
Refining
Gulf Coast
Refining
(Mileage Based)
≈$2.00
Heavy Oil
Refinery 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
NYSE: DVN
www.devonenergy.com
120,000
Slide 47
U.S. Natural Gas
Demand Growth By Sector 2013-2018
90
85
6.5
0.5
BCFD
80
2.1
3.7
75
2.5
87
-0.5
70
72
65
60
2013
Baseline
Industrial
Res/Com
Electric
Mex/Can
Exports
Other
Source: Wood Mackenzie, EIA, PIRA, Bloomberg, FERC, US DOE, and Devon estimates
NYSE: DVN
www.devonenergy.com
Slide 48
LNG
Exports
2018 Total
U.S. Natural Gas
Cumulative Coal Retirement Demand Forecast
6
3.7
4
BCFD
2.9
1.6
2
0
-0.2
0.0
-2
2014F
2015F
Renewable Generation
2016F
Coal Retirements
Source:
PIRA, and Devon estimates
NYSE:
DVN Wood Mackenzie, Bernstein,
www.devonenergy.com
2017F
Fuel Switching
Slide 49
2018F
Net Effect
U.S. Natural Gas
Annual Industrial Demand
25
22
21.1
21.5
2014F
2015F
22.1
22.5
22.9
2017F
2018F
BCFD
20.0
19
16
13
10
2008
2009
2010
2011
2012
Base
2013A
Y/Y Growth
Source: Devon estimates
NYSE: DVN
www.devonenergy.com
Slide 50
2016F
U.S. Natural Gas
LNG Projects
Facility
Developer(s)
Location
Total 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
Approved
4Q 2014 est
Lake Charles
Lake Charles
Exports/Trunkline
Lake Charles,
LA
2.0
2.0
2Q 2019
Approved
Pre-Filed
4Q 2016 est
Cove Point
Dominion
Lusby, MD
1.0
0.8
2017
Approved
Approved
4Q 2015 est
Freeport LNG
(phase 2)
Freeport LNG
Freeport, TX
1.4
0.4
4Q 2018
Approved
Pre-Filed
4Q 2014 est
Cameron
Sempra Energy
Hackberry, LA
1.7
1.7
2017
Approved
Approved
Aug 2014
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
Approved
1Q 2015 est
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
--
--
16 – 18
15 – 17
2017 - 2026
--
--
--
34.5-36.5
31.9-33.9
Others
TOTAL U.S.
NYSE: DVN
www.devonenergy.com
Canadian Natural Gas
LNG Projects
Facility
Developer(s)
Location
Capacity
(BCFD)
Start-Up
Date
NEB Export
License
Douglas Channel Energy
LNG Partners, Haisla
Nation
Floating LNG,
Kitimat, B.C.
0.1
2017
Approved
Kitimat LNG
Apache, Chevron
Kitimat, B.C.
0.7
2019
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
NYSE: DVN
TOTAL CANADA
www.devonenergy.com
12.6
Natural Gas Liquids Supply
Estimated Ethane Rejection
MMBPD
2.0
Ethane Extraction
Ethane Rejection
1.5
1.0
0.5
0.0
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
U.S. NGL Supply by Component (MMBPD)
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
Q1
Q2
Q3
Q4*
Q1
2013
Ethane after rejection
Q2
Q3F Q4F*
2014F
2014 2014 2015
(A+F) SA
SA
1.1 1.2 1.3
1.1 1.0 1.1
0.9
0.9
0.9
0.9
1.0
0.9
1.0
1.0
1.0
1.0
1.1
1.0
1.2
1.0
1.2
1.1
Refinery Propane
Isobutane
0.5
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.2
0.2
0.3
0.2
0.2
0.3
0.3
0.3
0.3
0.3
0.3
Normal Butane*
Natural Gasoline
0.2
0.3
0.5
0.4
0.4
0.4
0.1
0.3
0.2
0.3
0.5
0.4
0.5
0.5
0.2
0.5
0.4
0.4
0.4
0.5
0.4
0.5
Total US NGL Supply**
3.2
3.5
3.5
3.2
3.4
3.9
4.1
3.9
3.8
4.0
4.2
NG Propane
*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
Page 53
U.S. Natural Gas Liquids Demand
U.S. NGL Demand
Petchem
Other End Use
Refinery/Blender
Exports
5.0
4.5
4.0
3.9
3.6
MMBPD
3.5
3.8
3.2
3.0
4.3
4.1
3.9
3.7
3.5
3.3
3.2
3.0
2.5
2.0
1.5
1.0
0.5
0.0
Q1
Q2
Q3
Q4
2013
Q1
Q2
Q3 A+F
2014F
*2013 YTD – Actual data through Sept ’13
2014 YTD Actual data through June ’14 and forecast for Q3 ’14
Source: EIA, Hodson Report, IHS_CMAI, Wells Fargo, Bentek, and Devon forecasts
Q4F
2013
YTD*
2014
YTD*
2014
SA
2015
SA
Natural Gas Liquids
Demand – LPG and Ethane Exports
1600
Exports of Propane
Exports of Butane
1400
Exports of Ethane
LPG (Propane & Butane) Export Capacity
1200
LPG + Ethane Export Capacity
MBPD
1000
800
600
400
200
0
2009
2010
2011
2012
2013
Source: EIA, Argus, Platts, Waterborne Energy, Bentek and Wells Fargo
2014
2015
Page 55
2016
Natural Gas Liquids
Cracking Rates & Inventories
U.S. Ethane Inventories
U.S. Ethane Cracking Rates
5 Yr. High/Low
2014
2013
5 Yr. High/Low
5 Yr Avg.
1.1
MMBbl
MMBbl
1.3
0.9
0.7
0.5
2014
2013
5 Yr. AVG.
45
40
35
30
25
20
15
10
5
0.3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Jan Feb Mar Apr May Jun
U.S Propane Cracking Rates
0.6
5 Yr. High/Low
2014
2013
5 yr High/Low
5 Yr Avg.
MMBbl
MMBbl
Aug Sep Oct Nov Dec
U.S. Propane Inventories
0.5
0.4
0.3
0.2
0.1
0.0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Source: EIA and Hodson Report
Jul
2014
90
80
70
60
50
40
30
20
10
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Page 56
Appendix C
Key Modeling Statistics
Key Modeling Statistics
Based on 2014 Drilling Program
Bone Spring (Permian Basin)
Midland-Wolfcamp Shale (Permian Basin)
Working interest / royalty:
71% / 21%
Working interest / royalty:
Drill & complete costs:
$6 - $7 MM
Drill & complete costs:
30-day IP rate:
750+ BOED
30-day IP rate:
350 BOED
EUR:
450+ MBOE
EUR:
400 MBOE
Oil / NGLs as % of production:
65% / 20%
Oil / NGLs as % of production:
55% / 27%
Decline Rates
75%
75%
(1st month to 13th month)
60%
60%
45%
45%
30%
30%
15%
15%
0%
0%
Yr 1
NYSE: DVN
Yr 2
Yr 3
Yr 4
Yr 5
www.devonenergy.com
(1st
Yr 1
Yr 2
Slide 58
69% / 24%
$6 - $6.5 MM
Decline Rates
month to 13th month)
Yr 3
Yr 4
Yr 5
Key Modeling Statistics
Based on 2014 Drilling Program
Eagle Ford (DeWitt County)
Working interest / royalty:
Eagle Ford (Lavaca County)
48% / 25%
Working interest / royalty:
Drill & complete costs:
$9 - $10 MM
Drill & complete costs:
30-day IP rate:
1,200 – 1,400
BOED
30-day IP rate:
EUR:
850 – 950 MBOE
Oil / NGLs as % of production:
60% / 20%
Decline Rates
75%
$9 MM
1,000 – 1,100
BOED
EUR:
400 – 500 MBOE
Oil / NGLs as % of production:
70% / 10%
Decline Rates
90%
(1st month to 13th month)
81% / 22%
(1st month to 13th month)
75%
60%
60%
45%
45%
30%
30%
15%
15%
0%
0%
Yr 1
NYSE: DVN
Yr 2
Yr 3
Yr 4
Yr 5
www.devonenergy.com
Yr 1
Yr 2
Slide 59
Yr 3
Yr 4
Yr 5
Key Modeling Statistics
Based on 2014 Drilling Program
Mississippian Lime (Mississippian-Woodford Trend)
Woodford Oil Shale (Mississippian-Woodford Trend)
Working interest / royalty:
35% / 19%
Working interest / royalty:
42% / 22%
Drill & complete costs:
$3 - $4 MM
Drill & complete costs:
$3 - $4 MM
30-day IP rate:
250 - 350 BOED
30-day IP rate:
250 - 350 BOED
EUR:
300 – 400 MBOE
EUR:
300 – 400 MBOE
Oil / NGLs as % of production:
75%
(1st
40% / 20%
Decline Rates
month to
13th
Oil / NGLs as % of production:
75%
month)
60%
60%
45%
45%
30%
30%
15%
15%
0%
0%
Yr 1
NYSE: DVN
Yr 2
Yr 3
Yr 4
Yr 5
www.devonenergy.com
(1st
Yr 1
Yr 2
Slide 60
35% / 35%
Decline Rates
month to 13th month)
Yr 3
Yr 4
Yr 5
Key Modeling Statistics
Based on 2014 Drilling Program
Cana-Woodford Shale
Working interest / royalty:
Barnett Shale
51% / 21%
Working interest / royalty:
Drill & complete costs:
$8 - $8.5 MM
Drill & complete costs:
30-day IP rate:
1,200 BOED
30-day IP rate:
EUR:
1.7 MMBOE
EUR:
Oil / NGLs as % of production:
10% / 30%
Oil / NGLs as % of production:
75%
(1st
Decline Rates
month to
13th
60%
60%
45%
45%
30%
30%
15%
15%
0%
0%
Yr 1
NYSE: DVN
Yr 2
Yr 3
Yr 4
Yr 5
www.devonenergy.com
$3 - $3.5 MM
3 MMCFED
4 BCFE
75%
month)
89% / 18%
(1st
Yr 1
Yr 2
Slide 61
5% / 45%
Decline Rates
month to 13th month)
Yr 3
Yr 4
Yr 5
Discussion of Risk Factors
Information provided in this presentation includes “forward-looking statements” as defined by the Securities and Exchange Commission. Forward-looking
statements are identified in this presentation as “forecasts, projections, estimates, plans, expectations, targets, opportunities, potential, outlook, etc.” and
are 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-looking
statements 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 which
was 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 and
NGL production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development, production
and 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, environmental
risks, drilling risks, political changes; changes in laws or regulations, the uncertainty inherent in estimating future oil and gas production or reserves, and
other 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 prevailing
market conditions. Market conditions for these products are influenced by regional and worldwide economic conditions, weather and other local market
conditions. 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 vary
considerably due to differences between regional markets, differing quality of oil produced (i.e., sweet crude versus heavy or sour crude), differing Btu
contents of gas produced, transportation availability and costs and demand for the various products derived from oil, natural gas and NGLs. Substantially all
of Devon’s revenues are attributable to sales, processing and transportation of these three commodities. Consequently, Devon’s financial results and
resources 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 will
continue at levels that allow for profitable production of these products. There can be no assurance of such stability. Most of Devon’s Canadian production of
oil, natural gas and NGLs is subject to government royalties that fluctuate with prices. Thus, price fluctuations can affect reported production. Estimates for
Devon’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 will
continue 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 to
transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerous
other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for
Devon’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, natural
gas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from Devon’s price expectations for
its future production, some projects may be accelerated or deferred and, consequently, may increase or decrease capital expenditures. In addition, if the
actual material or labor costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from
Devon’s estimates.
Assumptions and Risks Related to Marketing and Midstream Estimates Devon cautions that its future marketing and midstream revenues and expenses are
subject to all of the risks and uncertainties normally incident to the marketing and midstream business. These risks include, but are not limited to, price
volatility, environmental risks, mechanical failures, regulatory changes, the uncertainty inherent in estimating future processing volumes and pipeline
throughput, cost of goods and services and other risks.