IPAA Oil & Gas
Investment Symposium
April 20, 2015
NYSE: DVN
devonenergy.com
Investor Contacts & Notices
Investor Relations Contacts
Howard J. Thill, Senior Vice President, Communications & Investor Relations
(405) 552‐3693 / [email protected]
Scott Coody, Director, Investor Relations
(405) 552‐4735 / [email protected]
Shea Snyder, Director, Investor Communications
(405) 552‐4782 / [email protected]
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 February 17, 2015.
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.
2
Devon Today
Superior Execution Delivering Shareholder Value

A leading North American E&P

Building operational momentum

Disciplined capital allocation

Oil driving production growth

Financial strength and flexibility

Significant midstream business
3
A Leading North American E&P
 Focused and balanced asset portfolio
Heavy Oil
— Proved reserves: 2.8 billion BOE
— Net production: 664 MBOED
— Upstream revenue: 60% oil
 Deep inventory of opportunities
—
—
—
—
Rockies Oil
Prolific Eagle Ford assets
High‐quality Permian Basin position
World‐class heavy oil projects
Top‐tier liquids‐rich gas plays
Anadarko Basin
Permian Basin
 Positioned to deliver visible, low‐risk
production growth
Barnett Shale
Eagle Ford
Oil Assets
Liquids‐Rich Gas Assets
Note: All figures represent Devon’s retained asset portfolio.
4
A Leading North American E&P
Strategy For Long‐Term Success
 Premier and sustainable asset portfolio
—
—
—
—
High‐returning projects
Positioned in top‐tier basins
Balanced between oil and gas
Deep inventory of opportunities
 Focused on superior execution
— Technical and operational excellence
— Production optimization
 Strategic midstream business
 Maintain financial strength and flexibility
5
Building Operational Momentum
Q4 & Full‐Year 2014 Highlights
 Delivered U.S. oil production growth of 82%
U.S. Oil Production Growth
MBOD
146
— Prolific Eagle Ford development results
― Excellent results in Delaware Basin
80
82%
 Q4 top‐line production 20% higher
Growth
Q4 2013
 Liquids approach 60% of production mix
Q4 2014
Q4 2014 Production Mix
664 MBOED
 Proved oil reserves increase to all‐time high Oil
Gas
 Record midstream operating profit
36%
43%
NGL
21%
Note: All figures represent Devon’s retained asset portfolio.
6
Disciplined Capital Allocation
2015 Capital Outlook
 Balances capital with cash inflows
2015 E&P Capital Budget
$4.1 ‐ $4.4 Billion
 Reduced 20% from 2014
 Focused on best development
opportunities
 Minimal exploration activity
 Dynamically allocate capital throughout 2015
7
Oil Driving Production Growth
2015 Production Outlook
 Oil production growth: ≈20% ‐ 25%
Total Oil Production
MBOD
— Driven by Eagle Ford, Permian & Jackfish 3
 Top‐line BOE growth: ≈5%
250 ‐ 260
209
≈20‐25%
 Capital efficient growth achievable with 20% less spend than 2014
Expected Growth
2014
Note: All figures represent Devon’s retained asset portfolio.
2015e
8
Oil Driving Production Growth
Significant Oil Producer in North America
Q4 2014 Oil Production Devon vs. N.A. Onshore Peers 350
300
MBOD
250
200
150
100
50
0
EOG
CLR
CHK
WLL
PXD
CXO
Note: All figures represent Devon’s retained asset portfolio.
MEG
ECA
NFX
XEC
OAS
SD
LPI
FANG
RRC
9
Financial Strength & Flexibility
 Strong investment‐grade ratings
—
Cash balances: $1.5 billion
—
Net debt(1): $7.8 billion (excluding EnLink)
 Cash flow protected by hedges
—
>50% of 2015 oil protected at $91 per barrel
—
≈40% of 2015 gas protected at $4.17 per Mcf
—
Fair market value of hedges: ≈$2 billion (12/31/14)
 Significant EnLink optionality
—
≈$570 million from sale of ENLK units
—
≈$215 million from Victoria Express dropdown —
≈$280 million of cash distributions from EnLink in 2015 (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.
10
Strategic Midstream Business
EnLink Overview
 Devon’s equity ownership interest
— 34% of MLP (ENLK: 98 MM units)
Market Value of EnLink Ownership
April 2015
— 70% of GP (ENLC: 115 MM shares)
 Highly accretive transaction
 Improves capital efficiency and growth
trajectory of midstream business
 Distributions to reach ≈$280 MM in 2015
 Midstream asset dropdown potential
— Access Heavy Oil Pipeline in Canada
11
HEAVY OIL
ROCKIES OIL
Oil Assets
Liquids‐Rich Gas Assets
ANADARKO BASIN
Asset Overview
Premier North American Portfolio
PERMIAN
BASIN
BARNETT SHALE
EAGLE FORD
12
E&P Operations
Delivering Superior Execution
 Maximize base production
—
Minimize controllable downtime
—
Enhance well productivity
—
Leverage midstream operations
—
Reduce operating costs
Capture Full Value
 Optimize capital program
—
Disciplined project execution
—
Perform premier technical work
—
Focus on development drilling
—
Reduce capital costs
Improve
Returns
13
Eagle Ford
Overview
 Top‐tier acreage position
— 82,000 net acres focused in DeWitt Co.
— Q4 net production: 98 MBOED
Gonzales
 Highest returning asset in portfolio
— Delivering industry‐leading well results
— ≈1,000 undrilled locations in inventory
— 2014 cash margin >$50 per BOE
Lavaca
Karnes
Dewitt
 2015 Outlook: High activity in DeWitt
— 2015 capital: ≈$1.1 billion
— Running 11 to 12 rigs in 2015
Devon Acreage
Oil Condensate & NGLs
Dry Gas
14
Eagle Ford
Prolific Production Results
 Production doubled since March 2014 acquisition
98
 Q4 2014 production increased 26% over Q3
 Light oil >60% of production mix
49
100%
Eagle Ford Production Growth
Increase
MBOED
March
Q2
Q3
Q4
15
Eagle Ford
Prolific Development Results
 Prolific Q4 results in DeWitt County
— 62 wells: 30‐day IP avg. 2,100 BOED
— Results >50% above type curve — IP’s for top 5 wells exceeded 3,000 BOED
 Raising type curve expectations
— Boosting 30‐day IP expectations by >25%
— Driven by production optimization program
— Potential for higher EURs Revised Eagle Ford Type Well
30‐Day IP Rate, BOED
1,650
1,300
>25%
Increase
Previous
Revised
2015 Eagle Ford Production Growth
MBOED
>100
65
 Expect 50%‐plus production growth in 2015
>50%
— Driven by DeWitt development program
Expected Growth
2014
2015e
16
Permian Basin
Overview
 Industry leader in basin
—
—
—
—
1.2 million net surface acres with stacked pay
Q4 net production: 98 MBOED
Production growth 23% higher in 2014
Liquids 77% of production mix
Permian Production Growth
2014 vs 2013 (MBOED)
 Deep inventory of low‐risk projects
— >5,000 locations in Delaware Basin
— Significant upside from downspacing
 2015 Outlook: Most active asset
— 2015 capital: ≈$1.3 billion
— Running 13 operated rigs in Delaware Basin
17
Permian Basin
Activity Focused in Delaware Basin
 Significant oil resource opportunity
Lea
 Activity focused on Bone Spring play
Bone Spring
Eddy
285,000 net acres
Delaware Sands
80,000 net acres
 Delivering prolific production growth
Leonard Shale
60,000 net acres
Wolfcamp
>100,000 net acres
Delaware Basin Production Growth
45
MBOED
Loving
Winkler
Reeves
Ward
≈190%
16
Growth
(CAGR: 23%)
2009
2010
2011
Oil
2012
NGL
2013
2014
Gas
18
Delaware Basin
New Completion Design Enhances Results
 Well performance exceeding expectations
—
—
—
—
Results highlighted by 13 wells in Q4 Targeting 2nd Bone Spring interval in NM
Applied ≈2x more sand than historic design
Initial 30‐day rates improved by >60%
 Further design enhancements underway
30‐Day IP Rates
BOED
940
575
>60%
Increase
Old Design
— Testing up to 3,000 lbs. of sand per lateral ft.
— Preliminary results positive
Sand
 2015 activity will utilize larger completions
Pounds Per Foot
Frac Stages
Q4 Results
Old Design
Q4
Results*
600
1,600
13
16
* Incremental capital for Q4 wells was
approximately $700,000 per well.
19
Delaware Basin
Significant & Growing Resource Opportunity
 Identified >5,000 risked, undrilled locations
— Conservatively assumes 4 to 5 wells per risked, drillable section
— ≈70% of inventory resides in the Bone Spring formation
 Downspacing pilots underway
— Testing 8 wells per section in lower 2nd Bone Spring interval (traditional landing zone)
— Appraising stand‐alone commerciality of upper portion of 2nd Bone Spring Risk Factor
Net Risked Acres
Risked Wells Per Section
Gross Risked Undrilled
Locations
160,000
50%
80,000
4
700
Leonard Shale
85,000
30%
60,000
5
700
Bone Spring
440,000
35%
285,000
4‐5
3,500
Wolfcamp
>100,000
n/a
>100,000
n/a
Evaluating
40,000
50%
20,000
4
>200
Net Prospective Acres
Delaware Sands
Formation
Other (Yeso & Strawn)
Total
>500,000
>5,000
20
Heavy Oil
Overview
 Located in best part of oil sands
—
—
—
—
Low geologic risk
Thick and continuous reservoir
Industry leading operating results
Massive risked resource: 1.4 BBO
6 Miles
Jackfish 1
Jackfish 3
T75
Pike Project Area
 Features of each Jackfish project:
— 300 MMBO gross EUR
— Long reserve life >20 years
— Flat production profile
T76
Jackfish 2
T74
Access Pipeline
T73
R6 R5
R4
Jackfish Acreage
100% WI
 2015 Outlook: 20%‐plus growth
— 2015 capital: ≈$700 million
— Delivering >20% production growth
Pike Acreage
50% WI
Access Pipeline
50% Ownership
21
Jackfish Heavy Oil Developments
Delivering Visible Oil Growth
 Jackfish 2 production increases
— Q4 gross production: 26 MBOD
— Production increased 10% YoY
 Jackfish 3 ramp‐up ahead of schedule
— Q4 gross production: 11 MBOD
— Expect 35 MBOD by end of 2015
% of Designed Capacity Utilized
— Q4 gross production: 37 MBOD
— Exceeding facility nameplate capacity
— Steam‐to‐oil ratio declines to record
low of 2.5
90 Day Moving Avg.
110%
100%
90%
80%
Facility Turnaround
70%
60%
2011
2011
2012
2012
2013
2013
2014
2014
Jackfish 3 Production Ramp‐Up
BOD
Gross Oil Production (BOD)
 Jackfish 1 delivering top‐tier results
Jackfish 1 Plant Utilization
15,000
10,000
Actual
Original Plan
+5,500 BOD
vs. Original Plan
5,000
0
Aug‐14
Sep‐14
Oct‐14
Nov‐14
Dec‐14
22
Anadarko Basin
Cana‐Woodford Overview
 Best position in play
—
—
—
—
280,000 net acres with stacked pay
Q4 net production: 76 MBOED
Production increased 35% YoY
1st operated STACK well brought online
Blaine
Kingfisher
Mullen 1H
24‐Hr IP: 1,500 BOED
Emma 1H
10,000’ Lateral
Q1 Completion
 Deep, high‐quality inventory
Canadian
— >2,000 liquids‐rich Woodford locations
— Emerging STACK play optionality
Caddo
Chiles & Hancock Pads
9 Wells
Avg. 30‐Day IP: 1,460 BOED
 2015 Outlook: Accelerating activity
— 2015 capital: $400 million
— Running 8 rigs in 2015
— Continue appraising STACK opportunity
Woodford
Meramec
23
Cana‐Woodford
Productivity Gains Enhances Results
 New completion drives enhanced economics
— 70% more sand with twice the frac stages
— Initial 30‐day rates improved by 30%
 High‐rate development wells in Q4 — 9 Woodford wells: 30‐day IP avg. 1,460 BOED
— Results >20% above revised type curve
— Testing additional design improvements
 Acid treatments enhance well productivity
Revised Cana‐Woodford Type Well
30‐Day IP Rate, BOED
1,200
920
30%
— 2x improvement to existing producers
— $250,000 cost payback in <3 months
— 1 BCF of additional recovery
Increase
Previous
Revised
24
Why Own Devon?

A leading North American E&P

Building operational momentum

Disciplined capital allocation

Oil driving production growth

Financial strength and flexibility

Significant midstream business
25
Thank you.
Appendix Permian Basin
Overview
 Industry leader in basin
— 1.2 million net surface acres with
stacked pay
— Q4 net production: 98 MBOED
— Production growth 23% higher in 2014
— Liquids 77% of production mix
Bone Spring, Delaware,
Leonard & Wolfcamp
Gaines
Eddy
Dawson
Borden
Wolfcamp
Lea
Andrews
Martin
Howard
Midland
Loving
Winkler
Ector
Mitchell
Glasscock
Midland
Sterling
Wolfberry
 Deep inventory of low‐risk projects
Ward
Crane
Upton
Reagan
Irion
— >5,000 locations in Delaware Basin
— Significant upside from downspacing
Reeves
Conventional
Pecos
Crockett
 2015 Outlook: Most active asset
Wolfcamp
Shale
— 2015 capital: ≈$1.3 billion
— Running 13 operated rigs in
Delaware Basin
28
Barnett Shale
Liquids‐Rich Gas Development
 Significant gas optionality
—
—
—
—
Net acres: 623,000
Best position in play
Q4 net production: 201 MBOED
Liquids 27% of production mix
 Generated free cash flow of $1 billion
in 2014
Denton
Wise
Dry Gas
Liquids‐Rich
Tarrant
Parker
Ft. Worth
 2015 Outlook
— 2015 capital: ≈$150 million
— Focused on optimizing base production
Hood
Johnson
29
Rockies Oil
Powder River Basin
 Emerging light oil opportunity
—
—
—
—
Net acres: 150,000
Stacked pay potential
1,000 risked locations in inventory
Q4 net production: 19 MBOED
Campbell
Parkman Focus Area
 Notable Q4 development activity
— 4 wells: 30‐day IP avg. 800 BOED
— Light oil 90% of production mix
Johnson
 2015 Outlook
— 2015 capital: ≈$350 million
— Running 2 operated rigs
Converse
30
Upper Eagle Ford Potential
DeWitt and Lavaca Counties
 Pay thickest in DeWitt County
 First 2 operated wells online
Medina 2H
Upper Eagle Ford Marl
30‐Day IP: 850 BOED
Lavaca
 Encouraging early results
Gonzales
Nancy 1H
Upper Eagle Ford Marl
30‐Day IP: 800 BOED
 2015 Outlook
— Bring 4 wells online
Karnes
Dewitt
Devon Operated
Net Pay (ft.)
40
35
30
25
20
15
10
5
0
31
Potential Drop Down Asset
Access Pipeline
 Three ≈180 mile pipelines from
Sturgeon Terminal to Devon’s
thermal acreage
JACKFISH & PIKE
16” Diluent Line
(Edmonton to Jackfish)
24” Diluent Line
 ≈30 miles of dual pipeline from
Sturgeon Terminal to Edmonton
(Sturgeon to Jackfish)
42” Blend Line
(Jackfish to Sturgeon)
Sturgeon
Terminal
30” Blend Line
EDMONTON
(Sturgeon to Edmonton)
 Capacity net to Devon:
— Blended bitumen: 170 MBOD
Oil Pipelines
HARDISTY
Express
To U.S. Rockies
 Devon ownership: 50%
— ≈$1 B invested to date
32
Key Modeling Statistics
Eagle Ford (DeWitt County)
Bone Spring (Delaware Basin)
Working interest / royalty:
48% / 22%
Working interest / royalty:
67% / 21%
30‐day IP rate:
1,650 BOED
30‐day IP rate:
750+ BOED
EUR:
900+ MBOE
EUR:
450+ MBOE
Oil / NGLs as % of production:
60% / 20%
Oil / NGLs as % of production:
65% / 20%
Decline Rates
75%
75%
(1st month to 13th month)
60%
60%
45%
45%
30%
30%
15%
15%
0%
0%
Yr 1
Yr 2
Yr 3
Yr 4
Decline Rates
Yr 5
(1st month to 13th month)
Yr 1
Yr 2
Yr 3
Yr 4
Yr 5
33
Key Modeling Statistics
Cana‐Woodford Shale
Rockies: Powder River Basin (Parkman)
Working interest / royalty:
51% / 21%
Working interest / royalty:
40% / 18%
30‐day IP rate:
1,200 BOED
30‐day IP rate:
525 BOED
EUR:
1.7 MMBOE
EUR:
300 MBOE
Oil / NGLs as % of production:
5% / 40%
Decline Rates
75%
Oil as % of production:
Decline Rates
90%
(1st month to 13th month)
95%
(1st month to 13th month)
75%
60%
60%
45%
45%
30%
30%
15%
15%
0%
0%
Yr 1
Yr 2
Yr 3
Yr 4
Yr 5
Yr 1
Yr 2
Yr 3
Yr 4
Yr 5
34
Discussion of Risk Factors
Forward‐Looking Statements: Information provided in this presentation includes “forward‐looking statements” as defined by the Securities and Exchange Commission. Forward‐looking statements are often identified by use of the words “forecasts”, “projections”, “estimates”, “plans”, “expectations”, “targets”, “opportunities”, “potential”, “outlook”, and other similar terminology.” Such statements 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 NGL. 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: A significant and prolonged deterioration in market conditions and the other assumptions on which our estimates are based will impact many aspects of our business and our results. Substantially all of Devon’s revenues are attributable to sales, processing and transportation of three commodities: oil, natural gas and NGL. Prices for oil, natural gas and NGL are determined primarily by prevailing market conditions, which may be impacted by a variety of general and specific factors that are difficult to control or predict. Worldwide and regional economic conditions, weather and other local market conditions influence the supply of and demand for energy commodities. In particular, concerns about the level of global crude‐oil and natural‐gas inventories and the production trends of significant oil producers like OPEC, among other things, have led to a significant drop in prices. In addition to volatility from general market conditions, Devon’s oil, natural gas and NGL prices may vary considerably due to factors specific to Devon, such as pricing differentials among the various regional markets in which our products are sold, the value derivable from the quality of oil Devon produces (i.e., sweet crude versus heavy or sour crude),the Btu content of gas produced, the availability and capacity of transportation facilities we may utilize, and the costs and demand for the various products derived from oil, natural gas and NGL. Estimates for Devon’s future production of oil, natural gas and NGL are based on the assumption that market demand and prices for oil, natural gas and NGL will be at levels that allow for profitable production of these products. As illustrated by recent market trends, there can be no assurance of such stability. Much of Devon’s production in Canada is subject to government royalties that fluctuate with prices, which, therefore, will affect reported production. Estimates for Devon’s future processing and transportation of oil, natural gas and NGL are based on the assumption that market demand and prices for oil, natural gas and NGL will be at levels that allow for profitable processing and transport of these products. As with our production estimates, there can be no assurance of such stability. The production, transportation, processing and marketing of oil, natural gas and NGL 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, tornadoes, extreme temperatures, and numerous other factors.
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.
35