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NYSE: DVNdevonenergy.com
Barclays CEO Energy-Power Conference
September 7, 2016
Investor Contacts & Notices
2
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]
Chris Carr, Supervisor, Investor Relations(405) 228-2496 / [email protected]
Forward-Looking StatementsThis presentation includes "forward-looking statements" as defined by the Securities and Exchange Commission (the “SEC”). Such statements are subject to a variety of risks and uncertainties that could cause actual results or developments to differ materially from those projected in the forward-looking statements. Please refer to the slide entitled “Forward-Looking Statements” included in this presentation for other important information regarding such statements.
Use of Non-GAAP InformationThis presentation may include non-GAAP financial measures. Such non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. For additional disclosure regarding such non-GAAP measures, including reconciliations to their most directly comparable GAAP measure, please refer to Devon’s most recent earnings release at www.devonenergy.com.
Cautionary Note to Investors The SEC 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, risked or unrisked resource, potential locations, risked or unrisked locations, exploration target size and other similar terms. 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 at www.devonenergy.com. 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.
Devon TodayA Leading North American E&P
3
Key Messages
Premier asset portfolio
— Top-tier N.A. resource plays
— Deep inventory of opportunities
Significant financial strength
Delivering best-in-class results
Disciplined capital allocation
— Focused on value and returns
Heavy Oil
Rockies Oil
Barnett Shale
STACK
Oil44%
NGL19%
Gas37%
Retained Asset Production Forecasted 2016: 558 - 578 MBOED
Delaware Basin
Eagle Ford
Approach To The Current Environment
4
Achieve additional operating cost savings
Further increase capital productivity
Focused on value and returns
Accelerate activity in STACK and Delaware Basin
Preserve continuity in other U.S. resource plays
Invest within cash flow
Divestitures to enhance financial strength
Successful Asset Divestiture ProgramEnhancing Financial Strength
5
Midland Basin$1.0 BillionClosed
San Juan BasinUndisclosed ValueClosed
Access Pipeline$1.1 BillionExpected close: Q3 2016
Granite Wash$0.3 BillionClosed
Divestiture program complete
Total proceeds: $3.2 billion
― E&P asset sales: $2.1 billion
― Access pipeline sale: $1.1 billion
Minimal cash taxes expected
Majority of proceeds to reduce debt
Mississippian$0.2 BillionClosed
East Texas$0.5 BillionClosed
Significant Financial Strength
6
Investment-grade balance sheet
― Adjusted cash balance: $4.6 billion(1)
― Undrawn $3 billion credit facility
Net debt(2) reduced >45% from early 2016
Debt reduction program underway
― $1.3 billion tendered to date
No significant debt maturities until mid-2021
$8.7
$4.7
Jan. 2016 Current
Net Debt(2)
$ Billions
>45%DECLINE
(1) Cash balance at 6/30/16 adjusted for asset divestitures expected to close in Q3 2016.(2) 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. Net debt is adjusted for assetdivestitures that have closed and those expected to close in Q3 2016.
P RO- FORMA L IQUID ITY
BILLION
Advantaged Midstream Business
7
Devon’s equity ownership interest
― 24% of MLP (ENLK: 95 million units)
― 64% of GP (ENLC: 115 million units)
Eliminates midstream capital requirements
Improves midstream growth potential
Provides visible cash flow stream
― Annual distributions: ≈$270 million
EnLink Overview
DVN’S ENLINK OWNERSHIP
BILLION
MARKET VALUE ON AUGUST 30th
Operating Strategy For Success
8
Maximize base production
— Minimize controllable downtime
— Enhance well productivity
— Leverage midstream operations
— Reduce operating costs
Optimize capital program
— Disciplined project execution
— Perform premier technical work
— Focus on development drilling
— Reduce capital costs
Delivering Best-In-Class Well Results
9
Devon delivered best well results of any U.S. producer during 2015
Key drivers of success:
— Enhanced completion designs and improved well placement
— Development drilling focused in top N.A. resource plays
0
150
300
450
600
2015 Avg. 90-Day Wellhead IPsBOED, 20:1
0
150
300
450
600
2012 2013 2014 2015 Top U.S. Producers
Source: IHS/Devon. Operators with more than 100 wells.
Devon’s Avg. 90-Day Wellhead IPsBOED, 20:1
≈250%INCREASE
Achieving Significant Cost Savings
10
D&C Well Cost DeclinesPeak cost to Q2 2016
S A V I N G S
Declining D&C costs across portfolio
― Up to 40% lower than peak rates
― Driven by efficiencies and supply chain costs
― More than offsetting larger completions
Delivering significant operating cost savings
― LOE and G&A reduced >30% from peak levels
― Operating costs to decline by ≈$1 billion in 2016
UP TO
2015 2016e
2016e Field-Level Operating Costs and G&A(1)
$ Billions
≈$1BSAVINGS
$3.7
$2.7 - $2.9
LOE
Prod. Taxes
G&A
(1) Includes capitalized G&A.
Disciplined Capital AllocationYielding Strong Results
11
37%
21%
17%
15%
10%
STACK
DelawareBasin
Eagle Ford
Heavy Oil
Other
2016 E&P Capital Budget$1.1 Billion - $1.3 Billion
Capital program focused on top U.S. resource plays
Accelerating activity in STACK and Delaware Basin
― Adding up to 7 operated rigs by year-end 2016
― Preparing for full-field development in 2017
Raised 2016 production targets
― Driven by strong base production results
― Retained Midland assets boost U.S. oil guidance
Positioned to stabilize and grow production by mid-2017
Strong Returns At Lower Prices
12
IRR
–B
TAX
no
G&
A
IRR
–A
TAX
w/G
&A
Other Properties
Assets in best U.S. resource plays
Inventory attractively positioned on cost curve
>10,000 risked locations in STACK and Delaware
Prepared to further accelerate activity
Incremental Well EconomicsAt $50 Oil & $2.50 Gas
Delaware BasinSTACK – MeramecEagle FordRockies
STACK – WoodfordBarnett (hz. refracs)
Note: The capital component of the IRR calculation includes the cost to drill and complete an incremental well. Seismic and G&G costs are excluded from this calculation.
30%+
30%to
15%
15%to
0%
20%+
20%to
10%
10%to
0%
STACKBest-In-Class Position
13
Canadian
Kingfisher
Blaine
Hunton
Woodford
Mis
siss
ipp
ian
Chester
Springer
Morrow
De
von
ian
Pe
nn
.
Osage
Atoka
Meramec
Custer
Caddo
Meramec – Best Results - Strong flow rates- Oil-weighted production- Low well costs
Woodford – Core Area - Repeatable development- High liquids production
STACK Play
World-class development opportunity
— 430,000 net surface acres
— Top targets: Meramec & Woodford
— Q2 net production: ≈91 MBOED
Acreage concentrated in core of play
— Deep inventory of low-risk projects
Accelerating activity in 2H 2016
— Up to 6 operated rigs by year end
— 2016 capital ≈$450 million
— Drilling focused in Meramec formation
Dewey
STACKA Multi-Decade Growth Opportunity
14
Largest leasehold position of any operator
Advantaged cost structure
Strong production growth
Significant resource
430,000
265,000203,000 171,000
130,00083,000
STACK AcreageNet Acres
Peers
Source: Company reports.
59
91
Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016
54%INCREASE
STACK ProductionMBOED
$5.88 $5.96
$4.42 $4.48
$3.78
Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016
36%IMPROVEMENT
STACK Field-Level Operating Costs(1)
$/BOE
R I S K E D L O C A T I ON S
STACK DRILLING INVENTORY
(1) Includes LOE and production taxes.
STACKMeramec Results Validate Core Position
15
OverPressuredOil
LiquidsRich
Dry GasPlay Windows NormalPressuredOil
Pressure Gradient (psi/ft.) >0.75 0.75 – 0.6 0.7 – 0.45 0.45 or less
Oil-Weighted Production30-Day IPs: ≈60% oil
EURs: ≈40% oil
Custer
Dewey
Canadian
Kingfisher
Blaine
Favorable characteristics ofcore oil window:
1. Attractive reservoir properties (thickness, permeability, porosity)
2. Strong flow rates due to high pressure gradients
3. Returns enhanced by oil-weighted production
4. Low well costs
Pony Express 27-1H30-Day IP: 2,100 BOED Born Free Staggered Pilot
30-Day IP: 2,200 BOED
Scheffler 1H-9X30-Day IP: 2,000 BOED
Blurton 1-7-6XH30-Day IP: 1,800 BOED
Otto 1H30-Day IP: 1,900 BOED
Maybel 1H-13X30-Day IP: 1,900 BOED
Meramec Core
Cows Face 0805-4AH30-Day IP: 2,200 BOED
Stiles 1407 2-4MH30-Day IP: 1,900 BOED
Pump House 7-well Pattern15-Day IP: 2,200 BOED
Wort 1-21H30-Day IP: 2,400 BOEDAlma 5-Well Pilot
30-Day IP: 1,400 BOED
Parker 1-33H30-Day IP: 2,000 BOED
Compton 1-2-35XH30-Day IP: 2,200 BOED
Blue Ox 3130 -4AH24-Hour IP: 4,000 BOED
Marmot 19-1HX24-Hour IP: 3,400 BOED
Meramec ResourceBest Emerging Development Play in North America
16
Meramec inventory conservatively risked (4 wells per surface section)
>10 spacing tests underway to drive risked location count higher
― First three Devon operated spacing pilots successful (Born Free, Alma and Pump House tests)
― Testing up to 8 wells per section across 1 interval in Meramec
― Staggered lateral pilots underway could further expand potential in Meramec
(1) Does not include upside potential from other target intervals within Meramec.
RISKED LOCATIONS
MERAMEC INVENTORYRisked
MER
AM
EC Pri
mar
ySe
con
dar
y
Upside
Meramec Inventory(1)
Up to 8 wells/section3 wells/section
Up to 6 wells/section1 well/section≈4,000 UNRISKED
Woodford ShaleA Top-Tier Liquids-Rich Development
17
Well productivity improved by >100%
— Recent wells averaging up to 1,900 BOED
— Results driven by enhanced completion design
5-section Hobson row development underway
— Completion activity begins in Q3 2016
— Higher oil rates expected
Future development to leverage long laterals
Deep inventory of lower risk projects
— 3,700 risked locations
— Acreage concentrated in liquids-rich window
Custer
Dewey
Canadian
Kingfisher
Blaine
Hobson Row30-Day IPs: Expected early 2017
Woodford Core
Golden RowAvg. 30-Day IP: 1,500 BOED
Chiles RowAvg. 30-Day IP: 1,500 BOED
Gordon RowAvg. 30-Day IP: 1,600 BOED
Haley PadAvg. 30-Day IP: 1,900 BOED
Delaware BasinA World-Class Oil Play
18
Industry leader in basin
— Net risked acres by formation: 585,000
— Q2 net production: 65 MBOED
Delivering top-tier well results
Deep inventory of low-risk oil projects
— >5,000 risked locations
Accelerating activity in 2H 2016
— Up to 3 operated rigs by year end
— 2016 capital ≈$250 million
EddyLea
Bone Spring
Wolfcamp
Leonard Shale
Delaware Sands
S L O P E
B A S I N
Delaware BasinIndustry Leading Well Productivity
19
Acreage position concentrated in basin of southeast New Mexico
Delivering the most productive wells in world-class field
90-day IP rates ≈20% higher than industry average
68
3828
14 10 7 6 6 6 5 4 4 2 2
Peers
Top 200 Delaware Basin WellsBased on 90-Day IP Rates, Number of Wells
Source: IHS/Devon. Data limited to wells with 90-day rates in southeast New Mexico (as of 6/30/16). Natural gas adjusted to BOE on a 20-to-1 basis.
Delaware BasinAchieving Significant Cost Savings
20
Record-low LOE costs reduced by ≈50%
Majority of cost savings are sustainable
— Improved electrical infrastructure
— Enhanced water handling infrastructure
Drilling and completion efficiencies accelerate
— 75% increase in feet drilled per day
— Completion costs reduced ≈60%
— Well costs as low as $5 million
$16.87
$14.80
$12.62$12.00
$10.76
$8.82
Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016
≈50%IMPROVEMENT
Delaware Basin Unit LOE$/BOE
C O S T R E D U C T I O N
Bone Spring Basin Completion CostsQ4 2014 to 1H 2016
Delaware BasinSignificant Resource Opportunity
21
Identified 5,200 risked locations (>16,000 unrisked)
— Bone Spring ≈65% of risked inventory
— Wolfcamp has massive upside potential
Appraisal work evaluating resource upside
— Evaluating tighter Bone Spring spacing
— Leonard Shale has staggered lateral potential
— Wolfcamp appraisal activity to increase in 2017
Results to optimize master development plan
Note: Graphic for illustrative purposes only and not necessarily representative across Devon’s entire acreage position.
Basin Slope
DEL
AW
AR
E SA
ND
S Madera
Lower Brushy
LEO
NA
RD A
B
C
BO
NE
SPR
ING
1st
2nd
(Upper &Lower)
3rd
WO
LFC
AM
P
X/Y
A, B, C & D
Risked Location Unrisked Location
1 Section 1 Section
Delaware Basin Master Development PlanTotal Reservoir Access Concept (TRAC)
22
A disciplined development approach
— Develop up to 9 intervals of stacked-pay
— Utilizes integrated surface facilities
— Leverages simultaneous operations
— Flexibility to add/defer development zones
Efficiencies gains to drive returns higher
TRAC project progressing
— Planning complete
— Permits submitted to BLM
— Initial drilling expected in 2H 2017
Premier Asset PortfolioPlatform For Value Creation
23
Asset Risked Opportunity Upside Potential
STACK 5,300 undrilled locations
>10 spacing tests underway
Delaware Basin
>5,000 undrilled locations
Spacing tests and appraisal work ongoing
Heavy Oil 1.4 billion barrels of risked resource
Technology to improve facility performance and increase future recovery rates
Eagle Ford ≈1,000 potential locations
Upper EF delineation and staggered lateral development of Lower EF
Barnett Shale
5,000-plus producing wells
Horizontal refrac testing underway
Rockies Oil >1,000 potential locations
Further de-risking of oil fairway
Heavy Oil
Rockies Oil
Barnett Shale
STACK
Delaware Basin
Eagle Ford
Devon EnergyA Leading North American E&P
24
Thank you.
25
Forward-Looking Statements
26
This presentation includes "forward-looking statements" as defined by the SEC. Such statements include those concerning strategic plans, expectations and objectives for future operations, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. Statements regarding our business and operations are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to: the volatility of oil, gas and NGL prices, including the currently depressed commodity price environment; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; the uncertainties, costs and risks involved in exploration and development activities; risks related to our hedging activities; counterparty credit risks; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks relating to our indebtedness; our ability to successfully complete mergers, acquisitions and divestitures; the extent to which insurance covers any losses we may experience; our limited control over third parties who operate our oil and gas properties; midstream capacity constraints and potential interruptions in production; competition for leases, materials, people and capital; cyberattacks targeting our systems and infrastructure; and any of the other risks and uncertainties identified in our Form 10-K and our other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this presentation are made as of the date of this presentation, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise.
NYSE: DVNdevonenergy.com
Appendix
Canadian Heavy Oil
28
Top-tier thermal oil position
— High reservoir quality: <2.5 SOR(1)
— Massive risked resource: 1.4 BBO
Significant leverage to higher prices
— Profitable at ≈$35 WTI
— $1 increase in WTI ≈$40 MM of annualized cash flow
Jackfish complex oil production up 36% YoY
65% decline in LOE from peak rates
(1) Current steam-to-oil ratio for Jackfish complex.
Eagle Ford
29
Top-tier acreage position
— 66,000 net acres focused in DeWitt Co.
— Q2 net production: 75 MBOED (77% liquids)
Expect ≈$300 million of free cash flow in 2016
— Best-in-class well productivity
— Low-cost asset: LOE $4 per BOE
Staggered lateral development to expand inventory
Completion activity to resume in 2H 2016
— Reduce DUCs to ≈50 by year end
2 0 1 6 e F R E E C A S H F L O W
MILLION
CR
ETA
CEO
US
AUSTIN CHALK
UPPER EAGLEFORD SHALE
LOWER EAGLEFORD SHALE
BUDA
DEL RIO
Staggered Lateral Development(9-well pattern testing up to 18 wells per section)
880’440’
Rockies
30
Johnson
Campbell
Converse
Weston
Niobrara
Natrona
Premier Powder River position
— ≈470,000 net surface acres
— Q2 net production: 21 MBOED (70% oil)
Development programs delivering strong results
— Targeting Parkman, Teapot and Turner formations
Barnett Shale
31
Future Focus Area
2015/2016 RefracWise
Parker
Johnson
Hood
Tarrant
Ft. Worth
Denton
Denton Significant gas optionality
— Net acres: 610,000
— Q2 net production: 167 MBOED (26% liquids)
Focused on optimizing base production
— Concluded refrac appraisal program in 2016
— Identified 1,000 horizontal refrac locations