Dvn august-investor-presentation

1. NYSE: DVN
devonenergy.com
Business Update
August 2016

2. Investor Contacts & Notices
2
Investor Relations Contacts
Howard J. Thill, Senior Vice President, Communications & Investor Relations
(405) 552‐3693 / howard.thill@dvn.com
Scott Coody, Director, Investor Relations
(405) 552‐4735 / scott.coody@dvn.com
Chris Carr, Supervisor, Investor Relations
(405) 228‐2496 / chris.carr@dvn.com
Forward‐Looking Statements
This 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 Information
This 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.

3. Devon Today
A Leading North American E&P
3
Key Messages
 Premier asset portfolio
— Focused in top‐tier resource plays
— Deep inventory of opportunities
 Significant financial strength
 Delivering top‐tier results
 Disciplined capital allocation
Heavy Oil
Rockies Oil
Barnett Shale
STACK
Oil
44%
NGL
19%
Gas
37%
Retained Asset Production
Forecasted 2016: 558 ‐ 578 MBOED
Delaware Basin
Eagle Ford

4. Approach To The Current Environment
4
 Invest within cash flow
 Divestitures to enhance financial strength
 Achieve additional operating cost savings
 Further increase capital productivity
 Accelerate activity in STACK and Delaware Basin
 Preserve continuity in other U.S. resource plays

5. Successful Asset Divestiture Program
Enhancing Financial Strength
5
Midland Basin
$1.0 Billion
Expected close: Q3 2016
San Juan Basin
Undisclosed Value
Closed
Access Pipeline
$1.1 Billion
Expected close: Q3 2016
Granite Wash
$0.3 Billion
Closed
 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 Billion
Closed
East Texas
$0.5 Billion
Closed

6. 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
 Tender offers outstanding to repurchase debt
― $1.2 billion program underway
― Targeting near term maturities
$8.7
$4.7
Jan. 2016 Current
Net Debt(2)
$ Billions
>45%
DECLINE
(1) Cash balance adjusted for asset divestitures that have closed and those 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 asset
divestitures that have closed and those expected to close in Q3 2016.
PRO‐FORMA LIQUIDITY
BILLION

7. 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 AT 6/30/16

8. 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

9. 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 IPs
BOED, 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 IPs
BOED, 20:1
≈250%
INCREASE

10. Achieving Significant Cost Savings
10
D&C Well Cost Declines
Peak 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
≈$1B
SAVINGS
$3.7
$2.7 ‐ $2.9
LOE
Prod. Taxes
G&A
(1) Includes capitalized G&A.

11. Disciplined Capital Allocation
Yielding Strong Results
11
37%
21%
17%
15%
10%
STACK
Delaware
Basin
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

12. Strong Returns At Lower Prices
12
IRR –BTAX no G&A
IRR –ATAXw/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 Economics
At $50 Oil & $2.50 Gas
Delaware Basin
STACK – Meramec
Eagle Ford
Rockies
STACK – Woodford
Barnett (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%

13. STACK
Best‐In‐Class Position
13
Canadian
Kingfisher
Blaine
Hunton
Woodford
Mississippian
Chester
Springer
Morrow
DevonianPenn.
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

14. STACK
A Multi‐Decade Growth Opportunity
14
Largest leasehold position of any operator
Advantaged cost structure
Strong production growth
Significant resource
430,000
265,000
203,000 171,000
130,000
83,000
STACK Acreage
Net Acres
Peers
Source: Company reports.
59
91
Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016
54%
INCREASE
STACK Production
MBOED
$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
RISKED LOCATIONS
STACK DRILLING INVENTORY
(1) Includes LOE and production taxes.

15. STACK
Meramec Results Validate Core Position
15
Over
Pressured
Oil
Liquids
Rich
Dry GasPlay Windows Normal
Pressured
Oil
Pressure Gradient (psi/ft.) >0.75 0.75 – 0.6 0.7 – 0.45 0.45 or less
Oil‐Weighted Production
30‐Day IPs: ≈60% oil
EURs: ≈40% oil
Custer
Dewey
Canadian
Kingfisher
Blaine
 Favorable characteristics of
core 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 27‐1H
30‐Day IP: 2,100 BOED Born Free Staggered Pilot
30‐Day IP: 2,200 BOED
Scheffler 1H‐9X
30‐Day IP: 2,000 BOED
Sidney 1H
30‐Day IP: 1,700 BOED
Blurton 1‐7‐6XH
30‐Day IP: 1,800 BOED
Compton 1‐2‐35XH
30‐Day IP: 2,200 BOED
Alma 5‐Well Pilot
30‐Day IP: 1,400 BOED Otto 1H
30‐Day IP: 1,900 BOED
Parker 1‐33H
30‐Day IP: 2,000 BOED
Maybel 1H‐13X
30‐Day IP: 1,900 BOED
Cows Face 0805‐4AH
30‐Day IP: 2,200 BOED
Stiles 1407 2‐4MH
30‐Day IP: 1,900 BOED
Wort 1‐21H
30‐Day IP: 2,400 BOED
Meramec Core

16. Meramec Resource
Best 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 two Devon operated spacing pilots successful (Born Free and Alma 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 INVENTORY
Risked
MERAMEC
PrimarySecondary
Upside
Meramec Inventory(1)
Up to 8 wells/section3 wells/section
Up to 6 wells/section1 well/section
≈4,000 UNRISKED

17. Woodford Shale
A 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 Row
30‐Day IPs: Expected early 2017
Woodford Core
Golden Row
Avg. 30‐Day IP: 1,500 BOED
Chiles Row
Avg. 30‐Day IP: 1,500 BOED
Gordon Row
Avg. 30‐Day IP: 1,600 BOED
Haley Pad
Avg. 30‐Day IP: 1,900 BOED

18. Delaware Basin
A 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
Eddy
Lea
Bone Spring
Wolfcamp
Leonard Shale
Delaware Sands
S L O P E
B A S I N

19. Delaware Basin
Industry 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
38
28
14 10 7 6 6 6 5 4 4 2 2
Peers
Top 200 Delaware Basin Wells
Based 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.

20. Delaware Basin
Achieving 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 Costs
Q4 2014 to 1H 2016

21. Delaware Basin
Significant 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
Formation
Net Risked
Acres
Gross Risked
Locations
Gross Unrisked
Locations
Delaware Sands 80,000 700 1,500
Leonard Shale 60,000 800 3,100
Bone Spring 285,000 3,500 5,700
Wolfcamp 140,000 Appraising 5,800
Other 20,000 200 200
Total 585,000 5,200 16,300

22. Canadian Heavy Oil
22
 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.

23. Eagle Ford
23
 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
2016e FREE CASH FLOW
MILLION
CRETACEOUS
AUSTIN CHALK
UPPER EAGLE
FORD SHALE
LOWER EAGLE
FORD SHALE
BUDA
DEL RIO
Staggered Lateral Development
(9‐well pattern testing up to 18 wells per section)
880’440’

24. Premier Asset Portfolio
Platform For Value Creation
24
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

25. Devon Energy
A Leading North American E&P
25

26. Thank you.
26

27. Forward‐Looking Statements
27
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.

28. NYSE: DVN
devonenergy.com
Appendix

29. Rockies
29
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

30. Barnett Shale
30
Future Focus Area
2015/2016 Refrac
Wise
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