Q1 2016 DVN Operations Report FINALs2.q4cdn.com/462548525/files/doc_financials/... · Oil production from core assets increased 10% compared to Q1 2015 and exceeded the midpoint of

Key Takeaways …………………….....….…...……………………….....……….. 2Results Overview & Outlook ………..…………………………......……...... 3Operating Areas:

STACK .................….………….…………………………………………….…… 7Delaware Basin ...............…………………………….……………………… 10Eagle Ford …………..……………………………………………………………… 13Rockies Oil ………….………………………….………………………………….. 16Heavy Oil …………….……………………………………………………………… 18Barnett Shale ………….……………………………………………………..….. 20

Email: [email protected]

Howard J. ThillSenior Vice President, Communications and Investor Relations405‐552‐3693

Scott CoodyDirector, Investor Relations405‐552‐4735

Chris CarrSupervisor, Investor Relations405‐228‐2496

Q1 2016 OPERATIONS REPORTMay 3, 2016

NYSE: DVNdevonenergy.com

Table of ContentsIR Contacts

KEY TAKEAWAYS

Q1 2016 OPERATIONS REPORT 2

Heavy Oil

Rockies Oil

STACK

Delaware Basin

Eagle Ford

BarnettShale

HIGHLIGHTS

OPERATING HIGHLIGHTS

Exceeded midpoint expectations for all production products

Raised full‐year production guidance by 3 percent

Reduced LOE costs by 21 percent year over year

Lowered 2016 operating cost outlook by $50 million

Improved balance sheet strength with liquidity increasing to $4.6 billion

STACK delivering top‐tier results

Leonard Shale potential expands in the Delaware Basin

Eagle Ford generating substantial free cash flow

Powder River Basin delivers best‐in‐class well results

Jackfish 2 exceeds nameplate capacity

RESULTS OVERVIEW & OUTLOOK


CORE ASSETS Q1 STATSQ1 2016 Q1 2015

Production:Oil & Bitumen (MBOD) 255 231NGL (MBLD) 108 105Gas (MMCFD) 1,310 1,332Core Assets (MBOED) 581 558

E&P Capital (in millions): $363Operated Rigs (at 3/31/16): 6 (including partner rigs)

Oil Production Exceeds Expectations

Total oil production averaged 285,000 barrels per day in the first quarter. Of this amount, 255,000 barrels per day were attributable to Devon’s core assets, where investment will be focused going forward.

Oil production from core assets increased 10% compared to Q1 2015 and exceeded the midpoint of guidance by 5,000 barrels per day (chart below).

231255

Q1 2015 Q1 2016

Q1 Oil Production(MBOD)

10%Growth

Core Asset Portfolio

Overall, net production from core assets averaged 581,000 Boe per day in the first quarter, surpassing the midpoint of guidance by 6,000 Boe per day.

Raising 2016 Production Guidance

With strong production performance year to date, Devon is raising the midpoint of its 2016 production guidance by 15,000 Boe per day or 3% (table below).

2016 PRODUCTION – CORE ASSETS2016 GUIDANCE

PREVIOUS REVISEDGUIDANCE CHANGE

(Using Midpoints)

Oil & Bitumen (MBOD) 227 ‐ 237 233 ‐ 243 3%

NGL (MBLD) 95 ‐ 100 98 ‐ 103 3%

Gas (MMCFD) 1,164 ‐ 1,217 1,199 ‐ 1,252 3%

Core Assets (MBOED) 516 ‐ 540 531 ‐ 555 3%

Lowering Full‐Year Operating Cost Outlook

Successful cost‐reduction initiatives resulted in LOE costs of $7.13 per Boeor $444 million in the first quarter. This was below the company’s guidance range and represents a 21% decrease year over year (chart below).

The decrease in LOE is driven primarily by improved power and water‐handling infrastructure, declining labor expense and lower supply chain costs across the company’s portfolio.

Based on strong Q1 results and additional cost savings expected throughout 2016, Devon is lowering its full‐year LOE outlook by $50 million to a range of $1.75 to $1.85 billion.

$8.97 $9.16$8.14

$7.66$7.13

Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016

21%Improvement

Unit LOE($/BOE)

5,000 BODAbove MidpointGuidance



G&A Cost Savings Initiatives Ahead of Schedule

Devon also realized significant G&A cost savings in the first quarter. G&A totaled $194 million, a 23% improvement compared to the first quarter of 2015 as a result of lower employee‐related costs (chart below).

The company will continue to deliver meaningful G&A reductions during the year, driven by its workforce reduction program that decreased Devon’s employee count by 20% in late February.

Due to these G&A cost reduction initiatives, overhead is projected to decline by an additional 20% sequentially to ≈$160 million in the second quarter.

Due to the strong Q1 result, the company remains on track to reduce G&A costs by up to $500 million on an annual basis.

EnLink Midstream Delivers Steady Cash Flow

Devon’s midstream business generated $202 million of operating profit in Q1, driven by the company’s investment in EnLink Midstream, which provides a steady cash flow stream even with volatile commodity pricing.

Devon has a 64% ownership in the general partner (ENLC) and a 25% interest in the limited partnership (ENLK). In aggregate, the company’s ownership in EnLink is valued at ≈$3 billion and is expected to generate cash distributions of $270 million in 2016.

Balance Sheet and Liquidity Bolstered

Devon exited Q1 with $4.6 billion of liquidity, consisting of $1.6 billion of cash on hand and $3.0 billion of capacity on its senior credit facility.

Liquidity was bolstered in Q1 by a $1.5 billion secondary offering, more than offsetting cash payments associated with the Felix acquisition on 1/7/16, repayment of short‐term debt and other working capital needs.

The company exited the quarter with net debt(1) totaling $7.7 billion (excluding non‐recourse EnLink obligations). The weighted‐average cost of Devon’s outstanding debt is 5%.

Devon has managed its debt maturity schedule to provide maximum flexibility with near‐term liquidity. The company has no significant long‐term debt maturities until December 2018 (chart below).

$350 $125

$750$700

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

LT Debt Maturities – Next 5 Years(3/31/16, $ Millions)

Liquidity

Liquidity($ Millions)

$4,600

Cash

CreditFacility

2016 2017 2018 2019 2020

Asset Divestiture Programs Advance

To further enhance its financial strength, the company is targeting total divestiture proceeds of $2 billion to $3 billion.

$251

$194$160

Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016e

G&A($ Millions)

23%Decline

WorkforceReductionImpact

(1) Net debt is a non‐GAAP measure. See earnings release for a reconciliation.

Strong Returns at Lower Prices

In 2016, Devon’s top priority is to protect its balance sheet by managing capital programs to be within cash inflows.

This disciplined approach will limit the company’s capital investment in 2016 to a range of $900 million to $1.1 billion.

However, Devon has attractive incremental investment opportunities in each of its resource plays in the U.S. that can generate strong well economics at lower prices (graphic below).

30%+

15% ‐30

%0%

‐15

%



Asset Divestiture Programs Advance (continued)

In April, Devon took another important step forward in the execution of this divestiture program by announcing the sale of its non‐core Mississippian assets in Oklahoma for $200 million. The transaction is scheduled to close in Q2.

The divestiture process for the company’s remaining non‐core upstream assets in the U.S. is ongoing. Data rooms have been open since early March and bids are expected by the end of the second quarter (map below).

Devon is also marketing its 50 percent interest in the Access Pipeline in Canada and anticipates an announcement in the first half of 2016.

Incremental Well Economics($50 Oil & $2.50 Gas)

IRR –BT

AX no G&A

IRR –AT

AXw/G

&A

Delaware BasinSTACK – MeramecEagle FordRockies

STACK – WoodfordBarnett (hz. refracs)

Other Properties

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.

20%+

10% ‐20

%0%

‐10

%

Once commodity prices incentivize higher activity, Devon is well positioned to accelerate highly‐economic activity across its best‐in‐class resource plays in onshore North America.

Q1 2016 PRODUCTIONRemaining Divestiture Assets MBOED % LIQUIDS

Midland Basin 26 65%

East Texas 22 30%

Granite Wash 14 50%

Total ≈62 50%

Significant Upside to Pricing Recovery

Devon’s cash flows have significant upside in a commodity price recovery, with potential to expand margins proportionately at a faster rate than most large producers in North America.

Every $1 increase in the company’s realized oil price translates into ≈$90 million of incremental annualized cash flow(1) (graphic below).

Devon’s gas and NGL production also have significant sensitivities to higher prices. For every $0.10 improvement in the company’s realized gas price or $1 change in the company’s NGL price, Devon’s annualized cash flows are increased by ≈$45 million and ≈$35 million, respectively(1).



REALIZED PRICE INCREASE ANNUALIZED CASH FLOW INCREASE (1)

1$ Million90C

OIL

GAS

$

10 Million45$

Million35NGL $

(1) At 2016 planned production levels from core assets.

≈≈≈

Per Barrel

Per Mcf

1$Per Barrel

STACK


STACK Q1 STATSQ1 2016 Q1 2015

Production:Oil (MBOD) 14 6NGL (MBLD) 29 22Gas (MMCFD) 286 230MBOED 91 65


Net production averaged a record 91,000 Boe per day in the first quarter. This strong result represents a 39% increase in production compared to the first quarter of 2015 (chart below).

Over‐Pressured Oil Window Delivering Top‐Tier STACK Results

Upon closing of the Felix transaction, the company has the premier STACK position in the industry with 430,000 net surface acres prospective for multiple intervals in both the Meramec and Woodford formations.

Devon’s STACK acreage resides in over‐pressured portions of the play, a large portion of which is located in the oil window with excellent reservoir properties. This area has delivered the best economics in the play to date (map right).

65

91

Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016

STACK Production Growth(MBOED)

39%Increase

This growing asset is achieving one of the lowest LOE costs of any property in the company’s portfolio at $4.28 per Boe, a decline of 21% compared to the first quarter of 2015.

STACK


Over‐Pressured Oil Window Delivering Top‐Tier STACK Results (continued)

Industry has now brought online ≈140 Meramec wells, and all fluid windows in this early‐stage development play have produced strong and repeatable economic results.

However, Devon’s position from the core of the over‐pressured oil window has consistently generated best‐in‐class well results (map below).

The core of the oil window has several favorable characteristics that drive superior economics compared to other portions of the STACK play. These favorable attributes include:

1. Attractive reservoir properties (thickness, permeability, porosity)

2. Lower well costs due to shallower depths

3. Higher IP rates and EURs due to attractive pressure gradients

4. Better margins due to a higher oil production mix

A World‐Class Reservoir with Tremendous Inventory Upside

Devon has identified 5,300 risked undrilled locations across its STACK position, of which ≈30% or 1,600 gross risked locations are attributable to the Meramec formation, which has 5 producible intervals.

Of these 5 producible intervals, 3 reside in the Upper Meramec and 2 in the Lower Meramec (geologic column below). The Upper Meramec thickens as you move to the southeast, while the Lower Meramec thickens as you move to the northwest (fluid content varies as shown on the map).

Given this geology, Devon expects 3 of the 5 intervals are prospective for development in any given section. The primary, secondary, and tertiary targets can vary depending upon the well location in the field.

Overall, Devon’s undrilled location count in the Meramec is conservatively risked at only 4 wells per section.

To pursue upside, the company is testing up to 8 wells per section in the primary interval. Devon is also testing the joint development of primary and secondary targets through staggered well pilots(1).

Penn

. MORROW

SPRINGER

Mississippian

CHESTER

UPPERMERAMEC

LOWERMERAMEC

OSAGE

Dev.

WOODFORD

Up to 6 wells/section1 well/section

Meramec Inventory(1)

Risked Upside

Primary

Secondary

Tertiary Appraising in 2017

Up to 8 wells/section3 wells/section

(1) Does not include upside potential from other formations.

STACK


Successful Staggered Well Test in Over‐Pressured Oil Window

Devon recently commenced production on its first staggered spacing pilot which tested 400’ spacing between 2 intervals in the over‐pressured Meramec oil window (graphic below).

The 2‐well Born Free pilot delivered initial 30‐day production averaging 2,200 Boe per day (53% light‐oil) per well and outperformed the company’s type curve expectations by 70% (chart below).

Importantly, initial results from the Born Free wells indicate fractures are contained to each targeted interval with minimal interference.

Meramec Delivers High‐Rate Development Wells

In addition to the successful Born Free pilot, Devon commenced production on 5 operated Meramec wells across the various windows of the play to hold acreage in Q1. 30‐day rates averaged 1,600 Boe per day, of which 63% was oil.

These initial flow rates exceeded Devon’s type curve by more than 20% and initial oil recoveries are trending above expectations.

This operated activity was highlighted by the Cows Face 0805‐4AH in the over‐pressured oil window that achieved a 30‐day rate of 2,150 Boe per day (72% oil).

The company also participated in 5 noteworthy non‐operatedwells that achieved peak 30‐day rates during the quarter. The wells were primarily focused in the oil windows of the STACK and attained flow rates of 1,700 Boe per day (57% oil).

Gordon Row Delivers Outstanding Woodford Shale Results

In addition to the company’s emerging Meramec development, Devon also has a world‐class liquids‐rich gas development in the Woodford Shale, which sits directly below and is the source rock for the Meramec.

During Q1, Devon reached peak rates for all 57 wells from the 7‐section Gordon Row in northeastern Canadian County.

Initial 30‐day rates from the 28 wells that reached peak rates during the first quarter averaged 1,600 Boe per day, of which 54% was liquids.

At peak rates, the gross monthly production from the Gordon Row reached nearly 300 MMcfe per day, exceeding Devon’s forecast by 30%.

Devon and its partner are now developing the 5‐section Hobson Row to the south of the Gordon Row in Canadian County. At the end of March, all 39 wells have been drilled. A decision on the timing of completion activity will be made in the upcoming months.

1,300

2,200

Type Curve Born Free

Staggered Test 30‐Day IP Results (BOED)

≈70%Higher

2‐Well Pilot

0

100

200

300

1 2 3 4 5 6

Gordon Row Gross Gas Uplift

MMCFD

Months

ActualForecast

≈30%Outperformance

Born Free Staggered Test

MER

AMEC

Prim

ary

Second

ary

≈400’

≈170’

DELAWARE BASIN

Q1 2016 OPERATIONS REPORT

DELAWARE BASIN Q1 STATSQ1 2016 Q1 2015


E&P Capital (in millions): $79Operated Rigs (at 3/31/16): 0

10

Net production averaged 63,000 Boe per day, a 21% increase compared to the first quarter of 2015 (chart below).

Significant LOE Savings Enhances the Value of Production

Devon continued to make significant progress lowering operating costs in the first quarter. LOE declined to $62 million or $10.76 per Boe, a decline of 36% from peak rates in early 2015 (chart right).

Driving the decrease in LOE are improved water‐handling infrastructure and lower power costs. The company has reduced disposal costs by investing in water handling infrastructure that now services 70% of its produced water in the Delaware Basin.

Devon has also converted the majority of its wells to electrical power which has reduced the use of rental generators in southeast New Mexico by 80%.

52

63

Q1 2015 Q1 2016

21%Growth

Delaware Basin Production(MBOED)

$16.87

$14.80

$12.62 $12.00$10.76

Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016

36%Improvement

Looking ahead, the company expects LOE costs to steadily decline throughout the remainder of year, exiting Q4 2016 with LOE costs trending toward $50 million.

Delaware Basin Unit LOE($/BOE)

Gua

d.

BRUSHY CANYON

Leon

ardian

LEONARDSHALE

LANDING INTERV

AL A

B

C

1ST BONE SPRING

2ND BONE SPRING

DELAWARE BASIN


Leonard Shale Program Outperforming Expectations

First‐quarter drilling activity in the Delaware Basin was highlighted by another outstanding Leonard Shale well in Lea County, New Mexico. The Thistle Unit 30‐H, which was landed in the Leonard “B” interval, achieved a 30‐day IP of 2,300 Boe per day, of which 80% was light oil.

Since mid‐last year, Devon has had success in this early‐stage development play with 3 high‐rate wells brought online (map below). In aggregate, these Leonard wells have averaged 30‐day rates of 1,900 Boe per day.

Based on results from these wells and other non‐operated activity in the area, Devon is raising its Leonard Shale type curve. IP rates and EURs are expected to be 65% and 25% higher than previous estimates, respectively (table below).

Leonard Shale Potential Expands

Devon has 60,000 net surface acres in the core of the Leonard Shale play, with a gross pay interval up to 1,100’ thick in some areas and as many as 3 different landing intervals (geologic column above right).

With the company’s recent success and the positive industry results adjacent to its leasehold, Devon is increasing its Leonard Shale risked location count by 15% to 800 risked locations (conservatively assumes 5 wells per section).

Leonard Shale Type WellKey Modeling Stats

30‐Day IPBOED

1,000

EURMBOE

500

D&C Cost$MM

$5 – 5.5

Oil% of EUR

≈50%

WI / NRI 63% / 50%

With industry activity in the area testing staggered wells spacing pilots as tight as 330 feet, Devon’s risked Leonard inventory has the potential to substantially expand over time (identified 3,100 unrisked locations).

Other Noteworthy Q1 Activity

Other noteworthy new well activity in Q1 included 9 wells across the basin and slope regions of the Delaware Basin.

In the over‐pressured basin of southeast New Mexico, Devon brought online 3 Bone Spring wells and a Delaware Sands well during the quarter. The 30‐day rates from these wells averaged nearly 1,000 Boe per day, with light‐oil accounting for roughly 80% of the production mix.

On the slope in the northern portion of the Delaware Basin, production commenced on 5 Bone Spring wells with initial 30‐day rates averaging 575 Boe per day. These slope wells, which are generally lower cost than the basin, exceeded the company’s IP rate expectations by 15%.

Rig Productivity Soars

Rig productivity for its Bone Spring program in the basin improved to a record‐high of 914 feet drilled per day in the first quarter of 2016. This represents an increase of >60% since the first half of 2015 (chart next page).

L E O N A R D S H A L E

INCREASE RISKEDLOCATIONS

DELAWARE BASIN


Rig Productivity Soars (continued)

The company’s recent Leonard Shale drilling has also achieved significant improvements with productivity gains in excess of 80% over the prior year.

Average Feet Drilled Per Day Bone Spring

569

914

1H 2015 Q1 2016

Average Feet Drilled Per Day Leonard Shale

>60%Increase InProductivity

429

790

1H 2015 Q1 2016

>80%Increase InProductivity

Inventory Attractively Positioned on Marginal Cost Curve

Devon has one of the best Delaware Basin positions in the industry with stacked‐pay potential providing exposure to the Delaware Sands, Leonard Shale, Bone Spring, and Wolfcamp formations that is well positioned on the marginal cost curve (see incremental well economics table, pg. 5).

Adding up leasehold by formation, the company has exposure to 585,000 risked net acres, with 5,200 risked undrilled locations and >16,000 unrisked locations in this world‐class basin (table above right).

To optimize future development plans and expand risked inventory, Devon is evaluating tighter spacing in the Bone Spring and Leonard Shale, and appraising the Wolfcamp formation.

Information from the spacing and appraisal tests will help Devon optimize its master development plan in the Delaware Basin and provide valuable information to maximize returns in various commodity and service cost environments.

2016 Program: A Disciplined Development Approach

In an effort to conserve cash flow, the company has limited its capital spending program in the Delaware Basin to around $200 million in 2016.

This disciplined capital program is focused on developing the 2nd Bone Spring and Leonard opportunities, which are delivering some of the best returns in Devon’s portfolio.

Appraisal drilling in the Wolfcamp formation (which possesses massive upside potential) will be limited in 2016 as capital is focused on the best development opportunities to maximize returns and cash flow.

Once commodity prices incentivize higher activity levels, the Delaware Basin will be one of the first areas in Devon’s portfolio to add incremental activity given the strong well economics available at the Bone Spring, Leonard Shale and Delaware Sands.

FormationRiskedNetAcres

RiskedGrossLocations

UnriskedGrossLocations

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 (Yeso & Strawn) 20,000 200 200

Total 585,000 5,200 16,300

EAGLE FORD


EAGLE FORD Q1 STATSQ1 2016 Q1 2015



Devon delivered solid operating results in Q1 with net production of 107,000 Boe per day and operating costs of $58 million, an 18% reduction year over year.

Base Production Initiatives Yielding Excellent Results

First‐quarter production was notably enhanced by improvements in controllable downtime from existing wells to a record low of just 0.9%, an improvement of >65% compared to the first half of 2015 (chart below).

2.7%

1.6%

0.9%

1H 2015 2H 2015 Q1 2016

Eagle Ford – Controllable Downtime (Percent of Production)

Eagle Ford Generates Substantial Free Cash Flow

This positive operating trend helped the Eagle Ford achieve the highest per‐unit margin of any Devon asset. Cash operating margin for the quarter averaged $13 per Boe, with margins approaching 70% of upstream revenue.

Even with the lower commodity prices in the first quarter, Devon’s Eagle Ford assets generated $78 million of free cash flow and remain on pace to deliver >$250 million of free cash flow in 2016, based on recent strip pricing (4/26/16).

>65%Improvement

Q1 HIGHLIGHTS

18%Yr.‐Over‐Yr.

78Million$

OPERATING COSTS

FREE CASH FLOW

EAGLE FORD


Delivering Best Wells in World‐Class Field

The Eagle Ford is one of the top oil resource plays in North America and Devon’s leasehold in DeWitt County resides in the economic core of this prolific field.

Since early 2015, the company’s 90‐day rates in DeWitt County have averaged nearly 1,200 Boe per day, exceeding the industry average across the Eagle Ford by more than 60%.

On a value basis, utilizing a gas‐to‐oil conversion ratio of 20‐to‐1, Devon’s 90‐day rates are even more differentiated. The company’s average well is double the peer average and it operates 81 of the top 150 wells from this world‐class field since 2015, the highest of any operator by a wide margin (chart below).

Devon continued this trend of excellence in the second quarter by adding 22 new Lower Eagle Ford wells to production in DeWitt County with initial 30‐day production rates averaging 1,700 Boe per day (map previous page).

Devon and its partner are also delivering meaningful improvements with completion operations. Since last year, the operating teams have increased frac stages per day by around 50% and reduced equipment move times by greater than 40%.

Base Production Initiatives Yielding Excellent Results (continued)

A noteworthy driver of this performance was a successful gas lift initiative that enhanced production uptime across the field.

Drilling times improved by >55% compared to the 2014 average, with a record rate of 26 wells per rig line per year achieved in the most recent quarter (chart below).

16.6

22.7

26.1

2014 Avg 2015 Avg Q1 2016

Wells Per Rig Per Year – DeWitt County

>55%Efficiency Improvement

Avg. Stages Per Day Avg. Move Time(Days)

3.4

5.0

Q1 2015 Q1 2016

≈50%Increase

2.6

1.5

Q1 2015 Q1 2016

>40%Reduction

81

2816 8 6 5 2 2 1 1

Top‐150 Eagle Ford Wells(Number of Wells)

PeersSource: IHS/Devon.

Eagle Ford Efficiencies Accelerate

The company’s low‐risk infill drilling program in DeWitt County continues to achieve significant efficiencies with its drilling and completion operations.

Staggered Lateral Infill Program Progressing

Due to the quality and thickness of the Eagle Ford reservoir, Devon is improving recoveries in DeWitt with a staggered lateral infill program.

EAGLE FORD


Staggered Lateral Infill Program Progressing (continued)

The current infill program is drilling staggered wells with spacing of 440 feet, increasing the potential for up to 12 wells per section in the lower Eagle Ford. This spacing estimate does not include any upside potential in highly prospective up‐hole zones.

The impact of reduced completion activity coupled with planned infrastructure downtime for maintenance is expected to limit Eagle Ford production in the second quarter to around 80,000 Boe per day.

Looking to the second half of 2016, the partnership expects to run on average 2‐3 rigs and a completion crew. This level of activity is projected to stabilize production at Q2 levels for the remainder of the year.

For the full‐year 2016, Devon remains on pace to invest around $200 million of capital into DeWitt County and, should conditions incentivize higher activity levels, operating teams are prepared to accelerate activity from this high‐returning asset.

To date, results from the staggered lateral wells have shown minimal pressure depletion impact to offsetting wells. Due to this positive result, Devon expects production and EURs from staggered lateral developments to remain comparable with recent high‐rate development wells in the play.

The company is currently implementing this development scheme in undeveloped portions of southwestern DeWitt County and has drilled >20 wells through the first quarter of 2016 (map previous page). Flow rates from these pads are expected in late 2016 and early 2017.

Updated 2016 Outlook

At the end of February, the company’s partner in DeWitt County elected to temporarily delay completion activity until mid‐year. As a result, the company’s inventory of Eagle Ford wells waiting to be placed online is expected to increase to approximately 90 wells by the end of the second quarter.

Cretaceo

us

AUSTIN CHALK

UPPER EAGLE FORD MARL

UPPER EAGLE FORD SHALE

LOWER EAGLE FORDSHALE

BUDA

DEL RIO

Staggered Lateral Development(Up to 12 wells/section)

880’440’

1 Section

Rockies Oil Production(MBOD)

ROCKIES OIL


ROCKIES OIL Q1 STATSQ1 2016 Q1 2015



Net production for retained assets averaged 23,000 Boe per day, a 22% increase compared to the first quarter of 2015.

Overall, Q1 Rockies oil production increased 39% year over year (chart below). This result was driven primarily by growth in the Powder River Basin.

With the increase in high‐quality oil production (≈40 degree API), oil now accounts for 86% of revenues in the Rockies (chart below).

Q1 2015 Q1 2016

12

17

39%Growth

PRB CO2

86%

3%11%

Oil NGL Gas

Powder River Position Delivering Best‐In‐Class Results

The company’s Powder River Basin leasehold of 470,000 net acres is the largest and highest‐quality acreage position in the basin, and Devon’s development programs have consistently delivered best‐in‐class results.

Since 2015, Devon’s initial 90‐day rates have been more than 40% higher than the industry average across the Powder River Basin (chart below).

0

160

320

480

640

Powder River 90‐Day Wellhead IPs(BOED, 20:1)

Source: IHS/Devon. Wellhead rates for operated wells online for 90 days beginning Q1 2015.

639

Peers

Average: 440 BOED

Rockies Revenue Mix(Q1 2016)

Powder River – Average Feet Drilled Per Day

ROCKIES OIL


Powder River Position Delivering Best‐In‐Class Results (continued)

The company is also delivering industry‐leading drilling results in the basin over this period with drilling productivity 64% greater than the peer average (chart below).

539

885

Peer Avg.

Turner Appraisal Wells Highlight Q1 Activity

New well activity in the Powder River was highlighted by two appraisal wells targeting the Turner formation on the company’s recently acquired acreage in Converse County, Wyoming.

Initial 30‐day rates from these two standard‐length lateral wells in the Cottonwood Draw unit averaged 850 Boe per day, of which 85% was light oil. When normalized for extended‐reach laterals, which is the likely well design in development mode, these wells are estimated to reach 30‐day rates around 1,500 Boe per day.

These encouraging appraisal results further affirm the significant Turner potential in the southern portion of the Powder River oil fairway.

Production growth from the Big Sand Draw project is projected to accelerate in the second half of 2016 and achieve a peak rate approaching 5,000 barrels of oil per day in early 2017.

Post ramp‐up, Big Sand Draw will maintain a steady production profile for ≈20 years with minimal capital requirements. The company has a 98% working interest and a 75% net revenue interest in the project.

Combined with the company’s Madison CO2 facility, which is fully operational, production from the Wind River Basin is expected to achieve peak rates of around 8,000 Boe per day.

CO2 Project Ramp‐Up Progressing

Last June, Devon commenced operations at its Big Sand Draw CO2 facility in the Wind River Basin and the company expects production from this project to reach rates in excess of 3,000 barrels of oil per day during the first half of 2016.

PERFORMANCEGREATER DRILLING

Source: IHS/Devon. Data includes results since the beginning of 2015.

2016 Outlook

While the company is achieving strong operational results from its Powder River Basin development program, Devon has elected to limit its capital spending to around $75 million in 2016 to conserve cash flow.

For the remainder of the year, the company will be focused on integrating its recently acquired acreage in the southern portion of the Powder River oil fairway.

This integration work will be centered on re‐permitting future development locations from standard to extended‐reach laterals. Additional geologic and reservoir modeling is also underway to help high‐grade the opportunity set.

HEAVY OIL


HEAVY OIL Q1 STATSQ1 2016 Q1 2015

Production:Oil & Bitumen (MBOD) 126 104Gas (MMCFD) 15 28MBOED 129 109


Driven by growth at the Jackfish complex, net oil production in Canada averaged 126,000 barrels per day in the first quarter. This represents a 22% increase compared to the first quarter of 2015.

Record‐Low Costs Achieved at Jackfish Complex

At the Jackfish complex, LOE has now declined 65% from peak rates. Key drivers of this strong result were higher volumes at Jackfish 2 and 3, declining fuel costs, lower labor expense and exchange rates (chart below).

$22.44

$18.15

$14.04

$17.43

$10.10 $9.63$7.87

Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016

Jackfish Complex Unit LOE($/BOE)

≈65%Improvement

Jackfish 1Turnaround

The quality of the Jackfish complex is further demonstrated by resilient cash flows at lower prices. Jackfish can cover operating cash costs with WTI oil prices as low as $35 per barrel and operating cash flow can approach up to $500 million annually at a $50 WTI price point (chart below).

The company’s heavy oil projects are also significant cash flow generators. Since first production occurred at the Jackfish complex in late 2007, these industry‐leading projects have generated more than $3 billion of cumulative cash flowfrom operations (chart right).

Operating Cash Flow Sensitivities

$0

$100

$200

$300

$400

$500

$35 $40 $45 $50Increm

ental Cash Flow

($ M

M)

WTI ($/Bbl)

Cash Flow Since 2007

Value

Jackfish 1

Jackfish 2

Jackfish 3$3.1 Billion

Jackfish Complex

12‐MonthStrip Pricing

Note: 12‐month strip as of 4/26/16.

HEAVY OIL


A Top‐Tier Thermal Oil Position

Devon’s thermal oil assets in Canada have several favorable characteristics that position the company’s projects to deliver attractive full‐cycle returns.

These positive attributes include good oil saturation, predictable geology, low operating costs, minimal capital requirements to maintain a flat production profile and a long reserve life of 20 to 30 years.

At year‐end 2015, Devon’s thermal leasehold had 520 million barrels of reserves booked with more than 1.4 billion barrels of risked resource (chart below). For perspective, Devon has only produced 0.1 billion barrels over the past decade.

This increase in production was driven by the successful ramp‐up from two new well pads that began steaming in late 2015. This boosted production at Jackfish 2 by greater than 40% over the past few months.

At Jackfish 1, gross production averaged 29,300 barrels per day in the first quarter of 2016 or 29,100 barrels per day after royalties.

A new well pad at Jackfish 1 is in the process of ramping‐up and expected to offset declines from older pads and boost production throughout the remainder of 2016. Produced Net Risked Resource Potential

Jackfish Complex

Pike

Produced2007 – Q1 2016

Net RiskedResource Potential

0.1

1.4

Q2 Production Outlook

Beginning in June, the company will bring its Jackfish 2 facility down for a scheduled 21‐day maintenance period that is expected to curtail heavy‐oil production by approximately 10,000 barrels per day in Q2.

As a result, Devon expects net oil production from its heavy‐oil operations to range between 122,000 and 127,000 barrels per day in the second quarter. The mid‐point of this forecast represents a growth rate in excess of 25% compared to the second quarter of 2015.

26.9

38.5

Nov‐15 Dec‐15 Jan‐16 Feb‐16 Mar‐16

Jackfish 2 Gross Production Ramp‐Up(MBOD)

Thermal Heavy Oil Resource(BBO)

Jackfish 3 Production Reaches 40,000 Barrels Per Day

Gross production at Jackfish 3 exceeded name‐plate capacity averaging 40,000 barrels per day in the first quarter. Net production averaged 39,800 barrels per day, an increase of more than 175% compared to the year‐ago quarter.

This impressive growth was driven by facility uptime of nearly 100% and strong reservoir performance. These factors make Jackfish 3 one of the most efficient thermal oil projects in the industry with a steam‐oil‐ratio of 2.2.

Jackfish 2 Exceeds Nameplate Capacity

Gross production at Jackfish 2 exceeded nameplate capacity of 35,000 gross barrels per day in March (chart below). For the first quarter, net production averaged 31,900 barrels per day, 19% higher than Q4 2015.

JackfishProvedReserves

(at 12/31/15)

>40%Increase

BARNETT SHALE


BARNETT SHALE Q1 STATSQ1 2016 Q1 2015



Net production averaged 168,000 Boe per day or 1.0 Bcfe per day in the first quarter. Liquids accounted for 26% of the production mix.

This strong production result was driven by contributions from the company’s horizontal refrac program and improvements in controllable downtime which declined to as low as 0.5% during the quarter.

Since mid‐2015, Devon has been able to successfully limit Barnett production declines to less than 5% with minimal capital spending of only $20 million per quarter.

Operating Costs Continue to Decline

Devon’s Barnett properties delivered another strong cost performance during the first quarter. LOE costs totaled $93 million or $1.01 per Mcfe in Q1. This represents a decline of $20 million or 18% compared to peak rates in 2014.

The company expects to achieve additional LOE cost savings through the remainder of 2016 due to renegotiated compression rates, additional water disposal savings, and declining chemical expenses.

Horizontal Refrac Program Delivering Consistent Results

First‐quarter activity was highlighted by three re‐stimulated horizontal wells that delivered an average 30‐day production uplift per well of 1 MMcfe per day, increasing production per well to 1.4 MMcfe per day.

Devon has now successfully concluded its initial horizontal refrac appraisal program in the Barnett Shale and has compiled data on more than 30 wells across the field since early 2015 (map right).

NOTABLE HORIZONTAL REFRACS

1.9Avondale Heights 6H

MMCFEDUplift

2.4Jerome Russell 1H

MMCFEDUplift

BARNETT SHALE


Horizontal Refrac Program Delivering Consistent Results (continued)

The average per‐well uplift from this 30‐well appraisal program was approximately 1 MMcfe per day, with leading wells delivering peak rates well above this average (map previous page).

Focused Development Program to Boost Refrac Results

The company’s successful horizontal refrac appraisal program in the Barnett has derisked a multi‐year inventory of high‐quality, low‐risk locations.

In development mode, Devon is raising its type‐curve expectations by targeting horizontal refrac costs of less than $1 million per well, with a 30‐day IP uplift of 1 MMcfe per day and reserve adds of 2 Bcfe per well (chart below).

0

250

500

750

1,000

1,250

0 1 2 3 4 5

Horizontal Refrac Type Well

MCFED

Years

Key Modeling Stats

30‐Day IP Uplift 1 MMCFED

Reserve Adds 2 BCFE

Capital Cost <$1 MM

IRR ≈15% (1)

(1) Assumes flat pricing of $2.50 per Mcf with each well burdened for corporate overhead and taxes.

Positioned to Unlock Significant Value

When conditions incentivize higher activity levels, Devon is prepared to resume its refrac programs in the Barnett where the company operates approximately 5,000 producing wells in the best part of the field.

In addition to the meaningful upside to higher recoveries, the Barnett Shale also has significant leverage to an improving commodity price environment.

Every 25‐cent increase in natural gas price translates into an additional $75 million of incremental annualized cash flow (at planned production rates for 2016).

FOR EVERY

HENRY HUB INCREASE

INCREMENTAL

ANNUALIZED CASH FLOW

Barnett Cash Flow Sensitivity

After burdening with taxes and overhead, this development type curve is expected to generate a rate of return around 15% at a flat Henry Hub price of $2.50 per Mcf.

≈

INVESTOR NOTICES & RISK FACTORS


Forward‐Looking Statements: Some of the information provided in this report includes “forward‐looking statements” as defined by the U.S. Securities and Exchange Commission (SEC). Forward‐looking statements 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. Such statements concerning future performance or events are subject to a variety of risks and uncertaintiesthat could cause actual results to differ materially from the forward‐looking statements contained herein. Certain risks and uncertainties are described below in more detail as well as in the “RiskFactors” section of our most recent Form 10‐K and under the caption “Forward‐Looking Statements” in the related earnings release included as an exhibit to our Form 8‐K furnished May 3, 2016.The forward‐looking statements provided in this report are based on management’s examination of historical operating trends, the information which was used to prepare reserve reports andother 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 anduncertainties 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 including the currentlydepressed commodity price environment, inflation or lack of availability of goods and services, environmental risks, drilling risks, political changes, changes in laws or regulations, the uncertaintyinherent 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 arebased 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 gasand 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 tocontrol or predict. Worldwide and regional economic conditions, weather and other local market conditions influence the supply and the level of world‐wide demand for energy commodities. Inparticular, concerns about the level of global crude‐oil and natural‐gas inventories, the production trends of significant oil producers like OPEC, among other things, have led to a significant drop inprices since the second‐half of 2014. 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 aspricing 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 forprofitable 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 governmentroyalties 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 theassumption 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, therecan 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 theexpected 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, deferred oreliminated 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 anticipatedamounts, 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 anduncertainties 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.

Cautionary Note to InvestorsThe 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 costsensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This report may contain certain terms, such as resource potential, 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 andaccordingly 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 toconsider 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 obtainthis form from the SEC by calling 1‐800‐SEC‐0330 or from the SEC’s website at www.sec.gov.

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