Q2 2015 DVN Operations Report MASTER - s2.q4cdn.com · Q2 2015 OPERATIONS REPORT PERMIAN BASIN Q2...

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

Permian Basin ..….………………………………………………………….…… 5Eagle Ford …………..……………………………………………………………… 9Heavy Oil …………….……………………………………………………………… 12Anadarko Basin …….…………………………………….……………………… 14Barnett Shale ………….……………………………………………………..….. 17Rockies Oil ………….………………………….………………………………….. 19

Email: [email protected]

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

Scott CoodyDirector, Investor Relations405‐552‐4735

Shea SnyderDirector, Investor Communications405‐552‐4782

Q2 2015 OPERATIONS REPORTAugust 4, 2015

NYSE: DVNdevonenergy.com

Table of ContentsIR Contacts

KEY TAKEAWAYS

Q2 2015 OPERATIONS REPORT 2

HIGHLIGHTS

Oil production exceeded expectations for the 4th consecutive quarter

On track to deliver full‐year 2015 production targets

Improved operating cost and capital spending outlook

Harvested $1.1 billion of value from EnLink

Devon reveals newest midstream drop‐down candidate

HIGHLIGHTS BY OPERATING AREA

Permian: Bone Spring outperforms expectations; Well costs decline >30%

Permian: Delaware Sands type curve raised

Eagle Ford: Best‐in‐class well results

Heavy Oil: Production growth driven by Jackfish 3

Anadarko Basin: Record‐setting pad online at Cana; Lower well costs

Anadarko Basin: Accelerating Meramec activity

Barnett Shale:Massive refrac potential

Rockies Oil: Powder River delivers high‐rate development wells

Rockies Oil

Anadarko Basin

Eagle Ford

Permian Basin

Oil AssetsLiquids‐Rich Gas Assets

Heavy Oil

Barnett Shale

RESULTS OVERVIEW & OUTLOOK


TOTAL COMPANY Q2 STATSQ2 2015 Q2 2014*

Production:Oil (MBOD) 270 205NGL (MBLD) 134 130Gas (MMCFD) 1,627 1,712MBOED 674 620

E&P Capital (in millions): $882Operated Rigs (at 6/30/15): 23

* Excludes non‐core divested assets.

Oil Production Exceeds Expectations for 4th Consecutive Quarter

Oil production averaged 270,000 barrels per day in the second quarter of 2015. This represents a 32% increase compared to the second quarter of 2014 (chart below), surpassing the midpoint of guidance by 5,000 barrels per day. The company has now exceeded expectations for 4 consecutive quarters.

The most significant growth came from the company’s U.S. operations, where oil production averaged a record high 172,000 barrels per day. This result was 35% higher than the year‐ago quarter and exceeded the top end of guidanceby 2,000 barrels per day.

Devon also achieved strong growth from its heavy oil operations in Canada. Driven by the ramp‐up of its Jackfish 3 facility, Canadian net oil production increased 27% compared to the year‐ago quarter, to 98,000 barrels per day.

Overall, net production averaged 674,000 Boe per day, 9% higher than the second quarter of 2014.

With strong growth in oil production, more than 70% of upstream revenue is derived from oil, which is the company’s highest margin product. Notably, ethane and propane (C2 & C3) account for only 3% of revenue (chart above).

Q2 2014 Q2 2015

Q2 Oil Production(1)(MBOD)

205

270

32%Growth

U.S. Canada

75%

3%3% 19%

Q2 Upstream Revenue(2)

OilC2 & C3

Gas

(1) Excludes non‐core divested assets.

C4 & C5

Cost Reduction Initiatives Drive Strong Q2 Results

Devon has several cost reduction initiatives underway that positively impacted Q2 results. Field‐level operating costs, which include LOE and production taxes, declined 8% to $11.05 per Boe compared to Q2 2014.

Devon also reduced G&A costs during the quarter. G&A totaled $3.45 per Boe, a 16% decline quarter over quarter. This strong cost result was 15 cents below the low end of company guidance.

Based on year‐to‐date cost savings, Devon now expects field‐level operating costs and G&A to decline to around $14.50 per Boe for the full‐year 2015. Compared to the company’s original mid‐point guidance in February, this implies a full‐year cost savings of around $400 million (chart below).

Original Guidance Revised Guidance

2015e Field‐Level Operating Costs and G&A(Using Midpoints, $/BOE)

≈$400MMCost Savings

$16.10≈$14.50

G&A

Prod. Taxes

LOE

(2) Includes hedging cash settlements.

RESULTS OVERVIEW & OUTLOOK


The EnLink Advantage: $1.1 Billion of Value Harvested

In the first half of 2015, Devon utilized its strategic investment in EnLink to further strengthen its financial position through a series of highly accretive transactions. In aggregate, the sale of the Victoria Express Pipeline, secondary offering proceeds and annual distributions from EnLink will create $1.1 billion of value for Devon in 2015 (chart below).

Devon’s Newest Dropdown Candidate

Devon has significant midstream dropdown value remaining including Access Pipeline in Canada and its pending acquisition of the NGPL gas pipeline.

Production Outlook On Track; Additional Capital Savings Achieved

The strong operational performance year‐to‐date positions the company to deliver oil production growth of 25% to 35% in 2015. Due to the substantial growth in oil volumes, Devon remains on track to increase top‐line production by 5% to 10% in 2015.

The company expects to achieve these attractive production growth targets with lower capital requirements. Devon has identified around $100 million of capital savings due to lower midstream and corporate spending plans.

As a result of these additional capital savings, Devon has reduced its 2015 capital spending guidance by $350 million compared to its original capital guidance in February (chart below).

The company has received regulatory approval and expects to close the NGPL transaction in early 2016.

NGPL is a 92‐mile gas pipeline that runs from North Texas to Central Oklahoma. The pipeline is strategic since it could connect the growing SCOOP, STACK and Cana plays with EnLink’s North Texas midstream assets.

These strategically located pipelines are candidates for dropdown into EnLink as early as next year.

Market Value($B)

ENLK (95 MM Units) $1.9

ENLC (115 MM Units) $3.1

DVN’s Ownership $5.0

Devon’s Retained Ownership

As of 7/31/15

EnLink Value Harvested in 2015

VEX Dropdown

Distributions

SecondaryOffering

Value

$655 MM

$215 MM

$270 MM

$1.1 B

$4,250 $4,000

$710 $610

Original Guidance Revised Guidance

2015 Capital Budget(Using Midpoints, $MM)

$350MMCapEx Savings

Midstream &Other

E&P

$4,960 $4,610

PERMIAN BASIN

Q2 2015 OPERATIONS REPORT

PERMIAN BASIN Q2 STATSQ2 2015 Q2 2014

Production:Oil (MBOD) 67 55NGL (MBLD) 21 18Gas (MMCFD) 152 134MBOED 113 95


5

Net production averaged a record 113,000 Boe per day, an 11% increase compared to the first quarter of 2015. Oil reached nearly 60% of Permian production.

Permian revenue increased 27% over the previous quarter to $370 million in Q2 due to strong growth in oil production and improved commodity pricing.

Second‐quarter lease operating costs also declined. LOE totaled $12.84 per Boe, a 14% decline compared to the first quarter of 2015. Enhanced well productivity, improved water handling infrastructure and lower fuel and trucking costs drove the strong cost performance.

Delaware Basin Drives Permian Growth

Permian production growth was driven entirely by the company’s Delaware Basin assets. Oil production in the Delaware Basin averaged 42,000 barrels per day in Q2. This represents a 56% year‐over‐year increase driven by strong well results from Devon’s Bone Spring and Delaware Sands drilling programs (chart below).

Activity Focused in Eddy & Lea Counties

Devon ran 13 rigs in Q2 across the Delaware Basin primarily targeting the Bone Spring, including 10 rigs in the basin and 3 on the slope (map below).

27

42

Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015

Delaware Basin Oil Production(MBOD)

56%Growth

Bone Spring Basin Type WellKey Modeling Stats

30‐Day IPBOED

900

EURMBOE

600

D&C Cost$MM

$7 – 7.5

Oil / NGL% of Production

65% / 20%

WI / NRI 71% / 56%

PERMIAN BASIN


Activity Focused in Eddy & Lea Counties (continued)

The basin is characterized by deeper, over‐pressured reservoirs with more contiguous pay zones. The channelized sands on the slope are generally lower cost than the basin due to shallower, more normalized pressures.

During the quarter, 22 new Bone Spring development wells were brought online. Of these wells, 16 were drilled in the basin and 6 on the slope.

Basin Results Enhanced By Improved Completion Design

Drilling activity was most active within the company’s Bone Spring program in the basin of Southeast New Mexico, which continued to deliver excellent performance.

Initial 30‐day production rates from the 16 Bone Spring basin development wells in Q2 averaged approximately 1,400 Boe per day, of which nearly 80% was light oil. IP rates from these high‐rate wells exceeded the company’s recently raised type well by more than 50% (charts below).

The Q2 results represents more than a 140% increase in 30‐day IP rates compared to a previous design of around 600 pounds per lateral foot.

900

1,400

Q2 2015

>50%Increase

Current TypeWell

1,500 ‐ 2,000 lbs./ft.

Bone Spring Costs Decline 30%+ From Peak 2014 Levels

Further enhancing returns, Devon’s Bone Spring basin development wells are beginning to achieve accelerated cost savings.

In the current commodity and service cost environment, a completion design of roughly 1,500 pounds per lateral foot maximizes per well returns. This compares with much larger tests that recently deployed sand volumes up to 3,000 pounds per foot. The current design represents savings as high as $2 million per well compared to peak 2014 costs.

In addition to lower completion costs, Devon has increased drilling productivity by 18% in the Bone Spring since Q4 of last year (chart below).

Due to these structural efficiencies, lower industry costs and right sizing of completion designs, Devon expects Bone Spring basin well costs to decline by more than 30% from peak 2014 rates to a target of around $7 to $7.5 million per well, with potential to achieve additional savings going forward (table below).

Larger completions and further optimization of other variables such as fluids, perf clusters and stage spacing drove these outstanding results. The average sand volume for the Q2 wells was approximately 1,500 pounds per lateral foot.

30‐Day IP Rates(BOED)

79%

10%11%

Production Mix

Oil NGL Gas

Q2 Bone Spring Basin Wells

Average Feet Drilled Per Day Bone Spring

523

574

615

Q4 2014 Q1 2015 Q2 2015

18%Increase InProductivity

Inventory Upside: Bone Spring Downspacing Tests

To optimize future development schemes and ultimately maximize resource value, the company is conducting a number of Bone Spring downspacing pilots in Eddy and Lea counties (graphic below).

Key Modeling Stats

30‐Day IPBOED

800

EURMBOE

600

D&C Cost$MM

$6 – 6.5

Oil% of Production

≈60%

WI / NRI 70% / 60%

PERMIAN BASIN


Delaware Sands Program Exceeds Expectations

Also in the Delaware Basin, the company is developing the Delaware Sands which sits above the Bone Spring at a depth of 7,000 to 9,000 feet.

Devon commenced production on 9 wells targeting the Lower Brushy Canyon interval of the Delaware Sands in Q2. Initial 30‐day rates from these wells averaged 1,040 Boe per day, of which 85% was light oil. These high‐rate wells exceeded the company’s type curve by more than 90%.

An improved completion design and new landing zone in the “D” sand drove these outstanding results. The new design has reduced sand volumes to around 700 pounds per lateral foot due to the conventional nature of the reservoir.

Based on these strong results, Devon is raising its Delaware Sands type well 30‐day IP rate and EUR by approximately 50% (table/chart above).

To date, Devon has identified 700 risked undrilled locations in the Delaware Sands and has a total unrisked inventory of about 1,500 locations. Devon plans to drill 10 additional Delaware Sands wells in the second half of 2015.

Delaware Sands (Brushy Canyon) Type Well


525

800

Previous Revised

≈50%Increase

Bone Spring Slope Program Contributes Solid Results

Production commenced on 6 Bone Spring slope development wells in Q2 with initial 30‐day rates averaging 500 Boe per day. Highlighting activity was the Diamond PWU 22‐11H which achieved an IP of 960 Boe per day.

These results were in‐line with type curve expectations. Devon expects its average Bone Spring slope well to deliver 30‐day IP rates of 500 Boe per day and recover 450 MBoe of resource.

With additional geologic modeling and further well design enhancements, the company believes there is significant upside to its Bone Spring slope results.

A portion of this activity will test tighter well spacing of 6 to 8 wells per section in the lower interval of the 2nd Bone Spring, which is the company’s traditional landing zone. In conjunction with the development of the lower portion of the 2nd Bone Spring, Devon is also testing the commerciality of the upper interval.

Drilling and completion activities on the spacing pilots are underway with data collection and analysis occurring in the 2nd half of 2015 and into 2016.

Lower

2ndBO

NE SPRING

Upp

er

3rd

BONE

SPRING

Pilot 1

Planned Pilot Well Existing Producer

Pilot 2660’

Pilot 3 Pilot 4 Pilot 5

660’ 880’

1,320’

280’660’

PERMIAN BASIN


Converting the Massive Delaware Basin Resource to Cash Flow

Converting the massive and growing opportunity in the Delaware Basin into production and free cash flow is a top priority for Devon.

The company plans to drill ≈140 gross wells in the Delaware Basin in 2015 and is on track to deliver year‐over‐year production growth of more than 30% (chart below).

With these strong industry results and Devon’s ongoing reservoir characterization work, the company is now increasing its Wolfcamp oil potential by 40% to 140,000 net prospective acres (map left).

This prospective Wolfcamp acreage has gross thickness up to 1,100’ with as many as 4 different landing zones. By year end, the company plans to drill or participate in approximately 10 Wolfcamp appraisal wells.

Leonard Shale and Wolfcamp Potential Increasing

While drilling activity is focused on lower‐risk, higher rate of return Bone Spring development opportunities, the company also has significant exposure to the Leonard Shale and Wolfcamp formations in the Delaware Basin.

In the Leonard Shale, Devon has 60,000 net acres and plans to drill 7 wells in 2015. To date, the company has identified 700 risked locations, assuming conservative spacing of only 5 wells per section (map below).

Activity adjacent to Devon’s prospective Leonard acreage is testing spacing as tight as 18 wells per section, which if successful could dramatically increase the company’s undrilled inventory.

Devon is also encouraged by recent progress in the Wolfcamp oil play in the Northern Delaware Basin. Industry has drilled roughly 50 Wolfcamp wells in Eddy, Lea, and Northern Loving County with leading IP rates as high as 2,900 Boe per day.

Once downspacing pilots are concluded, expected in early 2016, and industry conditions incentivize higher activity levels, Devon’s Delaware Basin asset teams are prepared to meaningfully accelerate drilling activity.

2014 2015e

Delaware Basin Production Outlook(MBOED)

>30%Growth

45

60+

Oil

NGL

Gas

EAGLE FORD


EAGLE FORD Q2 STATSQ2 2015 Q2 2014


E&P Capital (in millions): $192Operated Rigs (at 6/30/15): 0 (5 including JV rigs)

Net production averaged 114,000 Boe per day in the second quarter of 2015, a 75% increase compared to the second quarter of 2014 (chart below).

65

114

Q2 2014 Q2 2015

Eagle Ford Production(MBOED)

$7.04

$5.25

Q2 2014 Q2 2015

Eagle Ford Unit LOE($/BOE)

Consistently Delivering Best‐In‐Class Results

Devon’s most significant production growth came from DeWitt County, which has consistently delivered best‐in‐class results (chart below).

0

250

500

750

1,000

Eagle Ford 90‐Day Wellhead IPs(BOED, 20:1)

Source: IHS/Devon. Based on wellhead rates for operated wells online for 90 days from July 2014.

1,000

Peers

Average: 440 BOED

25%Decline

75%Growth

Eagle Ford Profitability Highest In Portfolio

Oil and liquids reached nearly 80% of Eagle Ford production in Q2. To maximize the value of this production, the company exported approximately 34,000 barrels per day of condensate during the quarter. The premium pricing of condensate exports achieved an uplift of more than $3 per barrel.

Devon also effectively controlled operating costs in the Eagle Ford. Second‐quarter LOE was $5.25 per Boe, a decline of 25% year over year (chart above).

These positive operating trends helped achieve the highest per‐unit marginacross Devon’s asset base. Cash operating margin in the Eagle Ford totaled $29 per Boe, an increase of more than 25% from the first quarter of 2015.

EAGLE FORD


Consistently Delivering Best‐In‐Class Results (continued)

Over the past year, Devon’s initial 90‐day rates in DeWitt County have been 125% higher than the industry average across the Eagle Ford. This data set includes approximately 2,000 wells placed online since July 2014.

Devon continued this trend of excellence in the second quarter by adding 35 new Lower Eagle Ford wells to production in DeWitt County with initial 30‐day production rates averaging 1,950 Boe per day.

These high‐rate wells exceeded the company’s type curve by 18% and represent a 74% increase in 30‐day IP rates compared to the company’s first month of ownership in March 2014 (charts below).

This increase in per‐well productivity is attributable to recent completion design improvements and better production operations management.

1,6501,950

Type Curve Q2 2015

DeWitt 30‐Day IP Results (BOED)

18%Increase

1,120

1,950

March 2014 Q2 2015

74%Increase

These drilling efficiencies are driven by improved well design, lower non‐productive time and faster rig moves.

The company has also realized completion cost savings of more than 25% from 2014 peak levels, driven by lower pressure‐pumping rates and recent design enhancements.

Based on these improvements, Devon is reducing well cost expectations in the Eagle Ford by approximately 20% to $7.5 million per well (chart below).

$9.5

$7.5

Previous Revised

≈20%Reduction

D&C Cost – DeWitt Eagle Ford Type Well($ Millions)

15.7 16.1 15.3

18.2

22.223.9

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

Wells Per Rig Per Year – DeWitt County

≈50%Efficiency Improvement

Drilling Efficiencies Drive Well Costs Lower

Devon’s low‐risk infill drilling program in DeWitt County is achieving significant drilling efficiencies.

Over the past year, drilling times have improved by approximately 50% to a recent high rate of nearly 24 wells per rig line per year (chart above right).

EAGLE FORD


Strong Upper Eagle Ford Marl Appraisal Result

In addition to Devon’s prolific Lower Eagle Ford development program, the company has identified Upper Eagle Ford Marl potential across the majority of its 75,000 net acres in DeWitt and Lavaca counties.

The company’s Q2 Upper Eagle Ford Marl activity delivered another encouraging appraisal well in Lavaca County. The Dickson Allen 1H achieved an average 30‐day production rate of 1,840 Boe per day (map below).

Updated 2015 Outlook

The company’s partner in DeWitt County elected to reduce drilling and completion activity in the second quarter. As a result, the partnership activity was limited to 1 completion crew for the majority of the quarter and exited June with only 5 rigs running.

Accordingly, the company’s inventory of Eagle Ford wells waiting to be placed online increased to 130 at quarter end.

The impact of reduced completion activity is expected to limit Eagle Ford production in the second half of the year to around 100,000 Boe per day.

Positioned For Future Growth

Devon and its partner will tailor activity to market conditions for the remainder of 2015 and into 2016. Once conditions incentivize higher activity levels, this premier asset is prepared to resume growth.

With best‐in‐class well productivity, significant upside remains for this world‐class asset, including the potential for staggered lateral development in the Lower Eagle Ford in DeWitt County.

To date, Devon’s Upper Eagle Ford Marl activity is highlighted by 5 operated wells across both DeWitt and Lavaca counties (map above). Initial 30‐day production rates from these wells averaged 1,165 Boe per day. With additional geologic modeling and further completion design enhancements, the company believes there is upside to these results.

Devon has identified approximately 450 unrisked locations in the Upper Eagle Ford Marl and will bring online 2 additional operated Upper Eagle Ford Marl wells in the second half of 2015.

Long‐Term Takeaway Capacity Improving

Due to the prolific growth of oil production in DeWitt County, takeaway capacity was constrained in localized portions of the field during Q2.

Devon has actively worked with its midstream providers to increase operational capacity by modifying facilities to improve stabilizer uptime and by optimizing trucking operations.

Overall, these initiatives are expected to increase gross oil takeaway capacity by up to 30,000 barrels per day in the second half of the year, or nearly 50,000 Boe per day including associated gas and NGLs.

HEAVY OIL


HEAVY OIL Q2 STATSQ2 2015 Q2 2014

Production:Oil & Bitumen (MBOD) 98 77Gas (MMCFD) 20 23MBOED 101 81


Net oil production in Canada averaged 98,000 barrels per day, a 27% increase compared to the second quarter of 2014 (chart below). This strong growth was achieved even with a scheduled plant turnaround at Jackfish 1 that curtailed production by 11,000 barrels per day in Q2.

Q2 2014 Q2 2015

Heavy Oil Production(MBOD)

Lloydminster

Jackfish 1

Jackfish 2

Jackfish 377

98

27%Growth

Devon continued to reduce costs in Canada. Excluding the impact of the Jackfish turnaround, unit LOE declined 30% year‐over‐year to $15.64 per barrel driven by higher volumes at Jackfish 3 and effective cost management.

This strong operating performance was further enhanced by improved Western Canadian Select (WCS) pricing. The WCS price increased 37% compared to Q1 and exited June at over $51 per barrel.

World‐Class Jackfish Complex Drives Q2 Performance

Q2 production growth in Canada was driven by Devon’s Jackfish SAGD complex which resides in the very best portion of the Alberta oil sands (map right).

HEAVY OIL


World‐Class Jackfish Complex Drives Q2 Performance (continued)

Overall, gross production from the Jackfish complex averaged 74,800 barrels per day in Q2. After adjusting for royalties, net production reached 72,900 barrels per day, a 41% increase compared to the second quarter of 2014.

Solid execution and top‐tier reservoir quality are key factors that make Devon’s Jackfish complex one of the most efficient thermal oil projects in the industry. Notably, productivity per well pair at Jackfish averages 650 barrels per day, more than 40% above the industry average (map inset previous page).

Jackfish 1 Turnaround Successful

In June, Devon successfully performed a scheduled 21‐day maintenance program on its Jackfish 1 facility that was deferred from 2014.

As a result of the turnaround, gross production was limited to an average of 24,200 barrels per day in the second quarter. After adjusting for royalties, net production averaged 23,300 barrels per day.

Jackfish 2 Production Advances

Gross production at Jackfish 2 continued to progress toward nameplate capacity averaging 27,500 barrels per day in the second quarter. After royalties, net production totaled 26,900 barrels per day, 19% higher than the year‐ago quarter.

The company plans to begin steaming a new well pad in the fourth quarter of 2015. The production contribution from this pad is expected to help Jackfish 2 achieve peak facility capacity in 2016.

Jackfish 3 Delivering Significant Growth

Devon’s newest thermal oil facility continued to ramp up in Q2, averaging 23,100 barrels per day of gross production or 22,700 barrels per day net of royalties.

Current gross production at Jackfish 3 is about 27,500 barrels per day. Facility nameplate capacity of 35,000 barrels per day is expected around year‐end 2015.

Front‐End Engineering & Design Work Continues at Pike

Activity at the company’s Pike project in the second half 2015 will consist of front‐end engineering and design work (FEED). Capital requirements at Pike will be limited to around $50 million for the remainder of the year.

Upon the completion of the FEED work, expected in the fourth quarter of 2015, the company will review the forward plan for Pike.

Q3 Outlook: 35% Production Growth Expected

In the upcoming third quarter, Devon expects net oil production from its heavy oil operations to range between 105,000 and 115,000 barrels per day. This represents a growth rate of approximately 35% compared to the third quarter of 2014 (chart below).

For the full year, the company’s heavy oil operations remains on track to produce 100,000 to 110,000 barrels of oil per day.

80

110

Q3 2014 Q3 2015e

Heavy Oil Production Outlook(Using Midpoint, MBOD)

≈35%Growth

ANADARKO BASIN


ANADARKO BASIN Q2 STATSQ2 2015 Q2 2014



Net production averaged 82,000 Boe per day in the second quarter, with controllable downtime declining to a company best at just 0.6% of total Anadarko Basin production.

Record‐Setting Pad Brought Online at Cana

The Cana‐Woodford play was the most significant contributor to production in the Anadarko Basin, averaging 59,000 Boe per day in the second quarter.

New well activity in the Cana‐Woodford was highlighted by the company’s participation in the 8‐well Haley section. Peak 30‐day rates from these wells averaged 1,850 Boe per day, of which 15% was light‐oil.

The Haley wells are among the most productive ever drilled at Cana, exceeding the company’s type curve by more than 50% (chart below).

1,200

1,850

Type Curve

>50%Higher

PreviousDesign

HaleyPad

SandPounds/Ft.

1,200 1,800 ‐2,400

Frac Stages 20 25 ‐ 30

Perf Clusters 80 100 ‐120


8 WellsHaley Pad

ANADARKO BASIN


59 58 ‐ 62

66 ‐ 70>70

Q2 2015 Q3 2015e Q4 2015e 2015e Exit Rate

Even with larger completions jobs, Devon is reducing well cost expectations at Cana by 15% to $7 million per well due to improved drilling efficiencies and lower service costs (table/chart below).

40.2

32.6

27.2

Q4 2014 Q1 2015 Q2 2015

Record‐Setting Pad Brought Online at Cana (continued)

Completion design enhancements drove these outstanding results. The Haley wells tested sand volumes ranging from 1,800 to as high as 2,400 pounds per lateral foot, up to 2 times the sand of the previous design (table previous page).

The company continues to monitor production from these larger completions. Learnings will be integrated into future development plans at Cana, including optimizing variables such as fluids, perf clusters and stage spacing.

Spud‐To‐Rig Release – Cana Woodford (Days)

32%Efficiency Improvement

Drilling Efficiencies Achieved At Cana

For the year, Devon plans to drill approximately 75 development wells in the Cana‐Woodford. This activity is focused exclusively on 70‐acre development drilling in the liquids‐rich core of the Cana‐Woodford play.

Through the first half of 2015 the company has drilled approximately 50 of the 75 Woodford wells planned for the year.

Since drilling resumed in the field late last year, Devon has achieved a 32% reduction in drilling times (chart below).

These drilling efficiencies are driven by the strong performance of recently contracted new‐build rigs and improved collaboration across the company’s technical teams.

Cana‐Woodford Positioned For Strong Growth

Due to the timing of pad drilling, a limited number of Cana‐Woodford wells were brought online in the first half of 2015. As forecasted, this resulted in a temporary decline of field production year to date.

However, in July the company commenced completion operations at Cana with 3 frac crews. This completion activity will rejuvenate production growth, with an expected year‐end exit rate in excess of 70,000 Boe per day (chart below).

Key Modeling Stats

30‐Day IPBOED

1,200

EURMBOE

1,700

D&C Cost$MM

$7

$8.2

$7.0

Previous Revised

Cana‐Woodford Type Well

15%Reduction

D&C Cost($ Millions)

Cana‐Woodford Production Outlook(MBOED)

ANADARKO BASIN


Emerging Meramec Play Continues To Deliver

In addition to the company’s best‐in‐class Cana‐Woodford development, Devon has also identified stacked‐pay potential across the majority of its 280,000 net acres, with the most promising opportunity in the Meramec play.

During the quarter, Devon and its partner brought 2 new Meramec appraisal wells online. Initial 30‐day production rates averaged around 1,500 Boe per day.

To date, the company has now drilled or participated in 14 Meramec wells with at least 30 days of production history. Initial 30‐day rates from these appraisal wells averaged approximately 1,500 Boe per day.

Anadarko Basin: A Tremendous Resource Opportunity

The Anadarko Basin provides the company with 340,000 net acres and more than 4,000 locations to develop (table below). This drilling inventory is one of the deepest and most economic in the company’s portfolio.

Within this leasehold, the largest opportunity is Devon’s Woodford and Meramec development with 340,000 net risked acres.

This premier stacked pay asset provides a highly visible source of growth for Devon for many years to come and a significant growth opportunity for EnLink Midstream.

Formation Window Net RiskedAcres

Gross RiskedLocations

MeramecOil and Liquids 60,000 >400

Gas TBD TBD

WoodfordLiquids‐Rich 200,000 2,300

Gas 80,000 1,300

Total 340,000 >4,000

Accelerating Meramec Activity

The company and its partners plan to further accelerate Meramec drilling in the second half of the year by increasing activity to as many as 6 rigs. This includes the potential reallocation of up to 2 operated Cana‐Woodford rigs to the play.

As a result of this increased activity, Devon now plans to spud or participate in 40 Meramec wells in 2015. This drilling program will include two Meramec spacing pilots and a staggered lateral test to evaluate the joint development of the Upper and Lower Meramec intervals (graphic below).

PlannedPilotWell

Spacing Pilot Staggered Lateral Pilot

MISSISSIPPIAN

1,150’

(5 wells/section)

660’

Lower

Upp

er

MER

AMEC

These pilot programs will help determine the optimal future development schemes of both the Meramec and Woodford formations.

BARNETT SHALE


BARNETT SHALE Q2 STATSQ2 2015 Q2 2014



Net production averaged 185,000 Boe per day in the second quarter, with liquids production accounting for 27% of total Barnett Shale production.

Enhancing Base Production

Devon’s Barnett Shale operations are focused on enhancing base production through optimizing existing well performance.

These optimization efforts include an active refrac program, artificial lift initiatives and efforts to further reduce controllable downtime (currently less than 1% of production).

Over the past year, these initiatives have improved the Barnett’s unaided PDP decline by approximately 3 percentage points. These activities have translated into incremental production of roughly 2.5 million equivalent barrels over this time period.

Activity Focused on Refracs

A significant portion of the company’s $150 million capital budget in 2015 is directed toward a vertical refrac program focused in Wise and Denton Counties where the company has re‐stimulated approximately 100 wells year to date.

Overall, the re‐stimulated vertical wells are achieving an EUR uplift of about 70 MBoe per well, with the top performers trending well in excess of 150 MBoe per well. Recently, refrac costs have declined to as low as $270,000 per well.

Upon completion of the vertical refrac program by year‐end, about 60% of the company’s 1,900 operated vertical wells will have been re‐stimulated.

2015 Capital Program Activity

Capital$MM

$150

Vertical Refracs

150

Horizontal Refracs Up to 15

PlungerLifts 350

Line Pressure Reduction Pilot

BARNETT SHALE


Activity Focused on Refracs (continued)

The company is also testing select vertical wells to re‐stimulate a second time, which with success could open up additional inventory.

In addition, with more than 3,000 horizontal wells, Devon has significant horizontal refrac potential in the Barnett. In the second half of 2015, the company will continue to evaluate the commerciality of this opportunity by testing refracs on up to 15 horizontal wells.

Improved Recovery Upside

With many legacy Barnett wells potentially in need of re‐stimulation, there is tremendous upside opportunity as refrac technology advances.

At year‐end 2014, the company had proved reserves in the Barnett Shale totaling more than 1.0 billion Boe. Of these reserves, 99% were proved developed from more than 5,000 gross producing wells.

Underpinning this proved reserve estimate is a resource recovery factor of only 18% across Devon’s 620,000 net acres in the Barnett Shale. Every 1% improvement in recovery leads to more than 100 million Boe of additional recoverable resource (chart below).

To put this into perspective, 100 million Boe represents nearly 10% of the company’s current Barnett proved reserves estimate.

Significant Cash Flow Generator

Devon’s Barnett Shale properties are some of the lowest‐cost assets in its portfolio, with LOE averaging around $6 per Boe in the second quarter.

Even with depressed gas prices, the Barnett has generated over $2 billion of cash flow for the company during the past two years, with only minimal capital requirements.

Should commodity prices improve, every 25‐cent increase in natural gas price translates into an additional $70 million of incremental annualized cash flow (at planned production rates for 2015).

82%

18%

Incremental Proved Resource Potential

Proved & ProducedRemaining Resource In Place

0

100

200

300

400

500

0% 1% 2% 3% 4% 5%

MMBO

E

% Increase in Recovery Factor

Barnett Resource

ROCKIES OIL


ROCKIES OIL Q2 STATSQ2 2015 Q2 2014



Net production averaged 27,000 Boe per day, a 34% increase compared to the second quarter of 2014.

Oil production from this emerging area has now increased more than 80% since the end of 2014 (chart below). This growth is attributable to strong results from the company’s Powder River development program and the start‐up of its Big Sand Draw CO2 project (map right).

In addition to this impressive production growth, unit LOE is also improving. Second‐quarter LOE declined 30% since the end of 2014 to $9.60 per Boe (chart above).

9

16

YE 2014 Q2 2015

Rockies Oil Production(MBOD)

Powder River Basin Delivers High‐Rate Development Wells

The most significant production growth in the Rockies came from the Powder River Basin development activity, which is delivering some of the best rates of return in Devon’s portfolio.

$13.75

$9.60

YE 2014 Q2 2015

Rockies Unit LOE($/BOE)

30%Decline

81%Growth

ROCKIES OIL


Powder River Basin Delivers High‐Rate Development Wells (continued)

Q2 drilling activity was highlighted by 8 development wells in the company’s Parkman Focus Area in Campbell County, Wyoming. Initial 30‐day production rates from these wells averaged 1,380 Boe per day, of which more than 90% was light oil (charts below).

Big Sand Draw is expected to reach a peak rate of more than 5,000 barrels per day in 2016 and maintain a steady production profile for approximately 20 years with minimal capital requirements. The company has a 98% working interest and an 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 increase to around 8,000 Boe per day by the second half of 2016.

A recently enhanced well design drove these outstanding results. The company’s new design uses extended‐reach laterals of 9,600 feet, more than 2 times the lateral length of the previous design.

Devon has 225,000 net prospective surface acres in the oil fairway, with stacked‐pay potential in the Parkman, Turner and Frontier formations.

The company has identified approximately 800 undrilled locations (1,450 locations without the use of extended‐reach laterals) and expects its drilling inventory to increase as the oil fairway continues to be de‐risked. The Parkman formation accounts for approximately 55% of this total undrilled inventory.

525

1,380

Old Design Q2 Wells


≈160%Increase

4,000’ Lateral

92%

Production Mix

Oil NGL Gas

Q2 Parkman Development Wells

9,600’ Lateral

Production Outlook Remains Strong

Devon remains on track to participate in 40 wells in 2015 and plans to run a 2‐rig program for the remainder of the year.

The capital investment associated with this 2015 activity is approximately $350 million, of which $100 million is attributable to start‐up of the Big Sand Draw CO2 project.

This highly‐economic development program is expected to generate light‐oil production growth of approximately 85% in the Rockies in 2015.

CO2 Projects Contribute to Rockies Oil Growth

In June, Devon commenced operations at its Big Sand Draw CO2 facility in the Wind River Basin. By quarter‐end, production had reached in excess of 2,000 barrels per day and was well ahead of initial ramp‐up expectations.

4%4%

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 “forecasts”, “projections”, “estimates”, “plans”, “expectations”, “targets”, “opportunities”, “potential”, “outlook”, and other similarterminology. Such statements concerning future performance or events are subject to a variety of risks and uncertainties that could cause actual results to differ materially from theforward‐looking statements contained herein. Certain risks and uncertainties are described below in more detail as well as in the “Risk Factors” section of our most recent Form 10‐K and underthe caption “Forward‐Looking Statements” in the related earnings release included as an exhibit to our Form 8‐K furnished August 4, 2015.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, inflation or lack ofavailability 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 orreserves, 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 of and demand for energy commodities. In particular, concernsabout 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. Inaddition 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 variousregional 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, theavailability 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,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 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 and exploration targetsize. 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 actuallyrealized. 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 atDevon 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’swebsite at www.sec.gov.

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