Q4 2015 DVN Operations Report FINAL - s2.q4cdn.coms2.q4cdn.com/.../2015/Q4/Q4-2015-DVN-Operations-Report-FINAL.pdf · Core Assets (MBOED) 571 535 Other (MBOED ... improvement compared

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

Delaware Basin ..….………….…………………………………………….…… 7STACK ..................….…………………………………….……………………… 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

Shea SnyderDirector, Investor Communications405‐552‐4782

Q4 2015 OPERATIONS REPORTFebruary 16, 2016

NYSE: DVNdevonenergy.com

Table of ContentsIR Contacts

KEY TAKEAWAYS

Q4 2015 OPERATIONS REPORT 2

APPROACH TO THE CURRENT ENVIRONMENT Heavy Oil

Rockies Oil

STACK

Delaware Basin

Eagle Ford

BarnettShale

Committed to balancing 2016 spending with cash flow

Decreasing capital spending by 75%

Reducing operating and G&A costs by ≈$800 million annually

Adjusting dividend to improve cash flow by $320 million annually

Preserve financial strength and flexibility

Nearly $4 billion of liquidity

No significant debt maturities until December 2018

Pursuing $2‐$3 billion of asset sales to further strengthen balance sheet

RESULTS OVERVIEW & OUTLOOK


TOTAL COMPANY Q4 STATSQ4 2015 Q4 2014

Production:Oil & Bitumen (MBOD) 247 196NGL (MBLD) 108 106Gas (MMCFD) 1,298 1,399Core Assets (MBOED) 571 535Other (MBOED) 110 (1) 130Total (MBOED) 681 665

E&P Capital (in millions): $856Operated Rigs (at 12/31/15): 10

(1) Includes ≈80,000 Boe per day of planned divestiture production.

Core Assets Deliver Strong Q4 Production Results

Total oil production averaged 278,000 barrels per day in the fourth quarter, a 16% increase compared to the fourth quarter of 2014.

Of this amount, 247,000 barrels per day was attributable to Devon’s core asset portfolio where investment will be focused going forward. Oil production from these core assets increased 26% year over year (chart below).

Q4 2014 Q4 2015

Q4 Oil Production(MBOD)

196

247

26%Growth

U.S. Canada

Overall, net production from core assets averaged 571,000 Boe per day, a 7% increase compared to the fourth quarter of 2014. This growth was achieved in spite of multiple severe winter events in Q4 that curtailed production by approximately 6,000 Boe per day.

With strong growth in oil production, which is the company’s highest margin product, liquids volumes now account for 62% of Devon’s core asset production mix (chart above).

43%

19%

38%

Q4 Production Mix(571 MBOED)

Oil NGL Gas

Core Asset Portfolio

Cost‐Reduction Initiatives Enhancing Margins

Devon has several cost‐reduction initiatives under way that positively impacted fourth‐quarter cash margins.

Field‐level operating costs, which include both lease operating expenses (LOE) and production taxes, declined 20% compared to the fourth quarter of 2014 to $8.82 per Boe.

The most significant operating cost savings came from LOE, which is the company’s largest field‐level cost. LOE declined 18% compared to the year‐ago period to $7.66 per Boe and was 4% below the low end of guidance.

$11.05

$8.82

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Field‐Level Operating Costs($/BOE)

20%Decline

Jackfish 1Turnaround



Cost‐Reduction Initiatives Enhancing Margins (continued)

Devon also realized significant general and administrative (G&A) cost savings in the fourth quarter. G&A expenses totaled $194 million, or $3.10 per Boe, a 25% improvement compared to the fourth quarter of 2014 (chart below).

EnLink Midstream Delivers Steady Profits

The company’s midstream business delivered another quarter of solid results, generating $210 million of operating profit. Driven by EnLink Midstream, operating profit reached $840 million for the full‐year 2015.

Devon currently has a 64% ownership in the general partner (ENLC) and a 25% interest in the limited partner (ENLK). In aggregate, the company’s ownership in EnLink generated cash distributions of $268 million in 2015.

Reserve Base Shifting Toward Higher‐Margin Liquids

At Dec. 31, 2015, Devon’s proved reserves totaled 2.2 billion Boe, with proved developed reserves accounting for 83% of the total.

Of this amount, 1.9 billion Boe of reserves was attributable to Devon’s core asset portfolio with oil and liquids increasing to 55% of the total. This compares to a weighting of 48% just two years ago.

During the year, the company’s drilling programs added 118 million Boe of reserves through successful drilling (extensions & discoveries). About 90% of these additions resulted from oil‐focused drilling in the U.S.

Revisions reduced reserves by 444 million Boe. This was primarily driven by price revisions due to the lower commodity price environment. The company’s risked recoverable resource was unaffected by these adjustments.

Significant Financial Flexibility

Pro forma for the closing of the Felix acquisition, Devon had $3.9 billion of liquidity at year‐end, consisting of $1.5 billion of cash and $2.4 billion of capacity on its senior credit facility (chart below).

The senior credit facility matures at the end of 2019 and contains only one material financial covenant that requires a debt‐to‐capitalization ratio to be no greater than 65%. At Dec. 31, 2015, this ratio was 24%.

Devon exited the year with net debt totaling $7.7 billion (excluding non‐recourse EnLink obligations). The weighted‐average cost of this 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).

$4.12 $4.08

$3.45$3.17 $3.10

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

25%Improvement

G&A Costs($/BOE)

$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(12/31/15, $ Millions)

Liquidity

Pro Forma Liquidity(1)($ Millions)

$3,900

Cash

CreditFacility

2016 2017 2018 2019 2020

(1) Pro Forma for the Felix transaction that closed Jan. 7, 2016.



Divestiture Program To Boost Financial Strength

To further enhance its financial strength, the company is targeting total divestiture proceeds of $2 to $3 billion in 2016.

The company is in negotiations to sell its 50% interest in Access Pipeline. An announcement is expected in the first half of 2016.

Devon’s upstream divestitures will include up to 80,000 Boe per day of production and approximately 200 million Boe of proved reserves from assets in the Midland Basin, East Texas and Mid‐Continent region (map/table below).

The divestiture process is off to a strong start with $72 million of assets sales completed in Q4 2015. The company plans to use upstream sale proceeds to reduce debt.

Q4 2015 PRODUCTION

MBOED % LIQUIDSMidland Basin 27 65%Carthage 22 30%Granite Wash 12 50%Mississippian‐Lime 14 70%Other 5 35%Martin County 15,000 net undeveloped acres

Total ≈80 50%

2016 Outlook – E&P Capital Spending Declines 75%

With current industry conditions, Devon’s top priority is to protect its balance sheet by managing its capital programs to be within total cash inflows, which include operating cash flow, EnLink distributions and sale proceeds from Access Pipeline.

In 2016, Devon’s E&P capital investment is estimated to range between $900 million and $1.1 billion, a decrease of 75% compared to 2015 (table below). Capitalized G&A and other non‐E&P capital requirements are projected to be around $300 million.

2016 E&P CAPITALE&P CAPITAL($Millions)

STACK $325

Delaware Basin $200

Eagle Ford $200

Heavy Oil $175

Rockies Oil $75

Barnett Shale $25

2016 Totals $900 ‐ $1,100

Importantly, should commodity price volatility continue, the company’s capital programs have significant flexibility with minimal exposure to long‐term service contracts, no long‐cycle project commitments and negligible leasehold expiration issues.



2016 Outlook – Oil Production To Remain Flat

Devon’s E&P investment in 2016 will be focused entirely on its core asset portfolio. This level of investment is expected to maintain relatively flat oil production from the company’s core assets compared to the full‐year 2015. Top‐line production from core assets is expected to decline by 6% due to lower gas volumes (table below).

2016 PRODUCTION – CORE ASSETS2015

ACTUAL2016

GUIDANCEYOY GROWTH(Using Midpoint)

Oil & Bitumen (MBOD) 238 227 ‐ 237 (3%)

NGL (MBLD) 104 95 ‐ 100 (6%)

Gas (MMCFD) 1,306 1,164 ‐ 1,217 (9%)

Core Assets (MBOED) 560 516 ‐ 540 (6%)

2016 Outlook – Cost Savings Expected to Continue

In 2016, Devon will continue to drive field‐level costs lower across all regions of its portfolio. Led by additional LOE savings, the company expects field‐level costs to decline an incremental $300 to $400 million for the full year.

The Company will continue to deliver meaningful G&A reductions in 2016 by reducing its workforce and other administrative costs to better align its cost structure with the needs of the business in the current commodity price environment.

Devon’s workforce reduction program will decrease Devon’s employee count by approximately 20 percent in the first quarter of 2016, bringing the total workforce reduction to more than 25 percent over the past 12 months.

The reductions are expected to decrease G&A costs by approximately $400 to $500 million on an annual basis, exclusive of reorganization charges.

2016 Outlook – Quarterly Dividend Adjusted

Devon’s board of directors declared a quarterly cash dividend of $0.06 per share for the second quarter of 2016. This compares to the previous quarterly dividend of $0.24 per share.

This action provides additional flexibility to balance spending with cash flow, aligns with Devon’s priority of maintaining a strong balance sheet, and moves the dividend yield and payout ratios in line with historic norms. The adjusted dividend will improve the company’s cash flow by approximately $320 million annually.

Reorganization charges are expected to approximate $225 to $275 million, with the majority projected to be incurred in the first quarter of 2016. Roughly one‐quarter of the total restructuring charges are non‐cash.

ANNUALIZED COST STRUCTURE SAVINGSANNUALIZED SAVINGS

($Millions)

Field‐Level Operating Costs $300 ‐ $400

G&A (includes capitalized G&A) $400 ‐ $500

Adjusted Dividend $320

Total $1,000 ‐ $1,200

Cost Structure Changes to Save >$1 Billion Annually

The changes the company is making to its cost structure will achieve savings of more than $1 billion annually (table below).

DELAWARE BASIN

Q4 2015 OPERATIONS REPORT

DELAWARE BASIN Q4 STATSQ4 2015 Q4 2014

Production:Oil (MBOD) 42 27NGL (MBLD) 11 8Gas (MMCFD) 82 66MBOED 66 46


7

Net production averaged 66,000 Boe per day, a 45% increase compared to the fourth quarter of 2014 (chart below).

This attractive production growth was achieved in spite of severe winter weather in late December that curtailed production by approximately 4,000 Boe per day in the fourth quarter.

Delaware Basin Production(MBOED)

LOE Cost Savings Enhancing Margins

Devon made significant progress lowering operating costs in the fourth quarter. LOE has now declined to $12 per Boe, a decline of nearly 30% from peak rates in early 2015 (chart right).

These significant improvements helped generate a cash margin of $14 per Boe in the fourth quarter.

In 2016, the company expects to reduce total LOE costs by an additional 20% due to improved water‐handling infrastructure, lower power costs and other efficiency gains across its operations.

Delaware Basin Unit LOE($/BOE)

$16.87

$14.80

$12.62$12.00

Q1 2015 Q2 2015 Q3 2015 Q4 2015

≈30%Improvement

46

66

Q4 2014 Q4 2015

45%Growth

WeatherCurtailments≈4 MBOED

DELAWARE BASIN


Bone Spring Results Drive Q4 Growth

Fourth‐quarter production growth was driven by outstanding well performance across the Bone Spring play in southeast New Mexico.

The company brought online 14 Bone Spring basin wells in Q4 that realized 30‐day IP rates in excess of 1,000 Boe per day (map below). This activity was highlighted by the Irritable 22 State 2H in Eddy County, New Mexico, that delivered a peak 30‐day rate of 1,700 Boe per day.

Devon also tied in 5 noteworthy Bone Spring slope wells in the northern portion of the Delaware Basin during the quarter with 30‐day rates averaging approximately 800 Boe per day (map below).

Delivering Top‐Tier Results in Southeast New Mexico

During 2015, Devon consistently delivered top‐quartile well results in the basin of southeast New Mexico.

Devon’s initial 90‐day rates have been nearly 50% higher than the industry average in 2015 (chart above right). This data set includes nearly 400 wells achieving peak 90‐day rates in 2015.

The strong per‐well productivity is attributable to completion design optimization and better technical understanding of the subsurface.

Delaware Basin Efficiencies Accelerate

Devon continued to deliver significant efficiencies with its drilling and completion operations in the fourth quarter.

Over the past year, rig productivity in the Delaware Basin has improved by 77% to a record‐high of 735 feet drilled per day in the fourth quarter (chart below). Leading wells have achieved >1,000 feet drilled per day.

0

250

500

750

SE NM Basin – 90‐Day Wellhead IPs(BOED, 20:1)

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

612

Average: 420 BOED

Peers

Delaware Basin – Average Feet Drilled Per Day

416 450510

572

735

2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

77%Increase In

Rig Productivity

DELAWARE BASIN


Delaware Basin Efficiencies Accelerate (continued)

Completion costs have also dramatically declined from peak 2014 rates. In the basin area of southeast New Mexico, the cost of a completion design with 1,500 pounds of sand per lateral foot has declined 52% due to improved efficiencies and lower service costs (chart below).

Previous Revised

≈20%Reduction

Bone Spring Basin Type Well

Key Modeling Stats

30‐Day IPBOED

1,000

EURMBOE

600

D&C Cost$MM

≈$6

D&C Cost($ Millions)

≈$6

FormationRiskedNetAcres

RiskedGrossLocations

UnriskedGrossLocations

UnriskedResourcePotential

Delaware Sands 80,000 700 1,500

Leonard Shale 60,000 700 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 5,100 16,300 ≈6 BBOEBone Spring Type Curve Costs Decline

As a result of these efficiencies, Devon now expects Bone Spring basin wells to cost approximately $6 million per well, a cost reduction of about 20% from the previous expectation and 40% below peak rates in 2014 (table/chart below).

Delaware Basin – A Tremendous Resource Opportunity

The company’s industry‐leading Delaware Basin position has tremendous resource potential with exposure to 585,000 net acres and 5,100 risked locations (table below).

$4.8

$3.8

$2.8 $2.6 $2.3

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

52%Cost Reduction

Bone Spring Basin – Completion Costs($MM)

To optimize future development plans and expand risked inventory, Devon is evaluating several ongoing downspacing pilots and appraisal tests in the Bone Spring, Leonard Shale and Wolfcamp formations.

The most active pilot program is in the Bone Spring where ≈20 wells are testing tighter spacing in the basin. While early, initial results have been positive, providing valuable data for future development plans.

Devon is also actively evaluating tighter spacing in the Leonard Shale and appraising the Wolfcamp formation. These two promising formations have significant upside with nearly 9,000 unrisked locations identified.

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

$7 ‐ 7.5

STACK


STACK Q4 STATSQ4 2015 Q4 2014



Net production averaged 70,000 Boe per day, a 9% increase compared to the third quarter of 2015 (chart below). This growth was achieved in spite of multiple severe winter weather events in the fourth quarter that curtailed production by approximately 2,000 Boe per day.

64

70

Q3 2015 Q4 2015

STACK Production(MBOED)

$5.82

$4.42

1H 2015 Q4 2015

STACK Field‐Level Operating Costs*($/BOE)

24%Decline

This growing asset is also achieving the lowest field‐level operating costs of any property in the company’s portfolio at $4.42 per Boe, a decline of 24% compared to the first half of 2015 (chart above).

Felix Acquisition Creates Best‐In‐Class STACK Position

Devon completed its previously announced acquisition of Felix Energy on Jan. 7, 2016. This transaction secured 80,000 net acres in the most economic portion of the STACK oil window (map right).

Net production from the Felix properties is currently 14,000 Boe per day, an increase of 55% from reported production in December.

9%Growth

* Includes LOE and production taxes.

STACK


Felix Acquisition Creates Best‐In‐Class STACK Position (continued)

Upon closing of the acquisition, the company’s leading position in the STACK play increased to 430,000 net surface acres. Situated in the over‐pressured oil window of the play, these properties include targets in up to 10 intervals.

STACK Well Productivity Improvements Continue

Industry has now drilled more than 100 Meramec wells since 2013, with well productivity increasing by about 40% over this time period (chart below).

This increase in per‐well productivity is attributable to improved well designs. A shift to hybrid completions, higher proppant volumes and increased frac stages is delivering superior results.

Devon expects future results will continue to improve as optimal landing zones are refined and well designs continue to advance. The company is also evaluating tighter spacing with ongoing pilot programs.

Drilling Efficiencies Drive Meramec Well Costs Lower

Further enhancing results, Devon’s Meramec program is achieving accelerated cost savings. Over the past 18 months, drilling times have improved by 40% to a record‐setting spud‐to‐rig release time of 21 days (chart below).

With these efficiency gains, Devon is targeting Meramec costs of $6 to $6.5 million per well for standard length laterals (assumes 2,600 pounds of proppant per lateral foot), a 20% decline since early 2015 (chart below).

Improved Completion Design Boosts Woodford Results

Devon and its partner brought online all wells from the 7‐section Gordon Row during the fourth quarter. A total of 57 Woodford wells were successfully completed in only 90 days.

Record‐Setting Meramec Well Results In Q4

Q4 Meramec activity was highlighted by Devon’s participation in 12 high‐rate wells that achieved peak 30‐day rates during the quarter. Production from these wells reached a new quarterly high averaging nearly 1,700 Boe per day.

Of these prolific wells, 8 were drilled on Devon’s legacy acreage and averaged 1,520 Boe per day, of which 45% was light oil (map previous page).

On the recently acquired Felix acreage, 4 development wells were brought online in Q4 within the oil windows of the play. Initial 30‐day production averaged 1,990 Boe per day, of which 60% was light oil (map previous page). These results exceed type‐curve expectations by more than 50%.

0

20

40

60

80

0 30 60 90

2015 Avg. Well2014 Avg. Well

Days

90‐Day Avg Cumulative Production – Meramec(MBOE)

≈40%Productivity Increase

Spud‐To‐Rig Release – Meramec (Days)

≈$8.0

Early 2015 Revised

≈20%Reduction

D&C Cost – Meramec($ Millions)

35

21

Mid‐2014 Q4 2015

40%EfficiencyGain

$6 ‐ 6.5

Improved Completion Design Boosts Woodford Results (continued)

Initial 30‐day IPs from the 29 wells that reached peak rates during the quarter averaged 1,600 Boe per day, of which 52% was liquids. These high‐rate wells exceeded the company’s type curve by more than 30%.

These results were driven by an enhanced completion design that uses 50% higher sand volumes (1,800 pounds per lateral foot) along with increased stage spacing and perf clusters.

STACK


STACK Position Provides World‐Class Inventory

Devon has the premier STACK position in the industry with 430,000 net acres and more than 5,000 undrilled locations to develop (table below).

Drilling Efficiencies Continue At Cana‐Woodford

Devon ran 3 operated rigs at Cana in the fourth quarter and continued to achieve significant drilling efficiencies.

Since the fourth quarter of 2014, drilling times have improved by 50% to a record‐low spud‐to‐rig release time of 20 days in the most recent quarter (chart below).

These drilling efficiencies are driven by detailed planning and improved drilling analytics across the company’s technical teams, along with strong rig performance.

This inventory is one of the deepest in the portfolio with >2 BBOE of risked resource. With additional spacing tests and appraisal drilling that is currently under way, Devon expects its risked inventory and recoverable resource estimates to increase over time.

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

2016 Outlook

For full‐year 2016, the company plans to invest around $325 million of capital in the STACK play.

Devon expects to run on average 4 rigs (including non‐operated activity) throughout 2016, with the majority of activity focused in the Meramec oil window.

40.2

32.6

27.223.4

20.2

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

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

50%Efficiency Improvement

Formation Window Gross RiskedLocations(1)

Gross UnriskedLocations

MeramecOil 700 2,000

Volatile Oil 900 1,800

Woodford

Oil 150 450

Liquids‐Rich Gas 2,250 4,200

Dry Gas 1,300 2,300

Total 5,300 10,750

(1) Represents a mix of standard length and extended‐reach laterals.

5165

115

2014 2015

EAGLE FORD


EAGLE FORD Q4 STATSQ4 2015 Q4 2014


E&P Capital (in millions): $151Operated Rigs (at 12/31/15): 0 (5 including JV rigs)

Net production averaged 111,000 Boe per day in the fourth quarter. Since acquiring these assets in March 2014, Devon has delivered tremendous results, increasing production by 125% (chart below).

$5.92

$4.57

2014 2015

23%Decline

Eagle Ford Production(MBOED)

Eagle Ford Unit LOE($/BOE)

Eagle Ford Profitability Highest In Portfolio

Oil and liquids production was approximately 80% of Eagle Ford volumes in 2015. In an effort to maximize the value of production, Devon exported on average 25,000 barrels per day of condensate during the year. The premium pricing of condensate exports achieved an uplift of roughly $3 per barrel.

These positive operating trends helped achieve the highest per‐unit marginacross Devon’s asset base. Cash operating margin in the Eagle Ford totaled $23 per Boe or approximately 80% of upstream revenues in 2015.

Best‐In‐Class Eagle Ford Position

Devon’s excellent Eagle Ford results are driven by its development in DeWitt County which is located in the economic core of the play.

DeWitt County has the lowest break‐even drilling economics of any county in the Eagle Ford play (chart below) and has consistently delivered some of the highest rate‐of‐return wells in North America.

The company also effectively controlled operating costs in the Eagle Ford. LOE declined to a record low $4.13 per Boe in Q4. For the full‐year 2015, per‐unit LOE costs declined 23% compared to 2014 (chart above).

$25

$35

$45

$55

$65

DeWitt Karnes Gonzales LaSalle Dimmit

Break‐even Drilling EconomicsWTI

Source: BMO Capital – “Breaking Down U.S. E&P Productivity Improvements” (12/10/15)

March 2014

125%Increase

EAGLE FORD


World‐Class Development Results In DeWitt

Devon continued to achieve world‐class results from its Eagle Ford drilling program in DeWitt County in the fourth quarter of 2015. The company added 52 Eagle Ford development wells to production in the quarter with 30‐day rates averaging 2,260 Boe per day.

The high‐rate wells brought online during the fourth quarter represent more than a 100% increase in 30‐day IP rates compared to the company’s first month of ownership in March 2014 (chart below).

Devon’s new well activity was highlighted by several high‐rate wells with 30‐day IP rates in excess of 3,000 Boe per day (table below).

Well Name 30‐Day IPBOED

Rayes B 2H 3,640

Wagner B 8H 3,540

Wagner B 7H 3,320

Wagner B 9H 3,180

Hartman A 11H 3,070

1,120

2,260

March 2014 Q4 2015

DeWitt 30‐Day IP Results (BOED)

>100%Increase

Notable Wells – DeWitt County

Efficiencies Driving Sustainable Cost Savings

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

Over the past year, drilling times improved by 45% compared to the 2014 average, with a record rate of 24 wells per rig line per year achieved in the most recent quarter (chart above right).

$9.5

$6.5

2014 Peak Revised

>30%Reduction

D&C Cost – DeWitt ($ Millions)

These efficiencies are driven by an improved well design, better lateral placement, lower non‐productive time and faster rig moves.

As a result of these efficiency gains and further cost reductions across the supply chain, Devon is reducing well cost expectations in the Eagle Ford to $6.5 million per well, a decline of more than 30% since peak rates at the end of 2014 (chart below).

16.6

22.724.1

2014 Avg 2015 Avg Q4 2015

Wells Per Rig Per Year – DeWitt County

Staggered Lateral Infill Program Under Way

Due to the quality and thickness of the Eagle Ford reservoir, the company commenced a staggered lateral infill program in DeWitt County in the second half of 2015.

45%Efficiency Improvement

EAGLE FORD


Staggered Lateral Development Concept

LOWER

EF

≈660’

≈330’

≈60’ ‐ 80’

2016 Outlook

For full‐year 2016, the company and its partner plan to run 2‐3 rigs and 1 fraccrew. This level of activity will require around $200 million of capital investment.

Staggered Lateral Infill Program Underway (continued)

The infill program will drill staggered laterals in the upper and lower portions of the Eagle Ford formation with spacing as tight as 330 feet (40‐acre spacing) (graphic below).

The company began implementing this staggered lateral development program in undeveloped portions of southwestern DeWitt County in Q4 with 15 wells. Initial production results are expected in 2016.

Future infill pilots will test this staggered lateral development concept in previously developed units. With success, Devon’s inventory in DeWitt has the potential to expand by more than 200 locations.

ROCKIES OIL


Net production for retained assets(1) averaged 23,000 Boe per day, a 38% increase compared to the fourth quarter of 2014. Overall, Q4 Rockies oil production increased 79% year over year.

16

23

Q4 2014 Q4 2015

Rockies Production(1)(MBOED)

38%Growth

The company also lowered operating costs in the Rockies region. For the full‐year 2015, LOE declined to an average of $11.38 per Boe, a decline of 19% compared to peak 2014 rates (chart above).

$14.05

$11.38

2014 Peak 2015

19%Decline

Rockies Unit LOE(1)($/BOE)

Acquisition Creates Premier Powder River Position

Devon completed its previously announced acquisition of 253,000 net acres in the Powder River Basin on Dec. 17, 2015. The acquired acreage is located to the south of Devon’s legacy position in Wyoming and includes production of 7,000 Boe per day (map right).

This contiguous acreage resides in the core of the oil fairway and allows for extended‐reach horizontal drilling.

ROCKIES OIL Q4 STATS(1)Q4 2015 Q4 2014



(1) Excludes production from recently sold San Juan assets.

(1) Excludes production from recently sold San Juan assets.

ROCKIES OIL


Acquisition Creates Premier Powder River Position (continued)

The acreage also has stacked‐pay potential across multiple oil‐prone formations including the Parkman, Teapot and Turner.

With the closing of this transaction, the company’s Powder River Basin leasehold more than doubles to 470,000 net acres. This is by far the largest and highest quality acreage position in the basin with several billion barrels of potential resource.

Powder River Consistently Delivering High‐Rate Wells

Rockies production growth was again driven by strong results from its Powder River development program, which is delivering some of the best well results in Devon’s portfolio.

Fourth‐quarter activity was highlighted by 3 wells targeting the Parkman formation. Initial 30‐day rates from these wells averaged 1,030 Boe per day, of which 95% was light oil.

To date, across its legacy acreage position, the company has brought online more than 30 wells with 30‐day rates exceeding 1,000 Boe per day, with top‐tier wells around 2,000 Boe per day (table below).

Drilling & Completion Efficiencies Drive Costs Lower

Since the shift to extended‐reach laterals in late 2014, drilling times have improved by 21% to an average spud‐to‐rig release of 17 days in the fourth quarter. Recently the company achieved a record‐setting spud‐to‐TD of 11 days.

Due to these drilling efficiencies, coupled with current market conditions, Devon is now targeting well cost expectations in the Parkman/Teapot formations of $6.5 million per well (table/chart below).

Powder River Basin – A Significant Resource Opportunity

The company has identified approximately 1,300 undrilled inventory locations in the core of the oil fairway and expects inventory to increase over time as the basin is further de‐risked.

To advance the understanding of stacked‐pay potential in this region, Devon acquired over 800 square miles of proprietary seismic data in 2015. The company now owns more than 4,000 square miles of data that will help high‐grade opportunities in the Powder River Basin.

The company also has approximately $70 million of joint venture drilling carry to help fund future appraisal activity in the area.

$8.0

$6.5

Mid‐2015 Revised

≈20%Reduction

Parkman/Teapot Type Well

Key Modeling Stats

30‐Day IPBOED

1,000 – 1,300

EURMBOE

425 – 500

D&C Cost$MM

$6.5

D&C Cost($ Millions)

Well Name 30‐Day IPBOED

% Oil

Wright Fed 05‐084372‐3XPH 2,060 94%

Wright Fed 05‐084372‐4XPH 2,060 93%

Iberlin Ranch Fed 044176‐1XFH 1,980 86%

Cosner Fed 21‐284372‐1XPH 1,910 92%

Wright Fed 05‐084372‐1XPH 1,840 94%

Notable Wells – Powder River Oil

HEAVY OIL


HEAVY OIL Q4 STATSQ4 2015 Q4 2014

Production:Oil & Bitumen (MBOD) 121 93Gas (MMCFD) 24 23MBOED 126 97


Net oil production in Canada averaged a record‐setting 121,000 barrels per day in the fourth quarter.

This represents a 31% increase compared to the fourth quarter of 2014 (chart below) and was right in‐line with company guidance.

Q4 2014 Q4 2015

Heavy Oil Production(MBOD)

Lloydminster

Jackfish 1

Jackfish 2

Jackfish 393

121

31%Growth

Resilient Cash Operating Margin At Jackfish Complex

The strong production growth was driven by Devon’s Jackfish complex where net production averaged 93,000 barrels per day, a 40% increase compared to the fourth quarter of 2014.

The impact of this robust growth was enhanced by significantly lower operating costs. Jackfish LOE has now declined nearly 60% from peak rates in 2014 to $9.63 per barrel in Q4 (chart right).

These excellent operating results generated a positive cash operating margin of $7 per barrel or $80 million of cash flow during the quarter.

Even with challenging industry conditions, Devon’s heavy oil assets delivered $440 million of cash flow before hedges for the full‐year 2015.

$22.44

$18.15

$14.04

$17.43

$10.10 $9.63

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

Jackfish Complex Unit LOE($/BOE)

≈60%Improvement

Jackfish 1Turnaround

Jackfish 3 Exceeds Nameplate Capacity

The most significant driver of fourth‐quarter production growth was the continued ramp‐up of Jackfish 3.

Gross production at Jackfish 3 exceeded nameplate capacity, averaging 38,100 barrels per day in the fourth quarter. Net production averaged 37,600 barrels per day, an increase of more than 250% compared to the fourth quarter of 2014.

HEAVY OIL


1.7

11.214.6

23.1

36.2 38.1

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

2016 Outlook

The company expects net oil production from its Canadian operations to average between 122,000 and 127,000 barrels per day in 2016.

The capital investment to deliver this production profile is approximately $175 million in 2016.

Jackfish 3 Gross Production Ramp‐Up(MBOD)

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‐to‐oil ratio approaching 2.0.

Jackfish 2 Production Advances

Gross production at Jackfish 2 continued to progress toward nameplate capacity averaging 27,400 barrels per day in the fourth quarter. After royalties, net production totaled 26,900 barrels per day, 12% higher than the year‐ago quarter.

The company began steaming two new well pads in the fourth quarter of 2015. The contributions from these new pads are expected to increase Jackfish 2 production to nameplate capacity by the third quarter of 2016.

New Pads Online At Jackfish 1

Gross production averaged 30,300 barrels per day in the fourth quarter. After royalties, net production was 28,900 barrels per day.

Devon began steaming a new well pad at Jackfish 1 in the fourth quarter. Production from these new wells is expected to offset declines from older pads and boost production levels back to nameplate capacity in the second half of 2016.

BARNETT SHALE


BARNETT SHALE Q4 STATSQ4 2015 Q4 2014



Net production averaged 175,000 Boe per day or 1.1 Bcfe per day in the fourth quarter.

Over the past year, Devon’s focus on enhancing existing well performance has reduced its Barnett unaided PDP decline by approximately 15%. This was achieved with a capital investment of only $108 million.

Devon also has had success lowering operating expenses, with field‐level operating costs declining to $1.07 per Mcfe in Q4. This represents a decrease of 14% compared to the third quarter of 2015 (chart below).

$1.25

$1.07

Q3 2015 Q4 2015

14%Decline

(1) Includes LOE and production taxes.

Barnett Field‐Level Operating Costs(1)($/MCFE) HORIZONTAL REFRACS UPSIDE

82%Remaining Resource In Place

>3,000Horizontal Producing Wells

5.0 TCFEProved Reserves (12/31/15)

Horizontal Refrac Results Exceed Expectations

During 2015, the company accelerated its horizontal refrac program in the Barnett to test the re‐stimulation of 25 wells.

BARNETT SHALE


Horizontal Refrac Results Exceed Expectations (continued)

Of these 25 tests, 19 wells have achieved peak 30‐day IP rates, with an average per‐well uplift of approximately 1.1 MMcfe per day. Leading wells delivered peak rates in excess of 2 MMcfe per day.

On average, these initial horizontal tests increased per‐well production by 340% and exceeded the company’s type curve by nearly 10% (graphic below).

Additionally, Devon’s most recent refracs trended toward a cost of $1 million per well, around 20% below expectations.

The company plans to refrac 6 horizontal wells in 2016 and is prepared to restart when conditions incentivize higher activity.

Vertical Refrac Program Delivers Excellent Results

Devon also had an active vertical refrac program in 2015 that delivered excellent results. The company re‐stimulated 140 vertical wells during the year with an average per‐well production uplift of 440 Mcf per day, exceeding type‐curve expectations by 12%.

Vertical refrac costs in 2015 declined by as much as 40% compared to peak levels in 2014, with several wells costing less than $250,000 per well. Improved completion efficiencies and lower service costs drove this improvement.

The company also has potential to expand its resource base with an undrilled development inventory of 1,500 locations (table below)

Significant Recovery Upside

At year‐end 2015, Devon’s proved reserves in the Barnett totaled 5 Tcfe. Underpinning this proved reserve estimate is a recovery factor of only 18% from the company’s 5,000‐plus producing wells.

Devon has tremendous opportunity to increase its recoverable resource in the Barnett through ongoing refrac programs. Every 1% improvement in recovery leads to more than 600 Bcfe of additional recoverable resource(chart below).

Barnett Shale Resource Potential

Proved reserves 5 TCFE

Legacy horizontal wells >3,000 wells

Legacy vertical wells 1,900 wells

Undrilled inventory 1,500 risked locations

Total risked resource potential ≈10 TCFE

INCREASE

1.01.1

Type Well 2015 Results

30‐Day IP Uplift (MMCFED)

10%Increase

Horizontal Refracs

Average Per‐Well Production Incremental Proved Resource Potential

3.8

4.4

5.0

5.6

6.2

6.8

7.4

8.0

17% 18% 19% 20% 21% 22%

TCFE

% Increase in Recovery Factor

Proved Reserves12/31/15

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 February 16,2016.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.

Documents

Q4 2015 DVN Operations Report FINAL - s2.q4cdn.coms2.q4cdn.com/.../2015/Q4/Q4-2015-DVN-Operations-Report-FINAL.pdf · Core Assets (MBOED) 571 535 Other (MBOED ... improvement compared