TECHNICAL TELECONFERENCE (Apr2014) · Longer Term Production Data Supports Infill Drilling Infill...

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Maximizing Recovery Efficiency in Unconventional Oil ReservoirsApril 10, 2014

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This presentation includes statements that the Company believes to be forward‐looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this presentation are forward‐looking statements. These forward‐looking statements are subject to risks, uncertainties, assumptions and other factors, many of which are beyond the control of the Company. Important factors that could cause actual results to differ materially from those expressed or implied by the forward‐looking statements include the Company’s business strategy, financial strategy, oil and natural gas prices, production, reserves and resources, the impacts of state and federal laws, the impacts of hedging on our results of operations, level of success in exploration, development, acquisition and production activities, uncertainty regarding the Company’s future operating results and plans, objectives, expectations and intentions and other factors described in the Company’s 10‐K dated December 31, 2013. Whiting’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

In this presentation, we refer to Adjusted Net Income, Discretionary Cash Flow, Cash Flow per Share, EBITDAX and Net Debt, which are non‐GAAP measures that the Company believes are helpful in evaluating the performance of its business. A reconciliation of such non‐GAAP measures to the relevant GAAP measures can be found at the end of the presentation.

Whiting uses in this presentation the terms proved, probable and possible reserves. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods

and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Probable reserves are reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.

Whiting uses in this presentation the term “total resources,” which consists of contingent and prospective resources, which SEC rules prohibit in filings of U.S. registrants. Contingent resources are resources that are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles. For contingent resources to move into the reserves category, the key conditions, or contingencies, that prevented commercial development must be clarified and removed. Prospective resources are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared. Estimates of resources are by nature more uncertain than reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.

Forward‐Looking Statements, Non‐GAAP Measures, Reserve and Resource InformationForward‐Looking Statements, Non‐GAAP Measures, Reserve and Resource Information

2Energy + Technology = Growth

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Energy + Technology = Growth 3

Maximizing Recovery Efficiency in Unconventional Oil Reservoirs

Reservoir CharacterizationDetermine mobile fraction of Oil in Place (MOIP)

Evolution of Completion Design – Optimizing Production‐Technology‐Performance vs Cost

Bakken Development‐Completions Results‐High Density Pilots‐Development Pattern

Niobrara‐Redtail Development‐Discovery of the Niobrara Sweet Spot‐Defining Development Well Density‐Performance vs Cost

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Conventional Oil Reservoirs

Unconventional Oil Reservoirs (Effective)

Unconventional Oil Reservoirs (non‐effective)

Molecular Diameters of Common Hydrocarbons

1 Micrometer

1 Nanom

eter

4

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5

Middle Bakken B FaciesBraaflat 11‐11

9985’

Mountrail County, NDSanish Field

5 µm

Niobrara B ChalkTerrace 36‐32M

5580.2’

Redtail AreaWeld County, CO

5 µm

Middle Bakken B FaciesBraaflat 11‐11

9985’

Mountrail County, NDSanish Field

5 µm

Niobrara B ChalkTerrace 36‐32M

5580.2’

Redtail AreaWeld County, CO

5 µm


7% Porosity 13% Porosity

High-resolution pore structure image from Scanning Electron Microscope

Energy + Technology = Growth

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Annulus StagesFrac Ports per Stage

PotentialEntry

PointsFree fluidbetween packers 30 1 30

Annulus Stages

PerforationClusters

per Stage

PotentialEntry

Points

Cemented 40 3 120

Sliding Sleeve Completion

Cemented Liner Completion

Maximizing Recovery EfficiencyImproving Frac Design


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Evolution of Completion Design

CompletionTechnique

EntryPoints

Whiting Operated Completions to Date

Pre-2013 Ball & Sleeve 30 696

March 2013 Cemented Liner 40 stages

x3 perf clusters/stage

up to 120 74

March 2014 Cemented Liner 40 stages

x5 perf clusters/stage

up to 200 1

March 2014 Coiled Tubing Conveyed Plug & Perf

(Skov 31-28-3H)

85 1

April 2014 Slick Water30 stages

x3 perf clusters/stage (Sundheim 21-27-1H)

90 1

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Evolution of Completion DesignSkov 31‐28 Unit at Missouri Breaks

Well Annulus Completion Method StagesEntry

Points

Skov 31-28-1H Open Sliding Sleeve 30 30

Skov 31-28-2H Cemented P&P-3 clusters/stage 30 90

Skov 31-28-4H Cemented P&P-5 clusters/stage 30 150

Skov 31-28-3H Cemented CT-Multistage+(P&P-5) 60+25x5 85

IP (boepd) IncrIncr.

Cost ($MM)

927 - 7.90 -

1072 16%8.10 3%

1219 31%8.10 3%

1607 73%8.80 11%

1

12

2

3

3

4

4

.

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New Completion Design Delivers Superior Results50% to 75% Increases in 30, 60, 90 Day Rates


(1) Missouri Breaks includes 9 wells completed with cemented liners in 2013 and 31 wells with sliding sleeves. All wells have at least 90 days of production history.(2) Pronghorn includes 5 wells completed with cemented liners in 2013 and 44 wells with sliding sleeves. All wells have at least 90 days of production history.(3) Hidden Bench includes 6 wells completed with cemented liners in 2013 and 62 wells with sliding sleeves. All wells have at least 30 days of production history.

+75.0%

+57.0% +52.0%

+66.0% +70.0%

+61.0%

+68.0%

+0.0%

+10.0%

+20.0%

+30.0%

+40.0%

+50.0%

+60.0%

+70.0%

+80.0%

+90.0%

30‐Day Average 60‐Day Average 90‐Day Average

% Increase Cemented Liners vs. Sliding Sleeves

Missouri Breaks Pronghorn Hidden Bench(1) (2) (3)

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Williston Basin Development Drilling Plan


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Longer Term Production Data Supports Infill DrillingInfill Wells at Hidden Bench Superior on IP, 30 and 60‐Day Rates


2,282

983

731

1,994

782

594

0

500

1,000

1,500

2,000

2,500

24‐Hour IP 30‐Day Average 60‐Day Average

Infill Wells(1) vs. 65 Existing Spaced Wells(2)

Infill Wells 65 Existing Spaced Wells

+15%+15%

+26%+26%

+23%+23%

(1) Consists of the four Mork Trust infill wells: Mork Trust 21‐17‐2H, Mork Trust 21‐17‐3H, Mork Trust 21‐17‐4H, Mork Trust 21‐17‐5H.(2) Consists of all 65 wells completed on the original 4 wells per DSU spacing pattern.

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Redtail DiscoveryDefining the Sweet Spot of the Niobrara

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OBJECTIVENiobrara “B” ShaleNiobrara “A” Shale

DEVELOPMENT PLANMix of 960 and 640‐acre spacing units8 Wells per spacing unit Niobrara “B”8 Wells per spacing unit Niobrara “A”3,300+ potential drilling locations

ACREAGEWhiting has assembled 169,677 gross (122,278 net) acres in our Redtail prospect in the northeastern portion of the Weld County, CO in the Denver Basin. • Average WI of 72%• Average NRI of 59%

COMPLETED WELL COSTHorizontal: $5.5 MM

DRILLING HIGHLIGHTSOur 27L pad is targeting the Niobrara “B” zone while our 27K pad is testing both the Niobrara “B” and “A” zones. Both pads are located in our Razor area and are testing a 16‐well per 960‐acre drilling spacing unit pattern. Initial results from both pads are encouraging with early results from both “B” and “A” zone wells tracking our typical 400 MBOE type curve.

RedtailThe Economic Sweet spot of the Niobrara


Source: IHS and internal Whiting production database

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Niobrara Reservoir

Whiting RAZOR 25-2514HGR Zone PHI Mineralogy BVFluid RES

0 200 30 -10 0 0.2 2000 10

A

B

C

Niobrara Resource Potential (1)

***

GOR=500 cf/boStimulated Rock Volume

Reservoir Porosity (%)

Thickness (ft)

OOIP (MMBOE/960ac)*

NIO A 13% 35 19NIO B 13% 65 40NIO C 11% 25 11

70

OOIP by Zone

Recoverable Oil 16 Well / DSU Density(Total OOIP A Zone + B Zone = 59 MMBOE/DSU)**

16 wells 10% Recovery



370 MBOE 560 MBOE 740 MBOE

(1) Please refer to the beginning of this presentation for disclosures regarding “Reserve and Resource Information.” Estimates updated as of December 31, 2013

Recoverable Oil 32 Well / DSU Density(Total OOIP A Zone + B Zone + C Zone = 70 MMBOE/DSU)**




330 MBOE 440 MBOE 550 MBOE

Redtail Resource PotentialNiobrara A & B Reservoirs


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27L PadDrilling Density

- 16 Wells/DSU- 330 ft.

Target: B-B-B-BStatus: Flowing

27K PadDrilling Density


Target: A-B-A-BStatus: Flowing

Razor Pilot16 Wells / 960ac DSURazor Pilot16 Wells / 960ac DSU

30F PadDrilling Density


Target: C-B-A-B-A-B-C-B

Status: Drilling

Horsetail Pilot32 Wells / 960ac DSUHorsetail Pilot32 Wells / 960ac DSU

Planned WellsProducing Wells

Future Infill Wells

Redtail High Density PilotsTesting 16 & 32 Wells per Drilling Spacing Unit


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16

Optimizing Well DensityWhiting High-density Pilots

Downhole Microseismic Survey Design:2 Zipper-frac wells (interior wells) 2 Microseismic Monitor wells (outboard wells)

Plot showing actual Microseismic events for Stages 21 through 40 on Razor 27K Pad

‐18 Geophones per Array‐5 Stages recorded at each position‐7 Array Positions ‐40 Stages

‐2 Entry Points per Stage

Energy + Technology = Growth

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LegendRedtail 16 Well Planning Well Status

Existing WellsFuture LocationsPermittedTownshipOperatedNon‐Operated

Redtail Development Plan3,310 Gross (1,654 Net) Wells Upper Niobrara (A & B Zones) as of December 31, 2013


• 2014 – 2018 Development Plan Includes Approximately 1,024 Gross Wells With an 84% Average Working Interest

NBL Operated

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(1) 10 wells included in plot have 90 or more days of production, 3 wells have more than 60 days of production and 4 wells have more than 30 days of production. 5 wells are 640‐acre spaced wells. 12 wells are 960‐acre spaced wells.

Redtail Niobrara Well PerformanceImproved Completion Technology Results in Improved Performance(1)


0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

0 30 60 90 120 150 180 210

Cum. B

OE

400 MBOE Type Curve Cum vs Time

17 Recent Well Average Cum vs Time

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8” Residue PipelineConstructed By TallGrass

Redtail PlantUnder ConstructionTerrace Plant

Pony Express

Kinder Morgan Interstate

TrailblazerRedtail Facilities Plan

Planned Gathering SystemGas Gathering Lines 141 MilesOil Gathering Lines 111 MilesSW Gathering Lines 54 MilesFrac Water Supply Lines 16 Miles

Redtail Gas PlantTrain 1 Capacity (Q1 2014) 20 MMcfdTrain 2 Capacity (Q4 2014) 50 MMcfdTrain 3 Capacity (Q3 2015) 70MMcfdTakeaway Capacity (Q3 2015) 140 MMcfd

Capital Investment Gas Plant $100 MMGas Gathering / Field Compression $95 MMOil Gathering / LACTs $80 MMElectricity $40 MMTotal $315 MM

Redtail Infrastructure PlanAs of March 2014


TallgrassPawnee Terminal

TallgrassBuckingham Terminal

Northeast Colorado Lateral to Pony Express

TECHNICAL TELECONFERENCE (Apr2014) · Longer Term Production Data Supports Infill Drilling Infill...

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