Maximizing Recovery Efficiency in Unconventional Oil Reservoirs
NYSE: WLL
Maximizing Recovery Efficiency in Unconventional Oil Reservoirs April 10, 2014
Forward‐Looking Statements, Non‐GAAP Forward‐Looking Statements, Non‐GAAP Measures, Reserve and Resource Information
Measures, Reserve and Resource Information 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.
NYSE: WLL
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.
Energy + Technology = Growth
2
Maximizing Recovery Efficiency in Unconventional Oil Reservoirs Reservoir Characterization Determine 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
NYSE: WLL
‐Discovery of the Niobrara Sweet Spot ‐Defining Development Well Density ‐Performance vs Cost Energy + Technology = Growth
3
Reservoir Characterization Determine mobile fraction of Oil in Place (MOIP)
Unconventional Oil Reservoirs (Effective)
NYSE: WLL
Conventional Oil Reservoirs
1 Micrometer
1 Nanometer
Molecular Diameters of Common Hydrocarbons
Unconventional Oil Reservoirs (non‐ effective)
4
Reservoir Characterization Determine mobile fraction of Oil in Place (MOIP) High-resolution pore structure image from Scanning Electron Microscope 5 µm
5 µm
NYSE: WLL
7% Porosity
13% Porosity
9985’ Middle Bakken B Facies Braaflat 11‐11 Sanish Field Mountrail County, ND Energy + Technology = Growth
5580.2’ Niobrara B Chalk Terrace 36‐32M Redtail Area Weld County, CO 5
Maximizing Recovery Efficiency Improving Frac Design
Sliding Sleeve Completion
Annulus Free fluid between packers
Frac Ports Stages per Stage
30
1
Potential Entry Points
30
Cemented Liner Completion
Annulus
NYSE: WLL
Cemented
Energy + Technology = Growth
Perforation Clusters Stages per Stage 40
3
Potential Entry Points 120
6
Evolution of Completion Design
Pre-2013
March 2013
Completion Technique
Entry Points
Whiting Operated Completions to Date
Ball & Sleeve
30
696
Cemented Liner
up to 120
74
up to 200
1
85
1
90
1
40 stages x3 perf clusters/stage
March 2014
Cemented Liner 40 stages x5 perf clusters/stage
March 2014 Coiled Tubing Conveyed Plug & Perf (Skov 31-28-3H)
NYSE: WLL
April 2014
Slick Water 30 stages x3 perf clusters/stage (Sundheim 21-27-1H)
Energy + Technology = Growth
7
Evolution of Completion Design Skov 31‐28 Unit at Missouri Breaks
1 2 3 4
Cost ($MM)
Incr.
IP (boepd) Incr.
Well
Annulus
Completion Method
Stages
Entry Points
Skov 31-28-1H
Open
Sliding Sleeve
30
30
7.90
-
927
-
Skov 31-28-2H
Cemented
P&P-3 clusters/stage
30
90
8.10
3%
1072
16%
Skov 31-28-4H
Cemented
P&P-5 clusters/stage
30
150
8.10
3%
1219
31%
Skov 31-28-3H
Cemented
CT-Multistage+(P&P-5) 60+25x5
85
8.80
11%
1607
73%
1 2
NYSE: WLL
4
3
Energy + Technology = Growth
8
New Completion Design Delivers Superior Results 50% to 75% Increases in 30, 60, 90 Day Rates % Increase Cemented Liners vs. Sliding Sleeves +90.0% +80.0% +70.0%
+75.0% +66.0%
+70.0%
+68.0%
+61.0% +57.0%
+60.0%
+52.0% +50.0% +40.0% +30.0% +20.0% +10.0% +0.0% 30‐Day Average
60‐Day Average (1)
NYSE: WLL
Missouri Breaks (1) (2) (3)
(2)
Pronghorn
90‐Day Average (3)
Hidden Bench
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. 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. 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.
Energy + Technology = Growth
9
NYSE: WLL
Williston Basin Development Drilling Plan
Energy + Technology = Growth
10
Longer Term Production Data Supports Infill Drilling Infill Wells at Hidden Bench Superior on IP, 30 and 60‐Day Rates Infill Wells(1) vs. 65 Existing Spaced Wells(2) 2,500 2,282
2,000
+15%
1,994
1,500
983
1,000
+26%
782
731
+23%
594 500
0 24‐Hour IP
30‐Day Average
NYSE: WLL
Infill Wells (1) (2)
60‐Day Average
65 Existing Spaced Wells
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. Consists of all 65 wells completed on the original 4 wells per DSU spacing pattern.
Energy + Technology = Growth
11
Redtail Discovery
NYSE: WLL
Defining the Sweet Spot of the Niobrara
12
Redtail The Economic Sweet spot of the Niobrara
OBJECTIVE Niobrara “B” Shale Niobrara “A” Shale DEVELOPMENT PLAN Mix of 960 and 640‐acre spacing units 8 Wells per spacing unit Niobrara “B” 8 Wells per spacing unit Niobrara “A” 3,300+ potential drilling locations ACREAGE Whiting 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%
NYSE: WLL
COMPLETED WELL COST Horizontal: $5.5 MM DRILLING HIGHLIGHTS Our 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.
Source: IHS and internal Whiting production database
Energy + Technology = Growth
13
Redtail Resource Potential Niobrara A & B Reservoirs Niobrara Resource Potential (1)
Niobrara Reservoir
OOIP by Zone
Whiting RAZOR 25-2514H GR 0 10
Zone 200
PHI 30
Mineralogy -10
BVFluid 0
A
RES 0.2
2000
Reservoir Porosity Thickness OOIP (% ) (ft) (MMBOE/960ac)* NIO A NIO B NIO C
13% 13% 11%
35 65 25
19 40 11 70
Recoverable Oil 16 Well / DSU Density
B
(Total OOIP A Zone + B Zone = 59 MMBOE/DSU)**
16 wells 10% Recovery 370 MBOE
16 wells 15% Recovery 560 MBOE
16 wells 20% Recovery 740 MBOE
Recoverable Oil 32 Well / DSU Density
NYSE: WLL
C
(Total OOIP A Zone + B Zone + C Zone = 70 MMBOE/DSU)**
32 wells 15% Recovery
32 wells 20% Recovery
32 wells 25% Recovery
330 MBOE
440 MBOE
550 MBOE
* GOR=500 cf/bo ** Stimulated Rock Volume (1) Please refer to the beginning of this presentation for disclosures regarding “Reserve and Resource Information.” Estimates updated as of December 31, 2013
Energy + Technology = Growth
14
Redtail High Density Pilots Testing 16 & 32 Wells per Drilling Spacing Unit 27L Pad Drilling Density - 16 Wells/DSU - 330 ft. Target: B-B-B-B Status: Flowing
27K Pad Drilling Density - 16 Wells/DSU - 330 ft. Target: A-B-A-B Status: Flowing
Razor Pilot 16 Wells / 960ac DSU
30F Pad Drilling Density - 32 Wells/DSU - 165 ft. Target: C-B-A-BA-B-C-B Status: Drilling
NYSE: WLL
Horsetail Pilot 32 Wells / 960ac DSU
Producing Wells Planned Wells Future Infill Wells
Energy + Technology = Growth
15
Optimizing Well Density Whiting High-density Pilots
Plot showing actual Microseismic events for Stages 21 through 40 on Razor 27K Pad
Downhole Microseismic Survey Design: 2 Zipper-frac wells (interior wells) 2 Microseismic Monitor wells (outboard wells)
‐18 Geophones per Array ‐5 Stages recorded at each position ‐7 Array Positions ‐40 Stages
NYSE: WLL
‐2 Entry Points per Stage
Energy + Technology = Growth
16
Redtail Development Plan 3,310 Gross (1,654 Net) Wells Upper Niobrara (A & B Zones) as of December 31, 2013
NYSE: WLL
•
2014 – 2018 Development Plan Includes Approximately 1,024 Gross Wells With an 84% Average Working Interest
NBL Operated
Energy + Technology = Growth
Legend Redtail 16 Well Planning Well Status Existing Wells Future Locations Permitted Township Operated Non‐Operated
17
Redtail Niobrara Well Performance Improved Completion Technology Results in Improved Performance(1) 80,000 70,000 60,000
Cum. BOE
50,000 40,000 30,000 20,000
400 MBOE Type Curve Cum vs Time
10,000
17 Recent Well Average Cum vs Time
0
NYSE: WLL
0
30
60
90
120
150
180
210
(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.
Energy + Technology = Growth
18
Redtail Infrastructure Plan As of March 2014 Kinder Morgan Interstate
Redtail Facilities Plan Planned Gathering System Gas Gathering Lines Oil Gathering Lines SW Gathering Lines Frac Water Supply Lines
141 Miles 111 Miles 54 Miles 16 Miles
Redtail Gas Plant Train 1 Capacity (Q1 2014) Train 2 Capacity (Q4 2014) Train 3 Capacity (Q3 2015) Takeaway Capacity (Q3 2015)
8” Residue Pipeline Constructed By TallGrass Pony Express
NYSE: WLL
Redtail Plant Under Construction
Terrace Plant
20 MMcfd 50 MMcfd 70MMcfd
Tallgrass Pawnee Terminal Northeast Colorado Lateral to Pony Express
140 MMcfd
Capital Investment Gas Plant Gas Gathering / Field Compression Oil Gathering / LACTs Electricity Total
Trailblazer
$100 MM $95 MM $80 MM $40 MM $315 MM
Energy + Technology = Growth
Tallgrass Buckingham Terminal
19
Maximizing Recovery Efficiency in Unconventional Oil Reservoirs April 10, 2014
Forward‐Looking Statements, Non‐GAAP Forward‐Looking Statements, Non‐GAAP Measures, Reserve and Resource Information
Measures, Reserve and Resource Information 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.
NYSE: WLL
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.
Energy + Technology = Growth
2
Maximizing Recovery Efficiency in Unconventional Oil Reservoirs Reservoir Characterization Determine 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
NYSE: WLL
‐Discovery of the Niobrara Sweet Spot ‐Defining Development Well Density ‐Performance vs Cost Energy + Technology = Growth
3
Reservoir Characterization Determine mobile fraction of Oil in Place (MOIP)
Unconventional Oil Reservoirs (Effective)
NYSE: WLL
Conventional Oil Reservoirs
1 Micrometer
1 Nanometer
Molecular Diameters of Common Hydrocarbons
Unconventional Oil Reservoirs (non‐ effective)
4
Reservoir Characterization Determine mobile fraction of Oil in Place (MOIP) High-resolution pore structure image from Scanning Electron Microscope 5 µm
5 µm
NYSE: WLL
7% Porosity
13% Porosity
9985’ Middle Bakken B Facies Braaflat 11‐11 Sanish Field Mountrail County, ND Energy + Technology = Growth
5580.2’ Niobrara B Chalk Terrace 36‐32M Redtail Area Weld County, CO 5
Maximizing Recovery Efficiency Improving Frac Design
Sliding Sleeve Completion
Annulus Free fluid between packers
Frac Ports Stages per Stage
30
1
Potential Entry Points
30
Cemented Liner Completion
Annulus
NYSE: WLL
Cemented
Energy + Technology = Growth
Perforation Clusters Stages per Stage 40
3
Potential Entry Points 120
6
Evolution of Completion Design
Pre-2013
March 2013
Completion Technique
Entry Points
Whiting Operated Completions to Date
Ball & Sleeve
30
696
Cemented Liner
up to 120
74
up to 200
1
85
1
90
1
40 stages x3 perf clusters/stage
March 2014
Cemented Liner 40 stages x5 perf clusters/stage
March 2014 Coiled Tubing Conveyed Plug & Perf (Skov 31-28-3H)
NYSE: WLL
April 2014
Slick Water 30 stages x3 perf clusters/stage (Sundheim 21-27-1H)
Energy + Technology = Growth
7
Evolution of Completion Design Skov 31‐28 Unit at Missouri Breaks
1 2 3 4
Cost ($MM)
Incr.
IP (boepd) Incr.
Well
Annulus
Completion Method
Stages
Entry Points
Skov 31-28-1H
Open
Sliding Sleeve
30
30
7.90
-
927
-
Skov 31-28-2H
Cemented
P&P-3 clusters/stage
30
90
8.10
3%
1072
16%
Skov 31-28-4H
Cemented
P&P-5 clusters/stage
30
150
8.10
3%
1219
31%
Skov 31-28-3H
Cemented
CT-Multistage+(P&P-5) 60+25x5
85
8.80
11%
1607
73%
1 2
NYSE: WLL
4
3
Energy + Technology = Growth
8
New Completion Design Delivers Superior Results 50% to 75% Increases in 30, 60, 90 Day Rates % Increase Cemented Liners vs. Sliding Sleeves +90.0% +80.0% +70.0%
+75.0% +66.0%
+70.0%
+68.0%
+61.0% +57.0%
+60.0%
+52.0% +50.0% +40.0% +30.0% +20.0% +10.0% +0.0% 30‐Day Average
60‐Day Average (1)
NYSE: WLL
Missouri Breaks (1) (2) (3)
(2)
Pronghorn
90‐Day Average (3)
Hidden Bench
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. 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. 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.
Energy + Technology = Growth
9
NYSE: WLL
Williston Basin Development Drilling Plan
Energy + Technology = Growth
10
Longer Term Production Data Supports Infill Drilling Infill Wells at Hidden Bench Superior on IP, 30 and 60‐Day Rates Infill Wells(1) vs. 65 Existing Spaced Wells(2) 2,500 2,282
2,000
+15%
1,994
1,500
983
1,000
+26%
782
731
+23%
594 500
0 24‐Hour IP
30‐Day Average
NYSE: WLL
Infill Wells (1) (2)
60‐Day Average
65 Existing Spaced Wells
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. Consists of all 65 wells completed on the original 4 wells per DSU spacing pattern.
Energy + Technology = Growth
11
Redtail Discovery
NYSE: WLL
Defining the Sweet Spot of the Niobrara
12
Redtail The Economic Sweet spot of the Niobrara
OBJECTIVE Niobrara “B” Shale Niobrara “A” Shale DEVELOPMENT PLAN Mix of 960 and 640‐acre spacing units 8 Wells per spacing unit Niobrara “B” 8 Wells per spacing unit Niobrara “A” 3,300+ potential drilling locations ACREAGE Whiting 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%
NYSE: WLL
COMPLETED WELL COST Horizontal: $5.5 MM DRILLING HIGHLIGHTS Our 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.
Source: IHS and internal Whiting production database
Energy + Technology = Growth
13
Redtail Resource Potential Niobrara A & B Reservoirs Niobrara Resource Potential (1)
Niobrara Reservoir
OOIP by Zone
Whiting RAZOR 25-2514H GR 0 10
Zone 200
PHI 30
Mineralogy -10
BVFluid 0
A
RES 0.2
2000
Reservoir Porosity Thickness OOIP (% ) (ft) (MMBOE/960ac)* NIO A NIO B NIO C
13% 13% 11%
35 65 25
19 40 11 70
Recoverable Oil 16 Well / DSU Density
B
(Total OOIP A Zone + B Zone = 59 MMBOE/DSU)**
16 wells 10% Recovery 370 MBOE
16 wells 15% Recovery 560 MBOE
16 wells 20% Recovery 740 MBOE
Recoverable Oil 32 Well / DSU Density
NYSE: WLL
C
(Total OOIP A Zone + B Zone + C Zone = 70 MMBOE/DSU)**
32 wells 15% Recovery
32 wells 20% Recovery
32 wells 25% Recovery
330 MBOE
440 MBOE
550 MBOE
* GOR=500 cf/bo ** Stimulated Rock Volume (1) Please refer to the beginning of this presentation for disclosures regarding “Reserve and Resource Information.” Estimates updated as of December 31, 2013
Energy + Technology = Growth
14
Redtail High Density Pilots Testing 16 & 32 Wells per Drilling Spacing Unit 27L Pad Drilling Density - 16 Wells/DSU - 330 ft. Target: B-B-B-B Status: Flowing
27K Pad Drilling Density - 16 Wells/DSU - 330 ft. Target: A-B-A-B Status: Flowing
Razor Pilot 16 Wells / 960ac DSU
30F Pad Drilling Density - 32 Wells/DSU - 165 ft. Target: C-B-A-BA-B-C-B Status: Drilling
NYSE: WLL
Horsetail Pilot 32 Wells / 960ac DSU
Producing Wells Planned Wells Future Infill Wells
Energy + Technology = Growth
15
Optimizing Well Density Whiting High-density Pilots
Plot showing actual Microseismic events for Stages 21 through 40 on Razor 27K Pad
Downhole Microseismic Survey Design: 2 Zipper-frac wells (interior wells) 2 Microseismic Monitor wells (outboard wells)
‐18 Geophones per Array ‐5 Stages recorded at each position ‐7 Array Positions ‐40 Stages
NYSE: WLL
‐2 Entry Points per Stage
Energy + Technology = Growth
16
Redtail Development Plan 3,310 Gross (1,654 Net) Wells Upper Niobrara (A & B Zones) as of December 31, 2013
NYSE: WLL
•
2014 – 2018 Development Plan Includes Approximately 1,024 Gross Wells With an 84% Average Working Interest
NBL Operated
Energy + Technology = Growth
Legend Redtail 16 Well Planning Well Status Existing Wells Future Locations Permitted Township Operated Non‐Operated
17
Redtail Niobrara Well Performance Improved Completion Technology Results in Improved Performance(1) 80,000 70,000 60,000
Cum. BOE
50,000 40,000 30,000 20,000
400 MBOE Type Curve Cum vs Time
10,000
17 Recent Well Average Cum vs Time
0
NYSE: WLL
0
30
60
90
120
150
180
210
(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.
Energy + Technology = Growth
18
Redtail Infrastructure Plan As of March 2014 Kinder Morgan Interstate
Redtail Facilities Plan Planned Gathering System Gas Gathering Lines Oil Gathering Lines SW Gathering Lines Frac Water Supply Lines
141 Miles 111 Miles 54 Miles 16 Miles
Redtail Gas Plant Train 1 Capacity (Q1 2014) Train 2 Capacity (Q4 2014) Train 3 Capacity (Q3 2015) Takeaway Capacity (Q3 2015)
8” Residue Pipeline Constructed By TallGrass Pony Express
NYSE: WLL
Redtail Plant Under Construction
Terrace Plant
20 MMcfd 50 MMcfd 70MMcfd
Tallgrass Pawnee Terminal Northeast Colorado Lateral to Pony Express
140 MMcfd
Capital Investment Gas Plant Gas Gathering / Field Compression Oil Gathering / LACTs Electricity Total
Trailblazer
$100 MM $95 MM $80 MM $40 MM $315 MM
Energy + Technology = Growth
Tallgrass Buckingham Terminal
19
