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Oil and Gas Supply Module

The NEMS Oil and Gas Supply Module (OGSM) constitutes a comprehensive framework with which to 

analyze crude oil and natural gas exploration and development on a regional basis (Figure 8). The OGSM is 

organized into 4 submodules: Onshore Lower 48 Oil and Gas Supply Submodule, Offshore Oil and Gas Supply 

Submodule, Oil Shale Supply Submodule [93], and Alaska Oil and Gas Supply Submodule. A detailed 

description of the OGSM is provided in the EIA publication, Oil and Gas Supply Module of the National 

Energy Modeling System: Model Documentation 2014, DOE/EIA-M063 (2014), (Washington, DC, 2014). The 

OGSM provides crude oil and natural gas short-term supply parameters to both the Natural Gas 

Transmission and Distribution Module and the Petroleum Market Module. The OGSM simulates the activity 

of numerous firms that produce oil and natural gas from domestic fields throughout the United States.

Figure 8. Oil and Gas Supply Model regions

OGSM encompasses domestic crude oil and natural gas supply by several recovery techniques and sources. 

Crude oil recovery includes improved oil recovery processes such as water flooding, infill drilling, and 

horizontal drilling, as well as enhanced oil recovery processes such as CO2 flooding, steam flooding, and 

polymer flooding. Recovery from highly fractured, continuous zones (e.g. Austin chalk and Bakken shale 

formations) is also included. Natural gas supply includes resources from low- permeability tight sand 

formations, shale formations, coalbed methane, and other sources.

Key assumptions 

Domestic oil and natural gas technically recoverable resources

The outlook for domestic crude oil production is highly dependent upon the production profile of individual 

wells over time, the cost of drilling and operating those wells, and the revenues generated by those wells. 
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Every year EIA re-estimates initial production (IP) rates and production decline curves, which determine 

estimated ultimate recovery (EUR) per well and total technically recoverable resources (TRR) [94].

A common measure of the long-term viability of U.S. domestic crude oil and natural gas as an energy source 

is the remaining technically recoverable resource, consisting of proved reserves [95] and unproved 

resources [96]. Estimates of TRR are highly uncertain, particularly in emerging plays where few wells have 

been drilled. Early estimates tend to vary and shift significantly over time as new geological information is 

gained through additional drilling, as long-term productivity is clarified for existing wells, and as the 

productivity of new wells increases with technology improvements and better management practices. TRR 

estimates used by EIA for each AEO are based on the latest available well production data and on 

information from other federal and state governmental agencies, industry, and academia. Published 

estimates in Tables 9.1 and 9.2 reflect the removal of intervening reserve additions and production between 

the date of the latest available assessment and January 1, 2012.

The resources presented in the tables in this chapter are the starting values for the model. Technology 

improvements in the model add to the unproved TTR, which can be converted to reserves and finally 

production. The tables in this chapter do not include these increases in TRR.

Table 9.1. Technically recoverable U.S. crude oil resources as of January 1, 2013 

billion barrels

Total Technically

Proved 

Reserves Unproved Resources

Recoverable 

Resources

Lower 48 Onshore 24.5 144.8 169.3

 East 0.3 2.6 2.9

 Gulf Coast 5.3 29.1 34.4

 Midcontinent 2.1 13.1 15.2

 Southwest 7.4 48.1 55.4

 Rocky Mountain 6.7 42.0 48.7

 West Coast 2.8 10.0 12.7

Lower 48 Offshore 5.6 47.5 53.1

 Gulf (currently available) 5.0 35.5 40.5

 Eastern/Central Gulf (unavailable until 2022) 0.0 3.7 3.7

 Pacific 0.5 5.9 6.4

 Atlantic 0.0 2.5 2.5

Alaska (Onshore and Offshore) 3.4 34.0 37.4

Total U.S. 33.4 226.4 259.8

Note: Crude oil resources include lease condensates but do not include natural gas plant liquids or kerogen (oil 

shale). Resources in areas where drilling is officially prohibited are not included in this table. The estimate of 7.3 

billion barrels of crude oil resources in the Northern Atlantic, Northern and Central Pacific, and within a 50-mile 

buffer off the Mid and Southern Atlantic Outer Continental Shelf (OCS) is also excluded from the technically 

recoverable volumes because leasing is not expected in these areas by 2040.

Source: Onshore and State Offshore - U.S. Energy Information Administration; Alaska - U.S. Geological Survey 

(USGS); Federal (Outer Continental Shelf) Offshore - Bureau of Ocean Energy Management (formerly the Minerals 

Management Service); Proved Reserves - U.S. Energy Information Administration. Table values reflect removal of 

intervening reserve additions between the date the latest available assessment and January 1, 2013.
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Table 9.2. Technically recoverable U.S. dry natural gas resources as of January 1, 2013

trillion cubic feet

Proved Unproved Total Technically

Reserves Resources Recoverable Resources

Lower 48 Onshore 287.3 1,392.0 1,679.3

 Tight Gas 65.3 353.7 418.9

 East 0.5 38.0 38.5

 Gulf Coast 13.4 159.1 172.5

 Midcontinent 6.9 10.8 17.7

 Southwest 7.2 33.3 40.5

 Rocky Mountain 37.2 112.5 149.7

 West Coast 0.0 0.0 0.0

 Shale Gas & Tight Oil 141.2 595.7 736.9

 East 44.6 254.2 298.8

 Gulf Coast 37.6 154.2 191.8

 Midcontinent 23.4 45.6 69.0

 Southwest 32.0 74.7 106.7

 Rocky Mountain 3.6 51.7 55.4

 West Coast 0.0 15.2 15.2

 Coalbed Methane 13.6 119.6 133.2

 East 1.7 4.1 5.8

 Gulf Coast 1.1 2.2 3.3

 Midcontinent 0.6 38.3 38.9

 Southwest 0.4 5.8 6.1

 Rocky Mountain 9.7 59.0 68.7

 West Coast 0.0 10.3 10.3

 Other 67.4 323.0 390.4

 East 11.5 29.6 41.1

 Gulf Coast 7.7 116.4 124.1

 Midcontinent 17.4 35.1 52.5

 Southwest 7.8 70.5 78.3

 Rocky Mountain 21.1 52.6 73.7

 West Coast 1.9 18.8 20.7

Lower 48 Offshore 11.2 305.3 316.5

 Gulf (currently available) 10.5 250.9 261.4

 Eastern/Central Gulf (unavailable until 2022) 0.0 21.5 21.5

 Pacific 0.7 9.3 10.1

 Atlantic 0.0 23.6 23.6

Alaska (Onshore and Offshore) 9.7 271.1 280.7

Total U.S. 308.2 1,968.4 2,276.5

Note: Resources in other areas where drilling is officially prohibited are not included. The estimate of 32.9 trillion cubic 

feet of natural gas resources in the Northern Atlantic, Northern and Central Pacific, and within a 50-mile buffer off the 

Mid and Southern Atlantic OCS is also excluded from the technically recoverable volumes because leasing is not 

expected in these areas by 2040. 

Source: Onshore and State Offshore - U.S. Energy Information Administration; Alaska - U.S. Geological Survey (USGS); 

Federal (Outer Continental Shelf) Offshore - Bureau of Ocean Energy Management (formerly the Minerals Management 

Service); Proved Reserves - U.S. Energy Information Administration. Table values reflect removal of intervening reserve 

additions between the date the latest available assessment and January 1, 2013.
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The remaining unproved TRR for a continuous-type shale gas or tight oil area is the product of (1) area with 

potential, (2) well spacing (wells per square mile), and (3) EUR per well. The play-level unproved technically 

recoverable resource assumptions for tight oil, shale gas, tight gas, and coalbed methane are summarized in 

Tables 9.3-9.4. The model uses a distribution of EUR per well in each play and often in sub-play areas. Table 

9.5 provides an example of the distribution of EUR per well for each of the Bakken areas. The Bakken is 

subdivided into five areas: Central Basin, Eastern Transitional, Elm Coulee-Billings Nose, Nesson-Little Knife, 

and Northwest Transitional [97]. Because of the significant variation in well productivity within an area, the 

wells in each Bakken area are further delineated by county. This level of detail is provided for select plays in 

Appendix 2.C of the AEO2014 Documentation for the OGSM. The USGS periodically publishes tight and shale 

resource assessments that are used as a guide for selection of key parameters in the calculation of the TRR 

used in the AEO. The USGS seeks to assess the recoverability of shale gas and tight oil based on the wells 

drilled and technologies deployed at the time of the assessment. AEO2015 introduces a contour map based 

approach for incorporating geology parameters into the calculation of resources; recognizing that geology 

can vary significantly within counties. This new approach was only applied to the Marcellus play.

The AEO TRRs incorporate current drilling, completion, and recovery techniques, requiring adjustments to 

some of the assumptions used by the USGS to generate their TRR estimates, as well as the inclusion of shale 

gas and tight oil resources not yet assessed by the USGS. If well production data are available, EIA analyzes 

the decline curve of producing wells to calculate the expected ̶ EUR per well from future drilling.
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U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 132

The underlying resource for the Reference case is uncertain, particularly as exploration and development of 

tight oil continues to move into areas with little to no production history. Many wells drilled in tight or shale 

formations using the latest technologies have less than two years of production history so the impact of 

recent technological advancement on the estimate of future recovery cannot be fully ascertained. 

Uncertainty also extends to areal extent of formations and the number of layers that could be drilled within 

formations. An alternative resource cases are discussed at the end of this chapter.

Lower 48 onshore 

The Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) is a play-level model used to analyze crude 

oil and natural gas supply from onshore lower 48 sources. The methodology includes a comprehensive 

assessment method for determining the relative economics of various prospects based on financial 

considerations, the nature of the resource, and the available technologies. The general methodology relies 

on a detailed economic analysis of potential projects in known fields, enhanced oil recovery projects, and 

undiscovered resources. The projects which are economically viable are developed subject to the availability 

of resource development constraints which simulate the existing and expected infrastructure of the oil and 

gas industries. For crude oil projects, advanced secondary or improved oil recovery techniques (e.g. infill 

drilling and horizontal drilling) and enhanced oil recovery (e.g. CO2 flooding, steam flooding, and polymer 

flooding) processes are explicitly represented. For natural gas projects, the OLOGSS represents supply from 

shale formations, tight sands formations, coalbed methane, and other sources.

The OLOGSS evaluates the economics of future crude oil and natural gas exploration and development from 

the perspective of an operator making an investment decision. An important aspect of the economic 

calculation concerns the tax treatment. Tax provisions vary with the type of producer (major, large 

independent, or small independent). For AEO2015, the economics of potential projects reflect the tax 

treatment provided by current laws for large independent producers. Relevant tax provisions are assumed 

unchanged over the life of the investment. Costs are assumed constant over the investment life but vary 

across region, fuel, and process type. Operating losses incurred in the initial investment period are carried 

forward and used against revenues generated by the project in later years.
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Table 9.3. U.S. unproved technically recoverable tight/shale oil and gas resources by play (as of 

January 1, 2013) 

Average EUR

Technically Recoverable 

Resources

Area with 

Potentiall

1

Average 

Spacing 

(wells/

Crude Oil2

(MMbls/

Natural 

Gas

Crude 

Oil

Natural 

Gas NGPL

Region/Basin Play (mi2) mi2) well) (Bcf/well) (Bbls) (Tcf) (Bbls)

East

 Appalachian Clinton-Medina 26,907 8.0 0.002 0.058 0.4 12.4 0.0

 Appalachian Devonian 51,842 7.5 0.000 0.061 0.0 23.7 0.4

 Appalachian Marcellus Foldbelt 869 4.3 0.000 0.323 0.0 1.2 0.0

 Appalachian Marcellus Interior 17,200 4.4 0.003 1.897 0.3 143.8 5.5

 Appalachian Marcellus Western 2,688 5.5 0.000 0.255 0.0 3.7 0.2

 Appalachian Tuscarora 765 8.0 0.000 0.724 0.0 4.4 0.0

 Appalachian Utica-Gas Zone Core 11,398 4.3 0.001 0.726 0.0 35.3 3.1

 Appalachian Utica-Gas Zone Extension 15,062 4.3 0.003 0.277 0.2 17.8 2.6

 Appalachian Utica-Oil Zone Core 2,300 2.6 0.052 0.176 0.3 1.0 0.0

 Appalachian Utica-Oil-Zone Extension 3,861 2.6 0.039 0.047 0.4 0.5 0.0

 Illinois New Albany 3,059 8.0 0.000 1.188 0.0 29.1 2.3

 Michigan Antrim Shale 13,178 8.0 0.000 0.120 0.0 12.7 1.0

 Michigan Berea Sand 7,451 8.0 0.000 0.110 0.0 6.6 0.1

Gulf Coast

 Black Warrior Floyd-Neal/Conasauga 1,402 2.0 0.000 1.520 0.0 4.3 0.0

 TX-LA-MS Salt Cotton Valley 8,773 12.0 0.008 1.323 0.8 139.3 2.7

 TX-LA-MS Salt Haynesville-Bossier-LA 1,883 6.0 0.002 4.279 0.0 48.3 0.0

 TX-LA-MS Salt Haynesville-Bossier-TX 1,521 6.0 0.001 2.735 0.0 25.0 0.0

 Western Gulf Austin Chalk-Giddings 2,572 8.0 0.059 0.255 1.2 5.2 0.7

 Western Gulf Austin Chalk-Outlying 9,866 7.1 0.061 0.075 4.3 5.2 0.3

 Western Gulf Buda 8,640 4.0 0.059 0.109 2.0 3.8 0.1

 Western Gulf Eagle Ford-Dry Zone 2,085 6.0 0.090 1.473 1.1 18.4 0.0

 Western Gulf Eagle Ford-Oil Zone 4,967 6.4 0.123 0.227 3.9 7.2 0.1

 Western Gulf Eagle Ford-Wet Zone 3,509 6.0 0.250 1.416 5.3 29.8 0.6

 Western Gulf Olmos 5,463 4.0 0.008 1.162 0.2 25.4 0.0

 Western Gulf Pearsall 1,196 6.0 0.001 0.676 0.0 4.9 0.0

 Western Gulf Tuscaloosa 7,448 4.0 0.107 0.021 3.2 0.6 0.0

 Western Gulf Vicksburg 329 8.0 0.026 0.980 0.1 2.6 0.1

 Western Gulf Wilcox Lobo 1,142 8.0 0.000 1.403 0.0 12.8 0.3

 Western Gulf Woodbine 1,222 4.0 0.120 0.061 0.6 0.3 0.0

Midcontinent

 Anadarko Cana Woodford-Dry Zone 737 4.0 0.023 1.995 0.1 5.9 0.0

 Anadarko Cana Woodford-Oil Zone 460 6.0 0.041 0.961 0.1 2.7 0.1

 Anadarko Cana Woodford-Wet Zone 1,068 4.0 0.016 1.310 0.1 5.6 0.5

 Anadarko Cleveland 639 4.1 0.048 0.384 0.1 1.0 0.0

 Anadarko Granite Wash 3,788 4.0 0.040 0.579 0.6 8.8 0.5

 Anadarko Red Fork 513 4.0 0.019 0.459 0.0 0.9 0.1

 Arkoma Carney 797 4.0 0.000 0.973 0.0 3.1 0.0

 Arkoma Fayetteville-Central 2,065 8.0 0.000 0.973 0.0 16.1 0.0

 Arkoma Fayetteville-West 773 8.0 0.000 0.700 0.0 4.3 0.0

 Arkoma Woodford-Arkoma 591 8.0 0.003 1.342 0.0 6.3 0.6

 Black Warrior Chattanooga 205 8.0 0.000 0.968 0.0 1.6 0.0

Southwest

 Fort Worth Barnett-Core 363 8.0 0.000 1.621 0.0 4.7 0.2

 Fort Worth Barnett-North 1,611 8.2 0.008 0.467 0.1 6.2 0.2

 Fort Worth Barnett-South 5,368 8.0 0.003 0.154 0.1 6.6 0.3
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Table 9.3. U.S. unproved technically recoverable tight/shale oil and gas resources by play (as of 

January 1, 2013) (cont.)

Average EUR

Technically Recoverable 

Resources

Area with 

Potentiall

1

Average 

Spacing 

(wells/

Crude Oil2

(MMbls/

Natural 

Gas

Crude 

Oil

Natural 

Gas NGPL

Region/Basin Play (mi2) mi2) well) (Bcf/well) (Bbls) (Tcf) (Bbls)

 Permian Abo 2,540 4.0 0.067 0.149 0.7 1.5 0.1

 Permian Avalon/BoneSpring 5,444 4.5 0.118 0.367 2.9 9.0 0.5

 Permian Barnett-Woodford 2,618 4.0 0.000 1.181 0.0 12.4 1.7

 Permian Canyon 6,482 8.1 0.016 0.209 0.9 10.9 0.0

 Permian Spraberry 12,209 6.6 0.131 0.152 10.6 12.3 1.2

 Permian Wolfcamp 17,560 4.1 0.085 0.347 6.1 24.9 2.0

Rocky Mountain

 Denver Muddy 3,999 16.0 0.001 0.180 0.1 11.5 0.0

 Denver Niobrara 6,985 5.0 0.013 0.078 0.4 2.7 0.1

 Greater Green River Hilliard-Baxter-Mancos 4,477 8.0 0.000 0.293 0.0 10.5 0.5

 Greater Green River Tight Oil Plays 1,452 5.8 0.105 0.014 0.9 0.1 0.0

 Montana Thrust Belt Tight Oil Plays 2,630 2.3 0.100 0.068 0.6 0.4 0.0

 North Central Montana Bowdoin-Greenhorn 461 4.0 0.000 0.078 0.0 0.1 0.0

 Paradox Fractured Interbed 1,171 1.6 0.534 0.427 1.0 0.8 0.0

 Powder River Tight Oil Plays 19,464 3.0 0.035 0.040 2.1 2.4 0.1

 San Juan Dakota 1,819 8.0 0.002 0.258 0.0 3.8 0.0

 San Juan Lewis 1,481 3.0 0.000 2.200 0.0 9.8 0.0

 San Juan Mesaverde 1,036 12.0 0.002 0.548 0.0 6.8 0.0

 San Juan Pictured Cliffs 101 4.0 0.000 0.262 0.0 0.1 0.0

 Southwestern Wyoming Fort Union-Fox Hills 1,888 8.0 0.010 0.792 0.1 12.0 1.0

 Southwestern Wyoming Frontier 2,827 8.0 0.017 0.312 0.4 7.1 0.0

 Southwestern Wyoming Lance 2,297 8.0 0.020 1.152 0.4 21.2 3.8

 Southwestern Wyoming Lewis 3,885 8.0 0.006 0.312 0.2 9.7 0.2

 Southwestern Wyoming Tight Oil Plays 1,730 5.8 0.108 0.014 1.1 0.1 0.0

 Uinta-Piceance Iles-Mesaverde 3,997 8.0 0.001 0.372 0.0 11.9 0.0

 Uinta-Piceance Mancos 1,553 8.0 0.000 0.752 0.0 9.3 0.0

 Uinta-Piceance Tight Oil Plays 91 16.0 0.047 0.105 0.1 0.2 0.0

 Uinta-Piceance Wasatch-Mesaverde 2,161 8.0 0.030 0.568 0.5 9.8 0.0

 Uinta-Piceance Williams Fork 1,619 10.0 0.004 0.692 0.1 11.2 0.0

 Williston Bakken Central 4,516 2.9 0.202 0.153 2.6 2.0 0.2

 Williston Bakken Eastern 3,240 2.7 0.243 0.093 2.1 0.8 0.1

 Williston Bakken Elm Coulee 1,912 2.0 0.139 0.098 0.5 0.4 0.0

 Williston Bakken Nesson 3,476 3.2 0.260 0.162 2.9 1.8 0.2

 Williston Bakken Northwest 2,857 2.0 0.077 0.020 0.4 0.1 0.0

 Williston Bakken Three Forks 28,016 4.0 0.127 0.062 14.2 7.0 0.7

 Williston Gammon 3,836 2.0 0.000 0.433 0.0 3.3 0.0

 Williston Judith River-Eagle 1,449 4.0 0.000 0.154 0.0 0.9 0.0

 Wind River Fort Union-Lance 709 8.0 0.018 1.131 0.1 6.4 0.3

West Coast

 Columbia Basin Central 943 8.0 0.000 1.620 0.0 12.2 0.0

 San Joaquin/Los Angeles Monterey/Santos 3,141 6.4 0.028 0.151 0.6 3.0 0.0

Total Tight/Shale 78.2 949.3 35.8

EUR = estimated ultimate recovery; NGPL=Natural Gas Plant Liquids 

1

Area of play that is expected to have unproved technically recoverable resources remaining. 2

Includes lease condensates.

Source: U.S. Energy Information Administration, Office of Energy Analysis.

 

 

 
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U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 135

Table 9.4. U.S. unproved technically recoverable coalbed methane resources by play (as of January 1, 

2013) 

Average EUR

Technically Recoverable 

Resources

Region/Basin Play

Area with 

Potential1 

(mi2)

Average 

Spacing 

(wells/mi2)

Crude Oil2

(MMbls/

well)

Natural 

Gas 

(Bcf/well)

Crude 

Oil 

(Bbls)

Natural 

Gas 

(Tcf)

NGPL 

(Bbls)

1-East

 Appalachian Central Basin 1,302 8 0.000 0.176 0.0 1.8 0.0

 Appalachian North Appalachian Basin - High 361 12 0.000 0.125 0.0 0.5 0.0

 Appalachian North Appalachian Basin – Mod/Low 493 12 0.000 0.080 0.0 0.5 0.0

 Illinois Central Basin 1,277 8 0.000 0.120 0.0 1.2 0.0

2-Gulf Coast

Black Warrior Extention Area 148 8 0.000 0.080 0.0 0.1 0.0

Black Warrior Main Area 694 12 0.000 0.206 0.0 1.7 0.0

Cahaba Cahaba Coal Field 264 8 0.000 0.179 0.0 0.4 0.0

3-Midcontinent

Forest City Central Basin 23,110 8 0.022 0.172 4.0 31.8 0.0

Midcontinent Arkoma 2,718 8 0.000 0.216 0.0 4.7 0.0

Midcontinent Cherokee 3,436 8 0.000 0.065 0.0 1.8 0.0

4-Southwest 

 Raton Southern 1,925 8 0.000 0.375 0.0 5.8 0.0

5-Rocky Mountain 

Greater Green River Deep 1,620 4 0.000 0.600 0.0 3.9 0.0

Greater Green River Shallow 644 8 0.000 0.204 0.0 1.1 0.0

Piceance Deep 1,534 4 0.000 0.600 0.0 3.7 0.0

Piceance Divide Creek 135 8 0.000 0.179 0.0 0.2 0.0

Piceance Shallow 1,865 4 0.000 0.299 0.0 2.2 0.0

Piceance White River Dome 201 8 0.000 0.410 0.0 0.7 0.0

Powder River Big George/Lower Fort Union 1,570 16 0.000 0.260 0.0 6.5 0.0

Powder River Wasatch 206 8 0.000 0.056 0.0 0.1 0.0

Powder River Wyodak/Upper Fort Union 6,162 20 0.000 0.136 0.0 16.8 0.0

Raton Northern 343 8 0.000 0.350 0.0 1.0 0.0

Raton Purgatoire River 174 8 0.000 0.311 0.0 0.4 0.0

San Juan Fairway NM 169 4 0.000 1.142 0.0 0.8 0.0

San Juan North Basin 1,353 4 0.000 0.280 0.0 1.5 0.0

San Juan North Basin CO 1,673 4 0.000 1.515 0.0 10.1 0.0

San Juan South Basin 1,030 4 0.000 0.199 0.0 0.8 0.0

San Juan South Menefee NM 373 5 0.000 0.095 0.0 0.2 0.0

Uinta Ferron 227 8 0.000 0.776 0.0 1.4 0.0

Uinta Sego 341 4 0.000 0.306 0.0 0.4 0.0

Wind River Mesaverde 418 2 0.000 2.051 0.0 1.7 0.0

Wyoming Thrust Belt All Plays 5,200 2 0.000 0.462 0.0 5.5 0.0

6-West Coast

Western Washington Bellingham 441 2 0.000 2.391 0.0 2.1 0.0

Western Washington Southern Puget Lowlands 1,102 2 0.000 0.687 0.0 1.5 0.0

Western Washington Western Cascade Mountains 2,152 2 0.000 1.559 0.0 6.7 0.0

 Total Coalbed Methane 4.0 119.5 0.0 0.0

EUR = estimated ultimate recovery; NGPL = Natural Gas Plant Liquids. 1

Area of play that is expected to have unproved technically recoverable resources remaining.

2

Includes lease condensates.

Source: U.S. Energy Information Administration, Office of Energy Analysis
September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 136

Table 9.5. Distribution of crude oil EURs in the Bakken

Play Name State County

Number of 

potential wells

EUR 

(Mbbls/well)

Bakken Central Basin MT Daniels 112 117

Bakken Central Basin MT McCone 313 117

Bakken Central Basin MT Richland 646 138

Bakken Central Basin MT Roosevelt 2933 169

Bakken Central Basin MT Sheridan 439 44

Bakken Central Basin ND Divide 21 241

Bakken Central Basin ND Dunn 160 266

Bakken Central Basin ND McKenzie 4,652 231

Bakken Central Basin ND Williams 3,769 227

Bakken Eastern Transitional ND Burke 1,382 114

Bakken Eastern Transitional ND Divide 632 116

Bakken Eastern Transitional ND Dunn 2,108 212

Bakken Eastern Transitional ND Hettinger 4 169

Bakken Eastern Transitional ND McLean 1046 214

Bakken Eastern Transitional ND Mercer 135 9

Bakken Eastern Transitional ND Mountrail 3,082 374

Bakken Eastern Transitional ND Stark 194 169

Bakken Eastern Transitional ND Ward 57 145

Bakken Elm Coulee-Billings Nose MT McCone 67 163

Bakken Elm Coulee-Billings Nose MT Richland 1,623 163

Bakken Elm Coulee-Billings Nose ND Billings 799 79

Bakken Elm Coulee-Billings Nose ND Golden Valley 130 96

Bakken Elm Coulee-Billings Nose ND McKenzie 1,204 151

Bakken Nesson-Little Knife ND Billings 573 80

Bakken Nesson-Little Knife ND Burke 312 188

Bakken Nesson-Little Knife ND Divide 596 133

Bakken Nesson-Little Knife ND Dunn 3,227 284

Bakken Nesson-Little Knife ND Hettinger 110 223

Bakken Nesson-Little Knife ND McKenzie 2011 344

Bakken Nesson-Little Knife ND Mountrail 1060 323

Bakken Nesson-Little Knife ND Slope 172 223

Bakken Nesson-Little Knife ND Stark 1,066 183

Bakken Nesson-Little Knife ND Williams 1997 249

Bakken Northwest Transitional MT Daniels 1,550 82

Bakken Northwest Transitional MT McCone 97 82

Bakken Northwest Transitional MT Roosevelt 787 82

Bakken Northwest Transitional MT Sheridan 1,710 62

Bakken Northwest Transitional MT Valley 603 1

Bakken Northwest Transitional ND Divide 616 160

Bakken Northwest Transitional ND Williams 350 106

Source: U.S. Energy Information Administration, Office of Energy Analysis.
September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 137

CO2 enhanced oil recovery

For CO2 miscible flooding, the OLOGSS incorporates both industrial and natural sources of CO2. The 

industrial sources of CO2 are:

• Hydrogen plants

• Ammonia plants

• Ethanol plants

• Cement plants

• Refineries (hydrogen)

• Fossil fuel power plants

• Natural gas processing

• Coal/biomass to liquids (CBTL)

The volume and cost of CO2 available from fossil fuel power plants and CBTL, are determined in the 

Electricity Market Module and the Liquid Fuels Market Module, respectively. Technology and market 

constraints prevent the total volumes of CO2 from the other industrial sources (Table 9.6) from 

becoming immediately available. The development of the CO2 market is divided into two periods: 1) 

development phase and 2) market acceptance phase. During the development phase, the required 

capture equipment is developed, pipelines and compressors are constructed, and no CO2 is available. 

During the market acceptance phase, the capture technology is being widely implemented and volumes 

of CO2 first become available. The number of years in each development period is shown in Table 9.7. 

CO2 is available from planned Carbon Sequestration and Storage (CSS) power plants funded by 

American Recovery and Reinvestment Act of 2009 (ARRA) starting in 2016.

Table 9.6. Maximum volume of CO2 available

Billion cubic feet

OGSM Region Natural Hydrogen Ammonia Ethanol Cement

Refineries 

(hydrogen)

Natural Gas 

Processing

East 0 3 0 52 94 17 23

Gulf Coast 292 0 78 0 86 114 114

Midcontinent 16 0 0 175 48 1 0

Southwest 657 0 0 68 74 0 0

Rocky Mountains 80 0 3 23 35 78 18

West Coast 0 0 0 4 48 93 40

Source: U.S. Energy Information Administration, Office of Energy Analysis.
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Table 9.7. CO2 availability assumptions

Source Type Development Phase (years)

Market Acceptance Phase 

(years) 

Ultimate Market 

Acceptance

Natural 1 10 100%

Hydrogen 4 10 100%

Ammonia 2 10 100%

Ethanol 4 10 100%

Cement 7 10 100%

Refineries (hydrogen) 4 10 100%

Natural Gas Processing 2 10 100%

Source: U.S. Energy Information Administration, Office of Energy Analysis.

The cost of CO2 from natural sources is a function of the oil price. For industrial sources of CO2, the cost 

to the producer includes the cost to capture, compress to pipeline pressure, and transport to the project 

site via pipeline within the region (Table 9.8). Inter- regional transportation costs add $0.40 per Mcf for 

every region crossed.

Table 9.8. Industrial CO2 capture and transportation costs by region

$/Mcf 

OGSM Region Hydrogen Ammonia Ethanol Cement

Refineries 

(hydrogen)

Natural Gas 

Processing

East $2.44 $2.10 $2.23 $4.29 $2.44 $1.92 

Gulf Coast $1.94 $2.10 $2.23 $4.29 $1.94 $1.92 

Midcontinent $2.07 $2.10 $2.23 $4.29 $2.07 $1.92 

Southwest $2.02 $2.10 $2.23 $4.29 $2.02 $1.92 

Rocky Mountains $2.03 $2.10 $2.23 $4.29 $2.03 $1.92 

West Coast $2.01 $2.10 $2.23 $4.29 $2.01 $1.92 

Source: U.S. Energy Information Administration. Office of Energy Analysis.

Lower 48 offshore 

Most of the Lower 48 offshore oil and gas production comes from the deepwater of the Gulf of Mexico 

(GOM). Production from currently producing fields and industry-announced discoveries largely 

determines the short-term oil and natural gas production projection.

For currently producing fields, a 20% exponential decline is assumed for production except for natural 

gas production from fields in shallow water, which uses a 30% exponential decline. Fields that began 

production after 2008 are assumed to remain at their peak production level for 2 years before declining.

The assumed field size and year of initial production of the major announced deepwater discoveries that 

were not brought into production by 2012 are shown in Table 9.9. A field that is announced as an oil 

field is assumed to be 100% oil and a field that is announced as a gas field is assumed to be 100% gas. If 

a field is expected to produce both oil and gas, 70% is assumed to be oil and 30% is assumed to be gas.
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Production is assumed to:

• ramp up to a peak level in 2 to 4 years depending on the size of the field,

• remain at the peak level until the ratio of cumulative production to initial resource reaches 20% 

for oil and 30% for natural gas, and

• then decline at an exponential rate of 20-30%.

The discovery of new fields (based on BOEM’S field size distribution) is assumed to follow historical 

patterns. Production from these fields is assumed to follow the same profile as the announced 

discoveries (as described in the previous paragraph). Advances in technology for the various activities 

associated with crude oil and natural gas exploration, development, and production can have a 

profound impact on the costs associated with these activities. The specific technology levers and values 

for the offshore are presented in Table 9.10.

Leasing is assumed to be available in 2018 in the Mid-and South Atlantic, in 2023 in the South Pacific, 

and after 2035 in the North Atlantic, Florida straits, Pacific Northwest, and North and Central California.

Table 9.9. Assumed size and initial production year of major announced deepwater discoveries

Field/Project Name Block

Water 

Depth (feet)

Year of 

Discovery

Field Size 

Class

Field Size 

(MMBoe)

Start Year of 

Production

Silvertip AC815 9,280 2004 12 90 2015

Gotcha AC865 7,844 2006 13 176 2015

Telemark Phase 2 AT063 4,450 2010 12 90 2015

Dalmation North DC004 5,831 2010 12 90 2014

Dalmatian DC048 5,917 2008 12 90 2014

Vicksburg DC353 7,457 2009 14 357 2019

Raptor DC535 8,200 2013 12 90 2018

Cardamom GB427 2,720 2010 13 176 2014

Bushwood GB463 2,700 2009 13 176 2019

Danny II GB506 2,800 2012 12 90 2022

Winter GB605 3,400 2009 11 44 2019

North Platte GB959 4,400 2012 13 176 2022

Samurai GC432 3,400 2009 12 90 2017

Stampede-Pony GC468 3,497 2006 14 357 2018

Stampede-Knotty Head GC512 3,557 2005 14 357 2018

Parmer GC823 3,821 2012 12 90 2022

Heidelberg GC903 5,271 2009 13 176 2017

Gila KC093 4,900 2013 11 44 2017

Tiber KC102 4,132 2009 15 693 2019

Kaskida KC292 5,860 2006 15 693 2015

Moccasin KC736 6,759 2011 13 176 2018

Buckskin KC872 6,920 2009 13 176 2018

Lucius KC875 6,822 2009 12 90 2016

Hadrian North KC919 7,000 2010 14 357 2020

Hadrian South KC964 7,586 2009 13 176 2019

Diamond LL370 9,975 2008 11 44 2018

Cheyenne East LL400 9,200 2010 9 12 2020

Amethyst MC026 1,200 2014 10 23 2019

Cardona South MC029 2,185 2014 8 6 2014

Mandy MC199 2,478 2010 13 176 2020
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Table 9.9. Assumed size and initial production year of major announced deepwater discoveries (cont.)

Field/Project Name Block

Water Depth 

(feet)

Year of 

Discovery

Field Size 

Class

Field Size 

(MMBoe)

Start Year of 

Production

Marmalard MC300 6,148 2012 12 90 2016

Appomattox MC392 7,217 2009 15 693 2017

Son Of Bluto 2 MC431 6,461 2012 12 90 2016

Santiago MC519 6,526 2011 12 90 2021

Rydberg MC525 7,500 2014 14 357 2019

Isabela MC562 6,535 2007 11 44 2017

Santa Cruz MC563 6,515 2009 12 90 2015

Big Bend MC698 7,273 2012 12 90 2016

Troubadour MC699 7,273 2013 12 90 2018

Tubular Bells MC725 4,334 2003 12 90 2014

Deimos South MC762 3,122 2010 12 90 2014

Kodiak MC771 4,986 2008 13 176 2018

Dantzler MC782 6,565 2013 12 90 2016

West Boreas MC792 3,112 2004 12 90 2014

Gunflint MC948 6,095 2008 12 90 2016

Vito MC984 4,038 2009 13 176 2020

Phobos SE039 8,500 2013 13 176 2018

Tomcat WC176 1,200 2014 12 90 2019

Big Foot WR029 5,235 2005 12 90 2015

Shenandoah WR052 5,874 2009 13 176 2017

Yucatan North WR095 5,860 2013 12 90 2017

Coronado WR098 6,127 2013 14 357 2017

Stones WR508 9,556 2005 12 90 2018

Julia WR627 7,087 2007 12 90 2016

St. Malo WR678 7,000 2003 14 357 2014

Jack WR759 6,963 2004 14 357 2014

Hal WR848 7,657 2008 11 44 2019

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.10. Offshore exploration and production technology levels

Technology Level

Total Improvement over 

30 years (%)

Exploration success rates 30

Delay to commence first exploration and between 15

Exploration & development drilling costs 30

Operating cost 30

Time to construct production facility 15

Production facility construction costs 30

Initial constant production rate 15

Decline rate 0

Source: U.S. Energy Information Administration, Office of Energy Analysis.
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Alaska crude oil production

Projected Alaska oil production includes both existing producing fields and undiscovered fields that are 

expected to exist, based upon the region’s geology. The existing fields category includes the expansion 

fields around the Prudhoe Bay and Alpine Fields for which companies have already announced 

development schedules. Projected North Slope oil production also includes the initiation of oil 

production in the Point Thomson Field in 2016. Alaska crude oil production from the undiscovered fields 

is determined by the estimates of available resources in undeveloped areas and the net present value of 

the cash flow calculated for these undiscovered fields based on the expected capital and operating 

costs, and on the projected prices.

The discovery of new Alaskan oil fields is determined by the number of new wildcat exploration wells 

drilled each year and by the average wildcat success rate. The North Slope and South-Central wildcat 

well success rates are based on the success rates reported to the Alaska Oil and Gas Conservation 

Commission for the period of 1977 through 2008.

New wildcat exploration drilling rates are determined differently for the North Slope and South-Central 

Alaska. North Slope wildcat well drilling rates were found to be reasonably well correlated with 

prevailing West Texas Intermediate crude oil prices. Consequently, an ordinary least squares statistical 

regression was employed to develop an equation that specifies North Slope wildcat exploration well 

drilling rates as a function of prevailing West Texas Intermediate crude oil prices. In contrast, SouthCentral wildcat well drilling rates were found to be uncorrelated to crude oil prices or any other 

criterion. However, South-Central wildcat well drilling rates on average equaled just over three wells per 

year during the 1977 through 2008 period, so three South-Central wildcat exploration wells are assumed 

to be drilled every year in the future.

On the North Slope, the proportion of wildcat exploration wells drilled onshore relative to those drilled 

offshore is assumed to change over time. Initially, only a small proportion of all the North Slope wildcat 

exploration wells are drilled offshore. However, over time, the offshore proportion increases linearly, so 

that after 20 years, 50% of the North Slope wildcat wells are drilled onshore and 50% are drilled 

offshore. The 50/50 onshore/offshore wildcat well apportionment remains constant through the 

remainder of the projection in recognition of the fact that offshore North Slope wells and fields are 

considerably more expensive to drill and develop, thereby providing an incentive to continue drilling 

onshore wildcat wells even though the expected onshore field size is considerably smaller than the oil 

fields expected to be discovered offshore.

The size of the new oil fields discovered by wildcat exploration drilling is based on the expected field 

sizes of the undiscovered Alaska oil resource base, as determined by the U.S. Geological Survey for the 

onshore and state offshore regions of Alaska, and by the Bureau of Ocean Energy Management (BOEM) 

(formerly known as the U.S. Minerals Management Service) for the federal offshore regions of Alaska. It 

is assumed that the largest undiscovered oil fields will be found and developed first and in preference to 

the small and midsize undiscovered fields. As the exploration and discovery process proceeds and as the 

largest oil fields are discovered and developed, the discovery and development process proceeds to find 

and develop the next largest set of oil fields. This large to small discovery and development process is 

predicated on the fact that developing new infrastructure in Alaska, particularly on the North Slope, is 
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U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 142

an expensive undertaking and that the largest fields enjoy economies of scale, which make them more 

profitable and less risky to develop than the smaller fields.

Oil and gas exploration and production currently are not permitted in the Arctic National Wildlife 

Refuge. The projections for Alaska oil and gas production assume that this prohibition remains in effect 

throughout the projection period.

Three uncertainties are associated with the Alaska oil projections:

• whether the heavy oil deposits located on the North Slope, which exceed 20 billion barrels of 

oil-in-place, will be producible in the foreseeable future at recovery rates exceeding a few 

percent.

• the oil production potential of the North Slope shale formations is unknown at this time.

• the North Slope offshore oil resource potential, especially in the Chukchi Sea, is untested.

In June 2011, Alyeska Pipeline Service Company released a report regarding potential operational 

problems that might occur as Trans-Alaska Pipeline System (TAPS) throughput declines from the current 

production levels. [98] Although the onset of TAPS low flow problems could begin at around 550,000 

barrels per day (bbl/d), absent any mitigation, the severity of the TAPS operational problems is 

expected to increase significantly as throughput declines. As the types and severity of problems 

multiply, the investment required to mitigate those problems is expected to increase significantly. 

Because of the many and diverse operational problems expected to occur below 350,000 bbl/d of 

throughput, considerable investment might be required to keep the pipeline operational below this 

threshold. Thus, North Slope fields are assumed to be shut down, plugged, and abandoned when the 

following two conditions are simultaneously satisfied: 1) TAPS throughput would have to be at or below 

350,000 bbl/d and two) total North Slope oil production revenues would have to be at or below $5.0 

billion per year.
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Legislation and regulations 

The Outer Continental Shelf Deep Water Royalty Act (Public Law 104-58) gave the Secretary of the 

Interior the authority to suspend royalty requirements on new production from qualifying leases and 

required that royalty payments be waived automatically on new leases sold in the five years following its 

November 28, 1995 enactment. The volume of production on which no royalties were due for the five 

years was assumed to be 17.5 million barrels of oil equivalent (BOE) in water depths of 200 to 400 

meters, 52.5 million BOE in water depths of 400 to 800 meters, and 87.5 million BOE in water depths 

greater than 800 meters. In any year during which the arithmetic average of the closing prices on the 

New York Mercantile Exchange for light sweet crude oil exceeded $28 per barrel or for natural gas 

exceeded $3.50 per million Btu, any production of crude oil or natural gas was subject to royalties at the 

lease-stipulated royalty rate. Although automatic relief expired on November 28, 2000, the act provided 

the Minerals Management Service (MMS) the authority to include royalty suspensions as a feature of 

leases sold in the future. In September 2000, the MMS issued a set of proposed rules and regulations 

that provide a framework for continuing deep water royalty relief on a lease-by-lease basis. In the model 

it is assumed that relief will be granted at roughly the same levels as provided during the first five years 

of the Act.

Section 345 of the Energy Policy Act of 2005 provides royalty relief for oil and gas production in water 

depths greater than 400 meters in the Gulf of Mexico from any oil or gas lease sale occurring within five 

years after enactment. The minimum volumes of production with suspended royalty payments are:

1. 5,000,000 BOE for each lease in water depths of 400 to 800 meters; 

2. 9,000,000 BOE for each lease in water depths of 800 to 1,600 meters;

3. 12,000,000 BOE for each lease in water depths of 1,600 to 2,000 meters; and

4. 16,000,000 BOE for each lease in water depths greater than 2,000 meters.

The water depth categories specified in Section 345 were adjusted to be consistent with the depth 

categories in the Offshore Oil and Gas Supply Submodule. The suspension volumes are 5,000,000 BOE 

for leases in water depths of 400 to 800 meters; 9,000,000 BOE for leases in water depths of 800 to 

1,600 meters; 12,000,000 BOE for leases in water depths of 1,600 to 2,400 meters; and 16,000,000 for 

leases in water depths greater than 2,400 meters. Examination of the resources available at 2,000 to 

2,400 meters showed that the differences between the depths used in the model and those specified in 

the bill would not materially affect the model result.

The MMS published its final rule on the “Oil and Gas and Sulphur Operations in the Outer Continental 

Shelf Relief or Reduction in Royalty Rates Deep Gas Provisions” on January 26, 2004, effective March 1, 

2004. The rule grants royalty relief for natural gas production from wells drilled to 15,000 feet or deeper 

on leases issued before January 1, 2001, in the shallow waters (less than 200 meters) of the Gulf of 

Mexico. Production of gas from the completed deep well must begin before five years after the effective 

date of the final rule. The minimum volume of production with suspended royalty payments is 15 billion 

cubic feet for wells drilled to at least 15,000 feet and 25 billion cubic feet for wells drilled to more than 

18,000 feet. In addition, unsuccessful wells drilled to a depth of at least 18,000 feet would receive a 

royalty credit for 5 billion cubic feet of natural gas. The ruling also grants royalty suspension for volumes 

of not less than 35 billion cubic feet from ultra-deep wells on leases issued before January 1, 2001.
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Section 354 of the Energy Policy Act of 2005 established a competitive program to provide grants for 

cost-shared projects to enhance oil and natural gas recovery through CO2 injection, while at the same 

time sequestering CO2 produced from the combustion of fossil fuels in power plants and large industrial 

processes. 

From 1982 through 2008, Congress did not appropriate funds needed by the MMS to conduct leasing 

activities on portions of the federal Outer Continental Shelf (OCS) and thus effectively prohibited 

leasing. Further, a separate Executive ban in effect since 1990 prohibited leasing through 2012 on the 

OCS, with the exception of the Western Gulf of Mexico and portions of the Central and Eastern Gulf of 

Mexico. When combined, these actions prohibited drilling in most offshore regions, including areas 

along the Atlantic and Pacific coasts, the eastern Gulf of Mexico, and portions of the central Gulf of 

Mexico. In 2006, the Gulf of Mexico Energy Security Act imposed yet a third ban on drilling through 2022 

on tracts in the Eastern Gulf of Mexico that are within 125 miles of Florida, east of a dividing line known 

as the Military Mission Line, and in the Central Gulf of Mexico within 100 miles of Florida.

On July 14, 2008, President Bush lifted the Executive ban and urged Congress to remove the 

Congressional ban. On September 30, 2008, Congress allowed the Congressional ban to expire. Although 

the ban through 2022 on areas in the Eastern and Central Gulf of Mexico remains in place, the lifting of 

the Executive and Congressional bans removed regulatory obstacles to development of the Atlantic and 

Pacific OCS.

Oil and gas supply alternative cases 

Tight Oil and Shale Gas Resource case 

Estimates of technically recoverable tight/shale crude oil and natural gas resources are particularly 

uncertain and change over time as new information is gained through drilling, production, and 

technology experimentation. Over the last decade, as more tight/shale formations have gone into 

production, the estimate of technically recoverable tight oil and shale gas resources has increased. 

However, these increases in technically recoverable resources embody many assumptions that might 

not prove to betrue over the long term and over the entire tight/shale formation. For example, these 

resource estimates assume that crude oil and natural gas production rates achieved in a limited portion 

of the formation are representative of the entire formation, even though neighboring well production 

rates can vary by as much as a factor of three within the same play. Moreover, the tight/ shale 

formation can vary significantly across the petroleum basin with respect to depth, thickness, porosity, 

carbon content, pore pressure, clay content, thermal maturity, and water content. Additionally, 

technological improvements and innovations may allow development of crude oil and natural gas 

resources that have not been identified yet, and thus are not included in the Reference case.

High Oil and Gas Resource case 

The High Oil and Gas Resource case was developed using assumptions that result in higher estimates of 

technically recoverable crude oil and natural gas resources than those in the Reference case. This case 
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U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 145

allows for an examination of the potential impacts of higher domestic supply on energy demand, 

imports, and prices, but it does not represent an upper bound for future domestic oil and natural gas 

supply. The assumptions includes: 

• 50% higher EUR per tight oil, tight gas, and shale gas well than in the reference case;

• 50% closer acre well spacing for tight and shale formations (minimum of 40 acres per well) than 

in the Reference case as well as additional unidentified tight oil resources to reflect the 

possibility that additional layers or new areas of low-permeability zones are identified and 

developed;

• diminishing returns on the EUR once drilling levels in a county exceed the number of potential 

wells assumed in the Reference case to reflect the increased probability that wells begin to 

interfere with one another at greater drilling density;

• long term technology improvement trends beyond what is assumed in the Reference case, 

represented as a 1% annual increase in the estimated ultimate recovery for tight oil, tight gas, 

and shale gas wells;

• kerogen development reaching 135,000 bbl/d by 2025; and

• 50% higher technically recoverable undiscovered resources in Alaska and the offshore Lower 48 

States than in the Reference case. A few offshore Alaska fields are assumed to be discovered 

and thus developed earlier than in the Reference case.

The total unproved technically recoverable resources are 453 billion barrels of crude oil and 3,267

trillion cubic feet in the High Oil and Gas Resource case compared to 226 billion barrels of crude oil and 

1,968 trillion cubic feet of dry natural gas in the Reference case. Proved reserves of oil and natural gas 

are the same in both cases; 33 billion barrels of crude oil and 308 trillion cubic feet of dry natural gas.
September 2015

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Notes and sources

[93] The current development of tight oil plays has shifted industry focus and investment away from the 

development of U.S. oil shale (kerogen) resources. Considerable technological development is required 

prior to the large-scale in-situ production of oil shale being economically feasible. Consequently, the Oil 

Shale Supply Submodule assumes that large-scale in-situ oil shale production is not commercially 

feasible in the Reference case prior to 2040.

[94] Technically recoverable resources are resources in accumulations producible using current recovery 

technology but without reference to economic profitability.

[95] Proved reserves are the estimated quantities that analysis of geological and engineering data 

demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under 

existing economic and operating conditions.

[96] Unproved resources include resources that have been confirmed by exploratory drilling and 

undiscovered resources, which are located outside oil and gas fields in which the presence of resources 

has been confirmed by exploratory drilling; they include resources from undiscovered pools within 

confirmed fields when they occur as unrelated accumulations controlled by distinctly separate structural 

features or stratigraphic conditions.

[97] The Bakken areas are consistent with the USGS Bakken formation assessment units shown in Figure 

1 of Fact Sheet 2013-3013, Assessment of Undiscovered Oil Resources in the Bakken and Three Forks 

Formations, Williston Basin Province, Montana, North Dakota, and South Dakota, 2013 at 

http://pubs.usgs.gov/fs/2013/3013/fs2013-3013.pdf. 

[98] Alyeska Pipeline Service Company, Low Flow Impact Study, Final Report, June 15, 2011, Anchorage, 

Alaska, at 

www.alyeskapipe.com/Inthenews/LowFlow/LoFIS_Summary_Report_P6%2027_FullReport.pdf.