### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 128 

# 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 201 4 , DOE/EIA

- M063 ( 201 4 ), (Washington, DC, 201 4 ). The

OGSM provides crude oil and natural gas short

- term supply parameters to both the Natural Gas

Transmission and Distribution Module and the Pet roleum 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 crud e 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 CO 2 fl ooding, 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 forma tions, 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.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 129 

### Every year EIA re

- estimates initial production (IP) rates and production decline curves, which determine

estimated ultimate recovery (EUR) per well and total technically reco verable 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 [9 5 ] and unproved

resources [9 6 ]. Esti mates 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 productivi ty 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

informatio n 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, 2 012.

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, 201 3

billion barrels

Total Technically

Proved

Reserves Unproved Resources Recoverable

Resources

Lower 48 Onshore 2 4. 5 144.8 169.3

E ast 0 .3 2 .6 2.9

Gulf Coast 5. 3 29.1 3 4.4

Midcontinent 2 .1 13 .1 15 .2

Southwest 7.4 4 8.1 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 Off shore

- 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 Adm inistration. Table values reflect removal of

intervening reserve additions between the date the latest available assessment and January 1, 2013.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 130 

### Table 9. 2

. Technically recoverable U.S. dry natural gas resources as of January 1 , 201 3

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 3 8.5

Gulf Coast 13.4 1 59.1 172.5

M idcontinent 6.9 10.8 17.7

Southwest 7.2 3 3.3 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

Midcon tinent 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 5 2.5

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 O ff shore 11.2 305.3 316.5

Gulf (currently available) 1 0 .5 250.9 2 61.4

Eastern/Central Gulf (unavailable until 20 22) 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.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 131 

### 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

sub divided into five areas: Central Basin, Eastern Transitional, Elm Coulee

- Billings Nose, Nesson

- Little Knife,

and Northwest Transitional [9 7 ]. 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 fo r 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 reco very 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 analy zes

the decline curve of producing wells to calculate the expected ̶ EUR per well from future drilling.

### September 2015

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, th e 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. CO 2 flooding, steam flooding, and polymer

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

shale formations, tight sands fo rmations, 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

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

independent, or small independent). For AEO201 5 , the economics of potential projects reflect the tax

treatment provided by current laws for large independent produc ers. 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

f orward and used against revenues generated by the project in later years.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 133 

### Table 9. 3

. U.S. unproved technically recoverable tight/shale oil and gas resources by play (as of

January 1, 201 3)

Average EUR Technically Recoverab le

Resources

Area with

Potential l 1 Average

Spacing

(wells/ Crude Oil 2

(MMbl s / Natural

Gas Crude

Oil Natural

Gas NGPL

Region /Basin Play (mi 2 ) mi 2 ) well) (Bcf/well) (Bbls) (Tcf) (Bbls)

East

Appalachian Clinton

- Medina 26,907 8.0 0.0 02 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 Marcel lus 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 Wo odford

- 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 Fayet teville

- 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

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 134 

### Table 9.3. U.S. unproved technically recoverable tight/shale oil and gas resources by play (as of

January 1, 201 3 ) (co nt.)

Average EUR Technically Recoverable

Resources

Area with

Potential l 1 Average

Spacing

(wells/ Crude Oil 2

(MMbl s / Natural

Gas Crude

Oil Natural

Gas NGPL

Region /Basin Play (mi 2 ) mi 2 ) 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 H illiard

- 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

- Greenhor n 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 1,48 1 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

Southweste rn 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 0.0 14 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

- Mesaverd e 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.

### September 2015

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,

201 3)

Average EUR Technically Recoverable

Resources

Region /Basin Play Area with

Potential 1

(mi 2 ) Average

Spacing

(wells/mi 2 ) Crude Oil 2

(MMbl s/

well) Natural

Gas

( B cf/well) Crude

Oil

(Bbl s ) Natural

Gas

(Tcf) NGPL

(Bbl s )

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

Sa n 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 0.77 6 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 ultimat e 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

(Mbbl s /well)

Bakken Central Basin MT Daniels 112 117

Bakken Central Basin MT McCone 313 117

Bakken Central Basin MT Richland 646 1 38

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

Ba kken 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 Tran sitional 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 M T 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

- Litt le 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 N orthwest 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 61 6 160

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 

## CO 2 enhanced oil recovery

For CO 2 miscible flooding, the OLOGSS incorporates both industrial and natural sources of CO 2 . The

industrial sources of CO 2 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 CO 2 available from fossil fue l 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 CO 2 from the other industrial sources (Table 9.6) from

becoming immedi ately available. The development of the CO 2 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 CO 2 is available.

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

of CO 2 first become available. The number of years in each development period is shown in Table 9.7.

CO 2 is available from planned Carbo n 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 CO 2 available

Billion cubic feet

OGSM Region Natural Hydrogen Ammoni a 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

So urce: U.S. Energy Information Administration, Office of Energy Analysis.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 138 

### Table 9. 7

. CO 2 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 CO 2 from natur al sources is a function of the oil price. For industrial sources of CO 2 , 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 CO 2 capture and transportation costs by region

$/Mcf

OGSM Region Hydrogen Ammonia Ethanol Cement Refineries

(hydrogen) Natural Gas

Processin g

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 as sumed 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.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 139 

### 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 histor ical

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

(MMB oe ) 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 90 201 5

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 3,821 201 2 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

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 140 

### 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

(MMB oe ) Start Y ear 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

Shenandoa h 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 14 357 201 4

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 produ ction rate 15

Decline rate 0

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

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 141 

## Alaska crude oil production

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

expected to e xist, 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 f or 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 s uccess 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

regre ssion 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, South

Central 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

explorat ion 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 apportion ment 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 we lls 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 undiscover ed 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

### September 2015

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:

• whet her 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

- Alask a Pipeline System (TAPS) throughput declines from the current

production levels. [9 8 ] 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 exp ected 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 condition s 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.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 143 

## Legislation and regulations

The Outer Continental Shelf D eep 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 g as

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 th e 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 40 0 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. 9,000,00 0 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 Sectio n 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 Provisi ons” 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

Me xico. 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 suspen sion for volumes

of not less than 35 billion cubic feet from ultra

- deep wells on leases issued before January 1, 2001.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 144 

### 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 W estern 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. Althoug h

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 R esource 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 experime ntation. 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 ass umptions 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, thickne ss, 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 Ref erence case. This case

### September 2015

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. Th e 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 re sources 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 ul timate 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 of fshore Alaska fields are assumed to be discovered

and thus developed earlier than in the Reference case.

The total unproved technically recoverable resources are 4 53 billion barrels of crude oil and 3, 267

trillion cubic feet in the High Oil and Gas Resourc e case compared to 2 26 billion barrels of crude oil and

1,9 68 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 3 08 trillion cubic feet of dry natural gas.

### September 2015

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2015 146 

# 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 la rge

- 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.

[9 5 ] 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.

[9 6 ] 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 For ks

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

.