NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Updated U.S. Geothermal 

Supply Characterization and 

Representation for Market 

Penetration Model Input

C. Augustine 

Technical Report

NREL/TP-6A20-47459

October 2011
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Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC. 

National Renewable Energy Laboratory

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Contract No. DE-AC36-08GO28308

Updated U.S. Geothermal 

Supply Characterization and 

Representation for Market 

Penetration Model Input

C. Augustine 

Prepared under Task No. GT09.3002

Technical Report

NREL/TP-6A20-47459

October 2011
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iii

Acknowledgments

This report was prepared for and made possible by the U.S. Department of Energy Geothermal 

Technologies Program. The author thanks Robin Newmark, Margaret Mann, Lynn Billman, and 

Katherine Young (NREL); Colin Williams (USGS); David Blackwell and Maria Richards 

(SMU); Susan Petty (AltaRock); Robert Smith (EIA); and Arlene Anderson and Jay Nathwani 

(DOE Geothermal Technologies Program) for their input and comments on the development of 

the U.S. geothermal supply curve update. The author also thanks Devin Egan and the NREL 

communications team for technical and style edits. Of course, any remaining errors or omissions 

are the responsibility of the authors. 

The results of this report were summarized and presented at the 35th Stanford Geothermal 

Workshop, held February 1-3, 2010 (Augustine, Young, et al. 2010). This report serves to 

provide thorough documentation of the methodology used to create the supply curves presented. 
iv

Acronyms and Abbreviations 

$M millions of U.S. dollars 

%ile percentile

Recovery Act American Recovery and Reinvestment Act

BLS Bureau of Labor Statistics o

C degrees Celsius

cm centimeters

DOD U.S. Department of Defense 

DOE U.S. Department of Energy 

EGS enhanced geothermal systems

EIA Energy Information Administration

ft feet

GEA Geothermal Energy Association

GETEM Geothermal Electricity Technology Evaluation Model 

GIS geographical information system 

GPRA Government Performance and Results Act of 1993 

GTP/the Program Geothermal Technologies Program 

GWe gigawatt (electric)

in inches 

k, km kilometers

kg/s kilograms/second 

kWe kilowatt (electric)

kWh kilowatt-hour 

LCOE levelized cost of electricity

MARKAL Market Al

MIT Massachusetts Institute of Technology

location Model 

MWe megawatt (electric)

MYRD&D Plan Multi-Year Research Development and Deployment Plan

NEMS National Energy Modeling System 

NGDS National Geothermal Data System

NREL National Renewable Energy Laboratory 

O&M operation and maintenance 

PPI producer price index

psi pounds per square inch 

RD&D research, development, and demonstration 

ReEDS Regional Energy Deployment System 

SEDS Stochastic Energy Deployment System 

SMU Southern Methodist University 

TPM technology performance metric

U.S. United States of America

USGS U. S. Geological Survey 

W-h/lbm watt-hours per unit pound (mass) of geofluid 
v 

Executive Summary

The U.S. Department of Energy (DOE) Geothermal Technologies Program (GTP) tasked the 

National Renewable Energy Laboratory (NREL) with conducting the annual geothermal supply 

curve update. The purpose of this project is to characterize and represent the supply of electricity 

generation potential from geothermal resources in the United States. The principal products of this 

task are quantitative estimates of the potential electric capacity of U.S. geothermal resources and the 

cost to develop those resources. The two products are integrated to generate geothermal supply 

curves. The supply curve data are used primarily as input into the annual Government Performance 

and Results Act of 1993 and DOE portfolio development support processes and are also used 

extensively as input for market penetration models. The results of this study were used for the Fiscal 

Year 2011 DOE planning cycle. This report documents the approach taken to identify geothermal 

resources, determine the electrical producing potential of these resources, and estimate the levelized 

cost of electricity (LCOE), capital costs, and operating and maintenance costs from these geothermal 

resources at present and future timeframes under various GTP funding levels. Finally, this report

discusses the resulting supply curve representation and how improvements can be made to future 

supply curve updates. 

The general approach and flow of information used to develop supply curves and incorporate the 

results as input into market penetration models is shown in Figure ES-1. The primary steps in 

generating a supply curve and model input were estimating the resource potential and the cost of

developing the resource. Estimating the cost of electricity from the geothermal resources required 

the resource characteristics, the assumptions under which resource development would take place, 

and component technology cost and performance data.

Figure ES-1. Supply curve information flow diagram. 

Schematic of general approach used to develop geothermal resource supply curve and incorporate results as input 

into market penetration models. Arrows show flow of information.
vi 

For this study, the geothermal resource was broadly split between two technologies: 

conventional hydrothermal and enhanced geothermal systems (EGS). Conventional 

hydrothermal technologies utilize naturally occurring hydrothermal resources and have been 

commercially developed for decades, while EGS is an emerging technology in which geothermal 

reservoirs are engineered to extract economical amounts of heat from geothermal resources that 

have low permeability and/or lack natural in-situ fluids for heat extraction. The resource was 

further subdivided into four categories: identified hydrothermal, undiscovered hydrothermal, 

near-hydrothermal field EGS, and deep EGS. The geothermal resource characterization took 

advantage of published or available resources whenever possible, and made assumptions as 

necessary to estimate geothermal resource potential. The characterization benefited greatly from 

the recent geothermal resource assessment performed by the U.S. Geological Survey (USGS) in 

2008 (Williams, Reed, et al. 2008b) and also uses methodologies and data from the 

Massachusetts Institute of Technology Future of Geothermal Energy report to characterize EGS 

resources (Tester et al. 2006). The results of the resource potential estimate and a brief 

description of the sources and methodology used are given in Table ES-1. 

Table ES-1. Summary of Results for Geothermal Resource Potential Estimate

Resource Resource Potential

Capacity 

(GWe) Source(s) and Description

Hydrothermal

Identified 

Hydrothermal 

Sites

6.39 

USGS 2008 Geothermal Resource Assessment1

• Identified hydrothermal sites

• Sites ≥110oC included 

• Currently installed capacity excluded

Undiscovered 

Hydrothermal 30.03 USGS 2008 Geothermal Resource Assessment1 

Enhanced 

Geothermal 

Systems 

(EGS)

NearHydrothermal 

Field EGS

7.03 

Based on data from USGS 2008 Geothermal 

Resource Assessment1 and methodology 

developed at NREL 

• Regions near identified hydrothermal sites

• Sites ≥110oC included 

• Difference between mean and 95%ile 

hydrothermal resource estimate

Deep EGS 15,908 

NREL 2006 Update2, MIT Report3, SMU Data4

• Based on volume method of thermal energy 

in rock 3-10 km depth and ≥150oC 

• Does not consider economic or technical 

feasibility 1

(Williams, Reed, et al. 2008b) 2

(Petty and Porro 2007) 3

(Tester et al. 2006) 4

(Richards 2009) 
vii 

When developing supply curves, two cases based on GTP budget funding and EGS technology 

advances were considered: (1) the “base” or “no-funding” case, which assumes a business-asusual case where there is no GTP budget for geothermal research, development, and 

demonstration so that only modest improvements are made in EGS reservoir performance from 

current benchmarks, and (2) the “target” case, which assumes DOE funding of $50 million/year 

and that the targets for GTP EGS reservoir performance in the Multi-Year Research 

Development and Deployment Plan (Geothermal Technologies Program 2008) are met. The 

EGS reservoir technology assumptions for each case are summarized in Table ES-2. 

Table ES-2. EGS Technology Assumptions Used in Base and Target Cases 

Enabling Technology Base Case Value Target Case

Value

RD&D Funding $0 M/year $50 M/year

Production Well Flow Rate 30 kg/s 60 kg/s

Thermal Drawdown Rate 3.0 %/year 0.3 %/year

Production/Injection Well Ratio 2:1 2:1 

Project development costs for each resource site in the supply curve were estimated using the 

Geothermal Electricity Technology Evaluation Model (GETEM). GETEM is a highly detailed 

Microsoft Excel-based techno-economic modeling tool that estimates the LCOE and capital costs 

associated with a hydrothermal or EGS project based on the user-defined inputs of the project’s 

resource attributes and component costs and performance levels. Geothermal technology 

component costs and performance inputs required by GETEM to estimate total project costs 

were based on probability distributions elicited from experts as part of the GTP’s annual risk 

assessment (Young, Augustine, et al. 2010). Risk analysis software was used to run Monte Carlo 

simulations in GETEM incorporating these expert input distributions. The incorporation of 

technology component uncertainty results in a distribution of probable project costs rather than a 

single value. Based on conversations with geothermal drilling contractors, drilling costs were 

assumed to be discounted 30% from the 2008 index value used in the GETEM model to account 

for significant declines from recent record-high values that were related in part to a rapid rise in 

crude oil costs starting in 2004. 

Supply curves based on the median, 10th-percentile, and 90th-percentile estimates of the LCOE 

were generated for each of the resource categories. The individual supply curves were combined 

to create aggregate supply curves for the base and target cases, shown in Figure ES-2, that 

include all geothermal resources in the supply curve. The aggregate supply curves are truncated 

to show the most cost effective 50 GWe of geothermal resource. Capital costs by project phase 

for the different technologies were also calculated and presented. Future cost multipliers for 

years 2015 and 2025 that account for the effect of technology improvements and cost reductions 

with time for each geothermal technology were calculated based on expert risk assessment input 

and GETEM results.
viii

Figure ES-2. Combined supply curves of all geothermal technologies for base and target cases. 

For the base case, identified and undiscovered hydrothermal resources dominate the lower part of 

the curve, with some EGS present at higher LCOE values. For the target case, hydrothermal 

projects still dominate the lower part of the curve, but a significant amount of near-hydrothermal 

field EGS resource is visible. The cost level at which a large amount of deep EGS resource is 

found in the supply curve is significantly lower for the target case than in the base case, 

indicating that meeting GTP goals could have a significant impact on deep EGS deployment. 

For the hydrothermal and near-hydrothermal field EGS resources, power plant costs tend to 

account for a significant portion of capital costs since these resources tend to be shallow with 

relatively low drilling costs. Exploration/confirmation and plant costs are comparable for 

hydrothermal and near-hydrothermal field EGS resources, with the major difference in capital 

costs for the two resources stemming from the need to stimulate the EGS reservoir. For the deep 

EGS resource, capital costs are dominated by drilling costs. LCOE and capital costs were 

generally higher for all geothermal resources in this update than in the last NREL study (Petty 

and Porro 2007), mainly due to a significant increase in drilling costs over the past several years. 

A sensitivity analysis confirmed that binary power plant costs and drilling costs most 

significantly affect the LCOE of hydrothermal and EGS projects, respectively. Since probability 

distributions were not used for EGS reservoir performance factors such as thermal drawdown 

rate and well production flow rate, they were not included in the sensitivity analysis. The 

differences between base and target case EGS costs indicate variations in their values could also 

have a large impact on the LCOE for EGS projects. 

0

5

10

15

20

25

30

35

40

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

Levelized Cost of Electricity (cents/kWh)

Cumulative Capacity (MWe)

Deep EGS

Undiscovered Hydrothermal

Near-Hydrothermal Field EGS

Identified Hydrothermal

BASE CASE

TARGET CASE
ix

An analysis of the minimum LCOE for the deep EGS resource by location was performed. 

Regions were grouped by favorability, with regions having the lowest LCOE identified as the 

most favorable and those having the highest as the least favorable. By grouping the data, the 

transition between resources is smoothed and the classification generalized; the results should 

apply even with some variation in the underlying costs (e.g., drilling or power plant costs) or 

assumptions (e.g., EGS reservoir performance, fixed charge rate) used in this study. The 

resulting analysis was mapped and the location of the identified hydrothermal sites (and hence 

the assumed near-hydrothermal field EGS resource) was also included. The resulting map, 

shown in Figure ES-3, summarizes many of the results from the supply curve study. 

Figure ES-3. Geothermal resource of the United States. 

Locations of identified hydrothermal sites, the co-located near-hydrothermal field EGS resource, and the relative 

favorability of the deep EGS resource. Undiscovered hydrothermal resources and other geothermal resources, such 

as co-produced fluids, are not represented. 

Although the best efforts were made to accurately assess the geothermal resource and estimate 

project development costs for the supply curve, there is room for improvement of both the 

resource potential and project development cost estimates. The report conclusions identify key 

findings and recommend actions for improving future reports. 
x 

Table of Contents

Acknowledgments ........................................................................................................................ iii

Acronyms and Abbreviations ..................................................................................................... iv

Executive Summary .......................................................................................................................v

Table of Contents ...........................................................................................................................x

List of Figures .............................................................................................................................. xii

List of Tables .............................................................................................................................. xiii

1 Introduction and Purpose ......................................................................................................1

2 General Approach and Assumptions ....................................................................................2

2.1 Supply Curve Cases ......................................................................................................... 4

2.2 GETEM and @Risk ......................................................................................................... 6

2.2.1 Use of @Risk in GETEM ......................................................................................... 6

2.3 Technology Cost and Performance Data from Risk Assessment ..................................... 7

2.3.1 Risk Assessment Process .......................................................................................... 7

2.3.2 Assumptions and Parameter Values Used in GETEM ............................................. 7

2.4 GIS Mapping .................................................................................................................. 11

3 Supply Curves .......................................................................................................................12

3.1 Identified Hydrothermal Sites ........................................................................................ 12

3.1.1 Resource Potential .................................................................................................. 12

3.1.2 LCOE Estimates ...................................................................................................... 14

3.2 Undiscovered Hydrothermal .......................................................................................... 16

3.2.1 Resource Potential .................................................................................................. 16

3.2.2 LCOE Estimate ....................................................................................................... 16

3.3 Near-Hydrothermal Field EGS ....................................................................................... 18

3.3.1 Resource Potential .................................................................................................. 18

3.3.2 LCOE Cost Estimates ............................................................................................. 19

3.4 Deep EGS ....................................................................................................................... 20

3.4.1 Resource Potential .................................................................................................. 20

3.4.2 LCOE Cost Estimates ............................................................................................. 23

3.5 Co-Produced and Geopressured Resources .................................................................... 25

4 Results and Discussion .........................................................................................................25

4.1 Summary of Results ....................................................................................................... 25

4.2 Hydrothermal Resource .................................................................................................. 30

4.2.1 Resource Potential .................................................................................................. 30

4.2.2 Capital Costs and LCOE ......................................................................................... 31

4.3 Near-Hydrothermal Field EGS Resource ....................................................................... 32

4.3.1 Resource Potential .................................................................................................. 32

4.3.2 Capital Costs and LCOE ......................................................................................... 32

4.4 Deep EGS Resource ....................................................................................................... 34

4.4.1 Resource Potential .................................................................................................. 34

4.4.2 Capital Costs and LCOE ......................................................................................... 35
xi 

4.4.3 Optimum Deep EGS Resource Depth..................................................................... 36

4.5 Sensitivity Analysis ........................................................................................................ 40

5 Future Costs of Geothermal Resources ..............................................................................43

6 Conclusions ...........................................................................................................................47

6.1 Detailed Recommendations for Future Supply Curve Studies....................................... 49

6.1.1 Resource Potential .................................................................................................. 49

6.1.2 Supply Curve .......................................................................................................... 50

References .....................................................................................................................................52

Appendix A. Reference Scenario Power Plants .......................................................................54

Appendix B. Geothermal Supply Curve Data ..........................................................................63
xii 

List of Figures

Figure ES-1. Supply curve information flow diagram. ........................................................................... v

Figure ES-2. Combined supply curves of all geothermal technologies for base and target cases.

......................................................................................................................................................viii

Figure ES-3. Geothermal resource of the United States.......................................................................ix

Figure 1. Supply curve information flow diagram. ................................................................................. 3

Figure 2. Historical GTP funding levels................................................................................................... 4

Figure 3. BLS drilling cost PPI................................................................................................................10

Figure 4. Supply curve for identified hydrothermal resource. ............................................................15

Figure 5. Undiscovered hydrothermal resource by state. ...................................................................16

Figure 6. Supply curve for undiscovered hydrothermal resource......................................................18

Figure 7. Supply curve for near-hydrothermal field EGS resource. ...................................................20

Figure 8. Temperature at depth of 5.5 km (Tester et al. 2006).............................................................22

Figure 9. Supply curve for deep EGS resource. ...................................................................................24

Figure 10. Supply curve for deep EGS resource using semi-logarithmic scale................................25

Figure 11. Base case aggregate supply curve of the four geothermal technologies analyzed.......27

Figure 12. Target case aggregate supply curve of the four geothermal technologies analyzed. ...28

Figure 13. Base case supply curve by capital costs of the four geothermal technologies

analyzed. .......................................................................................................................................29

Figure 14. Target case supply curve by capital costs of the four geothermal technologies 

analyzed. .......................................................................................................................................29

Figure 15. Hydrothermal resource capital costs by project phase.....................................................32

Figure 16. Base case near-hydrothermal field EGS resource capital costs by project phase. .......33

Figure 17. Target case near-hydrothermal field EGS resource capital costs by project phase......34

Figure 18. Deep EGS resource capital costs for base case. ...............................................................35

Figure 19. Deep EGS resource capital costs for target case...............................................................36

Figure 20. Optimum reservoir temperature for deep EGS resource by location for target case.....37

Figure 21. Optimum reservoir depth for deep EGS resource by location for target case................38

Figure 22. Geothermal resource of the United States..........................................................................40

Figure 23. LCOE distribution for hydrothermal reference plant. ........................................................41

Figure 24. LCOE distribution for deep EGS reference plant (target case).........................................41

Figure 25. Sensitivity analysis results for hydrothermal reference plant..........................................42

Figure 26. Sensitivity analysis results for deep EGS reference plant (target case). ........................42

Figure 27. Future cost multipliers for geothermal technologies.........................................................46

Figure B-1. Map of MARKAL regions.....................................................................................................84

Figure B-2. Map of NEMS regions. .........................................................................................................87
xiii

List of Tables

Table ES-1. Summary of Results for Geothermal Resource Potential Estimate................................vi

Table ES-2. EGS Technology Assumptions Used in Base and Target Cases...................................vii

Table 1. EGS Technology Performance Assumptions Used in Base and Target Cases.................... 5

Table 2. Risk Assessment EGS Reference Scenario Parameters......................................................... 7

Table 3. Summary of Expert-Elicited Geothermal Technology Performance Metric Input ................ 8

Table 4. Existing Capacity at Identified Hydrothermal Sites (EIA, 2009; GEA, 2009) .......................14

Table 5. Potential Electric Capacity Per Unit Rock Volume for Deep EGS Resources as a Function 

of Temperature.............................................................................................................................22

Table 6. Potential Electric Capacity (MWe) of Deep EGS Resource for Continental United States by 

Temperature-depth Combination ...............................................................................................23

Table 7. Summary of Results for Geothermal Resource Potential Estimate.....................................26

Table 8. Mean Values from Aggregated Distributions of Expert-Elicited Geothermal TPM Input for 

Future Years. ................................................................................................................................44

Table 9. Summary of Supply Curve Reference Scenarios...................................................................45

Table A-1. GETEM Input for Hydrothermal Reference Scenario .........................................................54

Table A-2. GETEM Input for Near-hydrothermal Field EGS Reference Scenario ..............................57

Table A-3. GETEM Input for Deep EGS Reference Scenario ...............................................................60

Table B-1. Identified hydrothermal sites................................................................................................63

Table B-2. Undiscovered Hydrothermal Resource ...............................................................................71

Table B-3. Near-Hydrothermal Field EGS Resource.............................................................................72

Table B-4. Deep EGS Resource – Capital and O&M Costs..................................................................80

Table B-5. Deep EGS Resource – Potential Capacity by MARKAL Region (see Figure B-1)...........82

Table B-6. Deep EGS Resource – Resource Potential by NEMS Region (see Figure B-2)...............85

Table B-7. Tabulated GETEM Input and Output for Hypothetical Hydrothermal Sites in 

Figure 15 .......................................................................................................................................88

Table B-8. Tabulated GETEM Input and Output for Hypothetical Near-Hydrothermal Field EGS 

Sites in Figure 16 and Figure 17................................................................................................. 89
1 

1 Introduction and Purpose

This report documents the approach taken as part of the U.S. Department of Energy (DOE) 

Geothermal Technology Program’s (GTP or the Program) annual supply curve update to 

characterize and represent the supply of electricity generation potential from geothermal 

resources in the United States. The geothermal supply curve is used as the basis for input into 

market penetration models for an array of tasks that analyze the competitiveness of geothermal 

electricity generation against other forms of electricity generation and forecast the penetration of 

geothermal technologies into the national electricity generation market. The primary use of data 

from the supply curve is to provide cost input for the annual Government Performance and 

Results Act of 1993 (GPRA) and DOE portfolio development support processes. The National 

Energy Modeling System (NEMS) and Market Al

The primary purposes of this report are to: 

location Model (MARKAL) market 

penetration models are used for these exercises. Geothermal supply curve data are also supplied 

to the Regional Energy Deployment System (ReEDS) and Stochastic Energy Deployment 

System (SEDS) market penetration models developed at the National Renewable Energy 

Laboratory (NREL). The results of this study were available for DOE use starting in August 

2010 and were used for the Fiscal Year 2011 DOE planning cycle. 

1) Document the approach taken in identifying geothermal resources and determining the 

electrical producing potential of these resources; 

2) Document the approach taken to estimate the levelized cost of electricity (LCOE), capital 

costs, and operating and maintenance (O&M) costs from these geothermal resources at 

present and future timeframes assuming various GTP funding levels; 

3) Discuss the resulting supply curve and how improvements can be made to future supply 

curve representations. 

While a geothermal resource is broadly characterized by the ability to extract heat from the 

ground and convert it to electricity, different technologies are used to achieve this task. The 

technologies are defined by the specific characteristics of the resource and methods used to 

extract the thermal energy and convert it to electricity. For this study, the geothermal resource 

was broadly split among two technologies: conventional hydrothermal and enhanced geothermal 

Systems (EGS). The hydrothermal resource consists of the naturally occurring geothermal sites 

conventionally used to produce electricity. EGS are artificial geothermal systems created by 

drilling into formations of hot rock, hydraulically stimulating the formation to open and extend 

fractures, intersecting the fractures with at least one more drilled hole, and then circulating fluid 

through the fractures. Injected fluid is heated by the hot rock as it is circulated through the 

reservoir, brought to the surface, and then used to produce electricity in a power plant before 

being re-injected into the reservoir, forming a closed-loop system. To develop the supply curves, 

the hydrothermal and EGS resources were further subdivided into four geothermal categories: 

identified hydrothermal, undiscovered hydrothermal, near-hydrothermal field EGS (EGS in 

regions near identified hydrothermal sites), and deep EGS (EGS at depths >3 km). 

In defining the geothermal resource, published and available resources were used whenever 

possible. In particular, the supply curve update benefited greatly from the recent geothermal 

resource assessment performed by the U.S. Geological Survey (USGS) in 2008 (Williams, Reed, 
2 

et al. 2008b). The study also drew upon methodologies and data from the Massachusetts 

Institute of Technology (MIT) Future of Geothermal Energy report to characterize U.S. EGS 

resources (Tester et al. 2006). The LCOE of the geothermal resources used to generate the 

supply curve were estimated using the Geothermal Electricity Technology Evaluation Model 

(GETEM), with cost input elicited from experts as part of a recent GTP geothermal risk 

assessment (Young, Augustine, et al. 2010). 

The approach used to characterize and create the geothermal supply curve in this report enables 

updates to the geothermal resource to be quickly incorporated into the supply curve and input 

into market penetration models. The approach takes advantage of geographical information 

system (GIS) mapping methods to categorize and assess resources, to generate illustrative maps 

of the resulting resources, and to generate regional input for the various market penetration 

models. The incorporation of expert input on the present and future costs and performance levels 

of geothermal technology components from the risk assessment is a critical step in accurately 

assessing geothermal project costs and integrating uncertainty into the supply curve. A 

sensitivity analysis of the impact of technology components on project development costs 

performed as part of the study also identifies critical areas where research, development, and 

demonstration (RD&D) efforts can be focused to reduce overall system costs. 

Although the best efforts were made to accurately estimate the geothermal resource and project 

development costs for the supply curve, there is ample room for improvement of both the 

resource potential and project development cost estimates. The report conclusions identify key 

findings and recommend actions for improving future reports. 

2 General Approach and Assumptions

Figure 1 shows the general approach and flow of information used to develop supply curves and 

incorporate the results as input into the various market penetration models. The same approach 

was used for each of the geothermal resource categories considered. The primary steps in 

generating a supply curve and model input were the resource characterization and the estimation 

of the cost to develop the resource. For the resource characterization, the category and scope of 

the geothermal resource were defined. Next, information sources were identified and gathered 

from the literature and other available sources and were assembled into a database of the 

potential electrical generating capacity of the resource. The characterization of each category of 

geothermal resource considered is described in detail in Section 3. 
3 

Figure 1. Supply curve information flow diagram. 

Schematic of general approach used to develop geothermal resource supply curve and incorporate results as input 

into market penetration models. Arrows show flow of information. 

The cost of developing each category of geothermal resource was estimated based on the 

resource characteristics from the characterization, the technology components required to 

develop the resource, and any factors or assumptions included in the funding case under which 

the resource would be developed. First, the various cases under which the resource is developed 

were defined. This included specifying budget and technology assumptions and the time frame 

under which the resource would be developed, as described in Section 2.1. Next, the cost of the 

technology components required to develop the resource were estimated, taking into account 

time frame and budget level. For this study, component cost and performance data were elicited 

from experts in the geothermal field as part of the geothermal risk assessment performed in 2009 

(Young, Augustine, et al. 2010). Expert input consisted of probability distributions of 

performance metrics for key technology components. The aggregated component cost and 

performance data was used as input into GETEM to provide a range of probable LCOE for each 

geothermal resource; a Monte Carlo approach was used to sample the distributions by coupling 

GETEM with risk analysis software. The component cost data provided by experts are discussed 

in Section 2.3, along with general assumptions and inputs used for estimating the costs of all the 

geothermal resources considered. Resource-specific assumptions are described in detail in 

Section 3. 

The potential electrical generating capacity from the resource characterization was combined 

with the estimated cost of developing that capacity to generate the supply curve. In order to be 

used as input in regional market penetration models, the supply curve data were matched to 

geospatial coordinates and assigned to regions specific to each market penetration model. This 

was accomplished using GIS mapping methods, as described in Section 2.4. 
4 

2.1 Supply Curve Cases

Two cases based on GTP budget funding and EGS technology advances were considered when

developing supply curves. The two cases are (1) the “base” or “no-funding” case, which

assumes a business-as-usual case where there is no GTP budget for geothermal RD&D, and (2) 

the “target” case, which assumes DOE funding of $50 million/year and that GTP EGS reservoir 

performance targets are met. The cases were driven by input required of all DOE energy 

technologies for annual GPRA reporting, which analyzes the benefits of RD&D funding for 

DOE programs. An “overbudget” case was initially considered but not included since it was not 

used in Fiscal Year 2011 GPRA analysis. 

The budget for the target case was set based on historic GTP funding levels, shown in Figure 2, 

and on the assumption that these budget levels would likely increase in coming years as 

indicated by the $400 million allocated to GTP as part of the American Recovery and 

Reinvestment Act (Recovery Act). The assumed $50 million/year budget level does not reflect 

any guaranteed future budget levels. Both the base case and target case include the one-time 

allocation of funds in the Recovery Act and assume that the funds enabled GTP to allocate $350 

million of the $400 million for RD&D of EGS and other geothermal-related technologies. 

Figure 2. Historical GTP funding levels. 

Along with budget levels, different assumptions about advances in enabling technologies for 

EGS were made for the two cases considered. The technology assumptions are based on major 

performance goals for EGS in the Program’s Multi-Year Research Development and 

Deployment (MYRD&D) Plan (Geothermal Technologies Program 2008). By 2015, the 

Program plans to demonstrate the ability to create an EGS reservoir capable of producing 5 

MWe. By 2020, they plan to validate the ability of such a reservoir to sustain 5 MWe of power 
5 

generation over a 5-year period. The assumptions in each case apply to three EGS enabling 

technology performance metrics (TPM) identified as part of the 2009 technical risk assessment

(Young, Augustine, et al. 2010): the production well flow rate (kg/s), the thermal drawdown rate 

of the reservoir (%/year), and the ratio of production wells to injection wells in the reservoir. 

In the base case, where no funding is available from the Program for geothermal RD&D, 

expensive EGS demonstration projects were assumed to be too risky for private industry to 

undertake on a large scale, so that only modest improvements were made in EGS reservoir 

performance from current benchmarks. The base case assumed a production well flow rate of 30 

kg/s, a thermal drawdown rate of 3.0%/year, and a production-to-injection well ratio of 2:1. A 

thermal drawdown rate of 3.0%/year corresponds to the EGS reservoir having to be re-drilled 

and re-stimulated once every 4-6 years, depending on its initial temperature, due to temperature 

declines in the produced fluid. 

In the target case, where $50 million/year funding for RD&D projects is available, it was 

assumed that GTP MYRD&D goals were met, indicating that significant advances were made in 

EGS reservoir technology. The target case assumed a production well flow rate of 60 kg/s, a 

thermal drawdown rate of 0.3%/year, and a production-to-injection well ratio of 2:1. A thermal 

drawdown rate of 0.3%/year corresponds to an EGS reservoir that can produce fluid without 

significant produced-geofluid temperature decline over the 30-year lifetime of the power plant 

and does not require re-drilling or re-stimulation of the reservoir. The EGS reservoir technology 

assumptions match those used in the risk assessment and are summarized in Table 1. 

Table 1. EGS Technology Performance Assumptions Used in Base and Target Cases 

Enabling Technology Base Case Value Target Case

Value

RD&D Funding $0 M/year $50 M/year

Production Well Flow Rate 30 kg/s 60 kg/s

Thermal Drawdown Rate 3.0 %/year 0.3 %/year

Production/Injection Well Ratio 2:1 2:1 

For both the base and target case, it was assumed that EGS would not be commercially viable 

until after 2020. At this point, construction of commercial EGS plants would commence, with 

the first plants coming online in 2024-2025. For the target case, the vast majority of RD&D 

funding would be spent on EGS enabling technologies until 2020. After, RD&D funds would be 

focused on technologies that reduce the costs associated with geothermal power plant projects. 

These assumptions were required as input for GPRA benefits analysis and for annual market 

penetration modeling, and are discussed in greater detail in Section 5. 

To account for the effect of technology improvements and cost reductions with time on overall 

geothermal project costs, two future year time frames were also considered. The risk assessment 

asked experts to estimate technology component costs and performance levels in target years of 

2015 and 2025. The component technology data and methods used for updating the present-day 

geothermal supply curves for the base and target cases to 2015 and 2025 are described in 

Section 5. 
6 

2.2 GETEM and @Risk

GETEM was used to estimate costs for all geothermal resources considered in this study. 

GETEM is a Microsoft Excel-based techno-economic systems analysis tool for evaluating and 

comparing geothermal project costs. GETEM is a highly flexible tool with more than 180 userdefined inputs that can be used to tailor cost estimates to a resource. GETEM was developed for 

the Program by Princeton Energy Resources International (Entingh 2006) in collaboration with 

researchers at DOE national laboratories and external consultants. GETEM is currently 

maintained by the Idaho National Laboratory and is periodically updated with corrections, 

current cost indices, and additional modeling capabilities. This study used GETEM Version 

2008-A6. The most current version of GETEM is available for download from the GTP website 

(Geothermal Technologies Program 2009a). 

GETEM is a deterministic model that uses a bottoms-up analysis to calculate the LCOE and 

capital costs of geothermal and hydrothermal projects based on a set of user-specified variables. 

The user defines the resource characteristics (e.g., hydrothermal or EGS, temperature, depth), 

project details (e.g., plant type and size, pump types, well productivity), and other required 

parameters. GETEM then calculates the individual component costs associated with each phase 

of the project, such as exploration, well field development, power plant construction, and O&M

costs, based on user-defined cost inputs, embedded cost and system performance correlations, 

and cost indices to account for the year the project is developed. Total project costs are 

calculated assuming a user-defined fixed charge rate for project financing. GETEM’s primary 

output is the LCOE for the project, but also provides the total capital costs and a breakdown of 

capital costs and LCOE contributions from the project phases. GETEM was designed to 

examine the impact of technology improvements and cost reductions on geothermal power costs. 

The user can specify technology or cost improvements in the model input parameters and 

GETEM quantifies the changes in project costs in a side-by-side comparison of the two cases. 

For this study, a baseline year of 2008 (the most current available in GETEM at the time) was 

used. 

2.2.1 Use of @Risk in GETEM

Since GETEM is a deterministic model, each set of user input results in a single cost output. 

However, the technology cost and performance data used as input for GETEM for this study 

comes from the 2009 technical risk assessment in the form of probability distributions, so that 

there is a range of possible input values for several of the key input parameters in GETEM. To 

accommodate these distributions, @Risk Version 5.0 software was used. @Risk is a Monte 

Carlo simulation add-in for Microsoft Excel available from Palisade Corporation that links 

directly to Excel to add risk analysis capabilities. For each geothermal resource in the supply 

curve, @Risk was used to run a Monte Carlo simulation in GETEM in which the technology cost 

and performance probability distributions were sampled. The Monte Carlo simulation computes 

a probability distribution of the LCOE for a geothermal power plant project based on the 

probability distributions of the inputs. For each simulation in this study, 1,000 Monte Carlo 

iterations were performed. 
7 

2.3 Technology Cost and Performance Data from Risk Assessment

2.3.1 Risk Assessment Process

Geothermal technology cost component data for estimating geothermal energy costs in GETEM 

were elicited from experts as part of the Program’s 2009 technical risk assessment. The goal of 

the risk assessment was to quantitatively assess the projected risk of geothermal RD&D in terms 

of the Program’s primary performance metric: the LCOE for geothermal resources. The experts 

were asked to estimate the probable range of technology performance metrics for the present and 

future times under different GTP funding levels. A team of geothermal experts comprised of 

industry experts, academic researchers, DOE laboratory researchers, and laboratory contractors 

was assembled during the 2009 Stanford Geothermal Workshop. Experts were divided into four 

geothermal technology areas: (1) exploration; (2) wells, pumps, and tools; (3) reservoir 

engineering; and (4) power conversion. The experts were trained on how the risk assessment 

process worked and, after lengthy discussions, converged on a set of reference scenarios, 

assumptions, and current status of technology on which to base their future technology 

performance estimates. Based on these discussions and their personal knowledge of the industry, 

each expert then provided a triangular probability distribution (compromised of the high, low, 

and most likely values) for each performance metric in their technology area. Input was elicited 

for future years of 2015 and 2025 assuming GTP RD&D budgets for each individual

performance metric of $0/per year (business-as-usual), $30 million/year, and $60 million/year. 

The preliminary input was analyzed and, in the case of outliers, experts were asked to justify 

their responses to eliminate any potential unintentional or erroneous input. The verified input 

was then combined to produce an aggregated distribution of the expert input. A description of 

the risk assessment process, the risk geothermal plant reference scenarios assumed while 

eliciting expert data, and results are detailed in Young, et al. (2010). 

2.3.2 Assumptions and Parameter Values Used in GETEM

The expert aggregated distributions of TPMs from the risk assessment were applied 

independently as input to GETEM in determining the LCOE for geothermal resources. As part 

of the initial discussion, the experts agreed on the current point values or distributions of the 

TPMs. Experts were given an EGS reference scenario on which to base their component cost 

estimates. A summary of the risk EGS plant reference scenario is shown in Table 2. Several of 

the values, such as well cost and binary power plant costs, are specific to the EGS power plant 

reference scenario assumed as part of the risk assessment. Experts were also asked to estimate 

several TPMs for hydrothermal exploration technologies. In all, distributions for 10 geothermal 

technology performance metrics were used to estimate the current LCOE for geothermal 

resources using GETEM for the supply curve study. The TPMs and the mean, 10th%ile , and 

90th%ile values of the expert distributions for the risk reference scenario are listed in Table 3. 

These reference distributions were applied when determining the supply curve in current (2008) 

US$ for both the base and target cases, so that only the enabling technology assumptions differed 

for the two cases. The future-year data was used to predict future costs of geothermal resources 

under the cases in Section 2.1 as described in Section 5. 
8 

Table 2. Risk Assessment EGS Reference Scenario Parameters 

Parameter Value

Geothermal Resource EGS

Plant Type Binary, air-cooled

Net Output 20 MWe

Resource Temperature 225oC 

Plant Design Temperature 200oC 

Well Depth 6 km

Production Well Flow Rate 60 kg/s

Thermal Drawdown Rate 3.0%/year 

Production/Injection Well Ratio 2:1 

This reference scenario was used when determining technology performance metric distributions. Note 

that the risk assessment EGS reference scenario differs slightly from reference scenarios used in this 

supply curve study.

Table 3. Summary of Expert-Elicited Geothermal Technology Performance Metric Input 

TPM Value

Technology

Area Name Units 10th%ile Mean 90th%ile

Exploration 

Non-Well Exploration Costs (EGS) $M 0.42 1.41 2.53 

Non-Well Exploration Costs (Hydro) $M 0.51 1.22 2.00 

Exploration Well Success Rate (EGS) % 50.0 64.1 83.4 

Exploration Well Success Rate (Hydro) % 20.1 34.8 50.0 

Well Pumps & Tools Well Drilling/Construction Cost $M 15.0 22.3 30.0 

Production Pump Cost (per well) $M 1.0 1.5 2.0 

Reservoir Engineering Stimulation Cost (per triplet) $M 2.7 8.4 15.1 

Power Conversion

Binary System Capital Cost $/kW 2,200 2,500 2,800 

Binary System O&M Cost/Yr ¢/kWh - 2.2 - 

Brine Effectiveness W-h/lbm - 9.50 - 

Input shown is expert-consensus present-day values or distributions of TPMs for the EGS risk reference 

scenario in Table 2 and for hydrothermal exploration technologies. The mean, 10th%ile, and 90th%ile

values of the TPM distributions are listed.

Wherever possible, the distributions and assumptions used by the experts for the reference 

scenarios were used as guidance for inputs to parameters and values in GETEM when estimating 

geothermal energy costs for this report. However, some assumptions had to be made when 

providing input to GETEM when the resource characteristics of the geothermal resource for the 

supply curve differed from those assumed for the risk reference scenario, when no relevant 

guidance was provided in the risk reference scenario, or when the guidance in the risk reference 

scenario resulted in unreasonable or unrealistic results when applied to the geothermal resource 

in the supply curve. 

A complete list of the input parameters and assumptions used for the hydrothermal and EGS 

supply curve reference scenarios is given in Appendix A (note: supply curve reference scenarios 
9 

used in this report differ slightly from risk reference scenarios used in Young, et al. (2010)). 

Similar parameters and assumptions were used for all GETEM runs in this report. GETEM 

inputs specific to each geothermal technology are discussed in Section 3, while key assumptions 

and adaptations of expert input to the geothermal resource used in the supply curve applied to all 

GETEM runs are listed below. 

2.3.2.1 Well Cost

The well cost distribution given by the experts assumes a 6 km-deep well for an EGS project. 

However, wells considered for the hydrothermal and EGS resources in the supply curve range 

from 0.3 to 10 km (1,000 to 33,000 ft) in depth. It was assumed that the distribution given by the 

experts applied to all well depths. The well cost distribution for the 6 km well was normalized 

by the GETEM drilling cost correlation value for a medium-cost 6 km-deep well. The well cost 

input for GETEM was calculated during simulations by taking the value from the normalized 

distribution sampled by @Risk and multiplying by the default GETEM value for the cost of a 

well at the depth of the geothermal resource being considered. 

When the risk assessment workshop was conducted in February 2009, drilling costs were near 

historic highs due to the scarcity of steel and cement and increased rig rental rates caused by high 

crude oil and natural gas prices (which led to increased demand for oil and gas drilling). The 

drilling costs used by the experts in the risk assessment represent drilling costs at a single point 

in time based on market conditions and reflect these high costs. The decreases in future drilling 

costs from RD&D and the learning-by-doing projected by the experts in this report indicate cost 

reductions relative to the assumed drilling costs, and do not consider market volatility. However, 

since drilling costs are a significant factor in the overall cost of a geothermal project, changes in 

drilling costs have a significant impact on LCOE. GETEM uses the Bureau of Labor Statistics 

(BLS) Producer Price Index (PPI) to adjust its drilling cost correlations from the year the cost 

correlations were developed to the model year. As Figure 3 shows, drilling costs have declined 

significantly from these recent record highs in the past year. When the supply curves in this 

study were generated in late summer 2009, it was obvious that drilling costs had decreased 

significantly from the values assumed during the risk assessment, but only preliminary values 

from the BLS PPI were available. Based on conversations with geothermal drilling contractors, 

drilling costs for this report were assumed to be discounted 30% from the 2008 BLS PPI index 

value in GETEM. 
10 

Figure 3. BLS drilling cost PPI. 

Index values from August 2009 onward are projected (Bureau of Labor Statistics 2009). 

2.3.2.2 Geofluid Pumping

Pumping of the injection and/or production wells is often required for geothermal resources. For 

hydrothermal resources, pumping may be required in production wells to increase the flow rate 

of geofluid to the surface, and in injection wells to overcome friction losses or the natural 

pressure of the formation the fluid is being injected into. For EGS resources, it is theoretically 

possible to form a thermosiphon in which the density difference between the cool injected 

geofluid and heated produced geofluid is great enough that the difference in the hydrostatic head 

between the injection and production wells causes the system to flow naturally. In this case, no 

pumping would be required. In reality, pressure losses in the wellbores and in the reservoir must 

be overcome, and these pressure losses increase as the geofluid flow rate increases, so some 

degree of pumping will likely be required. 

To be conservative, it was assumed for this study that both the injection and production wells 

must be pumped for all types of geothermal resources. The pumping power requirements were 

calculated by GETEM based on the injection/production well flow rates assuming a well casing 

inner diameter of 7.0 in (17.8 cm), a bottom hole pressure of 150 psi (10.3 bar) in the injection 

well, and pressure losses in the reservoir calculated assuming a simple permeability-multipliedby-surface-area model. Although the cost of the production pump had little impact on the overall 

LCOE, it was observed that the depth the production pump was set at, and hence its power 

requirements, could significantly impact project economics, especially for resources with low 

reservoir temperatures. Therefore, the cost of the production pump was based on expert input, 

but the production pump depth and power requirements were calculated by GETEM. 

2.3.2.3 Power Plant Costs

Similar to well costs, the power plant costs given by experts assumed the risk reference scenario 

of a binary power plant operating under a particular set of conditions while the geothermal 

resources in the supply curve cover a wide range of operating conditions. The experts estimated 

0

50

100

150

200

250

300

350

400

Drilling Cost PPI

(Dec-1985 = 100)

Month
11 

the cost of a binary power plant operating at a design temperature of 200oC with 20 MWe of net 

power output, while the supply curve includes geothermal resources ranging from 110o

 to 350oC. 

As with well costs, the distribution of binary power plant costs from the experts was normalized 

by the power plant cost calculated by the GETEM power plant cost correlation for the risk 

reference scenario, and power plant cost inputs were calculated during @Risk runs from the 

values sampled from the normalized distribution multiplied by the GETEM-calculated binary 

power plant costs. Since expert input was not elicited for flash plants, the GETEM-calculated

values were used. Sites with plant design temperatures less than 225oC were assumed to be 

binary plants, while those with design temperatures of 225oC and higher were assumed to be 

flash plants. 

2.3.2.4 Power Plant Performance/"Brine Effectiveness" 

The power plant performance or “brine effectiveness” measures how much electricity the power 

plant produces per unit mass of geofluid. The power plant performance has a thermodynamic 

maximum value and is a strong function of temperature. Although a high brine effectiveness 

increases power plant output, power plant costs tend to increase with plant performance so that 

there is an optimum brine effectiveness that minimizes LCOE. GETEM contains a macro that 

can be used to find this optimum for binary power plants. However, for this study, expert input 

was used to determine binary power plant performance. Since the power plant performance 

given by experts assumed a single risk reference scenario, the expert distribution was normalized 

by the theoretical maximum value in GETEM for the risk reference scenario and applied across 

the range of geothermal resources in the supply curve in the same method as for well costs and 

power plant costs. Since expert input was not elicited for flash plants, GETEM-calculated values 

were used. 

2.3.2.5 O&M Costs

The O&M costs given by experts assume the risk reference scenario. Therefore, the same 

methodology described above for well costs, power plant costs, and power plant performance 

was used to apply the expert estimated O&M costs across the range of geothermal resources in 

the supply curve. The normalized distribution was applied to both binary and flash plants. 

2.4 GIS Mapping

GIS mapping methods were used to incorporate results from the supply curves generated in this 

study into market penetration models. GIS is a system used to manage, analyze, and present 

information associated with a location. The market penetration models divide the United States

into different regions and require data input on a regional basis. The regions differ according to 

the market penetration model being used. For example, the SEDS model has only one region 

that covers the entire United States. MARKAL uses either one or 10 regions, while NEMS uses 

13 regions. The ReEDS model requires input for 134 “power control authority” regions. The 

supply curve data must be broken down by region to provide input for each of the market 

penetration models.

The GIS analysis was performed based on data from the resource potential estimates. For 

geothermal resources associated with a specific location, such as a hydrothermal site, the latitude 

and longitude was used to identify the site and determine which region it was in. For resource 

potential estimates based on the characteristics of a region, such as the temperature and depth 

data associated with the deep EGS resource, the resource was mapped and then overlain with the 
12 

model regional maps. GIS methods were also used to generate maps showing the potential 

geothermal power capacity of the United States and analyze the results of the deep EGS supply 

curve. 

3 Supply Curves

For this study, two types of geothermal resources were considered—hydrothermal and EGS. 

Supply curves were generated for each of the geothermal technologies using project costs 

estimated with GETEM. Costs are in 2008 US$. Future cost multipliers for each technology are 

discussed in Section 5. 

The hydrothermal resource consists of the naturally occurring geothermal sites used 

conventionally to produce electricity. The hydrothermal resource potential is based on the 

recently completed geothermal resource assessment of the United States performed by the USGS

(Williams, Reed, et al. 2008b). The USGS resource assessment is an update of USGS Circular 

790 (Muffler 1979) and is the first major update by the USGS to the geothermal resource 

assessment in almost 30 years. The assessment divides the resource into identified sites and 

“undiscovered” resources. 

EGS are geothermal reservoirs that have been engineered to extract economical amounts of heat 

from geothermal resources that have low permeability and/or lack natural in-situ fluids for heat 

extraction. An EGS reservoir is created by drilling into a formation of hot rock, hydraulically 

stimulating the formation to open and extend fractures, intersecting the fractures with at least one 

more drilled hole, and then circulating fluid through the fractures. Injected fluid is heated by the 

hot rock as it circulates through the reservoir, is brought to the surface, and is then used to 

produce electricity before being re-injected into the reservoir, forming a closed-loop system. In 

theory, since temperatures increase with depth, EGS can be developed anywhere. However, 

technological and economic considerations will limit the sites where EGS can be practically 

deployed. The cost of electricity from an EGS site depends heavily on the depth and temperature 

of the reservoir to be developed. For this study, the EGS potential resource is divided into two 

groups: the near-hydrothermal field EGS resource and the deep EGS resource. 

3.1 Identified Hydrothermal Sites

3.1.1 Resource Potential

The USGS 2008 geothermal assessment identifies 241 moderate- and high-temperature (>90o

C) 

sites on private or accessible public lands in the United States (Williams, Reed, et al. 2008b). 

The sites are concentrated entirely within 13 states in the western United States, Alaska, and 

Hawaii. The methodology used to estimate the recoverable energy from each site identified in 

the 2008 USGS assessment is similar to that used in the previous USGS Circular 790 assessment

(Muffler 1979), and is described in Williams, Reed, et al. (2008a). The volume method is used 

to calculate the amount of thermal energy in the reservoir, and a recovery factor is applied to 

determine the amount of thermal energy that can be recovered from the reservoir. The amount of 

useful energy that can be extracted from the thermal energy in the fluid produced from the 

reservoir is limited by the laws of thermodynamics as measured by the exergy of the fluid. The 

exergy of the recovered fluid is calculated based on the resource temperature and the reference 

(ambient) temperature. The electric energy potential is then determined by multiplying the 

exergy by the plant utilization efficiency, assuming a reservoir lifetime of 30 years. To account 
13 

for uncertainties in the estimate of the potential electric power generation, Monte Carlo 

simulations were conducted. For each site, triangular distributions of the probable reservoir 

volume and temperature were made using estimates of the minimum, maximum, and most likely 

values for these parameters. A uniform distribution ranging from 0.08 to 0.20 (0.10 to 0.25 for 

sediment-hosted reservoirs) was assumed. The result of the Monte Carlo simulations is a 

distribution of probable electric power generation potential for each site.

Based on this analysis, the USGS 2008 resource assessment predicts a mean total of 9,057 MWe

of power generation potential from identified hydrothermal systems on private or accessible 

public lands, with a 95% probability of only 3,675 MWe and a 5% probability of up to 16,457 

MWe being available (Williams, Reed, et al. 2008b). This mean value is significantly lower than 

the 23,000±3,400 MWe potential from only 52 identified sites listed in the USGS Circular 790 

assessment (Muffler 1979). The primary reason for this decline was a change in the assumed 

recovery factor for geothermal systems. The Circular 790 assessment assumed an average 

recovery factor of 0.25 based on experiences at the Geysers field in California, whereas the 

USGS 2008 assessment used much lower values based on more recent experiences from a large 

number of sites. Additionally, the more recent assessment assumes smaller reservoir volumes 

for some of the large hydrothermal sites and lower temperatures at others than those used in 

Circular 790, contributing further to the apparent reduction in the overall power producing 

potential (Williams 2009a). 

The total mean value of 9,057 MWe for the recoverable electric power generation potential from 

the USGS 2008 assessment was adopted as the starting point for the identified hydrothermal 

resource in this study. The site-specific data for the identified hydrothermal resources was 

obtained from the USGS (Williams 2009b). A cut-off temperature of 110o

C was adopted based 

on limitations in the range of power plant operating temperatures validated in the GETEM code. 

This results in the removal of 106 identified hydrothermal sites representing 460 MWe of power 

producing potential. The USGS 2008 assessment does not exclude currently installed generating 

capacity at hydrothermal sites. An assessment of installed hydrothermal capacity was made 

based on data from the Energy Information Administration (EIA) (Energy Information 

Administration 2009) and Geothermal Energy Association (GEA) (Geothermal Energy 

Association 2009) databases. The power plant capacity data from the EIA and GEA databases 

do not match directly, neither in names of plants, their listed capacities, nor the plants and 

locations included on each list. The existing plants from the two databases were matched as well 

as possible based on plant names, locations, and year that operation began. The selection and 

assignment of current power plant capacities to identified hydrothermal resources is complicated 

by the differences in the reported capacities between the two databases and the variations in the 

types of reported capacities (nameplate, summer, and winter) within the databases. The EIA 

database was chosen as the primary source for plant capacity and, following their convention, the 

summer capacities were used in the assignment of power plant capacities to identified 

hydrothermal sites. As shown in Table 4, total hydrothermal summer capacity in the EIA 

database, with the addition of several plants in the GEA database and recent plant additions 

reported by the media, is 2,480 MWe. According to the installed capacity, some sites, such as 

the Geysers in California, have a greater existing production capacity than potential capacity, so 

their potential was completely removed from the assessment. When current capacity and sites 

with temperatures <110o

C are removed from the USGS 2008 mean power producing potential, 
14 

the subsequent remaining mean potential capacity for identified hydrothermal sites in the United 

States used in this study is 6,394 MWe. 

Table 4. Existing Capacity at Identified Hydrothermal Sites (EIA, 2009; GEA, 2009) 

Identified Hydrothermal 

Site Name State

Installed 

Summer 

Capacity (MWe)

Heber Shallow CA 119.2

East Mesa CA 101.0

North Brawley CA 64.0

Salton Sea Area CA 298.0

Coso Area CA 229.3

Long Valley CA 42.9

Geysers CA 1,121.9

Amedee CA 2.2

Medicine Lake (Glass 

Mt.) CA 99.8

Puna Geothermal 

Venture HI 31.0

Raft River ID 19.6

Lightning Dock NM 10.0

Wabuska Hot Springs NV 0.9

Steamboat Springs and 

Steamboat Hills NV 85.6

Brady HS NV 26.0

Desert Peak NV 17.5

Stillwater Area NV 8.5

Soda Lake Area NV 10.9

Dixie Valley Geothermal 

Field NV 56.0

Dixie Valley Power 

Partners NV 25.0

San Emidio Desert Area NV 3.5

Beowawe HS NV 12.8

Cove Fort - Sulphurdale UT 16.0

Roosevelt HS UT 68.0

Thermo Hot Springs UT 10.0

 Total 2,479.6

3.1.2 LCOE Estimates

The present-day LCOE in 2008 US$ for the identified hydrothermal resource was estimated 

using GETEM on a site-by-site basis. First, site-specific resource definitions were input into the 

GETEM model. The reservoir temperature and capacity were obtained from the USGS 2008 
15 

resource assessment (Williams 2009b). Hydrothermal sites with reservoir temperatures below 

110o

C were excluded. The net power sales from the plant in GETEM were set equal to the 

potential capacity of the identified hydrothermal site. The plant size was capped at 100 MWe

and it was assumed that sites with larger potential capacities would have multiple power plants. 

The reservoir depth and production well flow rates for each site were not included in the USGS 

data. Therefore, flow rates and depths used for sites in a previous NREL supply curve update

(Petty and Porro 2007) were used. As in the previous NREL update, a reservoir depth of 1.524 

km (5,000 ft) and a production well flow rate of 44.19 kg/s (350,000 lb/hr) were assumed when 

site-specific estimates were not available. 

Once the hydrothermal site resource was defined, the cost of power was calculated in GETEM 

using the TPM inputs elicited from experts discussed in Section 2.3. For all hydrothermal sites, 

a 3:1 production/injection well ratio and a thermal drawdown rate of 0.3%/year were assumed. 

These values are consistent with those at a typical hydrothermal power plant. The resulting 

supply curve is shown in Figure 4. The median (50th%ile), 10th%ile, and 90th%ile LCOE values 

shown illustrate the range of likely values for the hydrothermal power plants given the current 

state of technology based on expert input. Since the base and target case assumptions are 

identical for hydrothermal resources, the supply curve is identical for hydrothermal for both 

cases.

Figure 4. Supply curve for identified hydrothermal resource. 

Present-day median (50th%ile), 10th%ile, and 90th%ile LCOE estimates in 2008 US$ from GETEM shown. 

It should be noted that because of the large number of hydrothermal sites, detailed site 

information was not considered when estimating the LCOE in GETEM. For example, the 

corrosive nature of the geofluid at the Salton Sea site in California was not taken into 

0

10

20

30

40

50

60

70

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000

Levelized Cost of Electricity (cents/kWh)

Cumulative Capacity (MWe)

90%ile LCOE

50%ile LCOE

10%ile LCOE
16 

consideration when estimating well construction and power plant equipment costs. The remote 

nature of the Puna site in Hawaii, which would increase rig mobilization and equipment shipping 

costs, was also not taken into consideration. For all sites, a single drilling costs curve was 

assumed, even though drilling costs can vary considerably based on the lithology of the 

reservoir. The use of @Risk to calculate LCOE distributions based on a probable range of 

technology cost and performance captures these cost variations somewhat. Ideally, project cost 

estimates would consider each site in detail, but the time required to incorporate such detail was 

deemed time-prohibitive for this study. Some of the sites with characteristics that would 

significantly affect costs, such as the Salton Sea and Puna, have been identified; future supply 

curve updates will attempt to incorporate these factors into GETEM.

3.2 Undiscovered Hydrothermal

3.2.1 Resource Potential

In addition to identified hydrothermal resources, the USGS 2008 geothermal resource assessment 

also estimated the power production potential from undiscovered geothermal resources. The 

undiscovered resource was estimated using GIS-based statistical methods to analyze the 

correlation between spatial datasets and existing geothermal resources to derive the probability 

of the existence of geothermal resources in unexplored regions (Williams and DeAngelo 2008). 

The undiscovered geothermal resource power generation potential from the study has a mean 

value of 30,033 MWe, with a 95% probability of 7,917 MWe and a 5% probability of 

73,286 MWe. For this study, the mean value (30,033 MWe) was used. The distribution of the 

undiscovered hydrothermal resource was broken down by state as shown in Figure 5. 

Figure 5. Undiscovered hydrothermal resource by state. 

Power producing potential in MWe based on mean estimates in USGS 2008 Geothermal Resource Assessment

(Williams, Reed, et al. 2008b). 

3.2.2 LCOE Estimate

Estimation of the LCOE in GETEM requires characterization of the geothermal resource. 

However, the actual resource characteristics of the undiscovered hydrothermal resource, such as 

Alaska

1,787 

Arizona

1,042 

California

11,340 

Colorado

1,105 

Hawaii

2,436 

Idaho

1,871 

Montana

772 

New Mexico

1,484 

Nevada

4,364 

Oregon

1,892 

Utah

1,463 

Washington

300 

Wyoming

174 

Undiscovered

Hydrothermal 

Resource by 

State

(MWe)

Mean Estimates from 

USGS 2008 Geothermal 

Resource Assessment
17 

reservoir depth and temperature, are unknown. In the absence of actual data, it was assumed that 

the undiscovered resources would be similar in nature to identified hydrothermal sites in the 

same region. Since the 2008 USGS resource assessment breaks down the undiscovered 

hydrothermal resource by state as shown in Figure 5, the undiscovered hydrothermal resource 

attributed to each state was assumed to look like the hydrothermal resource already identified 

within each state. 

To characterize the undiscovered hydrothermal resource, identified hydrothermal sites were first 

divided up by state. The identified sites were then further divided into two subgroups—those 

with reservoir temperatures ≥150o

C and those with temperatures <150oC—and the mean 

potential capacity from identified hydrothermal resources in each subgroup was totaled. The 

undiscovered hydrothermal resource in each state was apportioned between the designated 

temperature ranges based on the percentage of identified hydrothermal resource in each 

subgroup. For several states, such as Colorado, the entire undiscovered resource was assumed to 

have a temperature <150oC since all the identified hydrothermal sites in those states have 

estimated reservoir temperatures of <150oC. Only Hawaii, with one identified site at Puna, had 

all its potential resource appropriated to the ≥150o

C subgroup. 

A single reservoir temperature, depth, and production well flow rate was assumed for the 

undiscovered resource in each subgroup. The temperature, depth, and flow rate of the 

undiscovered hydrothermal resource in each subgroup was determined by calculating the meancapacity-weighted average of each of these parameters from the identified hydrothermal sites in 

each sub-group. Because the reservoir characteristics were determined using the potential 

power-capacity-weighted average, the undiscovered resource is assumed to be more similar to 

the large identified hydrothermal sites in each state that have large power producing potential. 

This means, for example, that the high-temperature undiscovered resource characteristics in 

California are heavily influenced by the characteristics of large sites such as the Geysers and the 

Salton Sea. 

By the nature of the resource, the methodology used to characterize the undiscovered 

hydrothermal resource is somewhat arbitrary. A range of other techniques could have been used 

to characterize the resource. On one extreme, the entire undiscovered resource could have been 

treated uniformly and assumed to have the properties of a “typical” hydrothermal site, so that a 

single estimated LCOE would apply for the entire undiscovered hydrothermal resource. On the 

other extreme, a wide range of possible reservoir temperature, depth, and production well flow 

rate distributions could have been estimated and the undiscovered resource could have been 

divided amongst the possible combinations using a Monte Carlo simulation. Whether either of 

these methodologies, or any other that can be imagined, is more “correct” than another is 

unknowable since the resource remains undiscovered. The methodology used attempted to make 

the best use of the information at hand to produce a reasonable approximation of the nature of 

the undiscovered resource. The undiscovered hydrothermal resource estimate would have 

benefited from greater knowledge of how the USGS arrived at their undiscovered hydrothermal 

capacity estimates. A report detailing how the undiscovered resource assessment was performed 

is scheduled to be published in the near future. Future supply curve updates should take this 

document into consideration once it is available. 
18 

Once the undiscovered hydrothermal resource characteristics were defined in GETEM, the 

process and assumptions used to estimate the LCOE were nearly identical to that used for the 

identified hydrothermal resources, with the following exceptions. The power plant net power 

output was assumed to be 20 MWe for each plant. To account for the added expenses of locating 

and identifying the undiscovered sites, exploration costs were assumed to be 150% of those for 

identified hydrothermal resources. The resulting supply curve consisting of the median 

(50th%ile), 10th%ile, and 90th%ile LCOE values is shown in Figure 6. As with identified 

hydrothermal sites, the same supply curve applies to both base and target cases. 

Figure 6. Supply curve for undiscovered hydrothermal resource. 

Present-day median (50th%ile), 10th%ile, and 90th%ile LCOE estimates in 2008 US$ from GETEM shown. 

3.3 Near-Hydrothermal Field EGS

3.3.1 Resource Potential

The near-hydrothermal field EGS resource consists of the areas around hydrothermal sites that 

lack sufficient permeability and/or in-situ fluids to be economically produced as a conventional 

hydrothermal resource. These resources require the application of EGS reservoir engineering 

techniques to become economic producers of electricity. Because these resources are around 

existing hydrothermal sites, they tend to be relatively hot and shallow, and are likely to be the 

least expensive and first EGS resources to be commercially developed, as demonstrated by the 

EGS demonstration projects DOE is funding to develop near-hydrothermal fields at the Geysers, 

CA; Raft River, ID; Desert Peak, NV; and Brady Hot Springs, NV (Geothermal Technologies 

Program 2009b), all of which are home to conventional hydrothermal power plants. 

A formal assessment of the near-hydrothermal field EGS resource has not yet been completed. 

However, if it is assumed that the rock in and around identified hydrothermal sites are at high 

temperatures, but lack sufficient permeability or in-situ fluids to be developed commercially, 

0

10

20

30

40

50

60

70

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

Levelized Cost of Electricity (cents/kWh)

Cumulative Capacity (MWe)

90%ile LCOE

50%ile LCOE

10%ile LCOE
19 

then a reasonable estimate of the near-hydrothermal EGS resource can be made. This approach 

assumes that the difference between the mean and high-end estimates of the electricitygenerating potential capacity for each identified hydrothermal site from the USGS 2008 

geothermal assessment (Williams, Reed, et al. 2008b) represents a part of the reservoir that could 

be made to economically produce electricity using EGS reservoir stimulation techniques. When

the difference between the 5% probability and mean power producing potential values for each 

identified hydrothermal site in USGS 2008 geothermal assessment sites is taken, and a reservoir 

cut-off temperature of 110o

C applied, the resulting estimate for the near-hydrothermal field EGS 

resource is 7,031 MWe. The near-hydrothermal field EGS potential resource around the 

undiscovered hydrothermal resource discussed in Section 3.2 was not considered for this study. 

3.3.2 LCOE Cost Estimates

Estimation of the LCOE of the near-hydrothermal field EGS resource was done on a site-by-site 

basis in GETEM similar to the approach taken for the identified hydrothermal resource. It was 

assumed that the reservoir temperature and depth for each near-hydrothermal field EGS site was 

the same as the corresponding identified hydrothermal site. The plant net power sales were set 

equal to the potential power capacity calculated for each site in the same manner as for the 

identified hydrothermal sites. Although the resource characteristics for each site were the same 

as for the hydrothermal scenario, the resource type in GETEM was designated EGS so that well 

stimulation costs were included. The non-well exploration costs and exploration well success 

rate for EGS were also used, and a 2:1 production-to-injection well ratio was assumed. The 

production well flow rate and thermal drawdown rate of the reservoir were set to the values 

assumed in the base and target funding case. For the base case, a production well flow rate of 30 

kg/s and a reservoir thermal drawdown rate of 3.0%/year were assumed, and for the target case, 

values of 60 kg/s and 0.3%/year, respectively, were assumed. The resulting supply curves for 

the base and target cases are shown in Figure 7. The 10th%ile and 90th%ile LCOE values are 

shown in gray to illustrate the range of likely values for the hydrothermal power plants given the 

current state of technology based on expert input. 
20 

Figure 7. Supply curve for near-hydrothermal field EGS resource. 

Present-day median (50th%ile) LCOE estimates in 2008 US$ from GETEM shown for base and target cases. 

10th%ile and 90th%ile values for each curve shown in gray. 

3.4 Deep EGS 

3.4.1 Resource Potential 

The deep EGS resource consists of all the thermal energy stored deep in the Earth’s crust at 

depths accessible using drilling technology. The deep EGS resource is not associated with 

localized hot spots around hydrothermal sites, but instead relies on the natural thermal gradient 

in the Earth’s crust to achieve reservoirs with temperatures high enough to economically produce 

electricity. Because these reservoirs tend to require deeper drilling and the creation of 

completely artificial engineered reservoirs, they likely will not be developed until EGS 

technologies have been proven at near-hydrothermal field EGS sites and the technology has 

matured somewhat. Because of this and its vast size, the deep EGS resource represents the longterm future of geothermal technology. 

The deep EGS resource potential is based on the thermal energy stored at depths 3-10 km below 

the Earth’s surface in the continental United States. The same methodology described in a 

previous geothermal supply curve update performed by NREL (Petty and Porro 2007) was used 

to determine the electricity-generating potential of the EGS resource. The supply available is 

based on the amount of thermal energy contained in a volume of rock. The thermal energy in 

place for each of these volumes, Qrock, is determined based on the rock density, ρ, heat capacity, 

Cp, volume, V, and the average temperature decline of the rock over production, ΔT, as shown in 

Eq. (1). 

 (1) .Eq ࢀ∆ࢂ࢖࡯࣋ ൌ ࢑ࢉ࢕࢘ࡽ

The temperature decline of the fluid produced from the reservoir over its productive lifetime is 

limited by the surface power plant equipment. The power plant is designed to work under a 

relatively narrow range of operating conditions, the temperature of the circulating fluid being one 

0

20

40

60

80

100

120

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Levelized Cost of Electricity (cents/kWh)

Cumulative Capacity (MWe)

BASE CASE

TARGET CASE
21 

of the key parameters. The power plant becomes less efficient as operating conditions stray from 

their design values, placing a practical limit on the allowable temperature decrease in the 

circulating fluid over the lifetime of the plant. In keeping with the methodology used in the 

previous study (Petty and Porro 2007), an average reservoir temperature decline of ΔT = 10o

C 

was assumed. Since this is the average temperature decline of the reservoir, localized regions of 

the reservoir near flow fractures will experience a much larger temperature drop than those 

regions far from the flow. 

Because of temperature gradients in the reservoir, only a fraction of the thermal energy stored in 

the reservoir can be recovered and carried to the surface by circulating fluid through it. This 

fraction is defined by the recovery factor, Rg. A model of flow in fractured systems by Sanyal 

and Butler (2005) found that beyond a stimulated volume of 1x108

 m3 the percentage of 

recoverable heat from an EGS reservoir is nearly constant at about 40%. Therefore, the 

conservative recovery factor of Rg = 20% assumed in the previous study (Petty and Porro 2007) 

was used. This recovery factor lies at the upper end of that assumed by the USGS for 

hydrothermal systems in its 2008 assessment (Williams, Reed, et al. 2008a; Williams, Reed, et 

al. 2008b) as discussed in Section 3.1.1. Eq. (2) shows the amount of recoverable thermal 

energy, Qth, available for conversion to electricity. 

 (2) .Eq ࢍࡾ࢑ࢉ࢕࢘ࡽ ൌ ࢎ࢚ࡽ

The recovered thermal energy is converted to electric energy by a power plant at the surface. 

The potential power capacity of the plant is determined by assuming a plant lifetime over which 

the energy is extracted from the reservoir and converted to electricity. The conversion efficiency 

of the power plant is limited by the laws of thermodynamics and is determined by the 

temperature of the recovered fluid and the ambient, or dead-state, temperature to which heat is 

rejected by the power plant. The conversion of thermal energy to electrical energy, We, was 

calculated from Eq. (3) using an analysis of binary cycle efficiency by DiPippo (2004) that 

considers the net electrical output based on all of the thermal energy from the circulating fluid to 

determine the net total cycle efficiency, ηnet. 

 (3) .Eq ࢎ࢚ࡽ࢚ࢋ࢔ࣁ ൌ ࢋࢃ

The electricity-generating potential for a given volume of rock was determined by applying 

Eq. (1)-Eq. (3). A plant lifetime of 30 years was assumed. Table 5 shows the results of these 

calculations as a function of the EGS reservoir temperature. Constant values were assumed for 

the rock density and heat capacity. The table shows that using this methodology, the amount of 

recoverable heat is independent of the resource temperature. However, the amount of electricitygenerating capacity of the EGS resource is greatly affected by its temperature. 
22 

Table 5. Potential Electric Capacity Per Unit Rock Volume for Deep EGS Resources as a Function 

of Temperature 

Resource 

Temp 

Range

Rock 

Density

Rock Heat 

Capacity 

Average 

Reservoir 

Temp 

Decline

Heat in 

Place

Recovery 

Factor 

Recoverable 

Heat

Plant 

Life

Plant 

Efficiency

Potential 

Electric 

Capacity 

(

o

C) (kg/km3) (kJth/kgoC) (

o

C) (MJth/km3) % (MJth/km3) (years) % (MWe/km3) 

T ρρock Cp ∆T Qrock Rg Qth ηnet We

150-200 2.55E+12 1 10 2.55E+10 20% 5.1E+9 30 11% 0.59 

200-250 2.55E+12 1 10 2.55E+10 20% 5.1E+9 30 14% 0.76 

250-300 2.55E+12 1 10 2.55E+10 20% 5.1E+9 30 16% 0.86 

300-350 2.55E+12 1 10 2.55E+10 20% 5.1E+9 30 18% 0.97 

>350 2.55E+12 1 10 2.55E+10 20% 5.1E+9 30 22% 1.19 

The deep EGS resource potential estimate was made using temperature vs. depth data obtained 

from the Southern Methodist University (SMU) Geothermal Laboratory (Richards 2009) 

featured in MIT’s The Future of Geothermal Energy report (Tester et al. 2006). The data consist 

of the maps showing the estimated temperatures at depths of 3-10 km in 1-km intervals for the 

entire continental United States. Insufficient temperature and depth data were available to 

include Alaska and Hawaii. The thermal energy in place was calculated for 1-km thick volumes 

at depths of 3-10 km (centered at 3.5, 4.5, 5.5, 6.5, 7.5, 8.5, and 9.5 km depths). Temperature 

data was binned in 50o

C increments ranging from 50o-350oC as shown in Figure 8. 

r 

Figure 8. Temperature at depth of 5.5 km (Tester et al. 2006).

The areal extent of each temperature bin at each depth was determined from the maps using GIS 

methods. Federally protected and U.S. Department of Defense (DOD) lands were excluded. The 

resulting rock volume for each temperature bin at each depth interval was multiplied by the 
23 

corresponding volumetric potential electric capacity in Table 5. The resulting EGS electricity 

potential for the continental United States for each temperature/depth interval is shown in 

Table 6. The reservoir is assumed to extend to the bottom of each 1-km slice, so that the 

resource estimate for the rock centered at 3.5 km has a reservoir depth of 4 km. The resource 

estimate identifies 15,908 GWe of electricity producing potential, although the amount of this 

resource that can be economically produced is likely much smaller.

Table 6. Potential Electric Capacity (MWe) of Deep EGS Resource for Continental United States by 

Temperature-depth Combination 

Potential Electric Capacity (MWe)

Resource Temperature (oC)

150-200 200-250 250-300 300-350 >350

Reservoir Depth (km)

4 92,500 117 0 0 

5 591,000 26,500 134 0 0 

6 1,140,000 228,000 7,680 50 0 

7 1,340,000 724,000 86,100 631 0 

8 1,540,000 1,130,000 345,000 33,000 320

9 1,880,000 1,160,000 762,000 138,000 9,920

10 1,910,000 1,250,000 1,020,000 434,000 69,300

The results of the deep EGS resource estimate in the study differ slightly from the previous 

NREL supply curve update (Petty and Porro 2007) due to the use of more accurate GIS methods 

when considering excluded federally protected and DOD lands. The previous study used the 

average value of excluded lands on a state-by-state basis and removed this percentage uniformly 

from all resources in a state, while this study takes into account the actual resource beneath the 

excluded areas. Since much of the excluded area lies beneath high-quality (high temperature and 

shallow depth) deep EGS resources, such as Yellowstone Park, the previous study overestimated 

the quantity of high-quality resource. This is evident from the many zero-valued potential 

electricity capacity entries in Table 6 (gray boxes) for resources in the >250o

C and <7 km range. 

On the other hand, this study estimates a much larger deep EGS resource than the 500 GWe

estimate reported in the USGS 2008 geothermal assessment (Williams, Reed, et al. 2008b) or the 

100 GWe figure commonly cited from the MIT report (Tester et al. 2006). Aside from the use of 

different resource estimate methodologies, this is because the USGS 2008 assessment only 

considered 11 states in the western United States, and only depths between 3-6 km, whereas this 

resource estimate includes the entire continental United States (48 states) and depths between 3-

10 km. Much of the almost 16,000 GWe deep EGS resource reported in this study is attributed to 

heat stored deep in the Earth at depths >6 km, as seen in Table 6. The MIT number of 100 GWe

was a goal for geothermal deployment for 2050 given sufficient RD&D investments, and was not 

a total resource estimate. 

3.4.2 LCOE Cost Estimates

The LCOE of the deep EGS resource was estimated using GETEM for each temperature and 

depth interval combination listed in Table 6. First, the resource was defined in GETEM for each 

combination. The reservoir depths, and the wells drilled into the reservoir, were assumed to 

extend to the full depth of each 1-km slice, so that the 3-4 km region is assumed to have a 

reservoir depth of 4 km. The reservoir temperature was conservatively assumed to be 12.5o

C 
24 

(1/4 of interval) above the lower end of the interval (e.g., 150o-200oC temperature interval was 

assumed to have a reservoir temperature of 162.5o

C). The production well flow rate and thermal 

drawdown rate of the reservoir were set to the values assumed in the base and target funding 

case. For the base case, a production well flow rate of 30 kg/s and a reservoir thermal drawdown 

rate of 3.0%/year were assumed, and for the target case, values of 60 kg/s and 0.3%/year, 

respectively, were assumed. 

Once an LCOE was estimated for each temperature/depth interval combination, the results were 

coupled to the resource estimate in Table 6 to generate the deep EGS resource supply curve. The 

resulting supply curves for the base and target cases are shown in Figure 9. The 10th%ile and 

90th%ile LCOE values are shown in gray to illustrate the range of likely values for the 

hydrothermal power plants given the current state of technology based on expert input. The 

supply curve has been truncated to show only the first 100 GWe of potential electric power 

capacity to enable the reader to more clearly see the details of the most cost effective power 

sources. Even at this truncated scale, many of the smaller, higher quality, more cost effective 

resources are not discernible. For this reason, the deep EGS supply curve was also plotted using 

a semi-logarithmic scale, shown in Figure 10. This graph extends out to 1,000 GWe of power 

capacity.

Figure 9. Supply curve for deep EGS resource. 

Present-day median (50th%ile) LCOE estimates in 2008 US$ from GETEM shown for base and target cases. 

10th%ile and 90th%ile values for each curve shown in gray. Supply curve truncated to first 100 GWe of potential 

power capacity.

0

10

20

30

40

50

60

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000

Levelized Electricity Cost (cents/kWh)

Cumulative Capacity (MWe)

BASE CASE

TARGET CASE
25 

Figure 10. Supply curve for deep EGS resource using semi-logarithmic scale. 

Present-day median (50th%ile) LCOE estimates in 2008 US$ from GETEM shown for base and target cases. 

10th%ile and 90th%ile values for each curve shown in gray. Supply curve truncated to first 1,000 GWe of potential 

power capacity.

3.5 Co-Produced and Geopressured Resources

The resource potential estimate only took into consideration conventional hydrothermal and EGS 

technologies and did not address all geothermal technologies that can be used to produce 

electricity. In particular, an assessment of electricity generation potential from fluids coproduced during oil and gas production and “geopressured” resources was not included. The coproduced fluid resource estimate in the last NREL supply curve update (Petty and Porro 2007) 

was based on the volume of water produced during oil and gas production (Curtice and 

Dalrymple 2004) and electricity generating potential assuming a range of co-produced fluid 

temperatures (Tester et al. 2006, pp. 2-29, 2-48), not actual temperature data. Also, the study 

triple-counted the size of the resource by treating the different temperature assumptions in the 

MIT report as individual resources. The author of this report felt that there was insufficient data 

to make a reasonable estimate of the co-produced and geopressured geothermal resource. An 

effort to perform an assessment of the co-produced fluid geothermal resource is planned and will 

be included in future assessments.

4 Results and Discussion

4.1 Summary of Results

A summary of the results of the geothermal resource potential estimate is given in Table 7. A 

detailed listing of the resource potential estimate for each of the geothermal resources included in 

the supply curve, including site specific data, and capital and O&M cost estimates, is given in 

Appendix B. Although estimates of the geothermal resource were made using the best available 

data, future values will likely differ as new hydrothermal sites are discovered and better data and 

methodologies become available for estimating the capacity of the geothermal resources. The 

0

10

20

30

40

50

60

70

80

90

100

1 10 100 1,000 10,000 100,000 1,000,000

Levelized Electricity Cost (cents/kWh)

Cumulative Capacity (MWe)

BASE CASE

TARGET CASE
26 

electricity producing potential of hot fluids co-produced with oil and gas, referred to as coproduced fluids, and of geopressured resources, were not included in this study. The available 

information was deemed inadequate to make an informed estimate of these resources. An effort 

to perform an accurate assessment of the co-produced fluid resource is planned and will be 

included in future updates. Future resource assessments will also be aided by the recently 

established National Geothermal Data System (NGDS). The goal of this Recovery Act project is 

to assess and classify all geothermal resources and facilitate access to geothermal data sets for 

developers to lower the development risk associated with geothermal projects. 

Table 7. Summary of Results for Geothermal Resource Potential Estimate

Resource Resource Potential

Capacity 

(GWe) Source(s) and Description

Hydrothermal

Identified 

Hydrothermal 

Sites

6.39 

USGS 2008 Geothermal Resource Assessment1

• Identified hydrothermal sites

• Sites ≥110oC included 

• Currently installed capacity excluded

Undiscovered 

Hydrothermal 30.03 USGS 2008 Geothermal Resource Assessment1 

Enhanced 

Geothermal 

Systems 

(EGS)

NearHydrothermal 

Field EGS

7.03 

Based on data from USGS 2008 Geothermal 

Resource Assessment1 and methodology developed 

at NREL

• Regions near identified hydrothermal sites 

• Sites ≥110oC included 

• Difference between mean and 95%ile 

hydrothermal resource estimate

Deep EGS 15,908 

NREL 2006 Update2, MIT Report3, SMU Data4

• Based on volume method of thermal energy in 

rock 3-10 km depth and ≥150oC 

• Does not consider economic or technical 

feasibility 1

(Williams, Reed, et al. 2008b) 2

(Petty and Porro 2007) 3

(Tester et al. 2006) 4

(Richards 2009) 

The supply curves presented in Section 3 for the separate geothermal technologies were 

combined to produce an aggregated supply curve for all geothermal technologies and are shown 

for the base case in Figure 11 and for the target case in Figure 12. The base case assumes current 

benchmarks for EGS reservoir performance and the target case assumes advanced reservoir 

technologies consistent with Program MYRD&D goals. The supply curves for identified and 

undiscovered hydrothermal are the same for both cases. The supply curves have been truncated 
27 

to show the first 50 GWe of potential capacity to emphasize the lowest cost resources that are 

likely to be developed first. The combined supply curve shows the likely order in which 

resources would be developed based on the LCOE estimated by GETEM. Because market 

penetration models consider a wider range of factors, such as capital costs, O&M costs, 

technology readiness time frames, future cost multipliers, and model-specific assumptions about 

financing and project development times to calculate the cost of developing resources, models 

differ slightly from each other and from the figures below in the order they build out the 

resources. However, the LCOE of a resource gives a good approximate measure of the most 

economical resource to build.

Figure 11. Base case aggregate supply curve of the four geothermal technologies analyzed. 

0

5

10

15

20

25

30

35

40

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

Levelized Cost of Electricity (cents/kWh)

Cumulative Capacity (MWe)

Deep EGS

Undiscovered Hydrothermal

Near-Hydrothermal Field EGS

Identified Hydrothermal
28 

Figure 12. Target case aggregate supply curve of the four geothermal technologies analyzed. 

Compared to the base case, the target case shows an increase in the number of near-hydrothermal 

field EGS projects included in the most cost-effective 50 GWe of potential capacity. The target 

case also contains a large amount of deep EGS at a significantly lower LCOE than in the base 

case. There are two small amounts of deep EGS capacity that are barely discernible in the 

figures, and a large amount of capacity that extends beyond the scale of the graph. This 

represents the 5km-200o

C depth-temperature combination for the deep EGS resource. It consists 

of more than 25,000 MWe of potential capacity. The target case assumes that EGS reservoir 

technology has advanced to the point where reservoirs can be reliably engineered with 

production well flow rates of 60 kg/s and thermal drawdown rates of 0.3%/year (versus 30 kg/s 

and 3.0%/year, respectively, for the base case). The large decrease in costs in the target case for 

the EGS projects is due to advances in EGS reservoir performance that require fewer wells to be 

drilled for the power plant and no additional costs incurred for drilling and stimulating new 

reservoirs over the lifetime of the power plant. 

Supply curves can also be shown as a function of the total capital costs of the project. The 

geothermal supply curves as a function of the 50th%ile capital costs for each technology are 

shown for the base and target cases in Figure 13 and Figure 14, respectively. 

0

2

4

6

8

10

12

14

16

18

20

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

Levelized Cost of Electricity (cents/kWh)

Cumulative Capacity (MWe)

Deep EGS

Undiscovered Hydrothermal

Near-Hydrothermal Field EGS

Identified Hydrothermal
29 

Figure 13. Base case supply curve by capital costs of the four geothermal technologies analyzed. 

Figure 14. Target case supply curve by capital costs of the four geothermal technologies

analyzed. 
30 

All geothermal technologies, especially EGS, saw increases in costs compared to those in the 

previous NREL supply curve update (Petty and Porro 2007) due to increases in drilling costs. 

The previous update had assumed 2004 drilling costs, which were much lower than current 

drilling costs (see Figure 3). Even though drilling costs in this study were assumed to be 30% 

less than the 2008 drilling cost index value in GETEM, drilling costs were still 64% higher than 

the index value used in 2004. This added significantly to the capital costs of geothermal 

projects. The capital costs estimated by GETEM for each of the geothermal technologies were 

broken down by project development phase. Four project development phases were identified: 

1) Exploration/Confirmation Costs 

o Non-well exploration costs

o Exploration well costs

o Confirmation well costs (two required to prove the resource, used as production 

wells)

2) Drilling Costs 

o Costs to drill remaining injection and production wells 

3) Other Wellfield Costs (non-drilling) 

o Injection and production pumps 

o Reservoir stimulation costs (for EGS sites)

4) Power Plant Costs 

o Costs of equipment and construction 

The breakdown of capital costs follows the phases of development for a geothermal project. The 

early phases, especially during the drilling of exploration and confirmation wells, carry a much 

higher risk of failure (Deloitte 2008). Acquiring capital for these early phases before the 

resource is confirmed is more difficult and carries a higher cost of capital, usually equity 

financing. Once exploration and confirmation is completed, the success rate of the project 

increases and capital can be acquired at lower interest rates, usually as debt financing. The 

capital costs for the individual geothermal technologies, as well as other results from the supply 

curve study, are discussed individually below. 

4.2 Hydrothermal Resource

4.2.1 Resource Potential

Like in the oil and gas industry, where advances in exploration and production continue to 

expand the recoverable resource base, hydrothermal sites are still being discovered and new 

geothermal technologies will increase the amount of energy that can be recovered from existing 

sites. This study supplements identified hydrothermal sites with the estimated undiscovered 

geothermal resource from the USGS 2008 geothermal resource assessment to represent the 

expected increase in the future identified geothermal resource. The undiscovered geothermal 

resource estimate was based on the assumption that the undiscovered resource looks like 

currently identified sites on a state-by-state basis. A forthcoming paper from the USGS should 

shed more insight on the methodology used to estimate the undiscovered hydrothermal resource. 

This methodology should be incorporated into future updates to more accurately reflect the likely 

distribution and nature of the undiscovered resource. 
31 

4.2.2 Capital Costs and LCOE

The capital costs estimated by GETEM for the identified and undiscovered hydrothermal 

resources were broken down by project development phase. Since project costs were estimated 

for nearly 150 hydrothermal sites, it is not practical to show the capital costs of every single 

project. Instead, project costs for a number of hypothetical hydrothermal plants representative of 

the sites in the hydrothermal resource were estimated in GETEM. Reservoir temperatures for the 

hypothetical sites ranged from 150o

-300oC and reservoir depths ranged from 1-3 km. All other 

resource characteristics and GETEM parameters for the hypothetical plants were set equal to 

those for the supply curve reference hydrothermal plant (summarized in Table 9 of Section 5 and 

described in detail in Appendix A). Actual hydrothermal sites can be compared to hypothetical 

sites with similar resource characteristics to determine a ballpark estimate of capital costs.

The breakdown of capital costs for the hypothetical plants is shown in Figure 15. The base and 

target case assumptions for the hydrothermal resource are identical, so the data shown in the 

figure apply to both cases. For the hydrothermal resource, the highest project risk occurs in the 

exploration/confirmation phase, but the majority of capital costs are from power plant 

construction. This is because conventional hydrothermal resources tend to be shallow and have 

relatively low drilling costs. Drilling costs increase non-linearly with depth. GETEM uses a 

drilling cost correlation in which drilling costs increase exponentially with depth. Higher 

temperature reservoirs require fewer total geothermal wells per net capacity output, so a lower 

number of injection and production wells are required for a given plant’s power output. Plant 

costs also decrease with resource temperature since more electricity can be extracted per unit 

mass of geofluid at higher resource temperatures.
32 

Figure 15. Hydrothermal resource capital costs by project phase. 

4.3 Near-Hydrothermal Field EGS Resource

4.3.1 Resource Potential

The near-hydrothermal field EGS resource estimate was made using many assumptions to give a 

reasonable order-of-magnitude estimate of the size of the resource. However, a formal 

assessment of the potential to use EGS techniques to develop marginal areas around identified 

hydrothermal resources is needed to give an accurate estimate of this resource. 

4.3.2 Capital Costs and LCOE

As with the hydrothermal resource, the number of potential near-hydrothermal field EGS sites 

was too numerous to list capital costs for all of them, so project costs for hypothetical fields with 

a range of reservoir temperatures and depths were modeled in GETEM to study how capital costs 

vary with the quality of the resource. The same methodology used for hydrothermal resources 

above was applied, except GETEM values for near-hydrothermal field EGS resources were used. 

Reservoir temperatures ranged from 150o

-300oC and reservoir depths ranged from 1-3 km. All 

other resource characteristics and GETEM parameters for the hypothetical plants were set equal 

to those for the supply curve near-hydrothermal field EGS reference plant as summarized in 

Table 9 of Section 5 and described in detail in Appendix A. The largest difference was that 

reservoir stimulation was required to engineer the EGS reservoir. Capital costs were estimated 

for both the base and target cases using the base and target case values for production well flow 

rate and thermal drawdown rate and a 2:1 production/injection well ratio.

0

2,000

4,000

6,000

8,000

10,000

12,000

Capital Costs ($/kW net installed)

Hydrothermal Resource Depth-Temperature

Power Plant

Other Wellfield

Drilling

Exploration/Confirmation
33 

The breakdown of capital costs by project phase for the base and target cases is shown in Figure 

16 and Figure 17, respectively. Exploration/confirmation and power plant costs are comparable 

between the hydrothermal plants above and the near-hydrothermal field EGS plants for both 

cases since the steps in these phases of the projects are nearly identical for both geothermal 

technologies. The major difference is that the near-hydrothermal field EGS sites have higher 

stimulation/other wellfield costs due to the need to stimulate and create the EGS reservoir. 

Drilling costs differ due to differences in the assumed production well flow rates and productionto-injection well ratios among the technologies and cases. Drilling costs are significantly higher 

for the near-hydrothermal field EGS base case than for the target case because a larger number of 

wells are needed to produce enough geofluid for the given power plant’s output. 

Figure 16. Base case near-hydrothermal field EGS resource capital costs by project phase. 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Capital Costs ($/kW net installed)

Near-Hydrothermal Field EGS Resource Depth-Temperature

Power Plant

Stimulation/Other Wellfield

Drilling

Exploration/Confirmation
34 

Figure 17. Target case near-hydrothermal field EGS resource capital costs by project phase. 

The stimulation capital costs in the figures above only include the creation of the initial EGS 

reservoir. The base case requires several reservoirs to be re-drilled over the lifetime of the plant 

because of its high thermal drawdown rate. These costs are included in the wellfield O&M costs, 

which subsequently are 3-10 times greater for the base case than for the target case, depending 

on the temperature and depth of the reservoir. The LCOE includes O&M costs in addition to the 

cost of project capital over the lifetime of the project. 

4.4 Deep EGS Resource

4.4.1 Resource Potential

Like the hydrothermal and near-hydrothermal field EGS estimates, the deep EGS estimate has 

room for improvement. First, it is based on incomplete temperature versus depth data. Many 

regions, especially in the eastern United States, lack significant amounts of data. For example, 

there is not a single data point in the state of Kentucky—the estimates in this region are 

extrapolated from distant neighboring points. More temperature versus depth data for the 

continental United States is needed to increase the accuracy of the estimate. Second, the 

resource potential methodology needs further refinement. The assumption of a 10o

C average 

reservoir temperature drop does not adequately capture how heat is transferred from the rock to 

the fluid and how the reservoir cools over its lifetime. This leads to the conclusion that the same 

amount of thermal energy can be recovered from a reservoir regardless of initial temperature. 

Future data collected by the NGDS, advanced reservoir models and results from early 

demonstration plants should help to refine the methodology used in future updates. 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Capital Costs ($/kW net installed)

Near-Hydrothermal Field EGS Resource Depth-Temperature

Power Plant

Stimulation/Other Wellfield

Drilling

Exploration/Confirmation
35 

4.4.2 Capital Costs and LCOE

A breakdown of the capital costs for the deep EGS resource temperature/depth combinations in 

Table 6 for the base and target cases are shown in Figure 18 and Figure 19, respectively. Even 

for deep EGS resources with relatively low capital costs, most of the capital costs are associated 

with drilling exploration, confirmation, and injection and production wells due to the depth of the 

resource. The stimulation and power plant costs are relatively small in comparison except for the 

highest quality resources. The target case has significantly lower drilling costs because a 

production well flow rate of 60 kg/s (versus 30 kg/s for the base case) is assumed, so that fewer 

wells need to be drilled for a given power plant output. The exploration and confirmation costs 

remain constant between the two cases because the majority of these costs are tied up in the cost 

of drilling the exploration and confirmation wells; the same number of exploratory and 

confirmation wells are required in each case. The magnitude of the drilling costs is exacerbated 

by high drilling costs in recent years (see Figure 3). Despite their recent declines, there is a 

continuing debate in the geothermal community about whether drilling costs will continue to 

decrease to pre-2004 levels or will stabilize at a higher level. Decreasing drilling costs will be an 

important step in developing the deep EGS resource at a large scale in the future. GETEM 

assumes the same drilling cost curve for all locations, whereas actual drilling costs will vary with 

lithology. 

Figure 18. Deep EGS resource capital costs for base case. 

The breakdown of the capital costs by project phase is given for each temperature/depth combination listed in 

Table 6. The lower bound of the reservoir temperature in each depth interval was used to identify the resource, so 

that “4k-150C” represents the deep EGS resource with a reservoir depth of 4 km and temperature of 150o

-200oC.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Capital Costs ($/kW net installed)

Deep EGS Resource Depth-Temperature

Power Plant

Stimulation/Other Wellfield

Drilling

Exploration/Confirmation
36 

Figure 19. Deep EGS resource capital costs for target case. 

The breakdown of the capital costs by project phase is given for each temperature/depth combination listed in 

Table 6. The lower bound of the reservoir temperature in each depth interval was used to identify the resource, so 

that “4k-150C” represents the deep EGS resource with a reservoir depth of 4 km and temperature of 150o-200oC.

As with the near-hydrothermal field EGS resource, stimulation capital costs in the figures above

only include the creation of the initial EGS reservoir. The base case requires several reservoirs 

to be re-drilled over the lifetime of the plant. Field O&M costs for deep EGS include the cost of 

having to redrill the reservoir. Plant O&M costs are nearly identical for the base and target 

cases, but field O&M costs for the base case range from 10-50 times greater than those for the 

target case, depending on the resource, due to the need to periodically drill and stimulate a new 

reservoir. 

4.4.3 Optimum Deep EGS Resource Depth

The supply curve assumes that the deep EGS resource can be developed at all depths at a given 

location. If a deep EGS resource is developed at one depth in a given location, the supply curve 

does not remove the resource at the remaining depths in that location from potential 

development—it assumes that if a reservoir is artificially created at 4 km depth, another reservoir 

could still be developed below it at 5 km, 6 km, 7 km, etc. as well. Given the current state of the 

technology, the likelihood of this type of development is questionable. It is more likely that the 

most-economical deep EGS resource at a location would be developed based on the temperature 

vs. depth profile at that location, and its presence would preclude the development of the 

remaining resource in that location for the lifetime (assumed to be 30 years) of the power plant. 

The optimum reservoir depth by location in the continental United States was determined based 

on the LCOE values estimated by GETEM for the target case using GIS mapping methods. At 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Capital Costs ($/kW net installed)

Deep EGS Resource Depth-Temperature

Power Plant

Stimulation/Other Wellfield

Drilling

Exploration/Confirmation
37 

each data point in the map, the LCOE for the deep-EGS resources at depths from 3-10 km (in 

1-km increments) were compared and the minimum was selected. The reservoir temperature and 

depth associated with the minimum LCOE at each data point was noted and then mapped. The 

optimum reservoir temperature by location is shown in Figure 20, and the optimum reservoir 

depth by location is shown in Figure 21. The LCOE was not assessed in regions where the 

temperature was not above 150oC at the maximum considered depth of 10 km, so no optimum 

temperature or depth was chosen. Excluded areas are shown in white. 

Figure 20. Optimum reservoir temperature for deep EGS resource by location for target case. 
38 

Figure 21. Optimum reservoir depth for deep EGS resource by location for target case. 

Because federally protected lands were excluded from the resource estimate, the highest quality 

resource (high temperature, shallow depth), which exists around Yellowstone National Park was 

not included in the estimate. The result is that for the remaining resource, the optimum reservoir 

temperatures are all between 150o-250oC1

 

1 GIS mapping of the assessment actually found small areas where the optimum reservoir depth and temperature 

were 4 km/150o

-200oC and 6 km/300o-350oC. 

. The vast majority of the optimum resource is in the 

150o-200oC range. Although higher temperature reservoirs exist, they are at greater depths so 

that the drilling costs associated with developing them result in a higher estimated LCOE. 

Another interesting result is that all optimum reservoir depths are 5 km or deeper1

. According to 

the results of this study, there are no locations where the optimum reservoir depth is 4 km. The 

deep EGS supply curve analysis determined that it was more economical to continue drilling at 

least 1 km more to encounter higher temperature reservoirs; the increase in plant power output 

justified the higher drilling costs. 

Table 6 indicates that the potential capacity of these areas is small. 

Moreover, the regions are extremely close to the federal exclusion zones around Yellowstone National Park and, 

given the accuracy of the mapping, are likely within the park. Because of their small size and proximity to excluded 

areas, these areas are not shown in Figure 20 or Figure 21. 
39 

The results of the analysis above are not definitive and come with significant caveats. First, the 

results are unique for the EGS reservoir technology performance levels assumed in the target 

case. Achieving higher production well flow rates or a higher production-to-injection well ratio 

could lower drilling costs and change the landscape. A change in drilling costs due to natural 

market forces could also affect the results of the optimum LCOE analysis. Second, the 

underlying temperature-depth data used in the deep EGS estimate is applied over large areas and 

is not very accurate. There are likely localized hot spots not captured by the data used in the 

estimate where high reservoir temperatures exist closer to the surface. Third, a single drilling 

cost curve was used for the entire continental United States. Regions of easy or difficult drilling 

will affect drilling costs and change the contour of the maps. Given these caveats, the analysis 

suggests that future deep EGS RD&D should focus on drilling wells 5 km and deeper and power 

plants operating in the 150o

-250oC range. 

Although Figure 20 and Figure 21 show the reservoir temperature and depth at the optimum 

LCOE, there is no guarantee that the optimum at a location is economically viable. Based on 

Figure 19, it is unlikely that any of the deep EGS resources with reservoir depths of 8-10 km 

would be cost effective in the foreseeable future. Therefore, a map based on the target case 

minimum LCOE by location for the U.S. deep EGS resource was made to illustrate the location 

of the most cost effective regions for developing the deep EGS resource based on the analysis in 

this study. A decision was made to avoid mapping all of the separate LCOE regions from the 

analysis. As discussed above, using raw data from the analysis can be misleading since changes 

in the assumptions used, changes in drilling costs (due to either market variations or local 

conditions), or improvements to the underlying temperature vs. depth data could easily alter the 

rank of the “best” regions. Instead, regions were grouped by favorability, with regions having 

the lowest LCOE identified as the most favorable and those having the highest as the least 

favorable. By grouping the data, the transition between resources is smoothed and the 

classification generalized, so that the results should apply even with variations in some of the 

underlying costs or assumptions. For this map, excluded areas were included. The location of 

the identified hydrothermal sites (and hence the assumed near-hydrothermal field EGS resource) 

was also included. The resulting map, shown in Figure 22, summarizes the majority of the 

geothermal resource of the United States.
40 

Figure 22. Geothermal resource of the United States. 

Figure shows the location of identified hydrothermal sites, the co-located near-hydrothermal field EGS resource, and 

the favorability of the deep EGS resource by location. The undiscovered hydrothermal resource and other 

geothermal resources, such as co-produced fluids, are not represented. 

4.5 Sensitivity Analysis

The use of TPM distributions based on expert input in Table 3 and the @Risk Monte Carlo Excel 

add-in during GETEM runs resulted in a distribution of probable LCOE values as output. 

Examples of the output LCOE distributions from Monte Carlo simulations of the hydrothermal 

and target case deep EGS reference plants (Appendix A) are shown in Figure 23 and Figure 24, 

respectively. Each Monte Carlo simulation consisted of 1,000 iterations. The supply curves in 

Section 3 show the median (50th%ile) LCOE values, as well as 10th%ile and 90th%ile values

presented in the figures. The incorporation of the results from the risk assessment and use of risk 

analysis software for the supply curve gives a more complete picture of the range of possible 

geothermal project costs based on the uncertainty of technology costs and performance levels. 
41 

Figure 23. LCOE distribution for hydrothermal reference plant. 

Figure 24. LCOE distribution for deep EGS reference plant (target case). 

Along with a probable distribution of the LCOE, the use of risk analysis tools allowed a study of 

the sensitivity of the LCOE to the GETEM inputs. Sensitivity analysis is used to identify the 

most significant parameters that affect the output of a model. An analysis was performed of the 

sensitivity of LCOE for deep EGS and hydrothermal sites to the TPM distributions given by 

geothermal experts as part of the risk assessment. The hydrothermal and target case deep EGS 

reference plants described in Appendix A were used to perform the analysis. The results of the 

sensitivity analysis are displayed as “tornado” charts in Figure 25 and Figure 26. The longer 

bars at the top represent the most significant inputs of those tested. The results indicate that, of 

the TPM distributions used, the binary system capital costs and well or drilling costs have the 

largest impact on LCOE for the hydrothermal reference plant. For the deep EGS reference plant, 

well costs are by far the most significant variable. For the deep EGS plant, the input 
42 

distributions for the stimulation costs and binary power plant costs have roughly the same impact 

on the LCOE. These results could also be inferred from the capital costs for the geothermal 

resources given above. The results of the sensitivity analysis indicate that RD&D efforts focused 

on lowering drilling costs and binary power plant costs would have the largest impact in 

lowering the overall costs associated with the geothermal technologies considered in this study. 

Figure 25. Sensitivity analysis results for hydrothermal reference plant. 

Figure 26. Sensitivity analysis results for deep EGS reference plant (target case). 

During the supply curve analysis, constant values for geothermal resource characteristics such as 

reservoir temperature, depth, and reservoir volume were used. The exact values of these 

resource characteristics are not known and there is some uncertainty to their value. The USGS 

2008 resource assessment used triangular distributions to represent these values and used a 

Monte Carlo approach to give a range of probable resource capacities (Williams, Reed, et al. 
43 

2008a; Williams, Reed, et al. 2008b). These resource characteristic distributions should have 

been used as inputs for @Risk during GETEM modeling and incorporated into the supply curve 

analysis to better gauge the uncertainty around the size and cost of developing the geothermal 

resources in the assessment. However, since the mean values for reservoir temperature and 

capacity from the USGS 2008 geothermal assessment were used for most inputs, the median 

LCOE values are likely close to what they would have been had the resource characteristic 

distributions been used. However, future supply curve studies should incorporate resource 

characteristic distributions into the risk analysis.

Likewise, distributions for the EGS reservoir performance characteristics, such as production 

well flow rate and reservoir thermal drawdown rate, should have been used. The sensitivity 

analyses above do not take into account the significance of these parameters and how changes in 

them affect LCOE. During preliminary supply curve analysis, it was seen that these factors can 

greatly affect the project costs for developing a geothermal resource. An attempt was made 

during the risk assessment to gather distribution data for reservoir performance from the experts, 

but the reservoir engineering expert discussions in the risk process were never concluded. 

Consequently, the resulting reservoir TPM distributions were inconsistent, conflicted with input 

from previous EGS studies, and were deemed invalid (Young, Augustine, et al. 2010). Future 

risk assessments and data from EGS demonstration projects should provide better reservoir 

performance data for future supply curve studies. 

5 Future Costs of Geothermal Resources

The supply curves in Section 3 show the estimated LCOE for geothermal technologies in 2008 

US$ assuming current technology and, for the target case, the LCOE for EGS technologies 

assuming current technology and that the reservoir technology performance goals proposed for 

EGS were met today. The risk assessment described in Section 2.3 also elicited input from 

experts of probable distributions for TPMs in the future. The purpose of the risk assessment was 

to estimate advances in geothermal technologies under different levels of RD&D funding from 

the Program, and to use these results to predict the effect Program spending could have on 

technology improvements, analyze the risk involved in project funding and guide Program 

funding strategies. The experts were asked to estimate likely distributions for the TPMs in the 

years 2015 and 2025 assuming funding levels of $0, $30M and $60M per year per technology 

component. The distributions from the experts were then aggregated into a single probability 

distribution. The mean values for the aggregated distributions in the present and future years 

under the assumed budget levels are shown in Table 8. A description of the process and 

methodology used to gather the expert input and results is given by Young et al. (2010). 
44 

Table 8. Mean Values from Aggregated Distributions of Expert-Elicited Geothermal TPM Input for 

Future Years 

TPM Year / Budget Level

Technology

Area Name Units

2008 2015 2025

--- $0 $30M $60M $0 $30M $60M

Exploration 

Non-Well Exploration Costs (EGS) $M 1.41 1.14 1.06 0.97 1.10 0.94 0.82 

Non-Well Exploration Costs (Hydro) $M 1.22 1.18 1.13 1.07 1.16 1.06 0.90 

Exploration Well Success Rate (EGS) % 64 64 66 68 66 69 73 

Exploration Well Success Rate (Hydro) % 34 37 41 43 40 45 49 

Well Pumps & 

Tools 

Well Drilling/Construction Cost $M 22.3 21.6 20.3 19.0 20.6 18.3 16.6 

Production Pump Cost (per well) $M 1.5 1.5 1.3 1.2 1.4 1.2 1.0 

Reservoir 

Engineering Stimulation Cost (per triplet) $M 8.4 7.9 7.5 6.8 7.3 6.4 5.8 

Power 

Conversion 

Binary System Capital Cost $/kW 2,500 2,470 2,380 2,010 2,390 2,250 1,870 

Binary System O&M Cost/Yr ¢/kWh 2.2 2.2 2.1 1.9 2.2 2.1 1.8 

Brine Effectiveness W-h/lbm 9.5 9.5 9.7 10.0 9.6 10.0 10.4 

Note: Budget levels assume RD&D funding per year per technology component. All dollar values assume 

2008 US$. 

The future TPM data from the risk assessment was used to estimate improvements in future costs 

of the geothermal technologies in this study for the future year base and target cases described in 

Section 2.1. The base case assumes “business as usual” for industry with no GTP RD&D 

funding. For the target case, an RD&D budget of $50M/year was assumed. Future costs were 

estimated for four future cases—two time frames and two budget levels: 

1) 2015 Base Case ($0/year GTP RD&D budget) 

2) 2025 Base Case ($0/year GTP RD&D budget) 

3) 2015 Target Case ($50M/year GTP RD&D budget) 

4) 2025 Target Case ($50M/year GTP RD&D budget) 

A sensitivity analysis of GETEM inputs using the TPMs listed in Table 8 found that well 

drilling/construction costs and binary system capital costs have the largest impact on the LCOE 

for the hydrothermal reference scenario, and that well costs dominate LCOE for the EGS 

reference scenario (see Figure 25 and Figure 26). The same conclusion was found when the 

effect of individual component costs was studied as part of the risk assessment (Young, 

Augustine, et al. 2010, Table 3). Based on these results, this study assumed that for the target 

case, the Program split its $50M/year budget evenly between funding RD&D to reduce well 

costs ($25M/year) and binary power plant costs ($25M/year). These budget levels differ from 

the $30M/year and $60M/year budget levels considered by experts in the risk assessment. 

Linear interpolation between the $0 and $30M/year budget levels was used to estimate 

technology benefits at the $25M/year RD&D level. Benefits from RD&D to well cost and 

binary power plant cost improvements were applied for all geothermal technologies in this study 

since well and power plant technology improvements would be applicable in both hydrothermal 

and EGS technologies. It was assumed that all other TPMs received no RD&D funding, so that 

their future year improvements followed those predicted by the experts for the $0/year budget 

level.
45 

The LCOE for each of the geothermal technologies was calculated using GETEM for the four 

cases using the future year TPM distributions described above. It was not practical to calculate 

the LCOE under each of the four future cases for every hydrothermal site and EGS resource. 

Moreover, several of the market penetration models only allow generic cost multipliers that are 

applied broadly to a technology type, so cost multipliers on a site-by-site basis would not be 

usable. Instead, reference scenarios representative of a typical plant were assumed for each 

technology type. Improvements to LCOE under each case were calculated for each reference 

scenario, and were assumed to apply to all the resources in each technology type. The resource 

characteristics for reference scenarios and LCOE output for each technology are summarized in 

Table 9. Hydrothermal covers both the identified and undiscovered hydrothermal resource. The 

reservoir technology parameters used for the EGS reference scenarios differ in the base and 

target cases. The near-hydrothermal field EGS reference scenario is a combination of the 

hydrothermal and deep EGS cases. Unless otherwise stated, GETEM parameter inputs and 

assumptions for the reference scenarios were the same as those used for each technology type in 

the supply curve. Detailed input used in GETEM for each of the reference scenarios is listed in 

Appendix A. 

Table 9. Summary of Supply Curve Reference Scenarios 

Detailed GETEM input for reference scenarios is listed in Appendix A.

Parameter Technology Type

Hydrothermal Near-Hydrothermal Field EGS Deep EGS

Plant Type Binary, air-cooled Binary, air-cooled Binary, air-cooled

Net Output 20 MWe 20 MWe 20 MWe

Resource Temperature 175 oC 175 oC 225 oC 

Well Depth 1.52 km 1.52 km 6 km

Production Well

Flow Rate 44.2 kg/s Base Case: 30 kg/sTarget Case: 60 kg/s

Base Case: 30 kg/s

Target Case: 60 kg/s

Thermal

Drawdown Rate 0.3%/year Base Case: 3.0%/yearTarget Case: 0.3%/year

Base Case: 3.0%/year

Target Case: 0.3%/year

Based on the results of the GETEM runs for each reference scenario, future cost multipliers were 

calculated for each geothermal technology. The future cost multipliers are based on the LCOE 

and are calculated by dividing the LCOE under a future case for the reference scenario by the 

present day LCOE for the reference scenario. Future costs for each technology are determined 

by multiplying the present value LCOE by the future cost multiplier for a given year. The future 

cost multipliers are shown in Figure 27. 
46 

Figure 27. Future cost multipliers for geothermal technologies. 

For EGS technologies, the base and target cases make different assumptions about production 

well flow rate and thermal drawdown rate. The future cost multipliers consider the effect of 

RD&D budget levels on future costs, not the assumed enabling technology advances from the 

base case to the target cases. This means that the current year values of LCOE for the EGS base 

and target cases differ from each other. The effect of the enabling reservoir technology advances 

assumed for the target case on LCOE can be seen by studying the EGS supply curves in 

Section 3. 

GTP MYRD&D goals call for a functioning EGS demonstration reservoir by 2015 and proven 

sustainable production from a reservoir by 2020. In the target case, it is not realistic to think that

the Program could spend their RD&D funding solely on drilling and power plant technology 

improvements and still achieve the reservoir performance goals at same time (or vice versa). 

Therefore, when cost multipliers were calculated for input into market penetration models for 

annual GPRA benefits analysis, it was assumed that the entirety of the budget was spent on 

enabling technologies for EGS through 2020—achieving assumed program reservoir technology 

goals of 60 kg/s production well flow rate and 0.3%/year thermal drawdown rate. After 2020, it 

was assumed that the Program had reached its MYRD&D goals and that EGS is commercially 

viable. After 2020, it was assumed that GTP splits its budget equally on funding RD&D for 

reducing well costs ($25M/year) and binary power plant costs ($25M/year). Such a funding 

scenario was not presented to the experts during the risk assessment process. The cost 

0.84

0.86

0.88

0.90

0.92

0.94

0.96

0.98

1.00

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026

Future Cost Multiplier

Year

Hydrothermal - Base Case Hydrothermal - Target Case

Near-Hydrothermal Field EGS - Base Case Near-Hydrothermal Field EGS - Target Case

Deep EGS - Base Case Deep EGS - Target Case
47 

multipliers for market penetration model input were estimated using a combination of the base 

and target cost multipliers shown in Figure 27. The base case multipliers were used through 

2020, and then the slope of the future cost multiplier curves from 2015 to 2025 was used to 

construct the future cost multiplier curves from 2020 onward. For these market penetration 

model runs, it was also assumed that EGS power plants were not commercially available until 

2020. 

6 Conclusions

The 2009 geothermal supply curve study updated the geothermal supply curve of the United 

States for use as input into market penetration models and GPRA benefits analysis. The study 

established an approach and methodology for performing future supply curve updates when new 

resource and cost data become available. The potential resource estimates made use of published 

and available data on geothermal resources, in particular the results of the USGS 2008 

geothermal resource assessment. When sufficient information was not available, methodologies 

and assumptions were established for estimating geothermal resource potential. 

The geothermal resource was divided among two technologies—conventional hydrothermal 

systems and EGS. Resources were further divided into four categories, two for each technology. 

The resource categories and the electricity generation potential capacity determined for each 

were: 

1) Identified Hydrothermal Resource: 6.39 GWe 

2) Undiscovered Hydrothermal Resource: 30.03 GWe 

3) Near-Hydrothermal Field EGS Resource: 7.03 GWe

4) Deep-EGS Resource: 15,908 GWe

The costs of developing the geothermal resources were estimated using GETEM. Two budget 

levels were considered: a base case based on the current status of geothermal technology with $0 

assumed for GTP RD&D research funding, and a target case with $50M/year assumed for GTP 

RD&D research funding and EGS reservoir performance based on Program goals from the 

MYRD&D. Probability distributions of technology costs and performance estimated by 

geothermal experts as part of the annual risk assessment were incorporated into the supply curve. 

These input distributions were used to run Monte Carlo simulations in GETEM with the @Risk 

risk analysis software. The incorporation of technology component uncertainty results in a 

distribution of probable project costs rather than a single value. Supply curves based on the 

median, 10th%ile, and 90th%ile estimates of the LCOE were generated for each of the resource 

categories. Future cost multipliers for the years 2015 and 2025 were also calculated for each 

geothermal technology based on expert risk assessment input and GETEM results.

The individual supply curves were combined to create aggregate supply curves for the base and 

target cases that include all geothermal resources in the supply curve. The aggregate supply 

curves focused on the most cost effective 50 GWe of geothermal resource. For the base case, 

identified and undiscovered hydrothermal resources dominate the lower part of the curve, with 

some EGS present at higher LCOE values. For the target case, hydrothermal sites still dominate 

the lower part of the curve, but a significant amount of near-hydrothermal field EGS resource is 

visible. The cost level at which a large amount of deep EGS resource is found in the supply 
48 

curve is significantly lower for the target case than for the base case, indicating that meeting 

GTP goals could have a significant impact on deep EGS deployment. 

Capital costs by project phase for the different technologies were also presented. For the 

hydrothermal and near-hydrothermal field EGS resources, power plant costs tend to make up a 

significant portion of the capital costs. These resources tend to be shallow, so they have 

relatively low drilling costs. Exploration/confirmation and plant costs are comparable for 

hydrothermal and near-hydrothermal field EGS resources, with the major difference in capital 

costs for the two resources stemming from the need to stimulate the EGS reservoir. For the deep 

EGS resource, drilling costs are the dominant component of the total capital costs. LCOE and 

capital costs were generally higher for all geothermal resources in this supply curve than in the 

last NREL study (Petty and Porro 2007) mainly due to a significant increase in drilling costs over 

the past several years. The previous study assumed 2004 drilling costs, while this study assumed 

a 30% discount from 2008 drilling costs based on conversations with geothermal drilling 

companies. Even at this discounted level, the index value used to adjust drilling costs in 

GETEM was 64% higher than its 2004 value. 

GIS tools were used to perform an analysis of the optimum LCOE for the deep EGS resource by 

location. It was found that across the country, the deep EGS reservoirs with the minimum LCOE 

at a given location were located at depths of ≥5 km and had temperatures in the 150o

-250oC 

range. It was concluded that deep EGS RD&D should favor technologies that would lower the 

cost of developing these types of resources. These conclusions are heavily influenced by the 

assumptions made for the base and target case, the current drilling cost trend, and the accuracy of 

the resource estimates. Distributions for the resource characteristics or EGS reservoir 

technology performance metrics were not included in the risk analysis or subsequent sensitivity 

analysis. 

A sensitivity analysis found that drilling costs and binary power plant costs most significantly 

affect the LCOE of both hydrothermal and EGS projects. These findings are supported by the 

results of the capital cost estimates. Future cost multipliers for each of the geothermal 

technologies were calculated based on funding assumptions in the base and target cases and 

expert input from the risk assessment.

There is ample room for improvement of the geothermal resource potential estimate as the 

quantity and quality of geothermal resource data continues to increase over the coming years. 

Both the undiscovered hydrothermal and near-hydrothermal field EGS resource estimates rely 

heavily on assumptions. The deep EGS resource is based on data that are sparse in many parts of 

the country. Additional efforts are needed to better characterize these resources. A co-produced 

fluid resource assessment is also needed. General recommendations for improvements to the 

supply curve cost estimates are to improve expert input during the risk assessment process, 

especially for EGS reservoir TPMs and the application of the expert input to the full range of 

geothermal resources, the inclusion of resource uncertainty measurements in the supply curve, 

and the development of drilling cost and reservoir creation models that take into account local 

lithology and well diameter. Detailed recommendations for future supply curve studies are 

discussed below.
49 

6.1 Detailed Recommendations for Future Supply Curve Studies

6.1.1 Resource Potential

Below is a list of recommendations for future supply curve studies. Some recommendations can 

be implemented relatively easily, while others are multi-year projects that would require a 

considerable amount of time, effort, and resources. Many recommended tasks will be completed 

as part of planned USGS resource assessments and the establishment of the NGDS, which will 

assess and classify all geothermal resources and facilitate access to geothermal data sets for 

developers to lower the risk associated with the development of geothermal projects. Future 

supply curves should incorporate these data as they become available. Recommendations are 

grouped by resource category: 

1) Identified Hydrothermal Resource: Current potential based on site-specific data from 

USGS 2008 geothermal resource assessment (Williams, Reed, et al. 2008b). 

o Continue to update database of indentified hydrothermal sites as they are 

discovered and currently installed capacity as new power plants are constructed 

and capacity at existing plants is expanded.

o Update estimates of hydrothermal resource characteristics to include probability 

distributions for reservoir temperature and volume (from USGS 2008 

assessment), and also verify estimated reservoir depth and production well flow 

rate figures.

2) Undiscovered Hydrothermal Resource: Current potential based on summary data from 

USGS 2008 geothermal resource assessment (Williams, Reed, et al. 2008b) and 

assumption that undiscovered resource is similar in nature to identified resource in same 

state.

o Learn details of methodology used by USGS to estimate undiscovered resource 

and apply them to more accurately predict nature and location of undiscovered 

resource.

3) Near-Hydrothermal Field EGS Resource: Based on difference between 95th%ile and 

mean estimates of identified hydrothermal resource from USGS 2008 geothermal 

resource assessment (Williams, Reed, et al. 2008b). 

o Work with industry to better define nature and characteristics of nearhydrothermal field EGS resource. 

o Perform thorough assessment of potential to use EGS techniques to develop 

marginal areas around identified hydrothermal sites is needed.

4) Deep EGS Resource: Based on SMU temperature vs. depth data (Richards 2009) and 

methodology described in MIT Future of Geothermal Energy report (Tester et al. 2006). 

o Increase quality and quantity of temperature vs. depth data in the United States. 

o Develop more robust methodology for estimating resource potential based on 

reservoir modeling and EGS demonstration results. 
50 

5) Co-Produced Fluids and Geopressured Resources: Not included due to insufficient data. 

o A project to perform an accurate assessment of the co-produced fluid resource is 

planned and will be included in future updates. 

6.1.2 Supply Curve

Recommendations for improving cost estimates for geothermal resources in the supply curve are 

given below: 

1) Resource Characterization 

o Identify sites with characteristics that would significantly affect costs, such as the 

Salton Sea2

2) Drilling Costs

and Puna, and incorporate these factors in GETEM cost estimates. 

o Single drilling cost curve used in all geothermal resource cost estimates. Actual 

drilling costs will vary greatly as a function of location. Long-term goal should 

be to map lithology with resource and correlate drilling costs with lithology, so 

that more accurate drilling costs can be used when estimating LCOE for 

geothermal resources on a spatial basis. Drilling costs should also take well 

diameter into account. 

3) GETEM Input 

o Geofluid pumping parameters greatly affect parasitic power losses. The 

assumptions and parameter inputs for geofluid pumping need to be better 

addressed in the risk assessment and GETEM modeling. GETEM should base 

well diameter on production and injection well flow rate to optimize LCOE. 

4) Risk Assessment

o Credible and consistent expert input on EGS reservoir technologies such as 

production well flow rate, thermal drawdown rate, and production-to-injection 

well ratio is needed.

o Expert inputs on drilling/well completion costs, binary power plant costs, O&M 

power plant costs, brine effectiveness, and production pump costs were all based 

on the risk assessment reference plants. These data had to be generalized and 

applied across the entire range of geothermal resources. Either a better method of 

gathering expert data that can be applied across a wide range of geothermal 

resources, or a better method of applying resource-specific expert input is needed. 

Some parameters, such as brine effectiveness and binary power plant cost, are 

calculated in GETEM using complex and detailed correlations. Using GETEM 

solely to calculate these parameters instead of expert input should be considered. 

 

2 Capital costs for Salton Sea have been updated to $4,000/kW for hydrothermal and $4,800/kW for nearhydrothermal field EGS for FY12 DOE budget planning cycle. Updates based on adjusting material and labor cost 

multipliers in GETEM to reflect use of exotic materials (titanium and inconel) compared to carbon steel in power 

plant equipment that come in contact with corrosive brine from reservoir. Drilling costs also adjusted by using 

“High” drilling cost curve in GETEM (Mines 2009). 
51 

5) Risk Analysis 

o GETEM modeling should include the uncertainty of the resource; @Risk should 

also take into account the distributions of the estimated resource temperature, 

depth, flow rate, etc. when calculating LCOE. 

o Distributions for EGS reservoir TPMs are needed. If they cannot be provided by 

the risk assessment, a reasonable range of values should be considered by the risk 

analysis.
52 

References 

Augustine, C.; Young, K.; Anderson, A. (2010). "Updated U.S. Geothermal Supply Curve." 

Prepared for the 35th Stanford Geothermal Workshop, Stanford University, CA, February 1-3, 

2010. NREL/CP-6A2-47458. Golden, CO: National Renewable Energy Laboratory, 19 pp. 

http://www.nrel.gov/docs/fy10osti/47458.pdf. 

Bureau of Labor Statistics. (2009). "Producer Price Index Industry Data: Drilling Oil, Gas, Dry, 

or Service Wells: PCU21311121311101." http://www.bls.gov/data/. Accessed December 28, 

2009. 

Curtice, R.J.; Dalrymple, E.D. (2004). "Just the Cost of Doing Business?" World Oil (225:10); 

pp. 77-78. 

Deloitte. (2008). Geothermal Risk Mitigation Strategies Report. Washington, D.C.: Department 

of Energy - Office of Energy Efficiency and Renewable Energy Geothermal Program. pp. 43. 

http://www1.eere.energy.gov/geothermal/pdfs/geothermal_risk_mitigation.pdf. 

DiPippo, R. (2004). "Second Law Assessment of Binary Plants for Power Generation from LowTemperature Geothermal Fluids." Geothermics (33); pp. 565-586. 

Energy Information Administration. (2009). "Form EIA-860 Database Annual Electric Generator 

Report." U.S. Department of Energy. http://www.eia.doe.gov/cneaf/electricity/page/eia860.html. 

Accessed December 28, 2009.

Entingh, D.J. (2006). Introduction to the Geothermal Electricity Technology Evaluation Model 

(GETEM). Rockville, MD: Princeton Energy Resources International. 

Geothermal Energy Association. (2009). "Geothermal Plants." http://www.geoenergy.org/information/plants.asp. Accessed June 1, 2009. 

Geothermal Technologies Program. (2008). Multi-Year Research, Development and 

Demonstration Plan: 2009-2015 with Program Activities to 2025. Washington, D.C.: U.S. 

Department of Energy Office of Energy Efficiency and Renewable Energy. 

http://www1.eere.energy.gov/geothermal/pdfs/gtp_myrdd_2009-complete.pdf. 

Geothermal Technologies Program. (2009a). "Geothermal Electricity Technology Evaluation 

Model (GETEM), Version 2008-A6." U.S. Department of Energy Geothermal Technologies 

Program. http://www1.eere.energy.gov/geothermal/getem.html. Accessed May, 2009. 

Geothermal Technologies Program. (2009b). "Geothermal Technologies Program Projects." U.S. 

Department of Energy Geothermal Technologies Program. 

http://apps1.eere.energy.gov/geothermal/projects/. Accessed November 4, 2009. 

Mines, G. (2009). E-mail correspondence with C. Augustine, December 9, 2009. Idaho National 

Laboratory, Idaho Falls, ID.
53 

Muffler, L.J. (1979). Assessment of Geothermal Resources of the United States - 1978. U.S. 

Geological Survey Circular 790. Washington, D.C.: U.S. Department of Interior. 

http://pubs.er.usgs.gov/publication/cir790. 

Petty, S.; Porro, G. (2007). "Updated U.S. Geothermal Supply Characterization." Prepared for 

the Thirty-Second Workshop on Geothermal Reservoir Engineering, Stanford University, CA, 

January 22-24, 2007. NREL/CP-640-41073. Golden, CO: National Renewable Energy 

Laboratory, 24 pp. http://www.nrel.gov/docs/fy07osti/41073.pdf. 

Richards, M. (2009). E-mail message to C. Augustine, May 29, 2009. SMU Geothermal 

Laboratory, Dallas, TX.

Sanyal, S.K.; Butler, S.J. (2005). "An Analysis of Power Generation Projects from Enhanced 

Geothermal Systems." Geothermal Resources Council Transactions (29); pp. 131-138. 

Tester, J.W., et al. (2006). The Future of Geothermal Energy: Impact of Enhanced Geothermal 

Systems (EGS) on the United States in the 21st Century. INL/EXT-06-11746. Cambridge, MA: 

Massachusetts Institute of Technology. 

http://www1.eere.energy.gov/geothermal/future_geothermal.html. 

Williams, C. (2009a). Personal communication with C. Augustine, March 30, 2009. U.S. 

Geological Survey, Menlo Park, CA. 

Williams, C.F. (2009b). Personal communication with C. Augustine, April 9, 2009. U.S. 

Geological Survey, Menlo Park, CA. 

Williams, C.F.; DeAngelo, J. (2008). "Mapping Geothermal Potential in the Western United 

States." Geothermal Resources Council Transactions (32); pp. 181-188. 

Williams, C.F.; Reed, M.J.; Mariner, R.H. (2008a). A Review of Methods Applied by the U.S. 

Geological Survey in the Assessment of Identified Geothermal Resources. U.S. Geological 

Survey Open-File Report 2008-1296. U.S. Department of Interior. pp. 27. 

http://pubs.usgs.gov/of/2008/1296/pdf/of2008-1296.pdf. 

Williams, C.F.; Reed, M.J.; Mariner, R.H.; DeAngelo, J.; Galanis, S.P.J. (2008b). Assessment of 

Moderate- and High-Temperature Geothermal Resources of the United States. U.S. Geological 

Survey Fact Sheet 2008-3082. U.S. Department of Interior. pp. 4. 

http://pubs.usgs.gov/fs/2008/3082. 

Young, K.R.; Augustine, C.; Anderson, A. (2010). "Report on the U.S. DOE Geothermal 

Technologies Program's 2009 Risk Analysis." Prepared for the Thirty-Fifth Workshop on 

Geothermal Reservoir Engineering, Stanford University, CA, February 1-3, 2010. NREL/ CP6A2-47388. Golden, CO: National Renewable Energy Laboratory, 12 pp. 

http://www.nrel.gov/docs/fy10osti/47388.pdf. 
54 

Appendix A: Reference Scenario Power Plants

Legend

Key Reference-Scenario Parameters 

Expert Data Provided from Risk 

Assessment

10thpercentile value-50thpercentile value-90thpercentile value

Values Calculated by GETEM 

Table A-1. GETEM Input for Hydrothermal Reference Scenario

Version Version 2008-A6

Case Name Hydrothemral Reference Scenario

Plant Type Binary, Air-Cooled

Reference Year 2008

Power Sales 20 MW

(1) ECONOMIC PARAMETERS

(1a) Fixed.Charge.Rate 0.128

(1b) Utiliz.Factor 0.95

(1c) Contingency 5%

(1d) Royalty [b] 10%

(1e) Year for Baseline Estimate 2008

(2) RESOURCE DEFINITION

(2a) Is the Resource Type Hydrothermal or EGS? Hydrothermal

(2b) Resource Temperature Used 175 C (347 o

F)

(2c) Resource Depth Used 1,524 m (5,000 ft)

(2d) Plant Design Temperature (used in all model calculations) 175 C (347 o

F)

(3) POWER SALES

(3a) Are calculations to be based upon 

Fixed Power Sales or Fixed 

Number of Production Wells?

Power

(3b) Enter either Sales or # of Wells 20 MW or count

(3c) Net Plant Output 21.44 MW

(4) EXPLORATION & CONFIRMATION

(4a) Input the # of Exploration Wells or Success Rate? Rate TPM 2

(4b) Enter success rate or # of wells 20-34-50 % or count TPM 2

(4c) Pro-rate Explor & Confirm Costs Based on Resource Potential? NO

(4d) # of Exploration Wells Used 2.87 = 1/(4b)

(4e) Number of Confirmation wells 2 Count

(4f) Confirmation well success 0.80 Ratio

(4g) Multiplier for Exploration Well Costs 0.50

(4h) Multiplier for Confirmation Well Costs 1.1

(4i) Non-Well Exploration Costs Used $513-$1,174-$2,002 $k/plant TPM 1

(4j) Non-Well Confirmation Costs Used $250,000

 

 

 

 

 

 

 

 

 

 

 

 

GETEM Input for Supply Curve Hydrothermal Reference Scenario
55 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

GETEM Input for Supply Curve Hydrothermal Reference Scenario

 

 

 

 

 

 

 

 

(5) WELL FIELD DEVELOPMENT

(5a) # of Spare Production Wells 0

(5b) # Production Wells Used (including any confirmation wells used) 8.42

(5c) Ratio of Injection Wells to Production Wells 0.33

(5d) Number of Injection Wells Used 2.81 = (5b)*(5c)

(5e) Production Well Depth Used 1,524 m (5,000 ft)

(5f) Calculated Production Well Cost - 2008 $2,004 $k/well

(5g) User Adjustment to Production Well Cost 0.59-0.86-1.18 TPM 3

(5h) Adjusted Production Well Cost $1,750 $k/well

(5i) Injection Well Depth Used 1,524 m (5,000 ft)

(5j) Calculated Injection Well Cost - 2008 $2,004 $k/well

(5k) User Adjustment to Production Well Cost 0.59-0.86-1.18 TPM 3

(5l) Adjusted Injection Well Cost $1,750 $k/well

(5m) Surface Equipment Cost $125 $k/well

(5n) Non-Well Costs Incurred (exclusive of drilling) $2,500 $k

(6) EGS SUBSURFACE FRACTURE SYSTEM

(7) WELL STIMULATION

(7a) Are wells Stimulated? No

(8) GF PUMPING

(8a) Are Production Wells Pumped? Yes TPM 7

(8b) Production Well Flow Rate 44.2 kg/s (350,000 lb/h) TPM 7

(8c) Injection Well Flow Rate 135.3 kg/s (1,052,159 lb/h)

(8d) Total GF Flow Rate - Production 372.1 kg/s (2,953,347 lb/h)

(8e) Total GF Flow Rate - Injection 372.1 kg/s (2,953,347 lb/h)

(8f) GF Pump efficiency 60%

(8g) Production well diameter (ID) below production pump 7.0 inch (17.8 cm)

(8h) Production pump casing size (ID) 7.0 inch (17.8 cm)

(8i) Injection well diameter (ID) 7.0 inch (17.8 cm)

(8j) Excess Pressure at Pump Suction/Surface 3.5 bar (50.8 psia)

(8k) Is Additional Pressure Required in Injection Well? Yes

(8l) Excess Pressure at Bottom of Injection Well 10.3 bar (150.0 psi)

(8m) Use inputted or calclulated reservoir ΔP? Calculate

Base reservoir dP calculation on k*A or simple fracture flow? k*A

Reservoir permeability 0.15 darcy

Reservoir height 125.0 m

Reservoir width 750.0 m

Distance between production and injection well 1,500.0 m

(8n) Input or Calculate Production Pump Depth? Calculate

(8o) Pump Depth Used 65.6 m (215.1 ft)

(8p) Production Pumping Power 47.9 kW/well

(8q) Total pumping power required 3.9 kW-s/kg (0.486 w-hr/lb)

(8r) Input or Calculate Production Pump Cost? Input TPM 4

If Pumped, Enter type of Pump used Submersible

(8s) Production Pump Cost $1-$1.5-$2.0 $million/well TPM 4

(8t) Injection Well Pump Costs $800,350

 

 

 

 

 

 

 

 

 
56 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

GETEM Input for Supply Curve Hydrothermal Reference Scenario

 

 

 

 

 

 

 

(9) THERMAL DRAWDOWN

(9a) Input Annual Decline Rate or Calculate Fluid Temperature? Decline Rate TPM 8

(9b) Input Annual Rate of Decline 0.3% %/yr TPM 8

(9c) Discount Rate for Makeup calculations 10.0%

(9d) Input Maximum Temperature Decline?? No = (2b)*(2d)

(9e) Maximum Temperature Decline 21.8 ΔC (39.2 ΔF)

(9f) First Reservoir Replacement N/A year

(9g) Number of Reservoirs Used 1.0 count

(10) OPERATING & MAINTENANCE COSTS

(10a) Input Annual O&M Costs or Let GETEM Calculate Input TPM 11

(10b) Input the annual O&M Cost for the Power Plant 2.20 ¢/kW-hr TPM 11

(10c) 0.44 

(Value Calculated by 

GETEM)

¢/kW-hr

(11) ENERGY CONVERSION SYSTEM

(11a) Number of independent power units 1

(11b) Power

(11c) Design Ambient Temperature 15 o

C (not changeable)

(11d) Is the Conversion System Flash or Binary? Binary

(11e) GF Pumping 0.49 w-h/lb

(11f) Sales per well 2,375 kW/well

(11g) Binary System Performance 7.26 w-h/lb TPM 12

(11h) Binary Conversion System Cost $2.72-$3.09-$3.46 $k/kW.plant output TPM 10

Apply performance improvement to reducing flow requirement or 

increasing power output?

Input the annual O&M cost for the Field 

(including production pumps)
57 

Table A-2. GETEM Input for Near-hydrothermal Field EGS Reference Scenario

Version Version 2008-A6

Case Name Near-Hydrothemral Field EGS Reference Scenario

Plant Type Binary, Air-Cooled

Reference Year 2008

Power Sales 20 MW

(1) ECONOMIC PARAMETERS

(1a) Fixed.Charge.Rate 0.128

(1b) Utiliz.Factor 0.95

(1c) Contingency 5%

(1d) Royalty [b] 10%

(1e) Year for Baseline Estimate 2008

(2) RESOURCE DEFINITION

(2a) Is the Resource Type Hydrothermal or EGS? EGS

(2b) Resource Temperature Used 175 C (347 o

F)

(2c) Resource Depth Used 1,524 m (5,000 ft)

(2d) Plant Design Temperature (used in all model calculations) 175 C (347 o

F)

(3) POWER SALES

(3a) Are calculations to be based upon 

Fixed Power Sales or Fixed 

Number of Production Wells?

Power

(3b) Enter either Sales or # of Wells 20 MW or count

(3c) Net Plant Output 21.47 MW

(4) EXPLORATION & CONFIRMATION

(4a) Input the # of Exploration Wells or Success Rate? Rate TPM 2

(4b) Enter success rate or # of wells 50-63-80 % or count TPM 2

(4c) Pro-rate Explor & Confirm Costs Based on Resource Potential? NO

(4d) # of Exploration Wells Used 1.58 = 1/(4b)

(4e) Number of Confirmation wells 2 Count

(4f) Confirmation well success 0.80 Ratio

(4g) Multiplier for Exploration Well Costs 0.50

(4h) Multiplier for Confirmation Well Costs 1.1

(4i) Non-Well Exploration Costs Used $417-$1,314-$2,534 $k/plant TPM 1

(4j) Non-Well Confirmation Costs Used $250,000

(5) WELL FIELD DEVELOPMENT

(5a) # of Spare Production Wells 0

(5b) # Production Wells Used (including any confirmation wells used) 6.21

(5c) Ratio of Injection Wells to Production Wells 0.50

(5d) Number of Injection Wells Used 3.11 = (5b)*(5c)

(5e) Production Well Depth Used 1,524 m (5,000 ft)

(5f) Calculated Production Well Cost - 2008 $2,004 $k/well

(5g) User Adjustment to Production Well Cost 0.59-0.86-1.18 TPM 3

(5h) Adjusted Production Well Cost $1,750 $k/well

(5i) Injection Well Depth Used 1,524 m (5,000 ft)

(5j) Calculated Injection Well Cost - 2008 $2,004 $k/well

(5k) User Adjustment to Production Well Cost 0.59-0.86-1.18 TPM 3

(5l) Adjusted Injection Well Cost $1,750 $k/well

(5m) Surface Equipment Cost $125 $k/well

(5n) Non-Well Costs Incurred (exclusive of drilling) $2,500 $k

 

 

 

 

 

 

GETEM Input for Supply Curve Near-Hydrothermal Field EGS Reference Scenario
58 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

GETEM Input for Supply Curve Near-Hydrothermal Field EGS Reference Scenario

(6) EGS SUBSURFACE FRACTURE SYSTEM

(6a) Is the EGS evaluation to be based 

on calculations of simplified 

subsurface model?

No

(7) WELL STIMULATION

(7a) Are wells Stimulated? Yes

(7b) Use Fixed Well Stimulation Cost or Base on Fracture Surface Area? Fixed Cost

(7c) Well Stimulation Cost Used $0.9-$2.6-$5.0 $million/Well TPM 6

(8) GF PUMPING

(8a) Are Production Wells Pumped? Yes TPM 7

(8b) Production Well Flow Rate 60.0 kg/s (476,198 lb/h) TPM 7

(8c) Injection Well Flow Rate 122.4 kg/s (971,444 lb/h)

(8d) Total GF Flow Rate - Production 372.7 kg/s (2,957,725 lb/h)

(8e) Total GF Flow Rate - Injection 380.1 kg/s (3,016,879 lb/h)

(8f) GF Pump efficiency 60%

(8g) Production well diameter (ID) below production pump 7.0 inch (17.8 cm)

(8h) Production pump casing size (ID) 7.0 inch (17.8 cm)

(8i) Injection well diameter (ID) 7.0 inch (17.8 cm)

(8j) Excess Pressure at Pump Suction/Surface 3.5 bar (50.8 psia)

(8k) Is Additional Pressure Required in Injection Well? Yes

(8l) Excess Pressure at Bottom of Injection Well 10.3 bar (150.0 psi)

(8m) Use inputted or calclulated reservoir ΔP? Calculate

Base reservoir dP calculation on k*A or simple fracture flow? k*A

Reservoir permeability 0.15 darcy

Reservoir height 125.0 m

Reservoir width 750.0 m

Distance between production and injection well 1,500.0 m

(8n) Input or Calculate Production Pump Depth? Calculate

(8o) Pump Depth Used 177.0 m (580.7 ft)

(8p) Production Pumping Power 177.2 kW/well

(8q) Total pumping power required 3.9 kW-s/kg (0.496 w-hr/lb)

(8r) Input or Calculate Production Pump Cost? Input TPM 4

If Pumped, Enter type of Pump used Submersible

(8s) Production Pump Cost $1-$1.5-$2.0 $million/well TPM 4

(8t) Injection Well Pump Costs $477,513

(9) THERMAL DRAWDOWN

(9a) Input Annual Decline Rate or Calculate Fluid Temperature? Decline Rate TPM 8

(9b) Input Annual Rate of Decline 0.3% %/yr TPM 8

(9c) Discount Rate for Makeup calculations 10.0%

(9d) Input Maximum Temperature Decline?? No = (2b)*(2d)

(9e) Maximum Temperature Decline 21.8 ΔC (39.2 ΔF)

(9f) First Reservoir Replacement N/A year

(9g) Number of Reservoirs Used 1.0 count

(10) OPERATING & MAINTENANCE COSTS

(10a) Input Annual O&M Costs or Let GETEM Calculate Input TPM 11

(10b) Input the annual O&M Cost for the Power Plant 2.20 ¢/kW-hr TPM 11

(10c) 0.52 

(Value Calculated by 

GETEM)

Input the annual O&M cost for the Field ¢/kW-hr

(including production pumps)
59 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

GETEM Input for Supply Curve Near-Hydrothermal Field EGS Reference Scenario

 

 

 

 

 

(11) ENERGY CONVERSION SYSTEM

(11a) Number of independent power units 1

(11b) Power

(11c) Design Ambient Temperature 15 o

C (not changeable)

(11d) Is the Conversion System Flash or Binary? Binary

(11e) GF Pumping 0.50 w-h/lb

(11f) Sales per well 3,220 kW/well

(11g) Binary System Performance 7.26 w-h/lb TPM 12

(11h) Binary Conversion System Cost $2.72-$3.09-$3.46 $k/kW.plant output TPM 10

 

 

Apply performance improvement to reducing flow requirement or 

increasing power output?
60 

Table A-3. GETEM Input for Deep EGS Reference Scenario

Version Version 2008-A6

Case Name Deep EGS Reference Scenario

Plant Type Binary, Air-Cooled

Reference Year 2008

Power Sales 20 MW

(1) ECONOMIC PARAMETERS

(1a) Fixed.Charge.Rate 0.128

(1b) Utiliz.Factor 0.95

(1c) Contingency 5%

(1d) Royalty [b] 10%

(1e) Year for Baseline Estimate 2008

(2) RESOURCE DEFINITION

(2a) Is the Resource Type Hydrothermal or EGS? EGS

(2b) Resource Temperature Used 225 C (347 o

F)

(2c) Resource Depth Used 6,000 m (19,685 ft)

(2d) Plant Design Temperature (used in all model calculations) 200 C (347 o

F)

(3) POWER SALES

(3a) Are calculations to be based upon 

Fixed Power Sales or Fixed 

Number of Production Wells?

Power

(3b) Enter either Sales or # of Wells 20 MW or count

(3c) Net Plant Output 26.34 MW

(4) EXPLORATION & CONFIRMATION

(4a) Input the # of Exploration Wells or Success Rate? Rate TPM 2

(4b) Enter success rate or # of wells 50-63-80 % or count TPM 2

(4c) Pro-rate Explor & Confirm Costs Based on Resource Potential? NO

(4d) # of Exploration Wells Used 1.58 = 1/(4b)

(4e) Number of Confirmation wells 2 Count

(4f) Confirmation well success 0.80 Ratio

(4g) Multiplier for Exploration Well Costs 0.50

(4h) Multiplier for Confirmation Well Costs 1.1

(4i) Non-Well Exploration Costs Used $417-$1,314-$2,534 $k/plant TPM 1

(4j) Non-Well Confirmation Costs Used $250,000

(5) WELL FIELD DEVELOPMENT

(5a) # of Spare Production Wells 0

(5b) # Production Wells Used (including any confirmation wells used) 5.68

(5c) Ratio of Injection Wells to Production Wells 0.50

(5d) Number of Injection Wells Used 2.84 = (5b)*(5c)

(5e) Production Well Depth Used 6,000 m (19,685ft)

(5f) Calculated Production Well Cost - 2008 $17,871 $k/well

(5g) User Adjustment to Production Well Cost 0.59-0.86-1.18 TPM 3

(5h) Adjusted Production Well Cost $15,607 $k/well

(5i) Injection Well Depth Used 6,000 m (19,685ft)

(5j) Calculated Injection Well Cost - 2008 $17,871 $k/well

(5k) User Adjustment to Production Well Cost 0.59-0.86-1.18 TPM 3

(5l) Adjusted Injection Well Cost $15,607 $k/well

(5m) Surface Equipment Cost $125 $k/well

(5n) Non-Well Costs Incurred (exclusive of drilling) $2,500 $k

 

 

 

 

 

 

GETEM Input for Supply Curve Deep EGS Reference Scenario
61 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

GETEM Input for Supply Curve Deep EGS Reference Scenario

 

 

 

 

 

 

 

(6) EGS SUBSURFACE FRACTURE SYSTEM

(6a) Is the EGS evaluation to be based 

on calculations of simplified 

subsurface model?

No

(7) WELL STIMULATION

(7a) Are wells Stimulated? Yes

(7b) Use Fixed Well Stimulation Cost or Base on Fracture Surface Area? Fixed Cost

(7c) Well Stimulation Cost Used $0.9-$2.6-$5.0 $million/Well TPM 6

(8) GF PUMPING

(8a) Are Production Wells Pumped? Yes TPM 7

(8b) Production Well Flow Rate 60.0 kg/s (476,198 lb/h) TPM 7

(8c) Injection Well Flow Rate 122.4 kg/s (971,444 lb/h)

(8d) Total GF Flow Rate - Production 340.7 kg/s (2,703,830 lb/h)

(8e) Total GF Flow Rate - Injection 347.5 kg/s (2,797,907 lb/h)

(8f) GF Pump efficiency 60%

(8g) Production well diameter (ID) below production pump 7.0 inch (17.8 cm)

(8h) Production pump casing size (ID) 7.0 inch (17.8 cm)

(8i) Injection well diameter (ID) 7.0 inch (17.8 cm)

(8j) Excess Pressure at Pump Suction/Surface 3.5 bar (50.8 psia)

(8k) Is Additional Pressure Required in Injection Well? Yes

(8l) Excess Pressure at Bottom of Injection Well 10.3 bar (150.0 psi)

(8m) Use inputted or calclulated reservoir ΔP? Calculate

Base reservoir dP calculation on k*A or simple fracture flow? k*A

Reservoir permeability 0.15 darcy

Reservoir height 125.0 m

Reservoir width 750.0 m

Distance between production and injection well 1,500.0 m

(8n) Input or Calculate Production Pump Depth? Calculate

(8o) Pump Depth Used 134.5 m (441.3 ft)

(8p) Production Pumping Power 980.7 kW/well

(8q) Total pumping power required 18.2 kW-s/kg (0.496 w-hr/lb)

(8r) Input or Calculate Production Pump Cost? Input TPM 4

If Pumped, Enter type of Pump used Submersible

(8s) Production Pump Cost $1-$1.5-$2.0 $million/well TPM 4

(8t) Injection Well Pump Costs $561,189

(9) THERMAL DRAWDOWN

(9a) Input Annual Decline Rate or Calculate Fluid Temperature? Decline Rate TPM 8

(9b) Input Annual Rate of Decline 0.3% %/yr TPM 8

(9c) Discount Rate for Makeup calculations 10.0%

(9d) Input Maximum Temperature Decline?? No = (2b)*(2d)

(9e) Maximum Temperature Decline 32.3 ΔC (58.1 ΔF)

(9f) First Reservoir Replacement N/A year

(9g) Number of Reservoirs Used 1.0 count

(10) OPERATING & MAINTENANCE COSTS

(10a) Input Annual O&M Costs or Let GETEM Calculate Input TPM 11

(10b) Input the annual O&M Cost for the Power Plant 2.45 ¢/kW-hr TPM 11

(10c) 1.10

(Value Calculated by 

GETEM)

¢/kW-hr

 

 

 

 

 

 

 

Input the annual O&M cost for the Field 

(including production pumps)

 

 
62 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

GETEM Input for Supply Curve Deep EGS Reference Scenario

 

 

 

 

 

(11) ENERGY CONVERSION SYSTEM

(11a) Number of independent power units 1

(11b) Power

(11c) Design Ambient Temperature 15 o

C (not changeable)

(11d) Is the Conversion System Flash or Binary? Binary

(11e) GF Pumping 2.29 w-h/lb

(11f) Sales per well 3,435 kW/well

(11g) Binary System Performance 9.50 w-h/lb TPM 12

(11h) Binary Conversion System Cost $2.22-$2.53-$2.83 $k/kW.plant output TPM 10

(11i) Binary Conversion System Cost Calculate $k/kW.sales

(11j) Binary Conversion System Cost Calculate total $

 

 

Apply performance improvement to reducing flow requirement or 

increasing power output?
63 

Appendix B: Geothermal Supply Curve Data

Table B-1. Identified hydrothermal sites

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

Adak AK N/A 9 51.98 -176.62 155 1.52 44.2 Binary 13.3 13.3 $7,632 $280

Akutan Fumaroles AK N/A 9 54.15 -165.91 250 1.52 44.2 Flash 49.2 49.2 $2,899 $139

Alvord HS OR 11 9 42.54 -118.53 135 1.22 63.1 Binary 19.5 19.5 $9,264 $352

Amedee CA 13 10 40.30 -120.18 115 0.46 101.0 Binary 7.8 5.6 $17,269 $770

Arrowhead HS CA 13 10 34.19 -117.27 115 1.37 50.5 Binary 7.1 7.1 $16,646 $590

Bailey Bay Hot Springs AK N/A 9 55.98 -131.66 125 1.52 44.2 Binary 16.9 16.9 $12,147 $389

Baker Hot Spring WA 11 9 48.76 -121.67 115 1.52 63.1 Binary 22.7 22.7 $18,339 $618

Baltazor Hot Springs NV 11 8 41.92 -118.71 140 1.07 94.7 Binary 20.5 20.5 $9,232 $386

Bell Island HS AK N/A 9 55.93 -131.57 120 1.52 44.2 Binary 10.6 10.6 $14,185 $464

Beowawe HS NV 11 8 40.57 -116.58 215 2.44 69.4 Binary 54.1 41.3 $4,164 $155

Big Creek Hot Springs ID 11 8 45.31 -114.34 135 1.52 63.1 Binary 21.1 21.1 $9,796 $356

Black Rock Point area NV 11 8 40.96 -119.11 120 1.52 44.2 Binary 8.5 8.5 $14,380 $480

Black Warrior NV 11 8 39.90 -119.22 135 1.52 44.2 Binary 17.0 17.0 $9,837 $328

Blue Mountain NV 11 8 41.00 -118.13 205 0.91 88.4 Binary 62.4 62.4 $3,707 $168

Boyes HS CA 13 10 38.31 -122.49 110 1.52 44.2 Binary 8.4 8.4 $19,948 $636

Bradfield Canal Hot Spring AK N/A 9 56.24 -131.26 110 1.52 44.2 Binary 7.3 7.3 $20,083 $649

Brady HS NV 11 8 39.79 -119.02 185 0.30 94.7 Binary 44.1 18.1 $4,495 $203

Breitenbush Hot Springs OR 11 9 44.78 -121.98 150 2.13 65.7 Binary 7.9 7.9 $9,408 $361

Butte Springs (Trego) NV 11 8 40.77 -119.11 115 1.52 63.1 Binary 7.3 7.3 $19,371 $712

Calistoga HS CA 13 10 38.58 -122.57 140 1.52 82.1 Binary 16.9 16.9 $9,829 $391
64 

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

Canby (I'SOT) CA 13 10 41.44 -120.87 120 1.52 44.2 Binary 9.4 9.4 $14,289 $473

Carson Lake Corral NV 11 8 39.36 -118.66 125 1.52 44.2 Binary 11.4 11.4 $12,420 $412

Carson River CA 13 10 38.77 -119.72 145 1.52 44.2 Binary 15.7 15.7 $8,433 $294

Clark Ranch OR 11 9 43.86 -118.55 110 1.52 44.2 Binary 7.1 7.1 $20,112 $652

Clear Lake (Sulphur Bank 

mine) CA 13 10 39.02 -122.65 300 3.66 37.9 Flash 29.2 29.2 $3,763 $135

Clifton Hot Springs AZ 12 8 33.08 -109.30 110 1.52 63.1 Binary 14.5 14.5 $24,274 $830

Colado area NV 11 8 40.23 -118.37 110 1.07 63.1 Binary 10.8 10.8 $20,028 $743

Coso area CA 13 10 36.05 -117.77 285 1.52 69.4 Flash 518.5 289.2 $1,838 $94

Cove Fort - Sulphurdale -

Liquid UT 11 8 38.60 -112.55 150 0.76 94.7 Binary 25.7 9.7 $7,228 $304

Cove Fort - Sulphurdale -

Vapor UT 11 8 38.60 -112.55 155 0.76 94.7 Binary 1.7 1.7 $11,728 $573

Crane Creek-Cove Creek 

area

ID 11 8 44.31 -116.74 150 3.05 63.1 Binary 54.8 54.8 $9,487 $260

Crump's HS OR 11 9 42.23 -119.88 150 1.52 44.2 Binary 44.0 44.0 $7,586 $244

Dann Ranch Hot Spring NV 11 8 40.32 -116.43 140 1.52 44.2 Binary 22.3 22.3 $8,891 $294

Darrough Hot Springs NV 11 8 38.82 -117.18 120 0.61 63.1 Binary 11.3 11.3 $11,970 $484

Deer Creek Hot Spring (old 

97) ID 11 8 44.09 -116.05 125 1.83 63.1 Binary 15.7 15.7 $13,911 $481

Desert Peak NV 11 8 39.75 -118.95 215 1.68 50.5 Binary 33.0 15.5 $4,071 $170

Dixie Hot Springs NV 11 8 39.80 -118.07 130 2.90 94.7 Binary 9.6 9.6 $61,150 $2,062

Dixie Valley Geothermal 

Field NV 11 8 39.99 -117.85 225 1.52 44.2 Flash 149.3 93.3 $3,416 $116

Dixie Valley Power 

Partners NV 11 8 39.95 -117.92 280 1.52 44.2 Flash 102.9 77.9 $2,178 $99
65 

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

Double Hot Springs area NV 11 8 41.05 -119.03 120 1.52 44.2 Binary 9.4 9.4 $14,294 $473

Dulbi AK N/A 9 65.27 -155.27 110 1.52 44.2 Binary 9.1 9.1 $19,844 $628

Dunes CA 13 10 32.80 -115.01 145 1.07 50.5 Binary 18.5 18.5 $7,716 $294

Dyke Hot Springs area NV 11 8 41.57 -118.57 110 1.52 63.1 Binary 5.4 5.4 $25,548 $941

East Brawley CA 13 10 32.99 -115.35 285 3.05 63.1 Flash 358.5 358.5 $2,289 $80

East Mesa (Deep) CA 13 10 32.78 -115.25 190 1.52 44.2 Binary 60.3 60.3 $4,943 $173

East Mesa (Shallow) CA 13 10 32.78 -115.25 165 1.07 94.7 Binary 142.4 41.4 $5,833 $224

Emigrant NV 11 8 37.86 -117.87 165 2.44 15.8 Binary 40.1 40.1 $11,416 $202

Ennis (Thexton) Hot 

Springs MT 11 8 45.37 -111.73 115 1.52 63.1 Binary 12.9 12.9 $18,729 $658

Fallon Naval Air Station NV 11 8 39.38 -118.65 195 2.13 31.6 Binary 53.4 53.4 $5,573 $151

Fernley area (Patua 

HS/Hazen) NV 11 8 39.60 -119.11 155 1.68 50.5 Binary 22.2 22.2 $7,357 $261

Fish Lake Valley NV 11 8 37.86 -118.05 205 1.52 44.2 Binary 57.1 57.1 $4,217 $158

Fort Bidwell CA 13 10 41.86 -120.16 110 0.76 75.8 Binary 9.1 9.1 $20,428 $825

Geyser Bight AK N/A 9 53.22 -168.47 182 1.52 44.2 Binary 97.9 97.9 $5,339 $173

Geysers CA 13 10 38.80 -122.80 242 1.83 94.7 Flash 519.7 0.0 $2,604 $112

Geysers Hi T Reservoir CA 13 10 38.80 -122.80 315 1.83 18.9 Flash 517.2 0.0 $2,882 $114

Gillard (Morenci) Hot 

Springs AZ 12 8 32.97 -109.35 110 1.52 63.1 Binary 11.8 11.8 $24,486 $848

Goddard Hot Springs AK N/A 9 56.84 -135.37 135 1.52 44.2 Binary 14.8 14.8 $9,922 $335

Great Boiling Springs 

(Gerlach) NV 11 8 40.66 -119.36 175 0.61 50.5 Binary 49.3 49.3 $5,063 $203

Great Sitkin Island AK N/A 9 52.07 -176.08 130 1.52 44.2 Binary 14.5 14.5 $10,948 $363
66 

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

Gregson (Fairmont) Hot 

Springs MT 11 8 46.04 -112.81 110 1.52 63.1 Binary 7.1 7.1 $25,102 $905

Heber Deep CA 13 10 32.72 -115.53 205 1.22 63.1 Binary 34.5 34.5 $3,983 $179

Heber Shallow CA 13 10 32.72 -115.53 170 1.22 63.1 Binary 125.1 5.9 $5,378 $193

Hot (Borax) Lake OR 11 9 42.33 -118.60 150 1.52 44.2 Binary 42.9 42.9 $7,594 $245

Hot Springs Bay (Akutan 

Island) AK N/A 9 54.17 -165.82 130 1.52 44.2 Binary 15.0 15.0 $10,930 $361

Hot Springs Cove AK N/A 9 53.23 -168.35 110 1.52 44.2 Binary 5.0 5.0 $20,900 $698

Hot Springs Ranch 

(Pumpernickel Valley) NV 11 8 40.76 -117.49 125 1.52 63.1 Binary 11.4 11.4 $13,068 $483

Hot Sulphur Springs -

Tuscarora NV 11 8 41.47 -116.15 155 0.76 107.3 Binary 35.9 35.9 $6,812 $286

Huckleberry Hot Springs WY 11 8 44.11 -110.69 120 1.52 63.1 Binary 38.7 38.7 $14,626 $485

Humboldt House - Rye 

Patch NV 11 8 40.54 -118.27 205 0.91 82.1 Binary 90.4 90.4 $3,648 $158

Jemez Springs (Ojos 

Calientes) NM 12 8 35.77 -106.69 110 1.52 44.2 Binary 8.6 8.6 $19,906 $633

Kahneetah Hot Springs OR 11 9 44.86 -121.20 115 1.07 65.7 Binary 6.1 6.1 $17,079 $682

Kellog HS CA 13 10 41.13 -121.02 110 1.52 44.2 Binary 5.4 5.4 $20,703 $688

Kelly HS CA 13 10 41.45 -120.83 120 1.83 63.1 Binary 9.5 9.5 $17,168 $605

Kluichef - Atka Island AK N/A 9 52.32 -174.19 230 1.52 44.2 Flash 43.4 43.4 $3,446 $154

Korovin - Atka Island AK N/A 9 52.35 -174.25 170 1.52 44.2 Binary 26.0 26.0 $6,146 $221

Lake City Hot Springs CA 13 10 41.67 -120.21 160 1.52 44.2 Binary 100.7 100.7 $6,496 $199

Lakeview area (Hunters 

and Barry Ranch Hot 

Springs)

OR 11 9 42.20 -120.36 135 1.07 65.7 Binary 20.1 20.1 $9,022 $351
67 

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

Latty Hot Springs ID 11 8 43.12 -115.31 110 1.52 18.9 Binary 6.4 6.4 $24,975 $568

Leach HS NV 11 8 40.60 -117.65 120 1.52 31.6 Binary 7.5 7.5 $15,386 $457

Lee Hot Springs NV 11 8 39.21 -118.72 150 1.52 31.6 Binary 26.4 26.4 $8,383 $253

Leonards Hot Sps./Seyferth 

HS CA 13 10 41.60 -120.09 125 1.52 44.2 Binary 10.0 10.0 $12,536 $422

Lightning Dock NM 12 8 32.15 -108.83 130 2.74 63.1 Binary 14.6 4.6 $15,507 $473

Little Valley area OR 11 9 43.89 -117.50 125 1.07 65.7 Binary 14.6 14.6 $11,600 $449

Long Valley caldera - deep CA 13 10 37.64 -118.91 205 3.05 31.6 Binary 47.5 47.5 $6,077 $151

Long Valley shallow CA 13 10 37.64 -118.91 175 3.05 31.6 Binary 15.0 0.0 $8,826 $226

Maazama Well (Crater 

Lake) OR 11 9 42.90 -121.99 140 3.05 31.6 Binary 32.3 32.3 $12,963 $251

Magic Reservoir area ID 11 8 43.33 -114.40 110 1.22 63.1 Binary 9.1 9.1 $21,563 $794

Makushin AK N/A 9 53.89 -166.92 205 1.52 82.1 Binary 107.3 107.3 $3,877 $157

McLeod 88 (Big Smokey 

Valley) NV 11 8 39.03 -117.14 120 1.52 44.2 Binary 9.9 9.9 $14,251 $469

Medicine Lake (Glass Mt.) CA 13 10 41.57 -121.57 255 2.74 37.9 Flash 365.6 265.7 $3,411 $78

Mickey HS OR 11 9 42.35 -118.35 170 1.07 63.1 Binary 41.0 41.0 $5,475 $218

Milky River - Atka Island AK N/A 9 52.32 -174.15 245 1.52 44.2 Flash 54.2 54.2 $2,982 $135

Mitchell Butte OR 11 9 43.76 -117.16 120 1.07 65.7 Binary 10.1 10.1 $13,754 $539

Mt. Signal CA 13 10 32.65 -115.71 135 1.52 44.2 Binary 14.7 14.7 $9,925 $335

Neal HS OR 11 9 44.02 -117.46 150 1.07 65.7 Binary 29.6 29.6 $7,151 $276

Newberry Caldera OR 11 9 43.72 -121.23 275 2.13 56.8 Flash 124.2 124.2 $2,222 $92

Newcastle area UT 11 8 37.66 -113.56 110 0.76 63.1 Binary 12.3 12.3 $17,659 $673

North Brawley CA 13 10 33.02 -115.52 250 1.52 44.2 Flash 138.0 74.0 $2,749 $107
68 

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

Olene Hot Springs OR 11 9 42.17 -121.62 110 1.52 63.1 Binary 8.3 8.3 $24,910 $886

Owl Creek Hot Springs ID 11 8 45.34 -114.46 110 1.83 63.1 Binary 7.8 7.8 $29,166 $997

Pilgrim Hot Springs AK N/A 9 65.09 -164.92 140 1.22 63.1 Binary 15.0 15.0 $8,588 $340

Pinto Hot Springs NV 11 8 41.35 -118.78 145 1.52 31.6 Binary 26.0 26.0 $8,886 $260

Puna Geothermal Venture HI N/A 9 19.48 -154.89 350 1.07 151.5 Flash 181.3 150.3 $1,354 $89

Raft River ID 11 8 42.10 -113.38 145 1.83 63.1 Binary 46.6 27.0 $8,261 $278

Railroad Valley NV 11 8 38.43 -115.53 135 1.52 44.2 Binary 17.1 17.1 $9,836 $327

Reese River NV 11 8 39.89 -117.14 135 0.76 63.1 Binary 17.1 17.1 $8,589 $348

Roosevelt HS UT 11 8 38.50 -112.85 250 1.22 107.3 Flash 119.5 51.5 $2,247 $111

Routt CO 12 8 40.56 -106.85 110 1.52 63.1 Binary 8.3 8.3 $24,907 $886

Rowland Hot Springs NV 11 8 41.88 -115.63 110 1.52 44.2 Binary 5.8 5.8 $20,483 $676

Salton Sea area CA 13 10 33.20 -115.60 310 2.29 69.4 Flash 2,209.

9 1,911.9 $1,781 $87

San Emidio Desert area NV 11 8 40.38 -119.40 190 1.07 75.8 Binary 65.2 61.7 $4,483 $184

Serpentine (Arctic) Springs AK N/A 9 65.86 -164.71 145 1.52 44.2 Binary 17.3 17.3 $8,370 $289

Sespe HS CA 13 10 34.59 -119.00 120 1.52 44.2 Binary 10.7 10.7 $14,174 $463

Sharkey Hot Springs ID 11 8 45.01 -113.61 115 1.83 63.1 Binary 10.0 10.0 $21,391 $734

Silver Star (Barkel's) Hot 

Springs MT 11 8 45.69 -112.30 115 1.52 63.1 Binary 9.1 9.1 $19,067 $689

Sitka Hot Spring AK N/A 9 56.85 -135.37 125 1.52 44.2 Binary 13.1 13.1 $12,329 $404

Smith Creek Valley area NV 11 8 39.31 -117.55 125 1.83 63.1 Binary 12.5 12.5 $14,102 $496

Soda Lake area NV 11 8 39.57 -118.85 205 1.37 94.7 Binary 48.1 37.2 $4,001 $181

Sonoma Mission Inn CA 13 10 38.31 -122.48 110 1.52 44.2 Binary 6.3 6.3 $20,315 $666
69 

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

South Brawley (Mesquite) CA 13 10 32.91 -115.54 250 3.05 63.1 Flash 42.3 42.3 $3,381 $123

Squaw Hot Springs area ID 11 8 42.12 -111.93 130 1.52 18.9 Binary 13.9 13.9 $14,675 $332

Steamboat Hills NV 11 8 39.37 -119.77 210 1.52 44.2 Binary 44.4 0.0 $4,137 $163

Steamboat Springs NV 11 8 39.39 -119.74 165 1.52 44.2 Binary 18.5 0.0 $6,635 $244

Stillwater area NV 11 8 39.52 -118.55 160 1.01 50.5 Binary 57.1 48.6 $6,136 $220

Sulphur Hot Springs (Ruby 

Valley) NV 11 8 40.59 -115.29 165 1.83 63.1 Binary 34.0 34.0 $6,427 $234

Summer Lake Hot Springs OR 11 9 42.73 -120.65 110 1.01 63.1 Binary 8.3 8.3 $19,799 $755

Surprise Valley HS CA 13 10 41.53 -120.08 115 1.52 44.2 Binary 7.8 7.8 $16,798 $552

Tecopa HS CA 13 10 35.87 -116.23 120 1.52 63.1 Binary 9.0 9.0 $15,622 $577

The Needles (Needle 

Rocks, Pyramid Lake) NV 11 8 40.15 -119.68 120 1.07 63.1 Binary 17.4 17.4 $13,158 $490

Thermo Hot Springs UT 11 8 38.18 -113.20 125 0.76 63.1 Binary 15.5 5.5 $10,674 $422

Tolvana AK N/A 9 65.27 -148.85 110 1.52 44.2 Binary 14.5 14.5 $19,452 $592

Trout Creek OR 11 9 42.19 -118.38 115 0.91 63.1 Binary 9.1 9.1 $15,455 $604

Tungsten Mountain NV 11 8 39.68 -117.69 125 1.52 44.2 Binary 12.5 12.5 $12,357 $407

Upper Division Hot Spring AK N/A 9 66.36 -156.77 110 1.52 44.2 Binary 7.0 7.0 $20,119 $652

Vale HS OR 11 9 43.99 -117.23 145 1.07 65.7 Binary 45.2 45.2 $7,331 $273

Valles Caldera - Redondo NM 12 8 35.89 -106.58 275 3.35 37.9 Flash 101.8 101.8 $3,312 $73

Valles Caldera - Sulphur 

Springs NM 12 8 35.91 -106.62 225 3.35 37.9 Flash 27.5 27.5 $5,980 $163

Vulcan Hot Springs ID 11 8 44.57 -115.70 115 1.52 18.9 Binary 10.1 10.1 $21,007 $461

Wabuska Hot Springs NV 11 8 39.16 -119.18 115 1.52 63.1 Binary 8.5 7.6 $19,152 $696

Waunita Hot Springs CO 12 8 38.51 -106.51 120 1.52 75.8 Binary 12.2 12.2 $18,021 $677
70 

Site Name

Location Data GETEM Input - Reserovoir Characteristics GETEM Output 

State

NEMS Region

MARKAL Region

Latitudea

Longitudea

Reservoir 

Tempa

Reservoir 

Depthb

Production 

Well Flow 

Rateb

Plant Typec

Potential 

Capacitya

Remaining 

Potential 

Capacityd

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MW MW 2008 US$/kW 

2008 

US$/kW/yr 

Wayland (Battle Creek) 

Hot Springs ID 11 8 42.13 -111.93 130 1.83 63.1 Binary 14.0 14.0 $12,098 $430

Wedell Hot Spring (Gabbs) NV 11 8 38.92 -118.20 140 1.52 44.2 Binary 17.7 17.7 $8,998 $305

Wendel CA 13 10 40.36 -120.25 125 1.52 44.2 Binary 11.4 11.4 $12,423 $413

West Ukinrek Maar AK N/A 9 57.80 -156.50 200 1.52 44.2 Binary 22.7 22.7 $4,668 $192

West Valley Reservoir CA 13 10 41.19 -120.39 130 1.83 63.1 Binary 12.6 12.6 $12,184 $437

White Licks Hot Springs ID 11 8 44.68 -116.23 110 1.22 63.1 Binary 9.0 9.0 $21,564 $794

Wilbur Springs CA 13 10 39.04 -122.42 160 1.07 82.1 Binary 29.3 29.3 $6,373 $264 a

Data provided by USGS from USGS 2008 Geothermal Resource Assessment. Median values for estimated reservoir temperature and potential capacity used. b

When available, estimated values from Petty and Porro 2007 used. Otherwise, default values of 1.52 km (5,000 feet) and 44.2 kg/s (350,000 lb/hr) used for reservoir depth and 

production well flow rate, respectively. c

Assumed that sites with estimated reservoir temperature ≥ 225oC were flash plants, otherwise assumed to be binary power plants. Dry steam plants not considered. d

Remaining potential capacity is difference between median potential capacity estimated from USGS and currently installed capacity in Table 4. In some cases, such as the 

Geysers, installed capacity exceeded estimated reservoir potential capacity, so remaining capacity was assumed to be zero.
71 

Table B-2. Undiscovered Hydrothermal Resource

Site ID

Location Data GETEM Input - Reservoir Characteristics GETEM Output 

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Production 

Well Flow 

Ratea

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

Undiscovered < 150 C - AK AK N/A 9 113 1.50 44.8 Binary 695 $17,027 $517

Undiscovered > 150 C - AK AK N/A 9 209 1.52 54.0 Binary 1,092 $4,292 $193

Undiscovered < 150 C - AZ AZ 12 8 110 1.52 63.1 Binary 1,042 $24,093 $803

Undiscovered < 150 C - CA CA 13 10 121 1.40 55.3 Binary 492 $13,447 $456

Undiscovered > 150 C - CA CA 13 10 279 2.11 62.8 Flash 10,848 $3,043 $200

Undiscovered < 150 C - CO CO 12 8 110 1.52 64.9 Binary 1,105 $25,027 $840

Undiscovered > 150 C - HI HI N/A 9 200 1.52 44.2 Binary 2,436 $4,743 $197

Undiscovered < 150 C - ID ID 11 8 115 1.67 51.9 Binary 1,563 $17,016 $535

Undiscovered > 150 C - ID ID 11 8 150 3.05 63.1 Binary 308 $10,071 $302

Undiscovered < 150 C - MT MT 11 8 107 1.52 62.1 Binary 772 $28,739 $1,040

Undiscovered < 150 C - NM NM 12 8 110 2.19 54.5 Binary 358 $26,309 $757

Undiscovered > 150 C - NM NM 12 8 264 3.35 37.9 Flash 1,126 $4,741 $185

Undiscovered < 150 C - NV NV 11 8 124 1.41 53.5 Binary 1,071 $12,128 $412

Undiscovered > 150 C - NV NV 11 8 203 1.39 58.9 Binary 3,293 $4,377 $200

Undiscovered < 150 C - OR OR 11 9 123 1.39 58.3 Binary 878 $12,531 $437

Undiscovered > 150 C - OR OR 11 9 206 1.69 55.1 Binary 1,014 $4,416 $193

Undiscovered < 150 C - UT UT 11 8 111 0.95 58.4 Binary 295 $17,073 $601

Undiscovered > 150 C - UT UT 11 8 231 1.13 105.0 Flash 1,168 $3,340 $227

Undiscovered < 150 C - WA WA 11 9 115 1.52 63.1 Binary 300 $18,445 $626

Undiscovered < 150 C - WY WY 11 8 120 1.52 63.1 Binary 174 $15,021 $519 a

Reservoir characteristic calculated from capacity-weighted mean of values from identified sites in same state and temperature group. b

Assumed that sites with estimated reservoir temperature ≥ 225oC were flash plants, otherwise assumed to be binary power plants. Dry steam plants not considered. c

Potential capacity based on median values by state in USGS 2008 Geothermal Resource Assessment. Capacity divided among temperature groups based on proportion of 

identified hydrothermal sites in state in each temperature group.
72 

Table B-3. Near-Hydrothermal Field EGS Resource

Site Name

Location Data GETEM Input - Reservoir Characteristics 

GETEM Output 

Base Cased Target Casee

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr

Adak AK N/A 9 155 1.52 Binary 12.6 $12,377 $889 $8,805 $291

Akutan Fumaroles AK N/A 9 250 1.52 Flash 48.7 $5,957 $377 $3,561 $144

Alvord HS OR 11 9 135 1.22 Binary 21.2 $15,790 $1,291 $11,145 $317

Amedee CA 13 10 115 0.46 Binary 8.7 $23,092 $2,167 $16,757 $479

Arrowhead HS CA 13 10 115 1.37 Binary 7.7 $25,506 $2,692 $19,537 $538

Bailey Bay Hot Springs AK N/A 9 125 1.52 Binary 21.4 $19,863 $1,840 $14,476 $378

Baker Hot Spring WA 11 9 115 1.52 Binary 24.5 $25,143 $2,656 $19,334 $466

Baltazor Hot Springs NV 11 8 140 1.07 Binary 21.6 $14,429 $1,074 $10,065 $296

Bell Island HS AK N/A 9 120 1.52 Binary 13.0 $22,402 $2,273 $16,869 $448

Beowawe HS NV 11 8 215 2.44 Binary 44.7 $8,072 $486 $5,026 $159

Big Creek Hot Springs ID 11 8 135 1.52 Binary 25.9 $16,204 $1,364 $11,487 $313

Black Rock Point area NV 11 8 120 1.52 Binary 11.0 $22,517 $2,292 $16,979 $460

Black Warrior NV 11 8 135 1.52 Binary 19.7 $16,324 $1,382 $11,600 $325

Blue Mountain NV 11 8 205 0.91 Binary 70.1 $7,108 $396 $4,692 $155

Boyes HS CA 13 10 110 1.52 Binary 10.3 $29,272 $3,502 $23,729 $602

Bradfield Canal Hot 

Spring AK N/A 9 110 1.52 Binary 9.1 $29,355 $3,523 $23,829 $613

Brady HS NV 11 8 185 0.30 Binary 31.6 $8,484 $475 $5,780 $205

Breitenbush Hot Springs OR 11 9 150 2.13 Binary 4.6 $15,636 $1,240 $11,645 $400

Butte Springs (Trego) NV 11 8 115 1.52 Binary 9.2 $25,701 $2,762 $19,916 $532

Calistoga HS CA 13 10 140 1.52 Binary 18.5 $15,120 $1,187 $10,616 $309

Canby (I'SOT) CA 13 10 120 1.52 Binary 10.5 $22,550 $2,297 $17,009 $463

Carson Lake Corral NV 11 8 125 1.52 Binary 13.8 $20,088 $1,876 $14,695 $402

Carson River CA 13 10 145 1.52 Binary 19.2 $13,964 $1,052 $9,787 $291
73 

Site Name

Location Data GETEM Input - Reservoir Characteristics 

GETEM Output 

Base Cased Target Casee

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr

Clark Ranch OR 11 9 110 1.52 Binary 8.6 $29,408 $3,534 $23,884 $619

Clear Lake (Sulphur Bank 

mine) CA 13 10 300 3.66 Flash 15.9 $6,745 $456 $4,228 $185

Clifton Hot Springs AZ 12 8 110 1.52 Binary 28.1 $28,732 $3,392 $23,142 $533

Colado area NV 11 8 110 1.07 Binary 12.8 $27,614 $3,090 $21,494 $547

Coso area CA 13 10 285 1.52 Flash 273.7 $4,446 $270 $2,588 $100

Cove Fort - Sulphurdale -

Liquid UT 11 8 150 0.76 Binary 20.9 $12,116 $806 $8,568 $274

Cove Fort - Sulphurdale -

Vapor UT 11 8 155 0.76 Binary 1.1 $17,944 $1,335 $14,117 $625

Crane Creek-Cove Creek 

area

ID 11 8 150 3.05 Binary 76.3 $15,006 $1,254 $10,490 $246

Crump's HS OR 11 9 150 1.52 Binary 51.8 $12,515 $876 $8,864 $245

Dann Ranch Hot Spring NV 11 8 140 1.52 Binary 34.6 $14,864 $1,150 $10,382 $282

Darrough Hot Springs NV 11 8 120 0.61 Binary 13.5 $20,475 $1,842 $14,753 $412

Deer Creek Hot Spring 

(old 97) ID 11 8 125 1.83 Binary 20.2 $20,704 $1,995 $15,221 $390

Desert Peak NV 11 8 215 1.68 Binary 18.9 $7,645 $452 $4,953 $189

Dixie Hot Springs NV 11 8 130 2.90 Binary 9.8 $22,384 $2,405 $16,822 $431

Dixie Valley Geothermal 

Field NV 11 8 225 1.52 Flash 95.2 $7,303 $424 $4,327 $126

Dixie Valley Power 

Partners NV 11 8 280 1.52 Flash 66.0 $4,739 $299 $2,818 $119

Double Hot Springs area NV 11 8 120 1.52 Binary 11.4 $22,489 $2,287 $16,952 $457

Dulbi AK N/A 9 110 1.52 Binary 11.7 $29,172 $3,483 $23,640 $591

Dunes CA 13 10 145 1.07 Binary 22.8 $13,343 $953 $9,286 $279

Dyke Hot Springs area NV 11 8 110 1.52 Binary 6.1 $29,991 $3,610 $24,319 $657
74 

Site Name

Location Data GETEM Input - Reservoir Characteristics 

GETEM Output 

Base Cased Target Casee

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr

East Brawley CA 13 10 285 3.05 Flash 273.1 $5,246 $336 $3,014 $94

East Mesa (Deep) CA 13 10 190 1.52 Binary 46.6 $8,522 $495 $5,774 $187

East Mesa (Shallow) CA 13 10 165 1.07 Binary 127.6 $10,316 $627 $6,989 $196

Emigrant NV 11 8 165 2.44 Binary 50.3 $11,844 $849 $8,066 $218

Ennis (Thexton) Hot 

Springs MT 11 8 115 1.52 Binary 18.0 $25,296 $2,681 $19,471 $483

Fallon Naval Air Station NV 11 8 195 2.13 Binary 60.5 $8,627 $530 $5,662 $172

Fernley area (Patua 

HS/Hazen) NV 11 8 155 1.68 Binary 23.3 $12,257 $873 $8,653 $263

Fish Lake Valley NV 11 8 205 1.52 Binary 62.6 $7,469 $429 $4,897 $158

Fort Bidwell CA 13 10 110 0.76 Binary 8.7 $26,948 $2,912 $20,547 $556

Geyser Bight AK N/A 9 182 1.52 Binary 79.7 $9,094 $536 $6,233 $185

Geysers CA 13 10 242 1.83 Flash 240.1 $6,392 $378 $3,763 $114

Geysers Hi T Reservoir CA 13 10 315 1.83 Flash 273.4 $3,964 $236 $2,271 $96

Gillard (Morenci) Hot 

Springs AZ 12 8 110 1.52 Binary 15.8 $28,984 $3,444 $23,428 $568

Goddard Hot Springs AK N/A 9 135 1.52 Binary 18.2 $16,361 $1,388 $11,632 $329

Great Boiling Springs 

(Gerlach) NV 11 8 175 0.61 Binary 50.0 $9,277 $542 $6,212 $198

Great Sitkin Island AK N/A 9 130 1.52 Binary 17.4 $17,987 $1,597 $12,929 $357

Gregson (Fairmont) Hot 

Springs MT 11 8 110 1.52 Binary 8.6 $29,407 $3,533 $23,883 $619

Heber Deep CA 13 10 205 1.22 Binary 26.5 $7,455 $437 $4,965 $184

Heber Shallow CA 13 10 170 1.22 Binary 83.8 $9,944 $611 $6,731 $192

Hot (Borax) Lake OR 11 9 150 1.52 Binary 40.5 $12,588 $887 $8,925 $253

Hot Springs Bay (Akutan 

Island) AK N/A 9 130 1.52 Binary 16.4 $18,018 $1,602 $12,959 $360
75 

Site Name

Location Data GETEM Input - Reservoir Characteristics 

GETEM Output 

Base Cased Target Casee

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr

Hot Springs Cove AK N/A 9 110 1.52 Binary 4.8 $30,552 $3,673 $24,896 $693

Hot Springs Ranch 

(Pumpernickel Valley) NV 11 8 125 1.52 Binary 13.8 $20,087 $1,876 $14,694 $402

Hot Sulphur Springs -

Tuscarora NV 11 8 155 0.76 Binary 21.8 $11,466 $749 $8,034 $260

Huckleberry Hot Springs WY 11 8 120 1.52 Binary 60.0 $21,805 $2,170 $16,235 $375

Humboldt House - Rye 

Patch NV 11 8 205 0.91 Binary 54.8 $7,144 $404 $4,727 $161

Jemez Springs (Ojos 

Calientes) NM 12 8 110 1.52 Binary 10.7 $29,239 $3,495 $23,698 $598

Kahneetah Hot Springs OR 11 9 115 1.07 Binary 7.0 $24,849 $2,519 $18,671 $531

Kellog HS CA 13 10 110 1.52 Binary 5.9 $30,066 $3,619 $24,396 $662

Kelly HS CA 13 10 120 1.83 Binary 10.4 $23,472 $2,494 $17,956 $477

Kluichef - Atka Island AK N/A 9 230 1.52 Flash 42.9 $7,132 $449 $4,275 $162

Korovin - Atka Island AK N/A 9 170 1.52 Binary 25.6 $10,481 $691 $7,186 $229

Lake City Hot Springs CA 13 10 160 1.52 Binary 81.3 $11,246 $724 $7,714 $211

Lakeview area (Hunters 

and Barry Ranch Hot 

Springs)

OR 11 9 135 1.07 Binary 20.9 $15,621 $1,253 $10,977 $315

Latty Hot Springs ID 11 8 110 1.52 Binary 8.1 $29,498 $3,545 $23,941 $625

Leach HS NV 11 8 120 1.52 Binary 5.7 $23,516 $2,405 $17,835 $525

Lee Hot Springs NV 11 8 150 1.52 Binary 31.7 $12,679 $897 $9,005 $262

Leonards Hot 

Sps./Seyferth HS CA 13 10 125 1.52 Binary 9.8 $20,342 $1,913 $14,932 $426

Lightning Dock NM 12 8 130 2.74 Binary 18.6 $21,331 $2,219 $15,791 $384

Little Valley area OR 11 9 125 1.07 Binary 17.3 $19,137 $1,678 $13,682 $376
76 

Site Name

Location Data GETEM Input - Reservoir Characteristics 

GETEM Output 

Base Cased Target Casee

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr

Long Valley caldera -

deep CA 13 10 205 3.05 Binary 25.0 $9,392 $665 $5,932 $188

Long Valley shallow CA 13 10 175 3.05 Binary 10.3 $12,772 $985 $8,674 $272

Maazama Well (Crater 

Lake) OR 11 9 140 3.05 Binary 41.6 $18,281 $1,695 $12,926 $297

Magic Reservoir area ID 11 8 110 1.22 Binary 11.1 $28,220 $3,227 $22,243 $570

Makushin AK N/A 9 205 1.52 Binary 68.8 $7,451 $427 $4,881 $155

McLeod 88 (Big Smokey 

Valley) NV 11 8 120 1.52 Binary 11.8 $22,471 $2,284 $16,933 $455

Medicine Lake (Glass 

Mt.) CA 13 10 255 2.74 Flash 264.3 $6,321 $398 $3,690 $105

Mickey HS OR 11 9 170 1.07 Binary 37.3 $10,007 $625 $6,811 $215

Milky River - Atka Island AK N/A 9 245 1.52 Flash 52.8 $6,169 $386 $3,684 $141

Mitchell Butte OR 11 9 120 1.07 Binary 13.2 $21,366 $2,043 $15,696 $429

Mt. Signal CA 13 10 135 1.52 Binary 10.2 $16,702 $1,440 $11,987 $363

Neal HS OR 11 9 150 1.07 Binary 36.5 $12,178 $818 $8,595 $254

Newberry Caldera OR 11 9 275 2.13 Flash 112.5 $5,014 $308 $2,914 $100

Newcastle area UT 11 8 110 0.76 Binary 14.5 $26,601 $2,848 $20,204 $517

North Brawley CA 13 10 250 1.52 Flash 92.9 $5,810 $341 $3,433 $114

Olene Hot Springs OR 11 9 110 1.52 Binary 9.9 $29,297 $3,509 $23,759 $605

Owl Creek Hot Springs ID 11 8 110 1.83 Binary 9.6 $30,695 $3,834 $25,481 $636

Pilgrim Hot Springs AK N/A 9 140 1.22 Binary 18.9 $14,661 $1,113 $10,262 $304

Pinto Hot Springs NV 11 8 145 1.52 Binary 26.0 $13,826 $1,034 $9,663 $278

Puna Geothermal Venture HI N/A 9 350 1.07 Flash 139.2 $3,327 $212 $1,899 $100

Raft River ID 11 8 145 1.83 Binary 47.9 $14,071 $1,076 $9,794 $259

Railroad Valley NV 11 8 135 1.52 Binary 19.9 $16,320 $1,381 $11,597 $325
77 

Site Name

Location Data GETEM Input - Reservoir Characteristics 

GETEM Output 

Base Cased Target Casee

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr

Reese River NV 11 8 135 0.76 Binary 19.9 $15,267 $1,182 $10,690 $313

Roosevelt HS UT 11 8 250 1.22 Flash 74.5 $5,720 $339 $3,389 $123

Routt CO 12 8 110 1.52 Binary 10.0 $29,292 $3,508 $23,752 $605

Rowland Hot Springs NV 11 8 110 1.52 Binary 6.8 $29,802 $3,583 $24,117 $642

Salton Sea area CA 13 10 310 2.29 Flash 1,773.8 $4,225 $253 $2,408 $95

San Emidio Desert area NV 11 8 190 1.07 Binary 51.3 $8,250 $472 $5,585 $184

Serpentine (Arctic) 

Springs AK N/A 9 145 1.52 Binary 22.9 $13,885 $1,041 $9,716 $283

Sespe HS CA 13 10 120 1.52 Binary 12.7 $22,415 $2,275 $16,881 $450

Sharkey Hot Springs ID 11 8 115 1.83 Binary 12.8 $26,629 $2,956 $20,887 $525

Silver Star (Barkel's) Hot 

Springs MT 11 8 115 1.52 Binary 11.4 $25,543 $2,732 $19,737 $514

Sitka Hot Spring AK N/A 9 125 1.52 Binary 15.7 $20,006 $1,864 $14,615 $394

Smith Creek Valley area NV 11 8 125 1.83 Binary 14.6 $20,873 $2,023 $15,410 $408

Soda Lake area NV 11 8 205 1.37 Binary 33.5 $7,503 $439 $4,963 $176

Sonoma Mission Inn CA 13 10 110 1.52 Binary 7.0 $29,746 $3,576 $24,087 $639

South Brawley (Mesquite) CA 13 10 250 3.05 Flash 37.1 $7,305 $494 $4,376 $161

Squaw Hot Springs area ID 11 8 130 1.52 Binary 20.2 $17,909 $1,586 $12,854 $349

Steamboat Hills NV 11 8 210 1.52 Binary 20.9 $7,634 $446 $4,969 $189

Steamboat Springs NV 11 8 165 1.52 Binary 9.8 $11,475 $796 $8,035 $285

Stillwater area NV 11 8 160 1.01 Binary 43.8 $10,970 $681 $7,517 $226

Sulphur Hot Springs 

(Ruby Valley) NV 11 8 165 1.83 Binary 39.7 $11,151 $752 $7,641 $223

Summer Lake Hot Springs OR 11 9 110 1.01 Binary 9.9 $27,577 $3,074 $21,434 $563

Surprise Valley HS CA 13 10 115 1.52 Binary 8.7 $25,767 $2,771 $19,967 $537
78 

Site Name

Location Data GETEM Input - Reservoir Characteristics 

GETEM Output 

Base Cased Target Casee

State NEMS 

Region

MARKAL 

Region

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Potential 

Capacityc

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr

Tecopa HS CA 13 10 120 1.52 Binary 10.1 $22,576 $2,302 $17,039 $467

The Needles (Needle 

Rocks, Pyramid Lake) NV 11 8 120 1.07 Binary 19.0 $21,164 $2,012 $15,527 $408

Thermo Hot Springs UT 11 8 125 0.76 Binary 16.8 $18,597 $1,570 $13,206 $370

Tolvana AK N/A 9 110 1.52 Binary 22.4 $28,819 $3,410 $23,241 $546

Trout Creek OR 11 9 115 0.91 Binary 11.4 $23,903 $2,357 $17,797 $481

Tungsten Mountain NV 11 8 125 1.52 Binary 14.6 $20,050 $1,871 $14,658 $399

Upper Division Hot 

Spring AK N/A 9 110 1.52 Binary 8.5 $29,419 $3,535 $23,891 $619

Vale HS OR 11 9 145 1.07 Binary 40.4 $13,156 $925 $9,104 $257

Valles Caldera - Redondo NM 12 8 275 3.35 Flash 84.2 $5,937 $391 $3,423 $102

Valles Caldera - Sulphur 

Springs NM 12 8 225 3.35 Flash 33.8 $9,608 $676 $5,757 $167

Vulcan Hot Springs ID 11 8 115 1.52 Binary 12.1 $25,505 $2,724 $19,693 $510

Wabuska Hot Springs NV 11 8 115 1.52 Binary 10.1 $25,637 $2,748 $19,834 $524

Waunita Hot Springs CO 12 8 120 1.52 Binary 14.5 $22,332 $2,262 $16,793 $441

Wayland (Battle Creek) 

Hot Springs ID 11 8 130 1.83 Binary 19.9 $18,602 $1,713 $13,470 $356

Wedell Hot Spring 

(Gabbs) NV 11 8 140 1.52 Binary 21.9 $15,040 $1,175 $10,545 $301

Wendel CA 13 10 125 1.52 Binary 12.7 $20,140 $1,884 $14,746 $407

West Ukinrek Maar AK N/A 9 200 1.52 Binary 21.5 $7,997 $491 $5,353 $198

West Valley Reservoir CA 13 10 130 1.83 Binary 13.6 $18,825 $1,746 $13,668 $378

White Licks Hot Springs ID 11 8 110 1.22 Binary 11.2 $28,217 $3,226 $22,237 $569

Wilbur Springs CA 13 10 160 1.07 Binary 32.1 $11,090 $701 $7,636 $236 a

Reservoir temperature and depth for near-hydrothermal field resource were assumed to be same as for identified resource at same site. b

Assumed that sites with estimated reservoir temperature ≥ 225oC were flash plants, otherwise assumed to be binary power plants. Dry steam plants not considered.
79 

c

Potential capacity assumed to be difference between USGS 2008 Geothermal Resource Assessment 90%ile value and median value for identified hydrothermal resource at site. d

Base case assumes production well flow rate of 30 kg/s, 3.0%/year thermal drawdown rate, and 2:1 producer/injector ratio for all sites. e

Target case assumes production well flow rate of 60 kg/s, 0.3%/year thermal drawdown rate, and 2:1 producer/injector ratio for all sites.
80 

Table B-4. Deep EGS Resource – Capital and O&M Costs

Site ID

Deep EGS Resource GETEM Input -Reservoir 

Characteristics 

GETEM Output 

Base Casec Target Cased

Reservoir 

Temp 

Range

Reservoir 

Depth 

Range

Potential 

Capacity

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km MWe oC km Binary/ 

Flash 

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr 

4k-150C 150-200 3-4 91,516 162.5 4.0 Binary $15,684 $1,615 $10,756 $317

5k-150C 150-200 4-5 589,759 162.5 5.0 Binary $20,295 $2,352 $13,410 $334

6k-150C 150-200 5-6 1,135,509 162.5 6.0 Binary $27,566 $3,551 $17,812 $358

7k-150C 150-200 6-7 1,332,595 162.5 7.0 Binary $39,720 $5,526 $24,867 $396

8k-150C 150-200 7-8 1,534,312 162.5 8.0 Binary $59,604 $8,773 $36,427 $460

9k-150C 150-200 8-9 1,870,329 162.5 9.0 Binary $92,413 $14,156 $55,756 $554

10k-150C 150-200 9-10 1,892,385 162.5 10.0 Binary $146,512 $23,017 $88,610 $749

4k-200C 200-250 3-4 117 212.5 4.0 Binary $10,221 $908 $6,438 $223

5k-200C 200-250 4-5 26,526 212.5 5.0 Binary $13,206 $1,284 $7,942 $228

6k-200C 200-250 5-6 227,962 212.5 6.0 Binary $17,873 $1,895 $10,383 $236

7k-200C 200-250 6-7 721,864 212.5 7.0 Binary $25,651 $2,894 $14,372 $248

8k-200C 200-250 7-8 1,124,638 212.5 8.0 Binary $38,185 $4,521 $21,012 $285

9k-200C 200-250 8-9 1,155,241 212.5 9.0 Binary $58,574 $7,176 $31,965 $347

10k-200C 200-250 9-10 1,247,675 212.5 10.0 Binary $91,896 $11,500 $50,046 $447

4k-250C 250-300 3-4 0 272.5 4.0 Flash $8,367 $752 $4,997 $220

5k-250C 250-300 4-5 134 272.5 5.0 Flash $11,133 $1,044 $6,304 $222

6k-250C 250-300 5-6 7,680 272.5 6.0 Flash $15,322 $1,519 $8,427 $225

7k-250C 250-300 6-7 86,056 272.5 7.0 Flash $22,370 $2,290 $11,950 $236

8k-250C 250-300 7-8 345,193 272.5 8.0 Flash $33,750 $3,551 $17,799 $268

9k-250C 250-300 8-9 760,475 272.5 9.0 Flash $52,194 $5,608 $27,262 $319

10k-250C 250-300 9-10 1,012,359 272.5 10.0 Flash $82,542 $8,959 $42,887 $402
81 

Site ID

Deep EGS Resource GETEM Input -Reservoir 

Characteristics 

GETEM Output 

Base Casec Target Cased

Reservoir 

Temp 

Range

Reservoir 

Depth 

Range

Potential 

Capacity

Reservoir 

Tempa

Reservoir 

Deptha

Plant 

Typeb

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km MWe oC km Binary/ 

Flash 

2008 

US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr 

4k-300C 300-350 3-4 0 312.5 4.0 Flash $6,218 $541 $3,730 $202

5k-300C 300-350 4-5 0 312.5 5.0 Flash $8,132 $711 $4,637 $203

6k-300C 300-350 5-6 50 312.5 6.0 Flash $11,177 $1,003 $6,123 $205

7k-300C 300-350 6-7 630 312.5 7.0 Flash $16,195 $1,477 $8,516 $207

8k-300C 300-350 7-8 32,964 312.5 8.0 Flash $24,306 $2,250 $12,579 $228

9k-300C 300-350 8-9 138,203 312.5 9.0 Flash $37,524 $3,513 $19,185 $261

10k-300C 300-350 9-10 433,329 312.5 10.0 Flash $59,140 $5,571 $29,944 $317

4k-350C 350+ 3-4 0 362.5 4.0 Flash $4,923 $452 $2,947 $189

5k-350C 350+ 4-5 0 362.5 5.0 Flash $6,190 $548 $3,612 $187

6k-350C 350+ 5-6 0 362.5 6.0 Flash $8,449 $751 $4,715 $186

7k-350C 350+ 6-7 0 362.5 7.0 Flash $12,151 $1,081 $6,531 $187

8k-350C 350+ 7-8 321 362.5 8.0 Flash $18,154 $1,618 $9,579 $202

9k-350C 350+ 8-9 9,922 362.5 9.0 Flash $27,944 $2,497 $14,508 $226

10k-350C 350+ 9-10 69,299 362.5 10.0 Flash $43,985 $3,928 $22,560 $266 a

Deep EGS reservoir assumed to have temperature 12.5oC above low end of temperature range and that reservoir extended to total depth of depth range. b

Assumed that sites with estimated reservoir temperature ≥225oC were flash plants, otherwise assumed to be binary power plants. Dry steam plants not considered. c

Base case assumes production well flow rate of 30 kg/s, 3.0%/year thermal drawdown rate, and 2:1 producer/injector ratio for all sites. d

Target case assumes production well flow rate of 60 kg/s, 0.3%/year thermal drawdown rate, and 2:1 producer/injector ratio for all sites.
82 

Table B-5. Deep EGS Resource – Potential Capacity by MARKAL Region (see Figure B-1) 

Potential Deep EGS Capacity (MWe) 

Site ID MARKAL Region Total

1 2 3 4 5 6 7 8 9 10 

4k-150C 0 0 0 0 0 0 0 65,854 15,207 10,454 91,516

5k-150C 0 0 0 15,194 0 2,459 67,122 378,969 81,749 44,266 589,759

6k-150C 0 535 0 70,584 1,046 26,408 166,077 670,108 119,380 81,371 1,135,509

7k-150C 1,923 6,458 6,444 276,637 17,319 58,832 253,740 569,521 77,735 63,985 1,332,595

8k-150C 52,513 26,654 143,677 393,478 90,545 86,818 306,251 363,357 29,107 41,912 1,534,312

9k-150C 78,562 58,357 247,530 518,104 167,156 168,782 350,729 228,807 10,197 42,107 1,870,329

10k-150C 82,955 83,918 337,181 396,268 251,569 194,338 341,707 150,833 14,130 39,486 1,892,385

4k-200C 0 0 0 0 0 0 0 117 0 0 117

5k-200C 0 0 0 0 0 0 0 17,327 5,126 4,073 26,526

6k-200C 0 0 0 0 0 0 0 177,456 32,378 18,129 227,962

7k-200C 0 0 0 14,772 0 1,280 49,792 497,801 97,907 60,312 721,864

8k-200C 0 243 0 61,202 2,554 14,590 162,451 665,738 130,397 87,462 1,124,638

9k-200C 176 2,674 575 124,954 7,874 46,318 240,455 569,892 97,110 65,213 1,155,241

10k-200C 4,191 12,478 9,461 349,548 26,555 71,146 250,251 443,399 40,006 40,640 1,247,675

4k-250C 0 0 0 0 0 0 0 0 0 0 0 

5k-250C 0 0 0 0 0 0 0 134 0 0 134

6k-250C 0 0 0 0 0 0 0 4,683 0 2,997 7,680

7k-250C 0 0 0 0 0 0 0 64,258 13,821 7,977 86,056

8k-250C 0 0 0 0 0 0 318 271,389 46,116 27,370 345,193

9k-250C 0 0 0 3,993 0 141 24,227 561,951 105,176 64,987 760,475

10k-250C 0 0 0 37,429 1,911 6,318 124,685 622,328 134,025 85,661 1,012,359

4k-300C 0 0 0 0 0 0 0 0 0 0 0 

5k-300C 0 0 0 0 0 0 0 0 0 0 0 
83 

Potential Deep EGS Capacity (MWe) 

Site ID MARKAL Region Total

1 2 3 4 5 6 7 8 9 10 

6k-300C 0 0 0 0 0 0 0 50 0 0 50

7k-300C 0 0 0 0 0 0 0 630 0 0 630

8k-300C 0 0 0 0 0 0 0 21,398 7,094 4,471 32,964

9k-300C 0 0 0 0 0 0 0 104,947 21,904 11,352 138,203

10k-300C 0 0 0 0 0 0 719 342,102 56,220 34,289 433,329

4k-350C 0 0 0 0 0 0 0 0 0 0 0 

5k-350C 0 0 0 0 0 0 0 0 0 0 0 

6k-350C 0 0 0 0 0 0 0 0 0 0 0 

7k-350C 0 0 0 0 0 0 0 0 0 0 0 

8k-350C 0 0 0 0 0 0 0 321 0 0 321

9k-350C 0 0 0 0 0 0 0 5,887 0 4,035 9,922

10k-350C 0 0 0 0 0 0 0 47,772 13,767 7,760 69,299
84 

Figure B-1. Map of MARKAL regions. 
85 

Table B-6. Deep EGS Resource – Resource Potential by NEMS Region (see Figure B-2) 

Potential Deep EGS Capacity (MWe) 

Site ID NEMS Region Total

1 2 3 4 5 6 7 8 9 10 11 12 13 

4k-150C 0 0 0 0 0 0 0 0 0 0 58,329 22,732 10,455 91,515

5k-150C 0 30,262 0 0 19,933 0 0 0 26,845 12,225 281,671 174,554 44,268 589,758

6k-150C 0 94,493 535 0 98,005 0 0 567 78,802 19,218 502,163 260,622 80,921 1,135,326

7k-150C 4,980 144,637 4,390 5,370 226,096 2,185 1,924 2,222 121,441 135,712 436,783 183,908 62,808 1,332,455

8k-150C 67,877 143,271 14,116 121,429 254,053 10,640 52,581 3,221 227,008 218,081 256,540 124,632 40,663 1,534,111

9k-150C 211,615 161,434 26,549 145,232 310,955 26,539 78,722 6,625 341,194 284,284 143,299 92,858 41,291 1,870,598

10k-150C 258,551 158,907 38,188 173,771 274,768 44,208 83,142 36,944 412,370 224,182 89,451 59,532 39,050 1,893,064

4k-200C 0 0 0 0 0 0 0 0 0 0 117 0 0 117

5k-200C 0 0 0 0 0 0 0 0 0 0 13,152 9,301 4,073 26,526

6k-200C 0 0 0 0 0 0 0 0 0 0 142,214 67,618 18,127 227,960

7k-200C 0 12,705 0 0 18,299 0 0 0 24,495 12,982 359,777 233,288 60,310 721,855

8k-200C 2,332 86,735 466 0 83,256 0 0 0 71,264 17,832 515,324 260,311 86,972 1,124,492

9k-200C 5,607 129,386 3,116 575 151,520 0 176 911 115,192 54,998 456,637 172,743 64,089 1,154,948

10k-200C 11,365 135,438 7,168 7,910 276,010 4,448 4,193 2,574 130,833 173,014 310,525 144,707 39,317 1,247,501

4k-250C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

5k-250C 0 0 0 0 0 0 0 0 0 0 134 0 0 134

6k-250C 0 0 0 0 0 0 0 0 0 0 498 4,185 2,997 7,680

7k-250C 0 0 0 0 0 0 0 0 0 0 48,919 29,156 7,981 86,056

8k-250C 0 318 0 0 0 0 0 0 0 0 199,295 118,215 27,364 345,193

9k-250C 0 8,002 0 0 5,627 0 0 0 8,743 6,333 406,726 260,129 64,948 760,508

10k-250C 1,827 55,361 84 0 48,339 0 0 0 55,253 18,917 505,150 242,048 85,296 1,012,276

4k-300C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

5k-300C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

6k-300C 0 0 0 0 0 0 0 0 0 0 50 0 0 50
86 

Potential Deep EGS Capacity (MWe) 

Site ID NEMS Region Total

1 2 3 4 5 6 7 8 9 10 11 12 13 

7k-300C 0 0 0 0 0 0 0 0 0 0 431 199 0 630

8k-300C 0 0 0 0 0 0 0 0 0 0 17,428 11,064 4,471 32,964

9k-300C 0 0 0 0 0 0 0 0 0 0 83,644 43,205 11,354 138,203

10k-300C 0 717 0 0 0 0 0 0 0 0 240,487 157,849 34,287 433,339

4k-350C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

5k-350C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

6k-350C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

7k-350C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

8k-350C 0 0 0 0 0 0 0 0 0 0 321 0 0 321

9k-350C 0 0 0 0 0 0 0 0 0 0 956 4,931 4,035 9,922

10k-350C 0 0 0 0 0 0 0 0 0 0 37,988 23,550 7,760 69,299
87 

Figure B-2. Map of NEMS regions. 
88 

Table B-7. Tabulated GETEM Input and Output for Hypothetical Hydrothermal Sites in Figure 15

Site ID

GETEM Input - Reservoir Characteristics GETEM Output 

Reservoir 

Temp

Reservoir 

Depth

Production 

Well Flow 

Rate

Plant 

Typea

Net Plant 

Output

Capital 

Cost O&M Cost

o

C km (kg/s) Binary/ 

Flash MWe

2008 

US$/kW 

2008 

US$/kW/yr 

1k-150C 150 1.0 44.2 Binary 20.0 $7,461 $278

2k-150C 150 2.0 44.2 Binary 20.0 $8,410 $268

3k-150C 150 3.0 44.2 Binary 20.0 $10,096 $261

1k-200C 200 1.0 44.2 Binary 20.0 $4,481 $203

2k-200C 200 2.0 44.2 Binary 20.0 $4,997 $187

3k-200C 200 3.0 44.2 Binary 20.0 $5,983 $186

1k-250C 250 1.0 44.2 Flash 20.0 $3,323 $219

2k-250C 250 2.0 44.2 Flash 20.0 $3,718 $206

3k-250C 250 3.0 44.2 Flash 20.0 $4,441 $187

1k-300C 300 1.0 44.2 Flash 20.0 $2,697 $212

2k-300C 300 2.0 44.2 Flash 20.0 $2,968 $202

3k-300C 300 3.0 44.2 Flash 20.0 $3,416 $190 a

Assumed that sites with estimated reservoir temperature ≥225oC were flash plants, otherwise assumed to be binary power 

plants. Dry steam plants not considered.
89 

Table B-8. Tabulated GETEM Input and Output for Hypothetical Near-Hydrothermal Field EGS Sites in Figure 16 and Figure 17

Site ID

GETEM Input - Reservoir Characteristics GETEM Output 

Base Casea Target Caseb

Reservoir 

Temp

Reservoir 

Depth

Plant 

Type

Net Plant 

Ouput

Capital 

Cost O&M Cost Capital Cost O&M Cost

o

C km Binary/ 

Flash MWe 2008 US$/kW 

2008 

US$/kW/yr 

2008 

US$/kW 

2008 

US$/kW/yr 

1k-150C 150 1.0 Binary 20.0 $12,243 $844 $8,749 $277

2k-150C 150 2.0 Binary 20.0 $13,416 $1,030 $9,584 $284

3k-150C 150 3.0 Binary 20.0 $15,430 $1,314 $10,915 $294

1k-200C 200 1.0 Binary 20.0 $7,639 $470 $5,188 $200

2k-200C 200 2.0 Binary 20.0 $8,446 $550 $5,580 $201

3k-200C 200 3.0 Binary 20.0 $9,785 $702 $6,247 $202

1k-250C 250 1.0 Flash 20.0 $6,315 $445 $3,975 $219

2k-250C 250 2.0 Flash 20.0 $6,794 $493 $4,293 $216

3k-250C 250 3.0 Flash 20.0 $7,717 $570 $4,814 $213

1k-300C 300 1.0 Flash 20.0 $4,929 $370 $3,109 $210

2k-300C 300 2.0 Flash 20.0 $5,224 $389 $3,295 $205

3k-300C 300 3.0 Flash 20.0 $5,833 $428 $3,629 $202 a

Base case assumes production well flow rate of 30 kg/s, 3.0%/year thermal drawdown rate, and 2:1 producer/injector ratio for all sites. b

Target case assumes production well flow rate of 60 kg/s, 0.3%/year thermal drawdown rate, and 2:1 producer/injector ratio for all sites.