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

Geothermal FIT Design: 

International Experience and 

U.S. Considerations

Wilson Rickerson

Meister Consultants Group 

Jason Gifford and Robert Grace

Sustainable Energy Advantage, LLC

Karlynn Cory

National Renewable Energy Laboratory

Technical Report

NREL/TP- 6A20-53320

August 2012
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.

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Geothermal FIT Design: 

International Experience and 

U.S. Considerations

Wilson Rickerson

Meister Consultants Group 

Jason Gifford and Robert Grace

Sustainable Energy Advantage, LLC

Karlynn Cory

National Renewable Energy Laboratory

Prepared under Task No. GTP2.9153

Technical Report

NREL/TP- 6A20-53320

August 2012
NOTICE

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iii

Acknowledgments

This work was funded by the U.S. Department of Energy’s (DOE) Energy Efficiency and 

Renewable Energy (EERE) Division’s Geothermal Technologies Program. 

The authors wish to thank participating staff and team members for providing overall direction 

and useful insights for this project: Jay Nathwani of the EERE Geothermal Technology Program, 

Tom Williams and Chad Augustine from the National Renewable Energy Laboratory, and Kevin 

Porter of Exeter Associates. 

We would also like to thank the report’s peer reviewers for their expert advice and counsel: Jeff 

Logan and Paul Schwabe from NREL, Benjamin Miethling from RWE Innogy GmbH, and 

Edward Einowski from Stoel Rives LLP. 

We are also grateful for the assistance of several individuals who provided invaluable feedback 

during the research and development phases of this report, particularly Dr. David Jacobs (IFOK 

GmbH), Dr. Johann Goldbrunner (Geoteam Ges.m.b.H), Neil Veilleux and Chad Gordon 

(Meister Consultants Group), and Christina Dietrich. We offer our appreciation to Scott Gossett 

and Mary Lukkonen at NREL for providing editorial support.
iv

List of Acronyms

BMU Ministry for the Environment (Germany)

BMWI Ministry of Economy and Finance (Germany)

CHP combined heat and power

CREST Cost of Renewable Energy Spreadsheet Tool

D/E debt to equity

DSCR debt service coverage ratio

EEG Erneuerbare-Energien-Gesetz

EGS enhanced geothermal systems

EPAct Energy Policy Act

EU European Union

FERC Federal Energy Regulatory Commission

FIT feed-in tariff

GW gigawatt

IPP independent power provider

ITC Investment Tax Credit

kWh kilowatt-hour

LCOE levelized cost of energy

MW megawatt

NEA National Energy Act

NREL National Renewable Energy Laboratory

O&M operation and maintenance

PPA power purchase agreement

PTC Production Tax Credit

PURPA Public Utility Regulatory Policies Act

QF qualifying facility

REC renewable energy certificate

RFP request for proposal

ROE return on equity

RPS renewable portfolio standard

RTO regional transmission organization

SO4 Standard Offer No. 4

USGS U.S. Geological Survey

WACC weighted average cost of capital
v

Executive Summary

Developing power plants is a risky endeavor, whether the plants utilize conventional or 

renewable generation technologies. Feed-in tariff (FIT) policies can be designed to address some 

risks specific to geothermal power plant development, although they have not been used in the 

United States to date. 

By April 2012, there were 11,224 megawatts (MW) of geothermal electric capacity installed in 

24 countries (Holm 2010; GEA 2012). The United States leads the world with 3,187 MW 

installed. Despite these statistics, the cumulative amount of geothermal electricity generating 

capacity installed in the United States has expanded slowly in recent years, increasing 

approximately 2.3% annually on average since 2008 (GEA 2012). During 2011 and the first 

quarter of 2012, the addition of two new geothermal plants and the expansion of three existing 

plants added 91 MW of new capacity.1 Geothermal market development faces a range of unique 

barriers related to the cost and uncertainty of resource exploration and confirmation drilling. In 

addition, geothermal projects face risks similar to other generation project development, 

including finding buyers for power, ensuring adequate transmission capacity, competing to 

supply electricity and/or renewable energy certificates (RECs), securing reliable revenue 

streams, navigating the legal issues related to project development, and reacting to changes in 

existing regulations or incentives. 

Instead of addressing all these risks and all the policies in the same analysis, this analysis focuses 

on the design of FIT incentive policies for geothermal electric projects and how FITs can be used 

to reduce risks other than the physical risk of drilling unproductive exploratory wells. The 

guarantee of a stable revenue stream over the life of the generation plant lowers the risk that 

large investments in exploration and development will not yield an off-take agreement. The 

combination of a guaranteed purchase, a pre-determined payment price, and a standardized offtake agreement can relieve some of the cost, risk, and pressure associated with overall project 

development since the project does not need to compete for or negotiate a contract before final 

project costs are known. Addressing exploration risk2 by incorporating some/all of the drilling 

costs in the FIT payment level can incentivize some amount of risk taking in the exploration 

phase. Policy risks should be considered too. The greatest risk associated with FITs—rapid and 

dramatic development in a timeframe too short to react and adjust—appears far less likely for 

geothermal projects due to: (1) longer development lead times and (2) geographic limitations on 

project locations. In short, policymakers should be able to see a problem coming with plenty of 

time to adjust. In sum, FIT policies can include risk-mitigating elements and can be tailored to 

support a few key financial risks of geothermal development. 

 1 In 2010, a single 15 MW project had been developed in the United States and was installed in Nevada (Jennejohn 

2011).

2 This study does not include a comprehensive look at policies that address exploration risks – just those that could 

be addressed in a FIT policy; another NREL study (underway in 2012) is examining specific policies that address 

exploration risks, specifically.
vi

Global Experience with FIT Incentives for Geothermal Electricity

FITs are currently the most common national renewable energy policy in the world and are in 

place in over 50 countries. Despite international interest in FITs, there has been a limited focus 

on geothermal FIT design specifically. This report represents the first in-depth attempt to explore 

how these policy elements could be aligned to support geothermal development. There are 

currently no geothermal FITs in North America, although the Public Utility Regulatory Policies 

Act (PURPA) of 1978, which contains elements similar to FIT policies, supported over 

1,300 MW of geothermal development by the end of the 1990s (Guey-Lee 1999). Around the 

world, 16 countries have established specific FIT incentives for geothermal. Based on a survey 

of international experience to date, we find that: 

• More than a dozen countries are experimenting with FIT policies that are specifically 

tailored for geothermal technologies. Countries have introduced FITs that target small 

scale geothermal plants, combined heat-and-power geothermal applications, specific 

types of geothermal resources (e.g., enhanced geothermal or low-temperature plants), 

specific geographies (e.g., islands), and domestic content. 

• Geothermal FIT payment levels vary widely across countries from $0.08/kilowatt-hour 

(kWh) in Uganda to $0.48/kWh in Switzerland (both for 20-year contracts). This range 

reflects resource differences, variations in local electricity prices, as well as different 

policy objectives (e.g., whether to support certain resource types) in different countries 

and different approaches to rate setting.

• There is a lack of empirical evidence about the impact of the varied FIT designs on 

market development. Geothermal market growth under FITs has been slow to date for a 

variety of reasons. These include the fact that many of the FITs are comparatively new, 

and that some of the prices are too low to support the comparatively poor quality, or 

expensive local resources. A key take-away from the international survey is that the 

presence of FITs alone has not driven results comparable to the results achieved for wind 

and solar power under European FITs, or to those achieved for geothermal under PURPA 

in the United States.

• A variety of rate-setting approaches are currently used.

o Examples in Germany and Spain demonstrate that the FIT rate-setting process can 

be used to reflect technology-specific risks and costs.

o Different approaches to FIT rate setting have been taken in different countries. 

FIT Policy Design to Support Geothermal Development in the United States

The report provides an in-depth, qualitative discussion on how FITs can be designed specifically 

to support geothermal power plant development in the United States. For comparative purposes, 

this report adopts investor security as a perspective for discussing each option in order to analyze 

the relationship between policy design and risk reduction.3

 

 3 In order to create the conditions for geothermal deployment, the perspectives of multiple stakeholders will need to 

be taken into account and appropriately balanced. These include, for example, end users and ratepayers, 
vii

The report identified key issues relating to geothermal FITs in the United States, listed in Table 

ES-1 below. Each policy design issue is evaluated based on its potential to lower investor risks.

Table ES-1. Summary of Geothermal FIT Design Issues and Options

Policy Design Issue Design Option Potential for Lowering Investor Risk

Integrating FITs with 

Geothermal Targets

Setting mandatory and specific targets for geothermal can improve investor 

confidence in a government’s commitment to geothermal procurement.

Technology 

Eligibility and 

Differentiation

The choice of eligibility or differentiation does not have direct impact on project 

risk. What matters from an investor risk perspective is whether the FIT rate 

available to geothermal generators of various sizes and types is sufficient to 

cover operating expenses and meet investors’ required returns. 

Incorporating 

Exploration 

Expense into FIT 

Rates

Accounting for exploration costs and risk when setting the FIT rate (i.e., by 

building exploration cost and probability of success assumptions into the rate 

setting model) can be an avenue for reducing investor risk and encouraging the 

flow of capital into geothermal development. Assurance of a financeable contract 

that enables the recovery of an estimate of incurred exploration expenses 

provides a signal to the market to invest, notwithstanding the fact that actual 

exploration experience is likely to differ from the estimate and that some 

exploration efforts will fail to produce a viable thermal resource.

Standard Pricing 

and Off-Take 

Contracts

FITs provide generators with standardized off-take contracts that can reduce 

power project risk and transaction costs. This has the potential to reduce investor 

return requirements and increase the pool of available capital.

Payment Structure Fixed FIT prices are lower risk (from the investors’ perspective) than payment 

streams that vary over time and are uncertain (Corfee et al. 2010).

Contract Duration To the extent that post-contract market revenue projections are utilized in setting 

a FIT payment level, longer contract durations reduce investor risk by reducing 

the proportion of lifetime revenues exposed to market price risk. If, however, FIT 

payments are designed to attain target investor returns prior to contract 

termination, investors should be indifferent to contract duration, all else being 

equal.

Policy and Contract 

Timing

The presence of a stable FIT policy that could be relied on for a period of several 

years by an early-stage, exploration-phase geothermal investor could decrease 

overall risk, thus reducing/eliminating developer risk premiums for request for 

proposal (RFP) bids.

Payment Indexing 

Over Time

Indexing payments to inflation, drilling costs, and/or other relevant indicators 

reduces the risk that project revenues will be inadequate.

Adjusting the Policy Adjustments that are made infrequently and on a schedule that is known in 

advance and using a process that is as transparent as possible increases 

investor confidence. 

 policymakers, and industry in addition to investors. A full multi-stakeholder analysis is beyond this scope of this 

report, however.
viii

Analyzing the Impact of Policy Design Choices on the Levelized Cost of Energy 

from Geothermal Electricity Generators

This report provides a quantitative analysis using the National Renewable Energy Laboratory’s

(NREL) Cost of Renewable Energy Spreadsheet Tool (CREST) model to illustrate policy design

impacts on the levelized cost of energy (LCOE) for geothermal electricity. The purpose of this 

analysis is not to determine the precise cost of a specific geothermal system. Rather, the analysis 

identifies considerations that can inform policymakers about how different FIT policy design 

choices can address some of the geothermal-specific risks that contribute to the LCOE, and thus 

how FIT design can be used to lower the LCOE of geothermal energy.

The quantitative analysis focuses on the interaction of FITs with several key variables: 

• Exploration success rate

• Duration of the confirmation stage

• Investor return requirements (equity and debt, if applicable) during each phase of 

development

• FIT contract duration

• The project’s total installed cost (including operations and maintenance costs).

The results show a connection between the investor return requirement, the amount of time it 

takes to complete a geothermal project (the amount of time this capital is deployed), and the 

LCOE. The impact that long-term, price-certain contracts with creditworthy counterparties have 

on project financing is also explored. Such contracts can help make project-level equity and debt 

more accessible and on more favorable terms. FIT designs that reduce revenue risk and contract 

price risk can reduce the associated investor risk and return requirements at each development 

phase. The availability of a long-term, price-certain FIT can shorten the geothermal development 

cycle by removing the need to compete for a power purchase agreement (PPA), which can also 

translate into a lower LCOE. Longer FIT contract durations can also achieve a lower LCOE. 

With regard to the impact of policy design on LCOE, this analysis shows that policies that

reduce the duration and return requirements of early-stage development activities will have the 

greatest impact. Increasing geothermal contract lengths and introducing mechanisms that reduce 

the cost of permanent equity and debt also have a significant impact on LCOE. The approach to 

setting payment levels under FIT policies (e.g., whether and how exploration and confirmation 

success and return requirements are taken into account when calculating payments) is also shown 

to have a direct and meaningful impact on geothermal LCOE.
ix

Table of Contents

List of Figures ............................................................................................................................................ xi

List of Tables ............................................................................................................................................. xii

1 Introduction........................................................................................................................................... 1

2 Overview of Geothermal Development Considerations and Risks................................................. 3

2.1 Overview of the U.S. Geothermal Market...........................................................................3

2.2 U.S. Geothermal Resources.................................................................................................4

2.3 Obstacles to Geothermal Power Plant Development...........................................................5

2.4 Addressing Geothermal Barriers and Risks Through Policy...............................................7

3 Global Experience with FIT Incentives for Geothermal Electricity................................................ 12

3.1 Defining FITs.....................................................................................................................12

3.2 FITs in North America.......................................................................................................13

3.3 International FITs...............................................................................................................14

3.3.1 FIT Payment Levels and Impacts by Country ..........................................................14

3.3.2 Lessons Learned from International FITs.................................................................18

3.3.3 Approaches to Setting FIT Payment Levels .............................................................20

4 FIT Design to Support Geothermal Development in the United States ........................................ 26

4.1 Integrating FITs with Geothermal Targets ........................................................................26

4.2 Technology Eligibility and Differentiation........................................................................26

4.3 Incorporating Exploration Expense in FIT Payment Levels..............................................27

4.4 Standard Pricing and Standardized Off-Take Contracts....................................................28

4.5 Payment Structure..............................................................................................................28

4.6 Contract Duration...............................................................................................................29

4.7 Policy and Contract Timing...............................................................................................30

4.8 Payment Indexing Over Time............................................................................................31

4.9 Adjusting the Policy...........................................................................................................31

4.10 Setting Geothermal FIT Payment Levels in the United States........................................32

5 Analyzing the Impact of Policy Design Choices on the Levelized Cost of Energy from 

Geothermal Electricity Generators ................................................................................................... 34

5.1 Using LCOE to Inform FIT Payment Level-Setting..........................................................34

5.2 Objectives: Understanding the Potential Impact of FIT Design Choices..........................34

5.3 Methodology: Literature Review and CREST Modeling ..................................................36

5.3.1 Literature Review......................................................................................................36

5.3.2 The CREST Model ...................................................................................................36

5.3.3 Enhancements to Geothermal CREST......................................................................36

5.3.4 Modeling the Phases of Geothermal Development and Financing...........................37

5.4 Inputs for Calculating Geothermal LCOE.........................................................................37

5.4.1 Exploration Success, Confirmation Duration, and Project Cost Inputs....................38

5.4.2 Financing Inputs........................................................................................................40

5.4.3 Other CREST Inputs Required for Calculating LCOE.............................................41

5.4.4 Explaining the Range of Possible Inputs..................................................................41

5.5 Reference Case Results......................................................................................................41
x

5.6 Sensitivity Analyses: LCOE Results and Lessons Learned...............................................41

5.6.1 Exploration Success Risk..........................................................................................42

5.6.2 Confirmation Drilling Risk.......................................................................................43

5.6.3 FIT Contract Duration...............................................................................................45

5.6.4 Installed Cost and Investor Return Requirements ....................................................46

5.7 Summary of LCOE Sensitivity Results .............................................................................48

6 Conclusions ........................................................................................................................................ 51

6.1 International Experience Provides Opportunity to Tailor Geothermal FITs 

to U.S. Market....................................................................................................................51

6.2 FIT Policy Design Provides Opportunities to Support Geothermal Deployment and 

Attract Additional Investment Capital into Geothermal Exploration and Development 

Activities............................................................................................................................51

6.3 FIT Policies can be Designed to Address Key Issues that Have a Significant Impact on 

LCOE: Confirmation Phase Duration and Equity Cost, Cost of Permanent Financing, and 

FIT Duration ......................................................................................................................52

References................................................................................................................................................. 53

Appendix A: Summary of Literature Review on U.S. Geothermal Costs ............................................ 63

Appendix B: Summary of Additional CREST Modeling Inputs ............................................................ 67

Appendix C: Geothermal Power Under PURPA..................................................................................... 68
xi

List of Figures

Figure 1. Cumulative installed U.S. geothermal electricity capacity (2008-First Quarter 2012)... 3

Figure 2. U.S. electricity generated by wind and geothermal plants (1999-2011)......................... 4

Figure 3. Comparison of FIT revenue NPV for 1-MW geothermal plant .................................... 19

Figure 4. Illustration of connection between exploration success and FIT payment setting........ 43

Figure 5. Sensitivity of LCOE to change in both confirmation duration and return requirement 45

Figure 6. Illustration of relationship between contract duration and LCOE................................. 46

Figure 7. Sensitivity of LCOE to change in cost of permanent financing, shown at three different 

levels of installed cost................................................................................................................... 48

Figure 8. Relative impact on LCOE (and thus FIT Payment Level) of each sensitivity analysis 49

Figure A-1. Range of exploration costs........................................................................................ 63

Figure A-2. Range of confirmation costs...................................................................................... 64

Figure A-3. Range of site development and construction costs.................................................... 64

Figure A-4. Range of total project costs (including exploration)................................................. 65

Figure A-5. Range of fixed O&M costs........................................................................................ 65

Figure A-6. Range of variable O&M costs................................................................................... 66

Figure C-1. Installed geothermal capacity under PURPA (MW)................................................. 68
xii

List of Tables

Table ES-1. Summary of Geothermal FIT Design Issues and Options........................................ vii

Table 1. Geothermal Electric FITs in the European Union (EU) ................................................. 16

Table 2. Geothermal Electric FITs in Non-EU Countries ............................................................ 17

Table 3. Size Categories and Tariff Payment Levels under Revised German EEG (2004) ......... 22

Table 4. Simplified Categories and Tariff Payment Levels for 2008 German EEG Revision ..... 22

Table 5. Key Parameters for Calculation of German FIT............................................................. 23

Table 6. Key Findings Regarding FIT Policy Design in the United States.................................. 33

Table 7. Range and Definition of Exploration Success Rate........................................................ 38

Table 8. Range of Confirmation Phase Duration.......................................................................... 39

Table 9. Range of Geothermal Cost Inputs................................................................................... 39

Table 10. Range of Geothermal Financing Inputs, by Development Phase ................................. 40

Table 11. Cost of Capital Assumptions for Lower and Higher Cost Sensitivity Analyses.......... 47

Table B-1. Project Size, Performance, and Development Inputs for LCOE Modeling................ 67
1

1 Introduction

Geothermal electricity4 represents a significant source of potential renewable electricity in the 

United States and it has several comparative advantages over other types of generation. 

Geothermal energy is a renewable resource that provides baseload, rather than intermittent, 

power at high availability and capacity factors (i.e., at or above 90%) (Green and Nix 2006). 

Geothermal power is a cost-effective alternative to non-renewable energy sources, primarily in 

western states where the strongest resource is concentrated, and has been used to effectively as a 

strategy to diversify state electricity portfolios since 1960 (Mines et al. 2010). However, 

developers of hydrothermal geothermal power plants face a unique and added challenge

compared to other renewable energy technologies. In addition to securing sites, permits, and 

contracts (all required to attract financing), geothermal developers also must find and confirm a 

commercially-exploitable thermal resource. The expense of drilling, and the potential to expend 

substantial capital without yielding a developable well, leaves geothermal developers with 

substantial exploration risk. Because of such project uncertainties, many geothermal resources 

remain undeveloped. The unique characteristics of geothermal electric development have 

important implications for effective policy design of geothermal projects.

This report explores how FITs have been, and can be, designed to account for the unique 

characteristics of geothermal project development, particularly reducing investor risk in the 

power plant. NREL is currently working on a separate report that explores policies to encourage 

geothermal exploration. This report explores international experience with geothermal FITs to 

date and discusses design considerations for geothermal FITs in the United States. The report 

uses NREL’s CREST5 to quantitatively examine the impacts and tradeoffs of different 

geothermal FIT designs. The analyses explore, for example, how different FIT designs can take 

development risk into account and the impact that reducing the cost of capital by decreasing 

investor risk could have on project economics. The report is organized as follows: 

• Section 2 provides a high level summary of U.S. geothermal energy, including 

geothermal resources, market trends6

, and policies. The section also reviews the barriers 

and risks that constrain geothermal energy development and the potential for different 

FIT design options to overcome them. 

• Section 3 defines FIT policy characteristics, reviews international experience with 

geothermal FITs in 16 countries (none in North America), and compares current FIT 

payment levels in these countries. Examples of the geothermal payment level setting 

process are detailed for Germany and Spain.

• Section 4 provides an in-depth, qualitative discussion on how FITs can be designed to 

address U.S. considerations for geothermal energy development.7 For comparative

purposes, this section adopts investor security as a benchmark for discussing each option, 

 4 This report does not consider geothermal heat pumps; it concentrates on geothermal electricity production.

5 The Cost of Renewable Energy Spreadsheet Tool (CREST) can be found at 

https://financere.nrel.gov/finance/CREST

6 A more detailed exploration of geothermal technology trends and market development can be found in other 

publications (e.g., Mines et al. 2010; GEA 2012; Beerepoot 2011). 7 A number of studies discuss a broad range of FIT design issues, options, and considerations in detail (Couture et al. 

2010; Grace et al. 2008).
2

but there is great flexibility in how geothermal FITs can be structured, designed, and 

evaluated. 

• Section 5 presents a quantitative analysis of the design tradeoffs identified in Section 4. 

Specifically, this section utilizes the CREST model to illustrate the impact of various 

policy design choices on LCOE. These include the impact of strategies to reduce

exploration, permitting, and financing risks.

• Section 6 contains conclusions and discussions of key findings.
3

2 Overview of Geothermal Development Considerations and 

Risks

2.1 Overview of the U.S. Geothermal Market

The United States has a significant presence in the global geothermal energy market. As of April 

2012, there are 11,224 MW of geothermal electric capacity installed worldwide (GEA 2012). 

The United States has the highest amount of geothermal capacity, with 3,187 MW installed

(Figure 1). Of an estimated $2 billion in new financial investments made in geothermal energy in 

2010, $0.7 billion, or 35%, was invested in the United States (McCrone et al. 2011).

8 Despite 

these statistics, the cumulative amount of U.S geothermal electricity installed has expanded 

slowly in recent years, increasing an average of 2.3% each year since 2008. From 2011 through 

the first quarter of 2012, two new projects and three expansions at existing facilities added 91

MW of geothermal capacity in the US (GEA 2012). 

Figure 1. Cumulative installed U.S. geothermal electricity capacity (2008-First Quarter 2012)

Source: GEA (2012)

The growth of the geothermal market stands in contrast to the U.S. wind and solar markets, 

which have grown significantly during that same time period (EERE 2011). Figure 2 shows 

annual U.S. electricity production for wind and geothermal over the last decade. In 2004, for 

example, the amount of electricity generated by geothermal power plants was slightly higher 

than the amount of electricity generated by wind energy. By 2011, however, the total amount of 

wind generation was over seven times higher than the total amount of geothermal generation.

 8 This figure excludes corporate and government research and development spending.

2700

2800

2900

3000

3100

3200

3300

2007 2008 2009 2010 2011 2012

Cumulative MW 
4

Figure 2. U.S. electricity generated by wind and geothermal plants (1999-2011)

Source: U.S. EIA (2012)

Geothermal growth has been slow compared to other renewable technologies, but there is 

significant potential to expand the market. The section below briefly reviews the U.S. geothermal 

resources available for electricity generation.

2.2 U.S. Geothermal Resources

The exact amount of available geothermal energy is unknown, but recent estimates have 

demonstrated that U.S. geothermal potential remains vast and largely untapped. The different

types of potential resources include9:

• Hydrothermal resources. Hydrothermal systems are naturally occurring underground 

geothermal reservoirs. Hydrothermal reservoirs can either be dominated by hot water or 

steam.10 Hydrothermal reservoirs are continuously recharged as heat flows into the 

reservoir from greater depths. If identified hydrothermal resources were developed to 

their full extent, the U.S. Geological Survey (USGS) estimates that that an additional 6.5 

gigawatts (GW) of geothermal electricity capacity could be brought online across 11 

western states, Alaska, and Hawaii (Williams et al. 2008). The USGS also estimates that 

there is an additional 30.3 GW of unidentified hydrothermal resource. 

• Deep or enhanced geothermal systems (EGS).11 EGS resources are engineered reservoirs 

that can be created by fracturing rock deep in the earth. Water is then injected into the 

 9 In addition to these three resources, there are also geopressured geothermal reservoirs that consist of deposits of 

pressurized hot fluid that typically contain dissolved methane. Geopressured geothermal resources can potentially be 

harnessed to produce energy from both the heat and hydraulic pressure of the reservoir. The methane can also be 

recovered and used for energy. Total geopressured resources are unknown, but early studies have estimated that 

there may be 10-40 GW in the Gulf of Mexico alone (Hunt, 1981). 10 Hot water dominated hydrothermal resources are far more common that steam dominated hydrothermal resources. 11 The German Energy Agency defines EGS as "The use of deep heat reservoirs with few or no water 

resources...Crystalline and dense sedimentary rock at depths of three to six kilometres with high temperatures (over 

150 °C) can serve as reservoirs. These are accessed via two or more boreholes drilled deep into solid rock. 

Hydraulic and chemical stimulation processes (Enhanced Geothermal Systems, EGS) are used to make cracks and 

0

20

40

60

80

100

120

140

1999200020012002200320042005200620072008200920102011

Annual Production MWh

Wind

Geothermal
5

fractures, heated through contact with the rock, and re-circulated to the surface. The 

Massachusetts Institute of Technology (MIT) estimated that the extractable portion of 

available EGS heat energy would exceed 2,000 times the annual consumption of U.S.

primary energy in 2005 and that 100 GW could be developed by 2050 if sufficient 

investment were committed (MIT 2006). The USGS, meanwhile, estimates the available 

EGS resource to be 500 GW (Williams et al. 2008).

12

• Co-produced resources. Hot water is often pumped up from underground as part of the oil 

and gas exploration process. This water could be captured and harnessed to produce 

geothermal energy in small-scale power plants connected to the distribution network 

(McKenna and Blackwell 2005; Hurlbut 2012). The total amount of co-produced 

geothermal resources is uncertain and has not been recently or comprehensively studied 

on a nationwide basis (Augustine et al. 2010). 

Today, the vast majority of geothermal electricity generation comes from hydrothermal 

resources, a minimal amount from co-produced resources, and only experimental plants use 

EGS. Given these potentially available resources, there is significant potential for the United 

States to scale-up its production of geothermal electricity. Market development, however, has 

been slow because of the presence of project risks and obstacles, as described below.

2.3 Obstacles to Geothermal Power Plant Development

Geothermal generation project developers face many of the same types of risks that any power 

plant project will face, such as: 

• Development Risk (Timing). The project will not achieve milestones (e.g., permitting, 

siting, and interconnection), will be delayed, and/or not completed.

• Development Risk (Contracting). The renewable energy project investor incurs 

significant cost on site control, engineering, permitting, and other development activities, 

as well as legal and other costs associated with competing for, or negotiating, a PPA, 

prior to knowing whether it will successfully secure a PPA, RECs and other commodities 

with a creditworthy buyer (i.e., off-taker). Investments in such development-stage are 

fully at risk, and therefore have commensurate return requirements.

• Contract price risk. The PPA price, which may be set (or proposed in a competitive 

solicitation) based on preliminary estimates and committed to before project development 

 fissures in the rock. Cold water is then pumped at high pressure down an injection well into the rock, where it is 

heated and returns to the surface via a second borehole. This hot water in turn heats a working fluid with a low 

boiling point (so-called Kalina Cycle and Organic Rankine Cycle, ORC), producing steam for a turbine. Heat can 

also be fed into district heating networks via a heat exchanger" (German DENA 2012). The U.S. Department of 

Energy’s definition of EGS is not that different: "Enhanced geothermal systems (EGS), also sometimes called 

engineered geothermal systems, offer great potential for dramatically expanding the use of geothermal energy. The 

EGS concept is to extract heat by creating a subsurface fracture system to which water can be added through 

injection wells. Creating an enhanced, or engineered, geothermal system requires improving the natural permeability 

of rock. Rocks are permeable due to minute fractures and pore spaces between mineral grains. Injected water is 

heated by contact with the rock and returns to the surface through production wells, as in naturally occurring 

hydrothermal systems. EGS are reservoirs created to improve the economics of resources without adequate water 

and/or permeability" (DOE 2012). 12 This estimate is limited to 11 states in the western United States and to the geothermal resource located at depths 

of between 3 and 6 km.
6

activities are complete and project costs are fully known, may not be sufficient to cover 

actual costs.

13

• Construction risks. The project will be delayed because of slow construction or 

negatively impacted because of construction costs overruns.

• Technology risk. The technology does not perform as expected.

• Resource risk. The renewable energy resource is not as strong as projected. 

• Market revenue risk. The revenue received by the project may be volatile over time, 

which may negatively impact project economic performance.

• Political (regulatory or legislative) risk. The policy framework under which the project 

was developed may be altered, which may negatively impact project revenues or 

operations.

These risks can constrain project development and increase the cost of capital to finance projects 

if not adequately addressed. For geothermal projects, the project risks outlined above can be 

magnified or compounded by the characteristics of the geothermal exploration and development 

process:

• Development timetable. The length of time to develop a geothermal project is longer than 

other renewable energy generators and is typically 4-7 years (NREL 2011; Richter 2009). 

The development process is complex and involves several distinct stages: exploration, 

confirmation drilling, production drilling, and power plant construction. The duration and 

complexity of these activities creates significant opportunity costs compared to the

development of other technologies with shorter development cycles and greater

opportunities for success.

• Complexity of siting and permitting. The geothermal siting and permitting process can be 

challenging because of a lack of clarity in resource ownership rights and because 

geothermal development may require complex interactions with overlapping federal and 

state regulatory bodies (Doris et al. 2009; Fish and Heaps 2009). 

• Transmission capacity. The best geothermal plants are often located far from large load 

centers. Geothermal power plants are faced with the choice of either using existing 

transmission capacity, which is often constrained, or attempting to build new 

transmission capacity, which is typically prohibitively expensive to build to serve a single 

power plant. A key challenge with new geothermal development, therefore, is identifying 

the transmission infrastructure that will bring the power to market (Hurlbut 2012). 

• Development and exploration costs. The upfront costs of developing geothermal projects 

are substantially higher compared to other energy generation technologies, and can 

account for 40%-50% of total geothermal project costs in the United States. (Cross and

Freeman 2009; Deloitte 2008). 

• Exploration risk. While the development process is expensive, it is not guaranteed to be 

successful; geothermal projects have an exploration success rate of 10%-40% (Augustine

 13 Costs that can diverge from estimates made at the stage of competing for a PPA include capital costs, operating 

costs, fuel costs, costs of securing permits, engineering, or costs associated with PPA pursuit.
7

et al. 2010; Hance 2005). In other words, geothermal prospecting may incur significant 

costs from surface exploration and exploratory drilling and yield only “dry” wells. 

(Importantly, the actual probability of dry wells depends on the hydrothermal 

application.14) This contributes to the upfront cost; drillers need to make higher returns 

on each successful well to make up for the dry wells. As a result of these risks, 

geothermal exploration may be supported by government programs or by industry 

participants with substantial balance sheets and a long-term outlook on geothermal 

electricity markets. In either case, this capital can be very difficult to obtain (Richter

2009; Salmon et al. 2011).

2.4 Addressing Geothermal Barriers and Risks Through Policy

The combination of the duration, complexity, cost, and other risks inherent of geothermal 

development means that geothermal power plants are challenging to build and finance. 

Geothermal projects typically require policy support in order to decrease project risks and 

overcome barriers.15 Policies can be used to decrease the risk and complexity of geothermal 

project development and financing.

There are numerous policy tools that can be used to reduce exploration and development risk and 

improve access to capital. These could include improved research and development, government 

risk sharing (e.g., publicly-funded or managed exploration, co-investment, drilling insurance, 

etc.), the development and coordination of inventories of geothermal data, and inter-agency 

coordination (Deloitte 2008; Doris et al. 2009; GEOFAR 2009a). This report does not focus on 

policies geared to directly address exploration risk since these were explored in other research 

efforts, including a forthcoming NREL report. 

This report instead focuses on analyzing policy options that establish revenue certainty and 

ensure known access to a revenue stream if exploration proves successful, removing not only the 

transaction, bid security, and legal costs of pursing a PPA, but mitigating a variety of the 

aforementioned risks.

16 Decreasing risks can increase investor confidence and reduce the time 

for financing. Recent studies have estimated that targeted renewable energy policy can reduce 

risk, lower the cost of capital required to finance wind and solar projects, and result in a 10%-

50% decrease in the levelized cost of energy of renewable generation (Varadarajan et al. 2011; 

 14 Geothermal projects that drill new wells to expand the utilization at existing, well-quantified sites are the least 

likely to have dry wells because the resource is well characterized (however there likely will be other issues like 

more quickly depleting the overall resource that feeds both plants). Geothermal projects that “step-out” and are 

adjacent to existing sites are more likely to have dry wells than co-located plants since the resource is nearby, but 

may not continue outside of the existing plant’s footprint. Rapid depletion of the shared resources at both sites may 

also be an issue. Next, greenfield wells at locations with surface manifestations appear to have a higher probability 

of dry wells than “step-out” facilities since the resource is not characterized at the required depths. Finally, “blind” 

geothermal that is not near other facilities and does not have a surface manifestation are the most likely to have dry 

wells (DOE, Geothermal Technologies Program 2011). 15 Some of these barriers and risks described in this report, such as the construction, technology risks, and resource 

risks are difficult to address through policy (Corfee et al. 2010; de Jager and Rathmann 2008). Construction and 

technology risks can be addressed through contracts and warranties with installers and manufacturers, whereas 

resource risks can be addressed through in-depth resource assessments. 16 Recent studies have argued that multiple policy instruments that take into account specific national technology 

and market developments must be combined in order to successfully support geothermal development (e.g., 

Miethling 2012).
8

de Jager and Rathmann 2008). This report focuses on policies that can address the following 

risks:

• Market revenue risk. Market revenue risk occurs when the price paid to the generator 

varies over time or when the future availability of a revenue stream (or other cashequivalent benefit stream) is unclear. Reliance on spot electricity markets for revenues is 

one form of market revenue risk. The temporary nature of federal incentives, including 

the Production Tax Credit (PTC) for example (i.e. reauthorized for 1-4 years at a time), 

can also create a net cash flow risk for geothermal investors and developers with long 

development timelines (Salmon et al. 2011).

17 Market revenue risk can be diminished by 

policies that provide geothermal developers with stable, long-term payments that are 

known in advance. Alleviating this risk can significantly improve investor security and 

reduce the cost of capital (Deutsche Bank Climate Change Advisors 2009). 

• Development risk. Development risk reflects the fact that a project may or may not find a 

buyer for its power, RECs, and/or other commodities before expending significant 

development capital on siting, engineering, and permitting. This could result, for 

example, from the absence of a policy stimulating demand for geothermal power,

shortage of viable counterparties, loss of a competitive procurement, or failure to 

conclude a successful power purchase agreement negotiation with a prospective buyer. 

This risk can be reduced through policy by assuring that a project can rely on access to a

PPA if it can find a technically and economically viable resource and secure necessary 

permits. 

• Contract price risk. Even when a mechanism is in place to provide a geothermal 

developer with an opportunity to compete for a PPA (such as under an renewable 

portfolio standard (RPS) in a western U.S. vertically-integrated electricity market), it is 

common that developers may need to offer price proposals before development 

contingencies have been fully resolved and therefore before project costs are fully 

understood. As a result, developers typically either build in a risk margin to account for 

these risks, or incur additional expenses to attempt to hedge uncertain costs. Alleviating 

the need to build in risk premiums or hedging costs can reduce the viable PPA price

(Wiser et al., 2006).

18 From the policymaker’s perspective, this risk may be daunting –

how does one set the “right” payment level? Some countries, like Switzerland, require 

that developers participating in the FIT provide cost data so that they have a database of 

cost information that grows over time and can be used to inform future payment levels 

(Couture et al. 2010).

• Legal risk. Legal risk refers to the risk of legal delays, costs, and failures during the 

process of competing for and negotiating a power purchase agreement. These risks can be 

diminished by policies that provide incentives that are available on a standard offer basis 

under standardized contracts. 

 17 The production tax credit, for example, has often been extended for one to two years at a time, insufficient to span 

geothermal project development timelines. 18 Many projects fail not because they do not secure a PPA, but because a PPA at a price bid is insufficient to get the 

project financed (i.e., to give investors their expected return).
9

• Political risk. Exposure to policy changes impacts a geothermal developer’s prospects 

and cannot be hedged by project investors. The longer development horizons of 

geothermal power leave investors more exposed to such risks than investors in wind or 

solar power. These risks can be lessened by policies that provide incentives that are 

available on a standard offer basis under standardized contracts, particularly if such 

incentives are established for a sufficient duration to allow for geothermal development 

cycles. Buyers often seek protection from such risks under PPAs, which can shift 

substantial risk to project owners. Standard PPAs without such political ‘outs’ can 

therefore reduce investor risk. 

Several recent studies have surveyed non-exploration geothermal policies in the United States

and evaluated their adequacy for mitigating risks, addressing barriers, and driving market 

development of new (or incremental) geothermal electricity facilities. NREL (Doris et al. 2009), 

for example, reviewed state policy and concluded that: 

• With few exceptions, current renewable energy policies are not sufficiently tailored to 

provide new geothermal power plants with the specific types of support they require. 

RPSs for new generation support inter-technology competition, which, in practice, has 

primarily favored new wind energy for reasons that may span differences in resource 

availability, development timeline, and exploration/development risk. By 2010, 91.2% of

the new renewable energy capacity motivated by RPS policies was wind, whereas only 

1.4% was geothermal (Barbose 2011). These specific values are influenced by the fact 

that state RPS programs are distributed nationally but geothermal development has been 

thus far limited to the western United States.

• The policies that specifically support geothermal are often limited in their ability to 

meaningfully impact the geothermal market due to funding or eligibility (e.g., project 

size) restrictions. 

In markets such as California’s where geothermal power plays a material role in RPS 

compliance, the policies are structured to include existing resources in utility RPS 

procurements.19 In many cases, these geothermal resources were originally developed under the 

PURPA. The feasibility of expansions at existing geothermal facilities has also been investigated 

as a result of the long-term utility procurements associated with RPS programs. In this case, the 

potential availability of a long-term contract provides the opportunity to develop a financing plan 

for expansion, but the short lead-time afforded by the RFP process presents a continuing 

challenge to long-lead time resources like geothermal. This issue is compounded for geothermal 

developers seeking financing for greenfield development. 

 19 Policies involving utility long-term contract procurement requirements, such as RPS mandates placed upon 

regulated utilities in western United States markets, can mitigate electricity market risk, but by failing to ensure 

market access, they expose developers to most aspects of development risk and contract price risk. FITs offering 

guaranteed access at known prices under standard contract terms can substantially reduce these aspects of power 

project risk. In addition, such competitive procurement policies fail to avoid many of the costs avoidable under a 

FIT, such as proposal preparation, cost estimation, hedging to lock in costs underpinning a bid (when possible), risk 

premium, bid security, and legal and other costs relating to contract negotiation. 
10

The NREL study identifies FITs as one possible policy approach that could expand or improve 

the existing policy landscape.

20 FITs have been identified in studies by Deutsche Bank and 

others as one of the most effective policies for mitigating key renewable energy project 

development risks, attracting investment capital, and scaling-up renewable energy markets

(Deutsche Bank Climate Change Advisors 2009). While experience is early, FITs can be 

designed to target geothermal generators and reduce geothermal project risks; specifically, 

geothermal FITs can be structured to: 

• Pay generators with a fixed, long-term price for electricity, RECs, and/or other 

commodities, which can decrease market revenue risks. Projects do not need to compete 

for or negotiate a contract before final project costs are known, reducing contract price 

risk. Projects under such circumstances may also not be subject to contractual milestones 

that could lead to contractual penalties, forfeiture of security payments, and termination 

of the off-take agreement if there are project delays.

• Require utilities (or other entities) to purchase geothermal output on a standard offer 

basis, which can ensure contract access. This removes the risk that investments in 

exploration and development will not yield an off-take agreement. This certainty may 

also attract a broader pool of capital providers to finance both the exploration and 

operations periods, thereby potentially lowering capital costs. 

• Provide generators with standardized contracts that can reduce transaction costs.

FITs might help the U.S. geothermal market achieve accelerated expansion goals, as a 

complement to policies designed specifically to address exploration risks. FITs that address 

revenue, market, development, legal, and political risks can have a positive impact on the 

decision of geothermal developers to move forward with geothermal exploration by removing 

some of the uncertainties of the development process in advance and accelerating development 

times. 

There are, however, limitations and challenges with FIT policies. First, FIT payments are 

typically set administratively rather than through competitive processes. Similar to tax credits, 

rebates, and performance-based incentives, policymakers need to carefully set the “right” price 

that most fully meets their FIT policy objectives. Setting a price too low may yield less 

development than desired whereas setting the rate too high may lead to overpayment and more 

development than desired. Second, without a competitive mechanism to help determine or 

benchmark incentive levels, the setting of FIT prices typically requires intensive data gathering 

processes. Third, periodic reviews are necessary to help ensure that the payment levels reflect 

market conditions and policy objectives accurately. Finally, some FITs have been designed 

without caps on the amount of generation to be developed (e.g., Germany). This approach can 

create uncertainty with regard to total policy impact and policy cost, and in some cases 

(involving short lead-time generation with ample resource potential), has led to substantial rate 

impacts (e.g., photovoltaics in Spain). In order to address these concerns, there are mechanisms 

that can be used to limit market growth and contain costs, such as caps and payment level 

adjustment mechanisms (Kreycik et al. 2011). 

 20 Other approaches that include geothermal specific policies and carve-outs, improvements to existing policies, and 

agency coordination are outside of the scope of this analysis.
11

The remainder of this report focuses on geothermal FIT design considerations and the risk 

implications of different design options in greater detail. This report does not revisit or 

summarize broader discussions of how FITs compare and contrast with other policy types. The 

next section explores FITs by first defining what they mean and then examining their application 

in support of geothermal energy in other countries.
12

3 Global Experience with FIT Incentives for Geothermal 

Electricity

3.1 Defining FITs

Although there are no geothermal FITs in North America, there are currently 16 countries that 

have established specific FIT incentives for geothermal.

FITs, also referred to as standard offers or CLEAN contracts,

21 are currently the most common 

national renewable energy policy in the world and are currently in place in over 50 countries 

(REN21 2011). FITs have driven the rapid scale-up of renewable energy technologies around the 

world and have supported 87% of the global photovoltaic capacity and 64% of global wind 

energy capacity as of 2010 (Tringas 2011). 

Several recent publications have catalogued and described the primary FIT design considerations 

(Couture et al. 2010; Grace et al. 2008; Klein et al. 2008; Mendonça et al. 2009). What is clear 

from these studies is that FITs are complex policies that can be implemented in a wide variety of 

forms. In fact, no two FITs have been implemented in the same way. The complexity of FITs is 

attributable to the fact that they are not a single policy focused on the payment level, but rather a 

package of regulations and incentives, which can contain all of the following elements:

• Interconnection rules. The term “feed-in” tariff derives from the 1991 law in Germany 

that first guaranteed independent power producers the right to connect to and feed their 

electricity into the grid. FIT policies may include requirements that utilities interconnect 

renewable generation (“guaranteed interconnection”), that renewable energy advance 

ahead of conventional generation in the interconnection queue (“priority 

interconnection”), and/or that the cost of interconnection or grid upgrades be passed 

through to ratepayers (Rickerson et al. 2011; Tweedie and Doris 2011).

• Purchase and dispatch requirements. FIT policies may also require that utilities not only 

purchase all of a generator’s output22, but then also prioritize its delivery ahead of nonrenewable generation. If renewable generation must be shut down or curtailed by the grid 

operator for technical reasons (e.g., in order to ensure grid security), some FIT policies 

further guarantee that generators will receive payment for the electricity they were unable 

to sell23 (Rogers et al. 2010). 

• Standardized contracts. FIT policies may include provisions that require utilities to offer 

standard and simplified contracts to generators, rather than requiring generators to 

negotiate contracts on a case-by-case basis (Couture et al. 2010). 

• Pre-determined long-term payments. FITs typically include a standard offer for a known 

payment to generators, available on a first come, first-served basis. FIT payment levels 

are usually set administratively, rather than relying on competition or market 

mechanisms, and are typically offered for durations of 15 to 20 years (Couture et al.

2010).

 21 Clean Local Energy Accessible Now, see e.g., Caperton et al. (2011) and Farrell (2011) 22 Similar to a “must take” contract 23 Similar to a “take or pay” contract
13

• Other policy objectives. Additional FIT policy features could include clear transmission 

cost allocation, cost of system upgrades, cost caps that limit total policy cost, forecasting 

obligations for variable generation, bonus payments to encourage generation where the 

electric system most needs it (e.g., urban areas, radial ends of distribution systems), 

bonus payments for innovative technologies, and repowering of old sites (Couture et al.

2010).

Despite international interest in FITs, there has not yet been much research that focuses on 

geothermal FIT design specifically. This report represents the first in-depth attempt to explore 

how these policy elements could be aligned to support geothermal development. As a first step, 

geothermal FITs internationally were surveyed in order to identify lessons learned. While it is 

too early to mathematically quantify the impact of geothermal FITs on accelerating project 

development, some early observations provide some useful insights.

3.2 FITs in North America

FITs have only recently appeared in North America. Ontario established its current FIT policy in 

2009 as a replacement for its earlier Renewable Energy Standard Offer Program (RESOP) 

(Ontario Power Authority 2011). Nova Scotia followed in Ontario’s footsteps by establishing its 

Community Feed-in Tariff (COMFIT) in 2011 (NSUARB 2011). A number of U.S. states have 

introduced FIT legislation during the past several years, but only California, Hawaii, and 

Vermont have enacted FITs (Couture and Cory 2009; Rickerson et al. 2008). Additionally, 

several cities24 have enacted FIT policies.

The experience with FITs in the United States and Canada, however, has been of limited 

relevance to geothermal either because geothermal is not eligible to participate, is not a viable 

local resource, or because the programs impose size limitations (e.g., for distributed, on-site 

generation) that would effectively exclude most geothermal electric generation.25

The closest analogue to large-scale FITs for sizable project in the United States is PURPA of 

1978. Under PURPA, utilities were required to purchase power offered by “small power 

production facilities26” at the utilities’ full avoided cost. The calculation of avoided cost was left 

to state discretion. Under PURPA, California created the Standard Offer No. 4 (SO4) contract, 

which defined avoided cost as a 10-year schedule of escalating payments (Pierce and Livesay 

1994). The GTP Blue Ribbon panel noted that SO4 “drove geothermal exploration in the 

1980s...Private industry was willing to take more drilling risk because of the higher electricity 

price (EERE 2011).” In total, PURPA supported 1,346 MW of geothermal capacity, including 

1,295 MW in California, 237 MW in Nevada, and 35 MW in Hawaii (Guey-Lee 1999). A more 

detailed discussion of PURPA and geothermal development can be found in Appendix C.

 24 E.g., Gainesville, Florida; Sacramento, California; and San Antonio, Texas. 25 It is important to note that some of the FIT design options described in Section 3.1 are not currently feasible in the 

United States. Priority interconnection and dispatch rules, which are a feature of European FITs, are not currently 

allowed in the United States because FERC requires that interconnection service and access to transmission be nondiscriminatory for projects over which it has jurisdiction (Fink et al. 2010). Groups such as the Regulatory 

Assistance Project (2010) have, however, suggested that priority interconnection and dispatch be introduced in the 

United States. And, these design features can be used by international readers of this report. 26 According to PURPA, a small power production facility “means a facility which is an eligible solar, wind, waste, 

or geothermal facility...and has a power production capacity which, together with any other facilities located at the 

same site...is not greater than 80 megawatts.” See http://uscode.house.gov/download/pls/16C12.txt. 
14

PURPA demonstrated that the combination of a guaranteed purchase and a fixed price could 

attract investment in geothermal development. PURPA was controversial, however, because the 

prices that were paid under long-term contract were judged to be too high in retrospect for many 

projects (Hirsh 1999).

27 The effectiveness of PURPA subsided as avoided costs levels decreased 

with the dramatic fall in natural gas and oil prices. The Energy Policy Act of 2005 (EPAct)

further restricted PURPA by exempting utilities that allow non-utility generators access to 

competitive markets from having to sign new PURPA contracts upon a demonstration to the 

Federal Energy Regulatory Commission (FERC) (Elefant 2011). Since PURPA provided 

generators with guaranteed market access and, in the case of SO4, a fixed price for power, many 

analysts refer to PURPA as the world’s first FIT (Lipp 2007; Mendonça et al. 2009; REN21 

2011). It is important to note, however, that PURPA was not tailored specifically to support 

geothermal energy and questions remain as to whether a more targeted policy design could better 

decrease geothermal development risk while providing generators with lower payments.

3.3 International FITs

International experience with geothermal-specific FITs is limited, but lessons learned to date can 

inform policy design for geothermal electricity. This analysis of these FIT policies focuses on

several key issues:

• A high-level comparison of FIT payment levels for geothermal across different countries

• The impact of geothermal FITs on the development of new capacity worldwide 

• Approaches to account for development and exploration costs when setting the FIT

payment level

In order to gather data on geothermal policies, reviews of original FIT legislation (or translated

legislation) were conducted if readily available in English, Spanish, or German. When laws were 

not either readily available and/or un-translated, secondary sources that summarized policy 

content (EGEC 2011; Rickerson et al. 2010) and websites such as RES LEGAL28 were

consulted. In total, 16 countries were identified with FITs specifically for geothermal.

29

3.3.1 FIT Payment Levels and Impacts by Country

The two tables below contain a high-level summary of the geothermal electric FITs surveyed. 

Table 1 summarizes geothermal FITs in European Union (EU) member states, whereas Table 2 

summarizes geothermal FITs in non-EU countries. The following data is shown for each country: 

• FIT payment structure refers to whether the payment is made as a fixed amount for 

electricity or whether it is paid as a premium on top of the wholesale price for electricity.

 27 There has also been controversy regarding the payment levels under some FITs, particularly with regard to FITs

for photovoltaic systems in countries such as Spain (Couture 2011). 28 http://www.res-legal.de/en.html 29 Several countries have policies that are sometimes referred to as FITs but that set a ceiling price for renewable 

generation, rather than a floor price. Kenya, for example, sets a ceiling price of 8.5 cents/kWh for geothermal 

(Ministry of Energy 2010). The contract rate must then be negotiated on a case-by-case basis. In Indonesia, 

generators must compete for power purchase agreements and the price of the power purchase agreements cannot 

exceed $0.097/kWh (MEMR 2011). These are not considered FIT policies for this analysis.
15

• Requirements for FIT payment. The types of geothermal plants that are eligible for FIT 

payments vary by country. Some of the countries specify constraints such as a minimum 

efficiency or a maximum project size, whereas other countries set forth multiple payment 

levels differentiated based on project size, resource temperature, or geographic location. 

Some countries allow bonus payments for plants with certain desirable characteristics

(i.e., specific technology, ability to achieve commercial operation within a specified 

period of time). If a specific plant meets all of these characteristics, then it can claim all 

of the bonus payments, incremental to the base FIT payment.

• FIT payment duration refers to the number of years that a geothermal plant is paid the 

FIT incentive. This ranges from 10 years (e.g., Turkey) to 20 years (e.g., Germany and 

France).

• Geothermal FIT payment refers to the amount of money received for every kilowatt-hour 

generated under the FIT. This amount is listed in both Euro (€) and in U.S. dollars (US$).

Currency conversion throughout this report is based on the Euro-USD exchange rate of 

1.4 on November 1, 2011.

• Geothermal Cumulative Installed Capacity refers to the total cumulative installed 

geothermal electric capacity in the country.

• Cumulative Geothermal Capacity Supported by FIT indicates the total cumulative 

amount of installed geothermal electric capacity that receives payments under the FIT 

policy. As can be seen in the table, the amount of geothermal capacity supported by FITs 

to date has been limited and this is discussed in greater detail in Section 3.3.2. 
16

Table 1. Geothermal Electric FITs in the European Union (EU)

Country

FIT

Payment

Structure*

Requirements for FIT Payment 

FIT 

Payment 

Duration 

(Years)

Geothermal FIT 

Payment (€/kWh)

Geothermal FIT 

Payment 

(US$/kWh) 

Geothermal 

Cumulative Installed 

Capacity (MW) 

(2010)

Cumulative Geothermal 

Capacity Supported by 

FIT (MW)

(as of 2010)

Austria Fixed Minimum 60% power plant 

efficiency 13 0.075 0.11 1.4 1.230

Czech 

Republic

Fixed None 20 0.18 0.25 0 0 Premium None 0.15 0.21 

France Fixed

Continental France (< 12 MW)

15

0.2 0.28 

16.5 16.5

Bonus payment for system 

efficiency (< 12 MW) 0.08 0.11 

Overseas Territories (OT) 

(< 12 MW) 0.13 0.18 

OT bonus for system efficiency 

(< 12 MW) 0.03 0.04 

Germany Fixed Base rate 20 0.25 0.35 7.5 7.5 Bonus payment for EGS 0.04 0.056 

Greece Fixed

Low temperature geothermal

20

0.15 0.21 

0 0 High temperature geothermal 0.099 0.14 

Bonus payment if generator does 

not receive other subsidies 0.2 0.28 

Italy 31 Fixed < 1 MW 15 0.2 0.28 843 0

Spain Fixed < 50 MW 20 0.073 0.10 0 0

Slovakia Fixed < 10 MW 15 0.196 0.27 0 0

Slovenia Fixed < 5 MW 15 0.153 0.21 0 0

Premium < 10 MW 15 0.093 0.13 0 0

* FIT payment structure refers to whether the payments are fixed over time or whether they are premium paid on top of wholesale electricity prices. 

Sources: (Bertani 2010; BMU 2011b; EGEC 2011; Holm et al. 2010; IGA 2011)32

 30 The Blumau and Altheim plants receive the Austrian FIT. The 200 kW Simbach-Braunau plant, which is a joint Bavarian-Austrian project on the border with Germany, receives the 

German FIT (personal communication, Dr. Johan Goldbrunner November 21, 2011). 31 Italy’s current geothermal capacity is not attributable to the FIT. Instead, Italy’s capacity was primarily built by the (previously) state-owned enterprise, Enel, which assumed the 

risk for the entire development process from exploration to power plant construction. It is unlikely that the FIT will be utilized in the near future because current projects in the 

pipeline are above 1 MW (GeothermEx 2010; Holm et al. 2010). 32 National Renewable Energy Action Plans were also consulted for each country. Available from: http://ec.europa.eu/energy/renewables/transparency_platform/action_plan_en.htm .
17

Table 2. Geothermal Electric FITs in Non-EU Countries

Country FIT Payment

Structure*

Requirements for FIT 

Payment

FIT Payment 

Duration 

(Years)

Geothermal FIT 

Payment (€/kWh)

Geothermal FIT 

Payment 

(US$/kWh)

Geothermal 

Cumulative Installed 

Capacity (MW) 

(2010)

Cumulative Geothermal 

Capacity Supported by 

FIT (MW) (as of 2010)

Croatia Fixed <1 MW 12 0.18 0.25 0 0 >1 MW 0.17 0.24 

Ecuador Fixed Mainland 15 0.093 0.13 0 0 Islands (Galapagos) 0.102 0.14 

Serbia Fixed N/A 12 0.075 0.11 0 0

Switzerland Fixed

<5 MW

20

0.34 0.48 

0 0 <10 MW 0.3 0.42 

<20 MW 0.23 0.32 

>20 MW 0.19 0.27 

Taiwan Fixed N/A 20 0.12 0.17 3.333 0

Turkey Fixed

Base rate

10

0.07 0.10 

81 0

Bonus: Steam or gas turbine 

domestic content 0.009 0.01 

Bonus: Generator and power 

electronics domestic content 0.05 0.07 

Bonus: Steam injector or gas 

compressor domestic content 0.05 0.07 

Uganda Fixed N/A 20 0.05 0.07 0 0

Sources: (Bertani 2005; Bertani 2010; Electricity Regulatory Authority 2010; Gipe 2011; Holm et al. 2010; IGA 2011; Kolarevic 2009)

 33 A 3-MW single-flash unit was installed in Qingshui in 1981 and a 300 kW unit was later installed at the same field. Both systems ceased operations in 1994 (Bertani 2005).
18

3.3.2 Lessons Learned from International FITs

A high-level review of the policy design and implementation details of global geothermal FITs

provides several insights:

• A diversity of geothermal FIT designs. It is noteworthy that of the approximately 50 

countries that have enacted FITs internationally, approximately one-third have crafted 

specific incentive levels targeting geothermal development. Of these, each of the 

different countries has designed their FITs to reflect different policy objectives and 

geothermal resource characteristics. These include a focus on small scale projects (Italy), 

minimum plant efficiencies (Austria), specific resources (e.g., EGS Germany and low 

temperature in Greece), different geographies (e.g., islands vs. mainland in Ecuador and 

France), and domestic content (Turkey). These design considerations can serve as useful 

benchmarks as policymakers in other countries consider their own customized designs.

• A broad range of remuneration levels. The diversity of FIT designs is also reflected in the 

manner in which the FIT payment levels are set. Figure 3 compares the highest rate paid 

for geothermal in each country by calculating the net present value34 of the revenue that 

would be paid to a one megawatt geothermal plant for the duration of the FIT contract as 

a means of comparing contracts of different lengths. This illustrates, for example, that the 

overall value of geothermal in the Czech Republic is higher than that in Croatia. 

Although both countries pay generators €0.18/kWh, generators receive this payment for 

20 years in the Czech Republic instead only 12 years in Croatia.35 As can be seen in the 

figure below, the value provided to generators varies widely. This reflects the fact that 

some countries have established payments designed to reflect the generation costs of 

comparatively expensive technologies, such as EGS in Germany or smaller-scale, islandbased systems in France.

36 Other countries, such as Serbia, have set payment levels more 

conservatively in order to target only lower-cost generators (Kolarevic 2009). The 

examples of Germany and Spain are discussed in greater detail in Sections 3.3.3.1 and 

3.3.3.2. 

 34 Assuming a 7% discount rate and a 72% net capacity factor. 35 The net present value of the total payments for one kilowatt-hour generated each year under the Czech FIT is 

€1.91 whereas the net present value of the total payments for one kilowatt-hour generated each year under the 

Croatian FIT is €1.43. 36 All of France’s overseas departments, with the exception of French Guiana, which is on the mainland of South 

America, are islands.
19

Figure 3. Comparison of FIT revenue NPV for 1-MW geothermal plant

Source: Calculations based on Figure 1 and Figure 2 (72% net capacity factor, 7% discount rate)

• A lack of empirical data on FIT impacts. Although the range of different designs is a 

useful benchmark, there is currently a lack of data with which to compare the impact of 

different design decisions. Despite the success of PURPA in the United States (and SO4 

in particular), response to international FITs to date has been limited. Only the FITs in 

Austria, Germany, and France have supported new geothermal capacity and, in these 

cases, the total amount of new generation has been under 20 MW. 37

There are several likely reasons for the lack of market response to geothermal FITs thus far. 

First, many of the countries in Europe have comparatively low levels of hydrothermal resources 

and are attempting to support EGS, which is an emerging technology (not fully commercial) and 

therefore has proven expensive and challenging to develop to date (GEOFAR 2010). Second, 

several of the geothermal FITs are comparatively new (or have been recently amended); 

geothermal developers have not yet had time to react given the long development lead times 

required of geothermal projects. As a result, policymakers have not had the benefit of calibrating 

their policies according to established policy track records (as they have been able to do with 

wind and solar FITs). Third, the payments offered under the FITs may be insufficient to support 

geothermal development because the payments are too low to compensate for the price of the 

 37 Conversely, none of the countries ranked in the top 10 for total geothermal capacity has a geothermal FIT in place 

except for Italy, whose FIT targets only generators 1 MW and under. In order, the top 10 countries include United 

States, Philippines, Indonesia, Mexico, Italy, New Zealand, Iceland, Japan, El Salvador, and Kenya.

$0

$5,000,000

$10,000,000

$15,000,000

$20,000,000

$25,000,000

$30,000,000

$35,000,000

NPV of FIT revenue for 1 MW Geothermal Plant
20

geothermal resource or because of other country-specific risks (e.g., political risk or currency 

risk) (GEOFAR 2011; Goldbrunner 2010). Fourth, the presence of other technical and nontechnical barriers to geothermal development (e.g., unmitigated exploration risks or lack of 

transmission) may serve as a barrier despite the presence of otherwise attractive payment levels

(GEOFAR 2009b; Hurlbut 2012). Finally, some of the FITs are available only to small projects

whereas geothermal project development has focused on larger-scale projects (e.g., Italy).

A key take-away from the international survey is that the presence of FITs alone has not driven 

results comparable to those achieved for wind and solar power under European FITs or to those 

achieved for geothermal under PURPA in the United States. On the other hand, international 

experience demonstrates that many countries are experimenting with crafting policies that are 

more specifically tailored to geothermal than North American policies (e.g., RPS and PURPA) 

have been in the past. Geothermal FIT policies are continuing to evolve and mature and there 

remains room for innovation and further research into international designs. FITs can be 

designed to take country-specific geothermal resources and risks into account and may be part of 

a broader package of geothermal risk mitigation policies, including exploration support or 

expedited permitting (Miethling 2011). 

Unlike many of the countries in the international survey, the United States has a strongly

identified and unexploited hydrothermal resource as well as a significant amount of as-yet 

unidentified hydrothermal resource. It is reasonable to assume, especially given the experience 

with PURPA, that appropriately crafted and targeted FITs in the United States could have a 

greater impact on market growth than in other parts of the world. 

3.3.3 Approaches to Setting FIT Payment Levels

A primary step to establishing targeted FITs for geothermal is determining the payment levels 

that will be offered to generators. As explored in a recent NREL report, a broad range of 

approaches can be used to set payments for FITs or other performance-based incentives (Gifford

et al. 2011). The key considerations when developing FIT payment levels include:

• Basis for setting payment levels. Payment levels can either be set based on the generation 

cost of a certain technology (a “cost based” approach) or pegged to measures of value 

such as the avoided cost of energy and/or avoided externalities.

• Contract length. As shown in Tables 1 and 2, the contract length varies widely between 

FITs. For generation cost based payments, the contract length can have an impact on the 

$/kWh payment to the generator. Shorter contracts require a higher payment than longerterm contracts to achieve the same rate of return.

• Model for setting payment levels. Different jurisdictions utilize different spreadsheet 

models to set their payment levels. The key policy choices related to model design are 

whether to employ cash flow forecasts or recovery factor analyses and whether to utilize 

a pre-tax or after-tax analysis. In a separate effort, NREL surveyed international FIT 

practices and U.S. policy requirements, and developed an after-tax discounted cash flow 

model called CREST38 that includes a geothermal model (Gifford et al. 2011). 

 38 Available for download at https://financere.nrel.gov/finance/content/CREST-model
21

• Type of input data. Models for setting payment levels can range from high-level and 

comparatively simple to highly complex models. The number of inputs and the 

granularity of those inputs can to a great extent determine model complexity. For 

example, modelers can choose to use a single input for “installed cost” or they can choose 

to break installed costs into labor cost, detailed equipment costs, and other upfront (e.g.,

development, permitting, financing-related) costs.

• Input selection. A range of values that can be considered “reasonable” for each input. 

Policymakers have a choice as to whether they select values at the upper or lower ends of 

these ranges. To a great extent, these choices will determine how aggressive or 

conservative39 the ultimate FIT payment level is and thus the volume of new generation 

that will be able to participate under the policy. 

As seen in Tables 1 and 2, the manner in which policymakers choose the basis for geothermal 

payment level setting and select modeling inputs can result in widely different FIT payment 

levels. Given the magnitude of the costs and risks of exploration and development, a key choice 

for U.S. policymakers will be whether and how these costs are incorporated into the development 

model. 

The two primary approaches to setting FIT payment levels are to base the payment on a measure 

of value (e.g., avoided cost) or to base the payment on expected generation cost of eligible 

projects (Grace et al. 2008). In North America, the current state FIT in California and the 

municipal FIT in Sacramento are based on avoided cost (plus adders reflecting externalities), 

whereas the remainder are generation cost-based policies. Cost-based FITs dominate world FIT 

policy methodology. This report focuses on generation cost-based FITs in order to highlight the 

wide number and variety of policy choices that could have implications for geothermal projects. 

The development of value-based payments could be the focus of future research.

This section reviews the geothermal policymaking and approach to setting payment levels in two 

countries, Germany and Spain, in order to explore this and other issues in greater detail.

3.3.3.1 Geothermal FIT Policy and Payment Level Setting in Germany

Germany’s fleet of installed geothermal capacity remains comparatively small. The first system 

was installed in 2003 and there were five systems totaling 7.5 MW by the end of 2010 (BMU, 

2011a). Compared to the U.S. generation fleet, these systems are very small scale and embrace 

less common approaches such as Kalina cycles, EGS, and combined heat and power systems

(GEOFAR 2010). 

Germany’s renewable energy FIT has been in place since 1991. The first tariff for geothermal 

power was introduced in 2000 with the passage of the Renewable Energy Law: the ErneuerbareEnergien-Gesetz (EEG).

40 The initial 20-year tariff level was set at 8.95 €cent/kWh (12.53

¢/kWh) for systems up to 20 MW in size and 7.16 €cent/kWh (10.02 ¢/kWh) for systems larger 

than 20 MW. The EEG included annual decreases in the available FIT payment for most 

 39 Conservative FIT rates are rates that are set at a level to encourage the lowest cost projects. Aggressive FIT rates 

are set to enable a broader range of systems to enter into the market (Grace et al. 2008). Policymakers can choose to 

set their FIT rates along the spectrum from conservative to aggressive rates, depending on their policy objectives 

(Gifford et al. 2011). 40 The Erneuerbare-Energien-Gesetz or EEG
22

generators according to a fixed schedule (i.e., a degression schedule41). Geothermal payments

were not subject to degression, however, in order to account for long development lead-times. 

The first geothermal power plant in Germany was built under the FIT in 2003. 

The German Ministry of Economy and Finance (BMWI) and the Ministry for the Environment 

(BMU)42co-financed the first geothermal electricity plant in order to gain a better understanding 

of geothermal economics.

43 Based on the experiences with the first power plant and additional 

research, policymakers concluded that the tariff levels under the EEG were too low to support 

geothermal market expansion, especially for small-scale generators (Jacobs 2012). In the 2003 

FIT progress report, the BMU recommended adjusting the tariff to better account for geothermal 

plant economies of scale (BMU 2003). The revised EEG of 2004 introduced two additional size 

categories below 20 MW, according to the table below:

Table 3. Size Categories and Tariff Payment Levels under Revised German EEG (2004)

Geothermal plant size €/kWh $/kWh

< 5 MW 0.15 0.21

5 MW – 10 MW 0.14 0.20

10 MW – 20 MW 0.0895 0.13

> 20 MW 0.0716 0.10

The 2004 law also introduced a new degression of 1% annually, but delayed the start of the 

decrease until 2008 to account for the lengthy development timeline.

In 2007, the BMU again released a progress report that evaluated the adequacy of German FIT 

payment levels. The report concluded that an additional increase in the tariff levels would be 

necessary in order to account for higher actual drilling costs resulting from increased activity in 

the oil and gas sector (BMU 2007). The revised 2008 EEG introduced simplified size categories 

with higher payment levels as can be seen in the table below; one goal was to provide revenue to 

cover the assumed project drilling costs. The law also included bonus payments for systems that 

went into operation before 2016, that used combined heat and power, and that used EGS 

technology. These bonuses are additive such that an EGS CHP system that is under 10 MW and 

installed prior to 2016 would receive €0.27/kWh (0.38 $/kWh) for 20 years.

Table 4. Simplified Categories and Tariff Payment Levels for 2008 German EEG Revision

Geothermal plant size €/kWh $/kWh

< 10 MW 0.16 0.22

> 10 MW 0.105 0.15

Bonus: Installed prior to 2016 0.04 0.06

Bonus: Combined heat and power 0.03 0.04

Bonus: EGS 0.04 0.06

 41 A degression schedule reduces the fixed rate available to new generators built at a later date as opposed to 

reducing the rate available to a particular generator over time.

42 Bundesministerium für Umwelt Naturschutz und Reaktorsicherheit 43 The 230 kW Neustadt-Glewe plant, which was Germany’s first geothermal power installation, utilized an Organic 

Rankine Cycle to generate electricity from lower-temperature water. The project added a power plant in 2003 to an 

existing geothermal heat plant. The cost of the power plant installation was €1.6 million (GEOFAR 2010).
23

On January 1, 2012, the German FIT was again revised to include a single payment level for 

geothermal projects of €0.25/kWh (0.35 $/kWh) for 20 years. EGS plants are eligible for a 

€0.04/kWh (0.056 $/kWh) bonus payment. The rates from 2007 were consolidated into one 

higher rate, and the new rate reflects that drilling costs had been more uncertain than 

anticipated44 and that financing costs were higher than previously modeled because of larger 

project risks. Degression is set at 5% a year but does not begin until 2018. This latest version of 

the German geothermal FIT payment values are captured in Table 1. 

The key parameters used to calculate the German FIT payment level in 2011 are contained in 

Table 5 below. It is noteworthy that drilling costs are assumed to make up the largest share of the 

installed cost for geothermal plants in Germany. These drilling costs are based on experience 

from six geothermal projects with 11 production wells between them (total 47,000 meters of 

drilling) (Jacobs 2012). For each project, drilling costs amounted to between €20 and €28 million

($28-$39 million). 

Table 5. Key Parameters for Calculation of German FIT

Debt to equity ratio 59/41

Return on equity 12.3%

Interest rate 6%

Weighted average cost of capital 9.3%

Contract length 20 years

Installed costs 10,900 € per kW installed

(15,260 $/kW)

Inflation rate 2% per year

Drilling costs (% installed costs) 47

Power plant costs (% installed cost) 27

Development costs (% installed cost) 6

Labor 100,000 € per year

($140,000 per year)

Full load hours per year 8,000

Source: BMU (2011a)

It should be noted that the weighted average cost of capital of 9.3% reflects costs of capital for 

the exploration, power plant construction, and operation phases. The German government 

analysis assumed that the exploration phase is 100% equity financed, with a 20% return on 

equity (ROE) (BMU 2011a). At the end of the development process, it is assumed that the 

project will secure permanent financing with a debt to equity (D/E) ratio of 70/30, an 11% ROE 

and a 6% interest rate. The weighted average return on equity from exploration to construction is 

12.3% and the weighted average D/E ratio is 59/41.

 44 In almost all cases, the initial drilling cost assumptions from previous years had been exceeded by 70% (BMU 

2011a). In order to further reduce drilling risks, the German government also created a grant program to support 

drilling parallel with the adjustments to the FIT.
24

3.3.3.2 Geothermal FIT Policy and Payment Level Setting in Spain

Spain’s FIT has gained international attention because it has supported a strong and sustained 

wind energy market growth (GWEC 2011) and because it created an unprecedented (and shortlived) solar photovoltaic market boom in 2008 (Ciesielska et al. 2011). 

Most of the Spanish FIT payment levels are based on the generation costs of each specific 

technology. Geothermal, however, does not receive a cost-based payment and instead receives a 

general payment available to “emerging” technologies such as wave power, ocean thermal 

energy conversion technologies, and tidal power (Jacobs 2012). 

The payment available to geothermal power plants in Spain has remained relatively stable over 

the years. The initial emerging technology tariff of 6.73 €cent/kWh (9.42 ¢/kWh) was enacted 

into law in 1999. From 2004-2007, the tariff was set at 90% of the average retail electricity rate, 

which was 6.49 €cent/kWh (9.09 ¢/kWh) in 2004 and 6.6 €cent/kWh (9.24 ¢/kWh) in 2005 and 

2006. In the 2007 amendment to the FIT law, the fixed emerging technology tariff payment level

was set at 6.89 €cent/kWh (9.65 ¢/kWh) (Jacobs 2012). The available payment level, which is 

indexed to inflation, has since increased to 7.441 €cent/kWh (10.42 ¢/kWh) in 2011. 

The FIT payment level is available for the first 20 years of operation. After the first 20 years, 

geothermal generators are eligible for a slightly lower payment level that is available for the 

remainder of their operational life. Currently, the payment level available after the 20th year is 

7.0306 €cent/kWh (9.84 ¢/kWh).

No geothermal power has been developed to date in Spain (Sanchez-Guzman and Garcia-de-laNoceda 2010). This is primarily because Spain does not have strong hydrothermal resources on 

the mainland45 and likely because the current emerging technology FIT payment level is not high 

enough to support hydrothermal or EGS development. 

3.3.3.3 Lessons from Germany and Spain

There are several key lessons from experiences in Germany and Spain.

• Policy objectives matter. The manner in which policy objectives are interpreted through 

policy design can have a dramatic impact on the payment levels that generators receive. 

Germany’s decision to provide a bonus payment for EGS (separately from hydrothermal), 

for example, resulted in much higher payment levels than Spain’s technology neutral 

payment level for emerging technologies.

• Exploration risk can be considered. The payment level setting process can be used to 

reflect exploration and development risks. Setting the payment level based on generation 

cost enables policymakers to specify the degree to which exploration risk is assumed to 

be a project cost driver. In Germany, for example, these risks are reflected in the 

significant share of project costs that derive from the development and exploration phases 

and in the financial assumptions. Incorporating a greater degree of exploration and 

development risk into the payment level results in higher payment levels that can allow a 

broader range of potential projects to be developed (but also creates higher policy costs if 

there is a significant volume response). 

 45 Hydrothermal exploration is ongoing in the Canary Islands (Hidalgo 2011).
25

• Generic FIT payments may not be effective. The experience in Spain demonstrates that 

generic FIT payments not set based on generation cost may be too low to support 

geothermal development, particularly in countries without a strong hydrothermal 

resource.
26

4 FIT Design to Support Geothermal Development in the United 

States

4.1 Integrating FITs with Geothermal Targets

FITs can be designed specifically to support geothermal energy development in the United 

States, by considering FIT design issues that are specifically relevant to the unique 

characteristics of geothermal power plant development and operations in the U.S. context.

Many FITs are directly linked to national or state energy targets. The 2008 FIT law in Germany, 

for example, explicitly specifies that the intent of the FIT is to meet the national renewable 

electricity target of at least 30% by the year 2020. FITs can also be linked explicitly to targets for 

individual technologies. The linkage of FIT policies with mandatory renewable energy targets

gives investors a better sense of the policies’ horizons and increases investor security (Deutsche 

Bank Climate Change Advisors 2011). If geothermal FITs are established, they can be explicitly 

linked with mandatory geothermal targets through law or regulation. 

While there is not a national U.S. renewable electricity target, there are currently 29 states that 

have mandatory RPSs and 8 states that have voluntary goals. FITs are one of the potential 

mechanisms that can be utilized to achieve RPS targets and objectives (Cory et al. 2009). 

Fourteen states have established specific targets for solar electricity and several have established 

specific goals for other technologies or applications (e.g., wind, distributed generation, etc.). At 

present, however, opportunities to integrate geothermal FITs with existing RPS targets are 

limited since no targets specific to geothermal energy exist.

46

Policy design assessment for lowering investor risk. Setting mandatory and specific targets for 

geothermal can improve investor confidence in a state’s commitment to geothermal procurement. 

Setting specific mandates for geothermal can also form the basis for states to set geothermalspecific payment levels under PURPA and reduce concerns about states’ ability to set premium 

wholesale rates.

47

4.2 Technology Eligibility and Differentiation

FITs can consider technologies in two distinct ways. Eligibility refers to whether a certain 

technology, ownership type, or project size is allowed to participate in (or is excluded from) a 

 46 In New Mexico, carve-outs exist for solar and wind and geothermal shares a combined target with biomass, 

certain hydropower facilities, and selected other renewables (Doris et al. 2009). 47 If carefully structured, the relationship between FITs and RPS targets may help mitigate concerns about whether 

states have the authority to set FIT rates. According to federal law, states do not have jurisdiction to set premium 

payment rates for wholesale power. States do, however, have authority under PURPA to set rates based on avoided 

cost. Recent guidance from FERC seems to indicate that state targets for renewable electricity can allow PURPA 

rates to be set at the avoided cost of meeting those targets. To the extent that states have set a technology-specific 

target, avoided cost can be defined as the cost of that specific technology for purposes of meeting the target (Cory 

2011; Elefant 2011; Hempling et al. 2010). RPS laws do not set payment rates for specific technologies, but they can 

set targets for specific technologies. PURPA allows states to set rates, but not above avoided cost. By combining 

RPS technology-specific targets (under state law) with PURPA rate setting authority (under federal law), states 

could achieve results very similar to setting technology-specific FIT rates,but only for projects that register as 

qualifying facilities (QF) under PURPA. This arrangement may not apply for utilities or regional transmission 

organizations (RTO) that are exempt from signing new PURPA contracts, i.e., a utility would have to voluntarily 

agree to sign such a FIT/RPS contract. 
27

given policy, whereas technology differentiation refers to how FIT payment levels are targeted to 

certain technologies, sizes, ownership models, or locations. As can be seen in Tables 1 and 2, 

international FITs generally have few eligibility requirements outside of overall project size 

caps, but are differentiated in ways that reflect diverse policy objectives. U.S. policymakers 

would be able to customize FITs to support different types of geothermal installations in a 

number of different ways. Based on recent U.S. development trends, FIT differentiation 

strategies could include:

• Geothermal resource type. In order to support the different types of geothermal resources

that are currently being explored, including hydrothermal, EGS, co-produced and 

geopressured, FIT payment levels could be tailored and differentiated to have a different 

payment level for each resource type. Such an approach acknowledges that each of these 

applications has different cost structures and would ensure that each receives adequate 

revenue for project development, but not more than is required (e.g., payments 

appropriate for EGS might result in overpayment for other applications).

• Project size. A broad range of geothermal project sizes are currently under development

in the United States, with a significant percentage of proposed plants smaller than 

50 MW (Jennejohn 2011). Since economies of scale can exist as projects get larger, FIT 

payments could be differentiated by size in addition to technology. As shown in Table 2, 

Switzerland uses four project sizes: <5 MW, 5-10 MW, 10-20 MW and 20+ MW.48 

• Resource vintage. Geothermal development is proceeding both at existing and new 

geothermal fields. The risks and costs of identifying and developing a greenfield 

geothermal site are markedly different from those involved in expanding an existing site 

or building on an identified reservoir. Tariff differentiation could take this difference into 

account as well.

Policy design assessment for lowering investor risk. The choice of eligibility or differentiation 

does not have direct impact on project risk, although it will impact which projects are more 

attractive to investors. The primary concern from an investor perspective is whether the payment

available is sufficient to cover operating expenses and meet the required returns for the project.

49

4.3 Incorporating Exploration Expense in FIT Payment Levels

Setting FIT payments often includes assumptions about the cost of measuring the available 

resource (e.g., wind speed, solar insolation, and wood fuel availability). For geothermal, 

establishing resource availability and adequacy requires going beyond desktop study or relatively 

inexpensive meteorological measurements, requiring costly field-based study, which often 

includes significant exploration and test well drilling activity. These resource assessment 

activities can comprise a much greater share of total project cost and a greater portion of the 

overall development timeline than for other renewable energy technologies. For geothermal, 

 48 When offering higher payments for smaller projects, it is important to design a FIT to avoid gaming such as 

carving a larger project into smaller phases to access higher payments than would be merited by the combined 

project scale.

49 It is also important that the eligible geothermal technologies be explicitly defined if it is the intent of policymakers 

to support a specific type of plant. For example, policymakers may wish to specify which geothermal electric 

configurations are eligible (e.g., hydrothermal, EGS, co-produced, and geopressured) and perhaps include or exclude 

geothermal heat or heat pumps. 
28

there is also a greater risk that these initial resource exploration activities will not produce a 

viable project. Multiple locations may need to be explored before a specific project location 

enters the design and permitting process. As a result, the manner in which estimates of 

exploration expense are incorporated into FIT payment setting models is a serious consideration. 

Options for incorporating exploration expense include:

• Include estimated total exploration costs. Incorporate an assumed exploration success 

rate, investor return requirement, and commensurate level of exploration expense 

explicitly in FIT payment setting. Using this method, the developer’s exploration risk is 

reflected through a higher FIT payment level. Different assumed exploration success 

rates and investor return requirements can be selected to establish different FIT payments 

for regions with existing geothermal facilities compared to those which have yet to be 

proven. The modeled exploration costs and return requirements are a policy choice and 

can reflect a preference for more aggressive or conservative payment setting. 

• Include a fraction of estimated exploration costs. Attributing only a portion of actual 

exploration expenses to a project by assuming developers will cost-share exploration 

costs, exploration costs could be spread over several power plants, or that a portion of the 

costs could be decreased by other public-sector cost sharing.

50 

• Ignore exploration costs. No exploration costs assumed in payment setting.

Policy design assessment for lowering investor risk. Acknowledging and accounting for 

exploration costs in FIT payment setting is one of the most effective ways to reduce investor risk 

and encourage the flow of capital, from both existing and new sources, into geothermal project 

development. Assurance of a financeable contract that enables the recovery of reasonably 

incurred exploration expenses provides a signal to the market to invest, notwithstanding the fact 

that not every exploration is expected to produce a viable thermal resource.

4.4 Standard Pricing and Standardized Off-Take Contracts

While competitive solicitations play a critically important role in the renewable energy market 

place, their cyclical and often fast-moving announcement, bidding, and negotiation schedule 

favors renewable energy technologies with shorter development lead times than geothermal

projects. Developing a long-term, standard offer price and standard contract for specified eligible 

facilities is an effective tool for supporting long lead-time projects. Standard offer prices and 

contracts can reduce the expense associated with periodic solicitations by removing the bid 

security, legal, bid preparation, and other transaction costs of pursuing a competitive PPA. 

Policy design assessment for lowering investor risk. FITs provide generators with standardized 

prices and contracts that can reduce the contract price risk, transaction costs, and uncertainty of 

PPA negotiation. This has the potential to reduce investor return requirements and increase the 

pool of available capital.

4.5 Payment Structure

As shown in Table 1, FITs can be structured as fixed “all-in” prices (that include the power and 

the attributes, or renewable energy certificates) or premium payments that float on top of (and 

 50 In order to support this approach, such supplemental policies would need to be confirmed or developed in tandem 

with the FIT and their relationship formally linked.
29

are additive to) wholesale market prices.51 In general, premium payment options are utilized to 

encourage generators to participate in wholesale electricity markets in order to support deeper 

and broader competition, and to encourage generators to respond to market signals. Geothermal 

power plants are baseload generators and unlikely to adjust their behaviors based on market 

prices. Moreover, several electricity markets in the United States do not have competitive 

wholesale markets with liquid spot prices. As a result, premium payments may not be a practical

option for geothermal FITs in some locations.

Policy design assessment for lowering investor risk. From the perspective of investors, fixed 

prices52 are lower risk than premium payments that leave greater uncertainty because the total 

payment level varies with market prices.

4.6 Contract Duration

Geothermal plant life is typically assumed to be at least 30 years (Lovekin and Pletka 2009; PT 

Castlerock Consulting 2010). As can be seen in Table 1, international FITs are paid out over 10-

20 years, with the exception of Spain which guarantees a payment for the entirety of project life 

(albeit at a lower payment level after year 20). As shown in Figure 6 in Section 5, under a costbased FIT, a longer contract length would lower the $/kWh payment paid to generators since 

project costs would be spread out over a longer period of time. A longer-term contract would 

therefore create greater opportunity for geothermal contracts to serve as an effective hedge 

against fossil fuel prices (or even create immediate savings if the avoided cost rises above the 

tariff payment). 

Longer contract durations also provide increased revenue certainty for project investors. This is 

likely to increase the number of investors willing to finance geothermal projects and reduce the 

cost of capital. Reductions in the cost of capital would stem from both the increase in the number 

of active investors and the reduction in risk provided by the long-term, stable cash flows.

Policy design assessment for lowering investor risk. To the extent that post-contract market 

revenue projections are utilized in setting a FIT payment,

53 longer contract durations reduce 

investor risk by reducing the proportion of lifetime revenues exposed to market price risk. If, 

however, FIT payments are designed to attain target investor returns prior to contract 

termination, investors should be indifferent to contract duration.

54

 51 A third option is the “spot market gap” structure in which the generator is guaranteed a fixed revenue and paid the 

difference between that fixed revenue (akin to the strike price in a contract-for-differences) and the wholesale 

market price over time (Couture and Gagnon 2010). This approach creates a similar risk profile, from an investor 

perspective, to a fixed, all-in price structure. 52 There are also different ways to structure fixed price payments. Offshore wind payments in Germany, for 

example, are designed with higher payment levels upfront and lower payment levels in later years in order to “front 

load” project revenues. This enables projects to more quickly pay off their debt (Couture et al. 2010). 53 I.e., the FIT rate calculation presumes revenue post-contract rather than recovering all up-front investment during 

the term of the FIT.

54 Different types of investors may have different perspectives on whether shorter or longer-term durations are 

preferable. Some investors may wish to realize their expected return in a shorter period of time whereas other 

investors (e.g., pension funds) may wish to invest in contracts with long-term revenues in order to better match their 

long-term liabilities. 
30

4.7 Policy and Contract Timing

Core characteristics of geothermal development, particularly long development horizons and the 

presence of substantial exploration risk, make aspects of policy timing particularly important. To 

have its greatest benefit in mitigating developer risk and therefore reducing financing costs, a 

FIT policy would (1) be of sufficiently long duration to be available upon project commercial 

operation to a developer investing in exploration-phase activities and (2) set and hold a FIT price 

available during the operation of a geothermal project well in advance so a geothermal developer 

could make exploration and development investment decisions based on specific and reliable 

revenue expectations. Such a FIT policy could reduce or eliminate the need for developers to 

build in a risk premium due to competitive RFP processes.

Establishing FIT cost-containment mechanisms, such as volume caps, price adjustment 

mechanisms, and/or automatic triggers for policy review, appear to help avoid FIT 

oversubscription and provide greater certainty about policy outcomes (Kreycik et al. 2011). It is 

worth noting that the experiences with oversubscription have been primarily with FITs 

established for solar and wind power, technologies with substantially shorter lead times and 

greater rates of technological advance (price evolution) than geothermal. For this reason, the 

potential for an explosive project development response to a geothermal FIT would appear far 

lower than for solar and wind; policymakers should have adequate time to adjust. Nonetheless, 

cost containment and policy review mechanisms appear to be a standard practice for FIT 

implementation today. If caps are implemented for geothermal, it is useful to acknowledge the 

policy tradeoffs. On the one hand, implementing volume caps and typical price adjustment 

mechanisms can undermine the benefit of assured market access and can increase developer risk. 

On the other hand, holding a price and access open for as long as 4- 7 years in advance (i.e., the 

development horizon for a geothermal plant) could restrict the establishment of meaningful cost 

control practices. 

Policy design assessment for lowering investor risk. At a minimum, the presence of a stable FIT 

policy that could be relied on by an early-stage geothermal developer investing in explorationphase activities could decrease developer risk. A policy designed to balance investor risk 

mitigation with policymaker/regulator needs to minimize ratepayer risk might have some or all 

of the following characteristics:

• Long duration. Be established for a sufficiently long duration to span the period for 

securing a long-term revenue stream from exploration decision to commercial operation.

• Developer queue with capacity cap. If a capacity cap is established for a geothermal FIT, 

it may be accompanied by a developer queue to provide regulators with a means to track 

development progress in response to the FIT while providing developers in the queue 

with the ability to rely on access to the FIT. This might include developer registration for 

a specific number of MW, accompanied by a modest $/MW deposit to maintain a queue 

position. First registrants in such a queue might receive a longer assured access to known 

price than developers later in the queue. To avoid speculative queuing and allow for 
31

removal of developers unprepared to move forward, an increasing deposit might be 

required over time to maintain a preferred queue position55.

• Adequate lead time for policy adjustments. Allow regulators to establish or modify 

quantity/cost caps and tariff prices with a lead-time that balances the needs of 

policymakers to contain costs and the value to developers of assured access to a FIT at 

known price. For projects whose remaining development activities are expected to extend 

beyond this lead-time, their investors will need to understand that caps might be reached 

(if applicable) and that adjustments might be made to the nonetheless cost-based tariff. 

The lead-time could be fixed (e.g., 4 years), or might be adjusted within a range based on 

the MW in the queue.

4.8 Payment Indexing Over Time

In some jurisdictions, the FIT payment (or a portion thereof) is adjusted annually to account for 

inflation. Since renewable generators such as solar and wind have small operation and 

maintenance (O&M) expenses, some analysts have argued that they do not require annual 

inflation adjustments (Boonin 2008). Geothermal plants, however, can have proportionately 

higher O&M expenses. In addition to power plant maintenance, geothermal power plants also 

require well field maintenance. Geothermal field production, for example, will decline over time 

depending on factors such as plant capacity and the rate of natural reservoir replenishment. In 

order to compensate for geothermal resource declines, power plants drill additional “make-up” 

wells to boost production. It has been estimated that annual make-up drilling costs correspond to 

5% of initial drilling cost (Hance 2005). During the past several years, the cost of drilling has 

been particularly volatile, rising up to 64% in the United States between 2004 and 2008 and then 

subsiding by 30% between 2008 and 2010 (Augustine et al. 2010; Lovekin and Pletka 2009). 

Given both the significance of make-up drilling costs and the volatility, an alternative to using a 

general inflation rate as an index for FIT payment adjustment is to index geothermal payments to 

follow the cost of drilling over time, provided that a representative, independent, and visible 

drilling cost index is available.

Policy design assessment for lowering investor risk. Given the potential size of geothermal 

maintenance O&M expenses, indexing a portion of a FIT payment to inflation, drilling costs,

and/or other relevant indices would reduce project risk and assure investors that long-term O&M 

costs were considered.

4.9 Adjusting the Policy

There are a range of different approaches to adjusting FIT policies over time in order to reflect 

changing market conditions and policymaker objectives. Adjustments can be characterized by 

what triggers the adjustment and the type of adjustment that is made. Triggers can include 

milestones such as the installation of a certain amount of capacity or the passage of a specified 

amount of time. The type of adjustments that can be made include an automatic adjustment to the 

available payment level, a hard cap on the policy after which no new FIT contracts are available, 

 55 There is a tradeoff when considering caps, queues, and security deposits. On the one hand, creating a “high bar” 

for entering the queue by establishing high security deposits, etc., could better ensure that only “serious” projects 

will enter the queue. On the other hand, high barriers to entry may shut out or deter smaller developers from 

participating in the market. This barrier to entry may constrain the achievement of specific economic development 

or industrial objectives (e.g., the encouragement of local developers or the deployment of innovative new 

technologies). 
32

or the instigation of a full policy review (Deutsche Bank Climate Change Advisors 2011). In 

Germany, for example, an automatic price decline is triggered every year, whereas a full policy 

review is triggered every four years (BMU 2011b). Policy adjustments are a key concern for 

technologies such as solar photovoltaics (PV) that have short development timelines, an almost

universally available resource, and the ability to scale-up rapidly. Since geothermal development 

timelines are long, however, time-based policy adjustments may not be necessary and instead the 

policy can link adjustments to the achievement of capacity targets or make them contingent upon 

the outcomes of periodic review. 

Policy design assessment for lowering investor risk. An ideal policy would have infrequent 

adjustments made on a schedule that is known in advance and would utilize a process that is as 

transparent as possible. 

4.10 Setting Geothermal FIT Payment Levels in the United States

Depending on a given state’s policy objectives, its geothermal resource, and other factors such as 

barriers, risks, and existing policies, actual FIT designs could vary widely. We considered the 

ability of a policy design element to lower investor risk as a simple analytical metric to 

distinguish between different design options. The evaluation criteria used to choose between 

different FIT designs will also vary from state to state and may give weight to stakeholder groups 

beyond investors (e.g., ratepayers). Moreover, this section does not attempt to compare or 

contrast FIT designs with other policy types.

Table 6 summarizes several of our findings.
33

Table 6. Key Findings Regarding FIT Policy Design in the United States

Policy Design Issue Design Option Potential for Lowering Investor Risk

Integrating FITs with 

Geothermal Targets

Setting mandatory and specific targets for geothermal can improve investor 

confidence in a state’s commitment to geothermal procurement. Setting specific 

mandates for geothermal can also form the basis for states to set geothermalspecific payments under PURPA and reduce concerns about states’ ability to set 

premium wholesale rates.

Technology 

Eligibility and 

Differentiation

The choice of eligibility or differentiation does not have direct impact on project 

risk. What matters from an investor risk perspective is whether the FIT payment

available to geothermal generators of various sizes and types is sufficient to 

cover operating expenses and meet investors’ required returns.56

Incorporating 

Exploration 

Expense into FIT 

Payments

Accounting for exploration costs when setting the FIT payment (i.e., by building 

exploration cost assumptions into the price setting model) reduce investor risk 

and encourage the flow of capital into geothermal development. Assurance of a 

financeable contract that enables the recovery of some level of estimated 

exploration expenses provides a signal to the market to invest, notwithstanding 

the fact that not every exploration is expected to produce a viable thermal 

resource.

Standard Pricing 

and Off-Take 

Contracts

FITs provide generators with standardized off-take contracts that can reduce 

power project contract price risk and transaction costs. This has the potential to 

reduce investor return requirements and increase the pool of available capital.

Payment Structure Fixed FIT prices are lower risk (from the investors’ perspective) than premium 

FIT payments, reducing the uncertainty associated with exposure to fluctuating 

market electricity prices.

Contract Duration If post-contract market revenue projections are utilized in setting a FIT payment, 

longer contract durations reduce investor risk by reducing the proportion of 

lifetime revenues exposed to market price risk. 

Policy and Contract 

Timing

The presence of a stable FIT policy that could be relied on for a period of several 

years by an early-stage, exploration-phase geothermal investor could decrease

overall risk, thus reducing/eliminating developer risk premiums for RFP bids.

Payment Indexing 

Over Time

Given the potential size of geothermal operations and maintenance expenses, 

indexing to inflation, drilling costs, and/or other relevant indices would reduce the 

risk that project revenues will be adequate.

Adjusting the Policy Adjustments that are made infrequently and on a schedule that is known in 

advance and using a process that is as transparent as possible increases 

investor confidence. Geothermal policies may not need to be adjusted as 

frequently as technologies with rapidly declining costs such as solar PV, or with 

shorter development timelines like solar PV and wind.

 56 Different technologies, for example, may have different technological risk profiles. Technological risk, however, 

should be reflected in the financial assumptions utilized to set the cost based rate and should therefore be reflected in 

the rate itself. 
34

5 Analyzing the Impact of Policy Design Choices on the 

Levelized Cost of Energy from Geothermal Electricity 

Generators

5.1 Using LCOE to Inform FIT Payment Level-Setting

FITs are typically set using either a constant price over the term of the contract, or a fully- or 

partially-escalating payment. This analysis uses the nominal LCOE as the evaluation metric for 

illustrating the quantitative impact of FIT policy design choices.

57 The nominal LCOE is the 

constant payment, expressed in nominal cents per kWh, which is sufficient to cover all of the 

costs of building and operating a power plant over its economic life, including meeting the 

minimum return requirements of investors. An LCOE has the equivalent economic effect over 

the analysis term (i.e., same net present value) as a time-varying payment stream covering the 

total cost of building and operating a generating plant over its life. This section takes a costbased approach to FIT payment-setting and calculates a long-term contract value,

58 which will 

enable the modeled geothermal project to secure financing by both covering its operating 

expenses and meeting investors’ minimum return requirements. For these purposes, the 

calculated LCOE over the duration of the FIT is equal to the assumed FIT payment. 

While assuming that the calculated LCOE is equivalent to the FIT payment can provide valuable 

insights for the purposes of this report, the cost of geothermal projects will vary based on a range 

of factors including project technology, size, and resource quality. Furthermore, the broader 

policymaking context may include additional objectives, such as rapid deployment, diversity in 

project size or location, or least cost deployment, which may result in selecting a FIT payment

that is more aggressive or more conservative59, respectively (as noted in Section 3.3.3). For these 

reasons, a single calculated LCOE model result can be used directly as the FIT payment, but 

policymakers may wish to use analyses such as this one to inform a FIT payment-setting process 

taking into account both cost variation and policy objectives. With this caveat, the terms LCOE 

and FIT payment (and references to ranges of these values) are used interchangeably for the 

remainder section.

5.2 Objectives: Understanding the Potential Impact of FIT Design Choices

A FIT represents not only the availability of a long-term contract, but also a potential shift in 

investor confidence with respect to geothermal investment. While the technical risk of 

identifying a viable resource remains (i.e. exploration risk), a FIT or similar policy alleviates the 

risk of whether a viable contract will be available to provide a means to sell the output and attract 

financing. 

To provide a simplified illustration: if the probability of successful exploration for an 

economically-viable geothermal plant in a specified region is thought to be 33%, and the 

 57 This analysis and the associated model are intended to be used primarily by policymakers considering FITs to 

support geothermal electricity development. In addition, this analysis and model may also be used by stakeholders in 

the policymaking process, including geothermal developers, financiers, and utilities. 58 A 20-year FIT is assumed in this analysis. Sensitivities are also included that test the change in LCOE for FITs of 

10, 15, 25, and 30 years.

59 The term ‘aggressive’ in this usage connotes a FIT rate intended to support a range of viable geothermal 

installations, while a ‘conservative’ FIT would only support the most cost-effective geothermal installations.
35

developer believes it has a 1-in-3 chance of securing a long-term power contract, then the

developer’s probability of recovering its exploration investment and securing permanent 

financing to construct and operate a power plant is 33% * 33% = 11%. With a FIT available to 

guarantee access to a cost-based revenue stream, the risk of contracting and permanent financing 

is removed (i.e., 100%) and the odds of the developer’s recovery of exploration capital increase 

to 33%, the probability of successfully identifying a viable resource. A simple understanding of 

risk and reward tells us all we need to know: the investment with an 11% probability of success 

will need to have a higher return potential than the investment with a 33% probability. The 

higher risk environment will also make it more difficult to attract the capital necessary to fund 

development activities. The cost of investment capital available to a geothermal project will 

behave similarly: the cost of capital decreases as the probability of success increases. Similarly, 

the availability of capital will increase as probability of success increases.

Competitive procurement for long-term contracts can mitigate only some of this risk, providing 

the possibility of access to a long-term fixed revenue stream with a credit-worthy entity but 

without the assurance of either the payment level or access to the revenue (both dictated by 

whether the project wins the competitive processes). Where binding policy support is not in 

place over a horizon long enough to earn a commercial return, or where long-term contracts are 

not offered, there is even less assurance of access to a revenue stream sufficient to attract 

financing. 

It is difficult to precisely project the degree to which financing costs might be reduced. Using a 

range of representative geothermal cost data and ‘what if’ analysis, the potential impact on 

LCOE of reducing financing risk to geothermal developers was explored. It is intended to meet 

several objectives for policymakers with respect to LCOE analysis and FIT payment-setting, 

including:

• To identify the range of LCOEs that result from different assumptions about the cost, 

duration, and financing terms of geothermal development;

• To use these LCOE results to consider how to craft geothermal (FIT) policy that brings

the greatest reduction in geothermal LCOE;

• To illustrate how a geothermal FIT can increase the availability of and/or reduce the cost 

of investment capital necessary to finance the exploration, development, and construction 

of geothermal facilities. 

These objectives are accomplished herein by identifying a range of geothermal cost, financing,

and operational input assumptions and conducting sensitivity analyses to establish a continuum 

of LCOE results for representative geothermal projects. Varying key inputs such as development 

duration and financing terms demonstrate potential market responses to different FIT designs. 

The resulting range of LCOE values is a proxy for the potential continuum of FIT payments that

might be considered in particular circumstances and locations. Examining the sensitivity analysis

can help policymakers identify FIT designs and other incentives that help minimize geothermal

LCOE while making investment attractive.
36

5.3 Methodology: Literature Review and CREST Modeling

5.3.1 Literature Review

A range of geothermal cost, performance, and financing inputs was developed through a detailed 

literature review. Publicly available geothermal cost research was compared and used to develop 

the series of inputs for LCOE modeling. A summary of the literature review is provided in 

Appendix A. 

5.3.2 The CREST Model

Geothermal LCOEs were subsequently calculated using the CREST model. NREL developed

CREST—an after-tax discounted cash flow model—based on a survey of international modeling 

practices and U.S. policy requirements (details captured in Gifford et al. 2011). A geothermalspecific version was released in 2011 and was used for this analysis. 

CREST is an economic cash flow model designed to enable PUCs and the renewable energy 

community assess projects, design cost-based incentives (e.g., feed-in tariffs), and evaluate the 

impact of tax incentives or other support structures. CREST is a suite of three analytic tools, for 

solar (photovoltaic and solar thermal), wind, and geothermal technologies, respectively and it 

can be downloaded at https://financere.nrel.gov/finance/content/crest-cost-energy-models. The 

CREST models were designed for use by state policy makers, regulators, utilities, beginning 

developers or investors, and other stakeholders. Inputs include the variables under study in the 

sensitivities and scenario analysis (e.g. installed costs, O&M costs, financing assumptions, 

contract duration, etc.). The models allow users to:

• Estimate the Year One cost of energy (COE) and levelized cost of energy (LCOE) from a 

range of solar, wind and geothermal electricity generation projects

• Inform the process of setting of cost-based incentive rates

• Gain understanding of the economic drivers of renewable energy projects, which lead to 

the calculated COE and LCOE

• Understand the relative economics of generation projects with differing characteristics, 

such as project size, resource quality, location (e.g. near or far from transmission) or 

ownership (e.g. public or private).

5.3.3 Enhancements to Geothermal CREST

The co-authors of this report were also the architects of the CREST model. As part of the scope 

of this report, NREL directed several enhancements to the geothermal CREST model to facilitate 

the analysis contained herein. Specifically, adjustments were made so that the capital structure 

(combination of debt and equity) and cost of invested capital (equity return requirement and debt 

interest rate, if applicable) can be specified separately for the exploration drilling,

60 confirmation

drilling, site construction, and permanent financing phases. 

Because CREST allows model users to input different financing assumptions for each phase of

geothermal development, policymakers can test the sensitivity of geothermal LCOE to the 

availability and cost of capital.

 60 The exploration and confirmation phases are assumed to be 100% equity funded and does not include a provision 

for debt financing.
37

5.3.4 Modeling the Phases of Geothermal Development and Financing

The development of a geothermal power plant includes at least four distinct activities, modeled 

in this analysis over three phases of development. For cost estimating purposes, and based on the 

literature review, this study views geothermal development as including the following four 

activities, each with its own financing assumptions:

• Exploration – desk-top studies, initial surface exploration, temperature gradient drilling, 

and, in some cases, deep exploratory drilling61

• Confirmation – continued deep exploratory drilling, resource assessment, and initial 

production wells

• Well Field Construction – completion of well field drilling, including remaining 

production wells and injection wells

• Power Plant Construction – including interconnection.

The manner in which geothermal development is financed influences LCOE and FIT paymentsetting. Geothermal projects typically involve different financing sources at different phases of 

project development (Deloitte 2008; Richter 2009; Salmon et al. 2011). These sources come in 

different ratios (e.g., debt to equity) by phase, and have different risk profiles and terms (e.g.,

return requirements, interest rates, and repayment schedules). For the purpose of this analysis, 

the CREST model analyzes geothermal development as having three financing phases, each with 

its own cost and financing assumptions. Equity investments are assumed to fund both the 

exploration and confirmation drilling phases. While some forms of debt (including so-called 

mezzanine debt, which has characteristics of both debt and equity) may have once been available 

for confirmation drilling and related activities, this analysis assumes that debt is first introduced 

at the well field and power plant construction phase once the availability and adequacy of the 

geothermal resources has been entirely proven, and once revenue expectations have been 

established. Well field and power plant construction are assumed to be financed at the same time, 

on the same terms, and occur more or less in parallel.

5.4 Inputs for Calculating Geothermal LCOE

As described in Section 3, a key component of the FIT payment-setting process is determining

the range and complexity of modeling inputs.62 The CREST model used for this analysis allows 

for an appropriately-detailed set of installed cost, performance, incentive, and financing 

assumptions. Each modeling input will have a continuum of possible values. Selecting which 

points on the continuum are used for modeling can be tied to policymaker preferences for more 

aggressive or conservative tariffs. 

It is important to understand that the inputs and associated LCOEs are intended to be illustrative 

rather than representative of the cost of a specific operating or proposed geothermal project. The 

most important function of this analysis is to explore the relative change in LCOE caused by 

changes in each of the factors explored in the sensitivity analyses, and not the absolute value of 

 61 Geothermal market participants do not universally agree on the distinction of exploration and confirmation costs, 

particularly as it relates to deep exploratory drilling.

62 A recent NREL study provides a detailed discussion of modeling inputs and their context (Gifford et al. 2011).
38

the calculated LCOE itself. A range of assumptions has been used for this report that, based on 

the literature review, should capture the majority of project costs and characteristics.

5.4.1 Exploration Success, Confirmation Duration, and Project Cost Inputs

As described in Section 4.3, incorporating expected exploration expenses in the FIT paymentsetting process is critical to establishing investor confidence and spurring investment. The 

success of geothermal exploration can vary widely, including the difference between exploring 

for the expansion of production in an area where geothermal resources have already been found 

and exploring in unproven territories. It is assumed that the costs of specific exploration efforts 

will be the same whether or not they are successful. For instance, drilling an exploratory well to 

a certain depth should cost about the same whether or not it yields a viable resource. Table 7 

below defines the range of exploration success rates considered. These exploration success rates

represent the probability, on average, that a series of exploration expenditures will result in the 

identification of a viable resource. These rates also denote the number of exploration wells 

drilled and associates “hit rate.” For example, a rate of 50% denotes identification of the 

geothermal resource on the second exploration well. By comparison, a rate of 10% denotes that a 

resource is not identified until the 10th exploration well drilled. The costs associated with 

exploration activities are provided later in this section and include both drilling and nondrilling63 activities. The exploration success rate is used to determine the total cost incurred 

before a viable resource is identified. This analysis does not include a scenario in which 

exploration capital is exhausted and no geothermal resource is found because LCOE cannot be 

calculated for such a scenario. Clearly, however, such outcomes are possible and perhaps warrant

a probability assignment by project developers and investors. 

Table 7. Range and Definition of Exploration Success Rate

Input Category ← Range of Input Values →

 Low Cost High Cost

Exploration Success Rate (%) 50% 33% 25% 10%

Sources: Hance (2005); Augustine et al. (2010)

The expected duration of the confirmation drilling phase could also be considered during the FIT 

payment-setting process. Excluding the costs associated with this phase from consideration in 

establishing a FIT would likely yield too low a revenue stream for many investors. As described 

in Section 5.3.4, the confirmation phase is assumed to include continued deep exploratory 

drilling, the completion of the resource assessment, and the drilling of initial production wells. 

This phase is assumed to be financed using 100% equity contributions. Without the benefit of a 

FIT, it is possible that certain development expenditures might be delayed, and the project 

timeline thus extended, until the project proponent successfully identifies and negotiates a PPA 

sufficient to enable permanent financing. Such delay makes the project less attractive to 

investors, who may compensate for this risk by requiring a higher return on invested capital. This 

translates into a higher LCOE than for a project that is able to proceed through development 

more efficiently and expeditiously due to the presence of a FIT that provides investors with 

power plant revenue certainty, even while the resource assessment is being completed. 

 63 Non-drilling exploration costs are held constant for the purpose of this analysis.
39

Table 8. Range of Confirmation Phase Duration

Input Category ← Range of Input Values →

 Low Cost High Cost

Confirmation Phase Duration 1.5 years 2 years 3 years

Sources: Augustine (2012)

Table 9 below summarizes the range of assumed geothermal project cost inputs, by development 

phase. These values are based on the aforementioned literature review and are described in more 

detail in Appendix A. The range of exploration cost represents differing industry opinion

regarding the cost of exploration assuming an average 25% success rate. This analysis employs 

both the range of exploration cost uncertainty and the range of success rate uncertainty.

Table 9. Range of Geothermal Cost Inputs

Cost Category ← Range of Input Values for Cost Uncertainty64 →

 Low Cost High Cost

Exploration Costs ($/kW) $100 $175 $225

Confirmation Costs ($/kW) $300 $550 $750

Site Development Costs ($/kW)

(well-field + power plant 

construction) 

$2,000 $3,000 $4,000 

TOTAL $2,400 $3,725 $4,975

Fixed O&M ($/kW-yr) $40 $50 $60 

Variable O&M (cents/kWh) 2.25 3.50 4.50

Sources: Exploration Costs: Sison-Lebrilla and Tiangco (2005), Hance (2005), Salmon et al (2011)

Confirmation Costs: Sison-Lebrilla and Tiangco (2005), Hance (2005)

Site Development Costs: Sison-Lebrilla and Tiangco (2005), Hance (2005), Geothermex (2010), 

Augustine et al. (2010)

Fixed O&M: Sison-Lebrilla and Tiangco (2005), Hance (2005), O'Donnell et al. (2009)

Variable O&M: Hance (2005), O'Donnell et al. (2009), Lovekin and Pletka (2009), Augustine et 

al.(2010), Geothermex (2010)

Table 9 also includes operations and maintenance (O&M) cost estimates. This study’s literature 

review finds that fixed and variable O&M cost categories are often inadequately defined, and 

that the two categories frequently overlap with each other from study to study. According to 

O’Donnell et al. (2009), fixed expenses include power plant operations and maintenance while 

variable O&M includes field, general O&M, and rework; make-up wells; and relocation injection 

wells. The O&M cost estimates are based on the literature review more broadly, but may be best 

 64 Assumes illustrative 50 MW project. Per literature review (see Appendix A), exploration assumes 25% success 

rate, confirmation assumes 60% success rate, and all costs assume economies of scale associated with a 50 MW 

project.
40

aligned with the allocation of costs described by O’Donnell. Additional detail on all cost 

estimates can be found in Appendix A.

5.4.2 Financing Inputs

Beginning in 2008, the global financial downturn shrank the pool of investors available to 

renewable energy projects. The decline in federal income tax liability associated with deep 

recession triggered a reduction in the number of viable tax equity investors—those able to 

effectively monetize the substantial tax benefits generated by renewable energy project 

investments. Despite this trend, this analysis assumes the continued availability of the Investment 

Tax Credit65 (ITC) and assigns equity rates of return that are intended to represent the investor’s 

efficient use of both cash and tax benefits.

At the same time, the economic downturn triggered among lenders the perception of increased 

market risk. This resulted in a shortening of loan tenors (durations), an increase in lender debt 

service coverage requirements, and an overall decline in the amount of debt offered to any 

individual project (Salmon et al. 2011). Debt remains available at the construction stage, with 

lenders requiring a 25%-45% equity contribution (Salmon et al. 2011). The inputs to this analysis 

are intended to reflect the current availability of debt, consistent with the literature review. The 

aforementioned enhancements to the geothermal CREST model account for perceptions of 

market risks by differentiating capital sources and return requirements by development phase. 

The table below summarizes the range of financing inputs.

Table 10. Range of Geothermal Financing Inputs, by Development Phase

Project Phase Capital 

Structure 

← Range of Input Values for Return or Interest Rate →

Low Cost High Cost

Exploration 100% Equity 50% 100% total return 2X (200%) 

Confirmation 100% Equity 15% 30% annual return 45% 

Site Development

(Construction 

Financing) 

35% Equity

65% Debt 

15%

5.5% 

Equity @ 20% annual return

Debt @ 7.5%2 interest rate

25%

10% 

Site Development

(Permanent 

Financing) 

45% Equity1

55% Debt

10%

5.5% 

Equity @ 15% annual return

Debt @ 7.5%2 interest rate

20%

10% 

DSCR66 1.60 times coverage

Financing Term: 18 yrs

PPA Term: 20 yrs

Sources: Salmon et al. 2011; Hance 2005; REFTI 2011

1) Includes cash, tax and developer equity

2) Use of the same interest rate assumption for both construction and permanent debt represents the balancing of two 

different risk profiles. Construction debt bears the risk of non-completion, but over a short time period. Permanent 

debt bears the risk of operations, but over a much longer time period. For this analysis, these risks and terms are 

assumed to balance and market interest rates for both activities are assumed to be the same.

 65 A federal Investment Tax Credit of up to 30% of eligible expenses is available to geothermal electricity projects 

coming into service on or before December 31, 2012. Thereafter, the geothermal ITC is expected to revert to its 

historic level of 10%. 66 DSCR stands for debt service coverage ratio.
41

5.4.3 Other CREST Inputs Required for Calculating LCOE

Using CREST for this LCOE analysis requires defining additional assumptions about the plant’s

specifications and operation. These estimates can be found in Appendix B along with additional 

detail on the literature review. As with the estimation of installed costs, these assumptions are 

intended to provide a reference case rather than be representative of any specific operating or 

proposed facility. 

Among these additional inputs is the assumption that the modeled geothermal project will 

operate for 30 years, but receive payment through a FIT only through the first 20 years. Rather 

than ignore the revenue potential of the last 10 years, the CREST model allows the user to 

include an electricity price forecast that it then applies to any gap between the assumed FIT 

contract duration and the project’s useful life.67 For this analysis, an illustrative electricity 

market price forecast is provided in order to account for project revenue for years 21 through 30, 

inclusive. The market price trajectory is calculated using a year-one rate of $40/MWh (in 2012) 

and an escalation rate of 2.0% (and again, is generic and does not represent actual electricity 

price projections of any particular location). 

5.4.4 Explaining the Range of Possible Inputs

The range of input values presented above is insufficient to provide FIT payment-setting insight 

on its own. These values provide the foundation for a sensitivity analysis that quantifies the 

change in LCOE with variation in selected key inputs. The range of financing inputs 

represents—for illustrative purposes—the potential reduction in cost of capital associated with 

the establishment of a FIT, which can increase investor certainty and translate into reduced risk. 

Of course, the magnitude of reduction of any input will be situation specific, personnel specific,

and difficult to project. However, the calculation of LCOE over a wide range of plausible inputs,

selected from detailed cost studies, reveals which inputs have the greatest impact on LCOE and 

therefore the greatest risk reduction opportunities. This analysis might help policymakers 

consider which FIT policy design options are most attractive, depending on their FIT policy 

goals.

5.5 Reference Case Results

A reference case was derived by modeling LCOE in CREST using the central estimate of each 

input value described above, and a 25% exploration success rate. The reference case is valuable 

for comparison purposes only; its LCOE is neither intended to reflect the cost of any specific 

project nor represent a recommended contract rate. The calculated LCOE for the reference case 

was 10.85 cents/kWh.

5.6 Sensitivity Analyses: LCOE Results and Lessons Learned

The purpose of this analysis is not to determine the precise cost of any given geothermal system, 

but rather to demonstrate the impact that a FIT might have on geothermal LCOE. 

This is done by changing key inputs from the reference case one or two at a time in order to 

understand how each factor impacts the cost of geothermal electricity. With these impacts 

measured, policymakers can gain insight into how a FIT might effectively decrease some of the 

 67 Importantly, investors may not make the same assumption. Many investors —particularly debt lenders—prefer to 

assume revenues only exist during the length of the PPA and thus require that financing term be shorter than PPA 

term (to protect themselves so they are fully paid back even if the project underperforms in the early years).
42

risks that contribute to the LCOE. Policymakers can also gain insight into how to differentiate 

FIT payments between areas where geothermal has already been proven and areas where it has 

not. The former may be assumed to have a higher exploration success rate and therefore a lower 

LCOE and a lower required FIT payment to attract investment.

We conducted a series of sensitivity analyses68 that explore changes in LCOE by varying:

• The exploration success rate

• The duration of the confirmation stage

• The FIT contract duration

• Total project cost

• Investor return requirements (equity and debt, if applicable) by development phase.

The result of these sensitivity analyses is a range of geothermal LCOE extending from 8.65 to 

13.85 cents/kWh, relative to the reference case LCOE of 10.85 cents/kWh. 

The impact on LCOE due to a reduction in soft costs and transaction costs that might result from 

the availability of a FIT, as discussed in Section 4, could also be examined. While we have not 

attempted to quantify such costs herein, the impact of reducing these costs, which ultimately 

reduce the cost subject to permanent financing, is embedded in the examination of the sensitivity 

of LCOE to total project cost.

5.6.1 Exploration Success Risk

Changes in exploration success rate and return requirements represent the impact on LCOE of a 

range of investor risk perception with respect to the earliest phase of geothermal development. If 

the presence of a FIT can provide the earliest investors with a greater degree of confidence that a 

geothermal resource, if validated, will result in a financed and constructed project, then such 

investors may be willing to make their capital available with lower expected return requirements 

to reflect the later reduction in risk due to the presence of a guaranteed long-term contract. If 

achieved, this reduction in the cost of capital can be translated into lower FIT payments. 

The reduction in perceived risk by exploration investors assumes that some projected quantity of 

exploration expenses are explicitly reflected in the payment-setting process, and that the 

exploration success rate assumptions used to set the FIT payment align with the geothermal 

developers own view of a project’s development prospects. Consider an example in which two 

developers, A and B, expect the same cost for exploration activities, but have differing views of 

expected success rate. Developer A assumes that six exploration wells will need to be drilled in 

order to identify one productive well. Developer B has a different market outlook and instead

assumes that only three wells will be necessary before a “hit” is achieved (a 33% success rate). 

These two developers have different views on their probability of success, and thus on

 68 The selected sensitivities included herein are intended to represent those variables most likely to respond to the 

presence of a FIT. Sensitivities to other variables may yield additional insights about the drivers of geothermal 

power, as a result of factors other than FITs. For example, geothermal LCOE will be highly sensitive to large 

variations in capacity factor. Annual production, however, is not expected to vary significantly based on the 

presence of a FIT.
43 

geothermal LCOE. If the policymaker sets the FIT payment by assuming that one out of every 

two exploration wells yields a productive resource (a 50% success rate), then neither developer 

will find it attractive to invest unless the presence of the FIT changes their market outlook. If the 

FIT payment is established assuming a cost equivalent to four exploration wells for every one 

productive well (a 25% success rate), then Developer B may find it attractive to invest while 

Developer A may not. If the FIT payment is established assuming a cost equivalent to seven 

exploration wells for every one productive well (a 14.3% success rate), then both developers may 

find it attractive to move forward with project development. This connection between 

exploration success and FIT payment-setting is illustrated in Figure 4. 

Figure 4. Illustration of connection between exploration success and FIT payment setting

Figure 4 suggests that the more exploration costs are built into the FIT, the higher the LCOE. 

This view is incomplete, however, as it ignores the expectation that the inclusion of more 

exploration cost in the FIT might lower the perceived risk to exploration investors. While 

difficult to quantify, it is important to consider how increasing the amount of exploration cost in 

the FIT, combined with guaranteed access to a cost-based revenue stream might reduce the 

expected return. Using a simplified example, a FIT that assumes it necessary to drill two 

exploration wells (a 50% success rate) might attract investors with a 200% return requirement. A 

FIT that assumes it necessary to drill seven exploration wells (a 14% success rate) might attract 

an exploration investor with a 50% return requirement. By making the act of geothermal 

exploration far less speculative, it is possible that the required LCOE to attract investment may 

reflect a lower exploration return. This interaction might cause the line in Figure 4 to flatten out 

as the number of exploratory wells assumed in the FIT increases, rather than increase linearly as 

currently shown. In other words, the cost of capital might decrease as the overall probability of 

success increases. 

5.6.2 Confirmation Drilling Risk 

Like exploration activities, confirmation drilling, which includes continued deep exploratory 

drilling, resource assessment, and initial production wells and therefore contains many 
44

exploration-type risks, is equity funded in today’s market. While it is possible that lenders will 

show willingness to bear resource risk in the future, they are currently considering investment 

only in projects that have demonstrated 100% of the projects’ required thermal resource. As a 

result, the cost and availability of confirmation capital is expected to behave much like 

exploration capital and be determined by the resource and project risk perceived by equity 

investors and the duration of time investors believe their capital will be exposed to these risks. 

Where resource risk is perceived to be relatively high and confirmation activities are expected to 

be spread over three or more years, the cost of capital available to fund such activities increases 

dramatically. Where resource risk is assumed to be lower and confirmation activities expected to 

take not much more than a year (as in the expansion of an existing facility), the capital required 

to fund this aspect of development is expected to be less costly and easier to secure. For this 

reason, the impact of the duration of the confirmation period and the cost of confirmation capital 

on LCOE are considered together in this analysis. 

Figure 5 shows the impact on LCOE of changes in both confirmation drilling duration and cost 

of capital together. Confirmation drilling started at a base case of 2 years, and ranged from a low 

cost sensitivity of 1.5 years, to a high cost sensitivity of 3 years. The cost of capital inputs are 

detailed in Table 11 and included varying levels of equity rate of returns (as low as 10% for lowcost permanent financing up to 200% for high cost exploration), and debt interest rate (5.5% for

low cost and up to 10% for high cost). While the ratio of debt to equity ratio is held constant, it 

differs by project development stage, based on when debt lenders are interested in financing 

project development. For example, exploration and confirmation drilling are too risky for debt 

lenders, so these phases are assumed to be 100% equity financed.

The example shows that a “lower return requirement and shorter contract duration” case (that 

uses 1.5-year confirmation phase duration and a 15% annual return requirement), results in a 

required LCOE of about 9.25¢/kWh. When a 3-year confirmation phase duration and 45% 

annual return requirement are assumed in the “higher return and longer contract duration” case, 

the required LCOE reaches almost 14¢/kWh. This impact is driven by both the magnitude of the 

confirmation stage costs (roughly three times greater than exploration costs according to Table 9) 

and the influence of compounding those costs over time.
45

Figure 5. Sensitivity of LCOE to change in both confirmation duration and return requirement

When investors have confidence in the availability of a financeable contract at a known payment 

level, it is more likely that they will proceed rapidly with early development activities, 

shortening the non-technical aspects of the geothermal development cycle, which in turn might 

reduce LCOE. As a result, if a FIT were able to create investor confidence and shorten the time 

necessary to attract and deploy capital for development activities, then project LCOE might be 

reduced.

If by providing the guaranteed availability of a financeable contract at known payment level, a 

FIT could enhance investor confidence resulting in (1) shortened development times (increased 

likelihood of proceeding expeditiously with confirmation after exploration yields potentially 

viable resource) and (2) lowered perceived risk (reflected in lower threshold equity cost of 

capital expectations), then a FIT could have the potential to substantially reduce the required 

LCOE to attract investment.

5.6.3 FIT Contract Duration

Longer contract durations facilitate lower LCOEs by extending the period over which equity 

investments and debt obligations are repaid. Through FITs, this benefit is realized as long as the 

contract price is known for the duration of the agreement. This report and quantitative analysis 

assumes a 20-year FIT throughout. The sensitivity of LCOE to FIT duration was also tested for 

FITs of 10, 15, 25, and 30 years. Geothermal projects operating beyond the FIT term are 

assumed to collect (forecasted) wholesale market revenues. No other payments are assumed 

during this period.

The impact of FIT contract duration on LCOE is shown in Figure 6. As shown, LCOE is highest 

for shorter duration FIT contracts, and the total impact between 10 and 30 years is approximately 

15%. The impact on LCOE levels out as the FIT contract duration extends and it virtually 

flattens out for FIT payments of 25 and 30 years. These results may illustrate why most FIT 

policies are between 15–20 years—most of the benefit is realized in this time period and 

extending the FIT longer than 20 years does not provide a marked additional benefit in reducing 
46

the LCOE. However, a longer FIT duration may expand the pool of investors interested in 

geothermal project development, a factor that is difficult to capture quantitatively.

Figure 6. Illustration of relationship between contract duration and LCOE

5.6.4 Installed Cost and Investor Return Requirements 

The cost of geothermal electricity is influenced by the installed project costs, as well as by the 

availability and cost of permanent financing. Installed project costs were detailed in Table 9, and 

ranged from $2,400/kW for the low cost case to $4,975/kW in the high case. These cost 

estimates are assumed to include all permanent financing transaction costs (e.g., bank fees and

reserve accounts) as well as payments to “cash out” the investors who supported all previous 

development phases. To this end, total project costs are impacted by the return requirements of 

each development stage. If the surety of a FIT reduces the cost of capital at any point in the 

development process, the impact of this should be felt, albeit potentially modestly, as a reduction 

in total project cost. 

Permanent financing assumptions are shown in Table 11. This is comprised of the long-term debt 

and equity that enable the payoff of construction financing and fund the ongoing operation of the

geothermal project; their required return is expected over an extended period of time. For debt, 

this period is most likely to match (or be a few years shorter than) the length of the FIT. For 

equity, the investment period is the project’s useful life, unless a sale of the asset is negotiated at 

an earlier date. To illustrate the impact of cost of capital on LCOE for a range of different project 

installed costs, the costs of equity and debt are combined into the weighted average cost of 

capital (WACC), a proxy for the total cost of permanent financing.
47 

Table 11. Cost of Capital Assumptions for Lower and Higher Cost Sensitivity Analyses 

Lower Cost 

of Capital

Higher Cost 

of Capital

Permanent Equity 

(includes cash, tax, and developer 

equity)

10% 15% 20%

Permanent Debt

(18-year tenor on 20-year PPA)

5.5% 7.5% 10%

Weighted Average Cost of Capital 

(50/50)

6.6% 9.7% 13.0%

Figure 7 shows the impact of the WACC as well as the capital cost on LCOE. As shown, the 

range of possible installed costs (Low = $2,400/kW, Reference = $3,725/kW, and High = 

$4,975/kW) greatly impacts the LCOE. Figure 7 illustrates three important points:

• For any given installed cost, the WACC impacts the LCOE significantly; if a FIT can 

reduce perceived risk, this relationship suggests that a FIT might materially reduce 

LCOE. For example, if the presence of a FIT enabled a 100 basis point savings on the 

WACC, the Reference Case in this analysis would be reduced from 10.85 to 10.45¢/kWh 

(a reduction of 3.7%). 

• If a FIT could reduce or eliminate various cost components, such as contract price risk 

premiums, bid security, legal, bid preparation, other transaction costs, or the cost of 

capital at either the exploration or confirmation phases, the LCOE would drop 

accordingly. For instance, a 5% drop in installed cost for a reference-level installed cost 

project would yield a roughly 0.3¢/kWh reduction in LCOE. 

• The higher the installed capital cost, the greater the impact on LCOE of reducing the 

WACC. 
48

Figure 7. Sensitivity of LCOE to change in cost of permanent financing, shown at three different 

levels of installed cost

5.7 Summary of LCOE Sensitivity Results

Figure 8 summarizes each sensitivity analysis by showing the range of FIT payment outcomes 

associated with the inputs tested (x-axis), and ranking their impacts on FIT payment relative to 

one another (y-axis). The input with the greatest impact on FIT payment occupies the highest 

position on the diagram. The array of input assumptions associated with these LCOE outcomes 

are based on the literature review and provided in the tables throughout this section. Additional 

detail is available in Appendix A.

Importantly, this analysis only considers the potential impact of a FIT policy and does not 

compare FITs to other policies, and therefore cannot conclude if a FIT is the best policy to 

achieve all of the desired objectives. Further analysis is needed to compare FITs to other policies 

for their effectiveness and cost efficiency.

Policies that spur decreases in the cost of capital at any development stage (by increasing 

investor confidence, increasing the pool of available capital, or other means) and help to reduce 

development delays are expected to have a sizable impact on LCOE. These impacts are 

demonstrated particularly at the confirmation phase, as it has been defined in this report. The 

duration of price-certain, creditworthy contracts (such as FITs) are also expected to have a 

notable impact on LCOE. This analysis also concludes that there are factors, such as total 

installed cost, which have the potential to impact LCOE similarly but are only modestly 
49

influenced by the presence of a FIT through reductions in fees and transaction costs typically 

associated with contract identification and negotiation, competitive bidding procedures, and/or 

permanent financing. Beyond the general nature of FIT policies to increase investor certainty, 

specific policy design choices regarding the manner in which exploration and confirmation 

success and return requirements are included in FIT payment-setting are also shown to have a 

direct and meaningful impact on geothermal LCOE. Each of these outcomes can be achieved,

either directly or indirectly, through the establishment of a long-term, price-certain FIT. 

Policymakers can use this approach to prioritize FIT design characteristics that best support their 

objectives. 

Figure 8. Relative impact on LCOE (and thus FIT Payment Level) of each sensitivity analysis

It is important to emphasize that this analysis comprises a “what if” analysis. While the 

directionality of impacts—the relationship between risk and return—are well-understood, the 

literature provides limited data on the quantitative impacts of these types of risk reduction on 

required investor returns. In addition, the specific impacts may differ by investor and at different 

times and circumstances. While actual FIT impacts on specific project LCOEs are difficult to 

determine, this analysis demonstrates that reductions in LCOE could result from careful choices 

in FIT design and implementation.

FITs have the potential to reduce the cost of capital by increasing investor confidence. In 

addition, the knowledge that a long-term price-certain contract is available for all qualifying 

generators may also help to avoid delays in the development process and interruptions in funding 

caused by the search for, and negotiation of, a financeable power purchase arrangement. In this 

vein, a well-developed FIT policy could result in compounding LCOE reductions. To this end, it 

is important to consider the role that an established and predictable program for long-term 

contracts plays in a project’s ability to secure the most competitive financing. 
50

While not demonstrable through a quantitative analysis, it is expected that the reduction in 

perceived risk that generates reductions in LCOE would also increase the pool of investors 

interested in funding the geothermal sector. The potential result is both equity and debt, which 

are more accessible to geothermal developers and perhaps on more favorable terms. The results 

demonstrate the positive impact of lower return requirements and shorter development cycles on 

geothermal LCOE. Further, the presence of a FIT may drive changes in investment terms for 

geothermal that perpetuate the potential LCOE differences shown in this analysis. In other 

words, once FITs are shown to reduce development risk, contracting risk, and the perception of 

overall market risk, it is increasingly likely that reductions in investor return requirements will 

follow as competition for geothermal investments increases, continuing the trend shown in this 

sensitivity analysis.
51

6 Conclusions

Geothermal electricity represents a significant and underutilized source of renewable electricity 

in the United States. Geothermal power plant developers face challenges beyond those 

experienced by other renewable electric facility developers. This analysis focuses on ways to 

address risks other than the physical risk of drilling unproductive exploratory wells, particularly 

through the design and implementation of geothermal-specific FIT policies. The unique 

characteristics of geothermal electricity development have important implications for the design 

of effective policy frameworks and incentives intended to support geothermal exploration and 

production.

6.1 International Experience Provides Opportunity to Tailor Geothermal FITs to 

U.S. Market

Despite international interest in FITs, there has been a limited focus on geothermal-specific FIT 

design. Sixteen countries have established specific FIT incentives for geothermal, but most are 

relatively new or limited in scope (e.g., project size limitations). FITs have been introduced that 

not only target geothermal development, but that target small scale plants, combined heat-andpower applications, specific types of geothermal resources, and specific geographies. While 

performance-based incentive structures have played an important role in the growing U.S. 

renewable energy industry, they have not provided the long-term certainty and basis for 

financing necessary to create a new wave of geothermal development. By studying international

tariffs and policy design choices, this report concludes that geothermal FITs can help facilitate 

the development of geothermal power plants by the private sector, when they are carefully 

designed and especially for proven resources. Because geothermal FITs are relatively new, more 

analysis could help target FITs to the unique risks of geothermal power projects.

6.2 FIT Policy Design Provides Opportunities to Support Geothermal 

Deployment and Attract Additional Investment Capital into Geothermal 

Exploration and Development Activities

The report finds that the key issues relating to geothermal FITs in the United States include:

• Linking FITs to specific geothermal targets to demonstrate a state’s commitment to 

geothermal procurement

• Targeting the FITs to specific types of geothermal resources (e.g., hydrothermal versus

EGS) and differentiating payment levels by technology to meet investors’ required 

returns

• Incorporating exploration expense and risk in FIT payment-setting methodology and 

payment levels to attempt to increase investment in inherently risky activity of 

geothermal exploration

• Creating standard pricing and standardized off-take contracts to reduce risk and 

transaction costs

• Structuring and setting the FIT payment to reduce risk

• Reducing market price risk by targeting appropriate contract duration

• Considering longer-term, stable FIT policies and FIT contracts
52

• Indexing payments to inflation, drilling costs or other relevant indicators

• Exploring scheduled and transparent policy adjustments over time.

We conclude that the availability of a FIT is likely to increase the likelihood of successful 

geothermal power plant development, financing, and operation relative to situations in which 

long-term, price-certain contracts are not guaranteed to qualifying generators. Importantly, the 

analysis did not complete a comprehensive analysis of ways to mitigate exploration risks using 

FITs or other policies. 

6.3 FIT Policies can be Designed to Address Key Issues that Have a Significant 

Impact on LCOE: Confirmation Phase Duration and Equity Cost, Cost of 

Permanent Financing, and FIT Duration

The assurance of a long-term, price-certain contract is expected to provide geothermal projects 

with access to a broader spectrum of less-expensive capital. If the cost of capital can be reduced

at each stage of development, reductions in LCOE will result. When establishing return 

requirements, investors will consider both the nature of the risk and the expected duration that 

their capital will be outstanding. Longer development and/or contracting time horizons translate 

into greater risk and a higher target return requirement for the pre-operating phase. By 

comparison, as the FIT contract duration increases, the LCOE is expected to decrease as debt and 

equity investments can be recovered over a longer period of time while maintaining revenue 

certainty. The illustrative quantitative analysis in Section 5 identifies the duration of the 

confirmation phase, the cost of confirmation phase equity, and the cost of permanent financing 

and FIT duration as the highest-impact inputs that can be influenced by FIT policy design. 

The availability of a long-term, price-certain FIT contract is guaranteed upon commercial 

operation and can help to shorten the geothermal development cycle by removing a lengthy and 

uncertain negotiation for a competitive PPA. In this case, significant benefits can be realized in 

the form of a lower LCOE. Similarly, if the availability of a FIT can increase the pool of 

available investment capital, then both competitive forces and a real reduction in the risk profile 

of geothermal investments is expected to result in a lower cost of capital for permanent equity 

and debt. This analysis demonstrates the impact of such a trend in the form of lower LCOEs.

Ultimately, lower LCOE would mean a lower FIT payment level, lower geothermal project 

development costs, and lower overall costs to ratepayers.
53

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Appendix A: Summary of Literature Review on U.S. Geothermal 

Costs

The cost, performance, and financing inputs employed in the LCOE analysis were developed 

through a detailed literature review. Publicly available geothermal cost research was compared 

and used to develop the low case, reference case, and high case estimates for the LCOE 

modeling. Cost comparisons and case definitions are shown in Figures A-1 through A-6.

(All data adjusted to 2010$; shown on graph in year of study)

Figure A-1. Range of exploration costs
64

Figure A-2. Range of confirmation costs

Figure A-3. Range of site development and construction costs
65

Figure A-4. Range of total project costs (including exploration)

Figure A-5. Range of fixed O&M costs
66

Figure A-6. Range of variable O&M costs
67

Appendix B: Summary of Additional CREST Modeling Inputs

Calculating LCOEs requires defining additional assumptions about the plant’s specifications and 

operation. These assumptions are intended to be central estimates rather than representative of 

any specific operating or proposed facility. 

Table B-1. Project Size, Performance, and Development Inputs for LCOE Modeling

Input Category Reference 

Case 

 Potential Range Notes and Sources

Nameplate 

Capacity 

50 MW 2–100 MW Most values between 15 and 50 MW 

Hance (2005), O’Donnell et al. (2009), 

Salmon et al. (2011), Klein (2009) 

Net: Gross 

Capacity Ratio 

80% 20% for “auxiliary loads”

Availability Factor 90% 80%–95% Hance (2005), Lovekin and Pletka (2009), 

O’Donnell et al. (2009), Sison-Lebrilla and

Tiangco (2005), Klein (2009)

Project Useful Life 30 Years Hance (2005)

Annual 

Degradation of 

Thermal Resource 

Assumes that combination of plant sizing and make-up wells keeps plant 

operating at capacity. Cost captured in O&M estimates. 

Exploration Well 

Success Rate 

25% 10%-50% 20%-25% Hance (2005)

 35% for “Hydro” Augustine et al. (2010)

Exploration Period 

Duration 

3 Years 2–4 Years NREL professional analysis experience

Confirmation Well 

Success Rate 

60% Hance (2005)

Confirmation 

Period Duration 

2 Years 1.5–3 Years NREL professional analysis experience

Production Well 

Success Rate 

75% NREL professional analysis experience

Construction 

Duration 

(Well Field and 

Power Plant) 

2 Years NREL professional analysis experience

Royalties 4% Hance (2005)
68

Appendix C: Geothermal Power Under PURPA

The Public Utilities Regulatory Policy Act is a federal law passed as part the broader National 

Energy Act (NEA) of 1978. Against the backdrop of the oil crises of the 1970s, during which 

energy prices tripled in 1974, the goal of NEA was to decrease national dependence on imported 

oil. The goal of PURPA was to increase the amount of electricity purchased from independentlyowned renewable energy and cogeneration plants. PURPA required utilities to a) purchase 

energy and/or capacity from non-utility generators69 and b) purchase the commodities at rates 

based on utilities’ avoided cost. In order to be eligible under PURPA, renewable energy 

generators had to be less than 50% owned by utilities, smaller than 80 MW of installed capacity, 

and have at least 75% of the total energy input provided by renewable energy (e.g., in the case of 

biomass plants co-fired with fossil fuels). PURPA rapidly expanded non-utility generation in the 

United States. By 1996, PURPA had supported the development of approximately 12,600 MW 

of renewable power, of which 11% was geothermal capacity in three states (Guey-Lee 1999). 

The majority of the geothermal capacity supported by PURPA was concentrated in California, as 

can be seen in Figure 15 below. 

Figure C-1. Installed geothermal capacity under PURPA (MW)

Source: Guey-Lee (1999)

The Federal Energy Regulatory Commission, which was responsible for certifying eligible 

generators under PURPA, left the definition of utility avoided cost to each state. Different states 

defined avoided cost in different ways. California created several standard offer power purchase 

contracts that generators could choose from. Standard Offer No. 4 (SO4), which defined avoided 

cost as a 10-year schedule of escalating payments, drove a boom in renewable energy 

development (Pierce and Livesay 1994). California supported approximately 25% of all 

 69 Generation from many PURPA plants was purchased under “must take” provision, which meant that the utility 

was obligated to purchase everything that a generator could produce but that generators were exempt from having to 

provide operating reserves and ancillary capacity services (Hurlbut 2012).

1,022

237

35

California

Nevada

Hawaii
69

renewable energy generation under PURPA, of which the largest percentage (~40%) was 

geothermal (Guey-Lee 1999). The price paid under PURPA for geothermal varied widely from 

state to state. The average price paid for geothermal plants in California was 12.44 ¢/kWh, for 

example. By contrast, the average price paid in Nevada was 5.31 ¢/kWh (Guey-Lee 1999).

Nationwide, PURPA stimulated exploration drilling at more than 50 prospects between 1979-

1985, many of which were subsequently developed. Many of the geothermal sites developed 

under PURPA benefitted from federal cost-share programs, including both grants for exploration 

and confirmation drilling and loan guarantee programs (DOE 2008). The remaining exploration 

activity was primarily financed through equity from large oil, gas, mining, and utility companies 

(GeothermEx 2010). As the U.S. DOE’s Geothermal Technologies Program Blue Ribbon Panel 

concluded, “Private industry was willing to take more drilling risk because of the higher 

electricity price” (EERE 2011, p. 8), in addition to the other programs and incentives.

Following the initial renewable energy market growth under PURPA, a decline in the price of 

oil, the entry of lower-cost natural gas power generation into the electricity market, concerns 

over excess generating capacity, and a sharp drop in the cost of commercial loans dramatically 

decreased the avoided cost of most utilities. This not only reduced the prices offered under 

PURPA but also created controversy about the pricing of existing PURPA contracts. By 1995, 

the average wholesale price of electricity was 3.53 ¢/kWh, whereas the average price for nonutility generators under PURPA was 6.31 ¢/kWh (Guey-Lee 1999). PURPA was amended in 

2005 to remove the mandatory purchase obligation and requirement that utilities pay avoided 

cost-based rates in states where generators have “nondiscriminatory access to competitive 

markets or open-access transmission services provided by a regional transmission operator”

(Elefant 2011). While utilities in some jurisdictions have applied for these PURPA exemptions, 

utilities in other states have continued to procure renewable energy under PURPA. In Idaho, for 

example, PURPA supported the development of the Raft River geothermal plant, which came 

online in 2008 (Doris et al. 2009). 

PURPA was similar to modern FITs in that it allowed IPPs to connect and sell power to the grid. 

PURPA has also been crediting with not only jumpstarting renewable energy development, but 

also inspiring FITs in countries such as Denmark and Germany. Unlike many modern FITs, 

however, the price paid under PURPA was based on avoided cost, rather than on the generation 

cost of specific technologies.