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

Guidebook to Geothermal 

Power Finance – Draft 

February 17, 2010 – March 15, 2011

J. Pater Salmon, J. Meurice, N. Wobus,

F. Stern, and M. Duaime

Navigant Consulting

Boulder, Colorado

Subcontract Report

NREL/SR-6A20-49391

December 2010
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

1617 Cole Boulevard

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303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Guidebook to Geothermal 

Power Finance – Draft 

February 17, 2010 – March 15, 2011

J. Pater Salmon, J. Meurice, N. Wobus,

F. Stern, and M. Duaime

Navigant Consulting

Boulder, Colorado

NREL Technical Monitor: Paul Schwabe 

Prepared under Subcontract No. LGJ-0-40242-01

Subcontract Report

NREL/SR-6A20-49391

December 2010
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iii

Acknowledgements 

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

Program (GTP). The authors wish to thank Arlene Anderson and GTP for their support of this 

work. The authors also wish to thank the following individuals for providing information and 

valuable perspectives for this report: John C. S. Anderson, John Hancock Financial Services; C.J. 

Arrigo, Glacier Capital Partners; Todd Eagleston, NV Energy; Marco Fossataro, ENEL; Karl 

Gawell and Dan Jennejohn, Geothermal Energy Association; Smadar Lavi, Ormat; Martin 

Piszczalski, Sextant Research; Stephen Ponder, NV Energy; Alexander Richter, Islandsbanki; 

Dan Schochet, Ram Power; Michael Ware, Good Energies. 

In addition, the authors would like to express their gratitude for the guidance, assistance, and 

input provided by key staff members at the National Renewable Energy Laboratory. Chad 

Augustine, Karlynn Cory, Paul Schwabe, Bethany Speer, and Katherine Young added significant 

value to this report through their initial framing of the project, regular input into the underlying 

research, and review of the draft versions of this report. The authors appreciate the opportunity to 

work with this dynamic team.

Finally, the authors also offer their gratitude to Devin Egan in NREL’s Communications Office for 

providing editorial support.
iv

Abstract

Investment in conventional geothermal projects on the utility side of the meter has evolved 

dramatically since the economic downturn began in 2008. Developers and investors identified

innovative approaches to address the capital constraints that permeate the market and to take 

advantage of new policy incentives that emerged. These innovations are especially important in 

the early stages of project development, when capital providers must be comfortable with the 

risk associated with resource identification and test well drilling. Innovations later in the project 

development process responded to changes in the way that projects took advantage of federal 

incentives including the Section 1603 Treasury Cash Grant Program that reduced the need for tax 

equity in 2009 – 2011 and possibly beyond.

This guidebook is intended to facilitate further investment in conventional geothermal projects in 

the United States. It includes a brief primer on geothermal technology and the most relevant

policies related to geothermal project development. The trends in geothermal project finance are 

the focus of this tool, relying heavily on interviews with leaders in the field of geothermal project 

finance. Using the information provided, developers and investors may innovate in new ways, 

developing partnerships that match investors’ risk tolerance with the capital requirements of 

geothermal projects in this dynamic and evolving marketplace.
v

Table of Contents

Acknowledgements...................................................................................................... iii

Abstract......................................................................................................................... iv

Table of Contents.......................................................................................................... v

List of Figures .............................................................................................................. vi

List of Tables ................................................................................................................ vi

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

2 Technology............................................................................................................... 2

2.1 Basic Geothermal Technology.............................................................................................2

2.2 Emerging Geothermal Technologies ...................................................................................5

3 Policies and Incentives ........................................................................................... 7

3.1 Current Federal and State Policies and Incentives...............................................................7

3.1.1 Tax Incentives.............................................................................................................7

3.1.2 Inter-agency Coordination and Streamlining of Federal Permitting 

and Land Lease Processes..............................................................................................9

3.1.3 Renewable Portfolio Standards.................................................................................10

3.1.4 Greenhouse Gas Emissions Reduction Policies........................................................11

3.2 Roles of Key Policy Considerations..................................................................................12

4 Financing Geothermal Projects............................................................................ 14

4.1 The New World of Renewables Financing........................................................................14

4.2 Financing Geothermal Projects..........................................................................................15

4.3 The Staging of Geothermal Project Financing...................................................................16

4.3.1 Early-Stage Financing...............................................................................................17

4.3.2 Late Development Financing....................................................................................21

4.3.3Construction & Operation Financing.........................................................................22

4.4 Common Pitfalls in Obtaining Geothermal Financing ......................................................28

5 Conclusion ............................................................................................................. 29

6 References ............................................................................................................. 32

Appendix A. Additional Detail on Relevant Policies ................................................ 39

Appendix B. Renewable Energy Certificate Value in Geothermal Project Finance44

Appendix C. Greenhouse Gas Policy ........................................................................ 50

Appendix D. Additional Resources............................................................................ 53
vi

List of Figures 

Figure 2-1. Depiction of typical binary geothermal power plant...............................................2

Figure 2-2. Cost per kW of geothermal energy developmental stages (typical 50 MW plant).5

Figure 2-3. Identified potential geothermal sites in the United States (black dots)...................5

Figure 3-1. Key federal legislation for geothermal project activity...........................................7

Figure 3-2. EPAct 2005 provisions for geothermal.................................................................10

Figure 3-3. Effect of key policies on geothermal project income statement ...........................13

Figure 4-1. Reasons for lack of utility activity in geothermal project development and 

ownership...........................................................................................................................16

Figure 4-2. Geothermal project development and financing by stage .....................................17

Figure 5-1. Summary of this guidebook’s key information for financing

geothermal projects............................................................................................................31

Figure B-1. Policy provisions and market forces that shape REC prices................................46

Figure B-2. Example of the role of REC revenue in project finance.......................................48

Figure B-3. Map of North American REC tracking and trading systems................................49

List of Tables 

Table 2-1. Description of Three Geothermal Power Plant Technologies..................................3

Table 3-2. Summary of Federal Financial Incentives for Geothermal Projects ........................8

Table 3-3. Roles of Four Policy Types in the Project Development Process..........................12

Table 4-1. Early-Stage Equity Financing Requirements .........................................................21

Table 4-2. Mezzanine Financing Requirements ......................................................................22

Table 4-3. Possible Construction Financing Requirements.....................................................27

Table 4-4. Possible Post-Construction Project Financing Requirements ................................28

Table A-5. Summary of State RPS Policies.............................................................................42

Table B-6. REC Pricing Across Markets.................................................................................45
1

1 Introduction

The United States is the global leader in installed geothermal capacity with approximately 3,086 

megawatts (MW) of installed capacity, and is expected to continue that leadership in the next 

decade (Islandsbanki 2009). Even so, less than 0.5% of the United States’ electricity generation 

currently comes from geothermal resources (Jennejohn 2010). Yet, geothermal energy could be 

an important contributor to a sustainable energy portfolio in the United States (Tester et al.

2006).

One of the main constraints on geothermal project development is the ability to secure capital. 

Despite the technology’s 50-year history of providing power at the utility scale (U.S. DOE 

2006(c)), challenges remain in raising sufficient capital, especially during the early stages of 

project development. The 2008 economic downturn exacerbated this situation and re-shaped the 

market for capital across all technologies.

This guidebook provides an overview of the strategies currently used to raise capital for 

geothermal projects with the following characteristics:

• Use conventional, proven technologies

• Located in the United States

• Produce utility power (roughly 10 MW or larger)

This guidebook builds on a fundamental understanding of investment decisions. The acceptance 

of risk must be rewarded through financial returns. Different types of investors tolerate different 

levels of risk and offer various financial products based on their risk thresholds in order to access 

those opportunities. The market for all types of investment is much different in late 2010 than it 

was before the economic downturn that started in 2008; this guidebook provides information 

about how investment decisions are made in the current environment. 

The information in this guidebook includes a high-level overview of relevant geothermal 

technology and policy and a more in-depth discussion of the strategies used to fund geothermal 

projects: 

• Section 2 provides an overview of the most widely used electricity-producing geothermal 

technologies. 

• Section 3 summarizes the current policy environment that supports geothermal projects. 

• Section 4 summarizes the innovations in financing used since the 2008 economic 

downturn, highlighting the types of investors interested in funding each stage of project 

development and the requirements for competing for their capital.
2

2 Technology

Geothermal electricity generation has a long track record. The first geothermal power plant was 

built in Lardellero, Italy, in 1904 (Lund 2004). The first U.S. geothermal power plant was built 

in the early 1930s at the Geysers in California (Lund 2004) in the same location as the first largescale plant (11 MW), which began operation in 1960 (U.S. DOE 2006(c)). The basic 

technologies are discussed in Section 2.1. Recent developments of new technologies are briefly 

discussed in Section 2.2.

2.1 Basic Geothermal Technology

Geothermal power plants work similarly to traditional thermal plants in many respects in that 

they convert heat to electricity using a turbine-generator. The difference is the source of the heat: 

in geothermal projects, heat is provided by underground geothermal fluids. 

The process used to extract geothermal fluids is similar to the process used to extract oil and gas. 

Before any drilling can take place, developers must invest in exploration of potential areas to 

identify the location of actual geothermal resources. Wells are then drilled thousands of feet deep 

to tap into steam and hot water reservoirs. 

Figure 2-1 shows a schematic of a typical binary geothermal power plant, including the pathways 

of the fluids. 

Figure 2-1. Depiction of typical binary geothermal power plant

Source: NREL 2010

Conventional geothermal electricity power plants utilize the fluid produced from the geothermal 

reservoir to generate power using one of three methods as shown in Table 2-1. Each graphic 

visually represents the mechanics of one technology.
3

Table 2-1. Description of Three Geothermal Power Plant Technologies

Power 

Plant Description Graphic Representation

Flash 

Steam 

Plant

» Description: Geothermal fluids lose 

pressure as they rise to the surface 

and flash (i.e., boil) to create steam 

that turns turbines

» Market: Composes about 45% of 

electrical generation in the U.S. 

geothermal market

» Technology Specification: Better for 

high-temperature reservoirs 

(>360°F/182°C) with a mix of hot water 

and steam to allow for an easier 

transition from water to steam

» Example: Dixie Valley, Nevada

Dry 

Steam 

Plant 

» Description: The simplest plant design, 

as dry steam is produced from the 

reservoir and piped from wells to the 

plant to directly turn turbines

» Market: Composes less than 40% of 

electrical generation in the U.S. 

geothermal market

» Technology Specification: Possible 

when the reservoir produces only hightemperature steam

» Example: The Geysers, California

BinaryCycle 

Plant

» Description: Passes geothermal fluids 

through a heat exchanger to boil 

organic fluids that vaporize at a lower 

temperature than water. Vapor turns 

turbines, is condensed, re-pressurized,

and returned to the heat exchanger to 

be used again in a closed-loop

» Market: Composes about 15% of 

electrical generation in the U.S. 

geothermal market, but is most 

common on a units-installed basis

» Technology Specification: Best for 

lower-temperature reservoirs (up to 
4

360°F/182°C)

» Air emissions are minimized by 

separating the water/steam and 

organic materials in separate closed 

loops

» Example: Raft River, Idaho

Sources: Idaho National Energy Laboratory 2010; Kagel 2008; and U.S. DOE 2008(a)

The overall installed costs range from approximately $3,000 to $4,000 per kilowatt (kW) for 

each of the three technologies (Cross and Freeman 2009). Costs have increased significantly in 

recent years and are subject to change due to changes in commodity costs (e.g., for steel and 

cement), cooling technology, and demand for drilling rigs for oil and gas exploration, among 

others (GEA 2009).

The choice of power plant technology is usually based on the characteristics of the available 

resource. While the three technologies are typically used autonomously, they can also be used in 

conjunction with one another (e.g., a flash-binary plant) to achieve higher efficiency. 

Cooling systems are an important part of power plants as they can greatly affect the maximum 

amount of power that can be extracted from the geothermal fluids—the lower the cooling 

temperature, the greater the potential plant efficiency. Geothermal power plants typically use 

water as a cooling fluid in cooling towers when water is inexpensive and available for use. In 

some cases, air may also be used as a cooling agent if water resources are limited. Air cooling 

has higher capital costs and parasitic load but lower non-energy operating and maintenance costs. 

The cooling ability of air is directly proportional to the outside temperature, so there can be

significant diurnal and seasonal cooling capacity fluctuations. The resulting potential lack of 

stability in plant output from air cooling can be a deterrent for those seeking consistent 

operational efficiency (Kagel 2008). 

There are several phases between exploration of potential resources and construction of a power 

plant. Figure 2-2 shows the estimated development costs for a typical geothermal power plant.1

As shown in Figure 2-2, the upfront activities of Resource Identification, Resource Evaluation, 

and Test Well Drilling account for approximately 13% of the overall cost; these costs are 

nonetheless significant because they are risky activities (i.e., subject to dry holes) and, as a result,

have high financing costs. The remainder of the capital investment (87%) comes in the later 

phases of drilling and construction. 

 1 These project costs are location-specific and can vary significantly from one site to another. 

The breakdown of costs among the various stages of project will also vary by site. Figure 2-2 is 

for illustrative purposes only.
5

Figure 2-2. Sample cost per kW of geothermal energy developmental stages (typical 50 MW plant)

Source: Cross and Freeman 2009

Most high-temperature geothermal resources are located in the western United States, as shown 

in Figure 2-3 (Williams et al. 2008). Accordingly, nine of the 13 Western states shown in Figure 

2-3 host at least one conventional geothermal project (Jennejohn 2010). The U.S. Geological 

Survey anticipates that additional geothermal resources appropriate for use with the two 

dominant conventional geothermal power plant technologies, flash steam and dry steam, exist in 

every Western state (Williams et al. 2008).

Figure 2-3. Identified potential geothermal sites in the United States (black dots)

Source: Williams et al. 2008

2.2 Emerging Geothermal Technologies

While the intent of this guidebook is to describe financing characteristics for existing 

hydrothermal technologies, readers should be cognizant of emerging technologies in the 

geothermal arena. Many of these technologies are still in the research and development (R&D)

Resource 

Identification

Exploration

$14/kW 

installed

< 1% 

of costs

Resource 

Evaluation

Permitting &

Steam 

Gathering

$300/kW 

installed

8% 

of costs

Test Well 

Drilling

Exploratory 

Drilling

$169/kW 

installed

5% 

of costs

Production 

Well Drilling

Production 

Drilling

$1,367/kW 

installed

38% 

of costs

Plant 

Construction

Plant & 

Construction

Transmission

$1,800/kW 

installed

49% 

of costs

Total Capital 

Costs

$3,650/k

W 

installed
6

phase; it may be years before they enter the market. Some examples of emerging geothermal 

electricity generating technologies include:

• Enhanced Geothermal Systems (EGS). Designed to enable cost-effective production of 

electricity at sites that lack sufficient rock permeability and/or water for conventional 

geothermal technologies. EGS involves the injection of water at sufficient pressure (or 

temperature differential) to enlarge and propagate existing fractures to develop a 

reservoir. Injected fluid that circulates through the reservoir is heated. Once the reservoir 

is created, production wells are drilled and heat is extracted from the rock by fluid that is 

heated as it circulates through the reservoir (U.S. DOE 2006(b)). 

• Co-produced systems. Use hot water extracted during the oil and gas recovery process to 

produce electricity; these systems are innovative in their use of water but can use either 

conventional or emerging generating technologies to produce electricity (Cross and 

Freeman 2009).

• Advanced binary-cycle plants. Use organic fluids with even lower boiling points than 

traditional binary-cycle plants, enabling more efficient power conversion at low 

temperatures or from fluids extracted using EGS (GE Global Research 2010). 
7

3 Policies and Incentives 

A variety of federal and state policies and incentives support geothermal electricity project 

development. Some directly benefit a project’s financial outlook by providing grants and tax 

incentives and defraying upfront costs. Others affect a project’s financial returns through less 

direct means, such as reducing the cost of leasing and permitting by streamlining processes. 

Federal legislation supporting geothermal technologies is highlighted in Figure 3-1. The Public 

Utility Regulatory Policy Act (PURPA) requirements for utility purchases of renewable energy 

are credited with driving a surge in geothermal project development from the late 1970s through 

the mid-1980s. Project activity then slowed for nearly two decades until the Energy Policy Act 

(EPAct) of 2005. RD&D funding has also been a significant driver of project activity.

Figure 3-1. Key federal legislation for geothermal project activity

Source: Navigant 2010

Section 3.1 presents an overview of current policies and incentives that help support geothermal 

project development. Section 3.2 highlights policy-related factors of particular relevance to 

investment in geothermal projects.

3.1 Current Federal and State Policies and Incentives

This section describes relevant policies that affect the financing of geothermal projects. 

Additional discussion of these and other state and federal policies affecting geothermal project 

finance can be found in Appendix A. 

3.1.1 Tax Incentives

Tax incentives enhance the financial returns of geothermal projects by offsetting tax liabilities. 

Important elements of tax-related incentives for geothermal projects are included in Table 3-2.

2005

Energy Policy Act of 2005 

improves land access, 

transmission planning, resource 

assessment and optimization 

of resource use

2009

American Recovery and 

Reinvestment Act of 2009 

extends tax incentives, 

adds cash grant, 

allocates $350 million in 

funding for geothermal RD&D.

1978

Public Utilities Regulatory 

Policies Act (PURPA): required 

utilities to purchase electricity 

from qualifying renewable 

energy facilities 

2007

Energy Independence and 

Security Act of 2007 

provides guidance for 

funding of geothermal RD&D, 

technology transfer, 

and information sharing.
8

Table 3-2. Summary of Federal Financial Incentives for Geothermal Projects

Source: DSIRE 2010(a)

Description

Timing of 

Payment

Tax 

Appetite 

Required?

* Relevant Dates

Production Tax 

Credit (PTC)**

2.2 cents/kWh (2010$) 

produced for first 10 years

At end of each of the first 

11 tax years Yes In service on or before 12/31/2013 to qualify

Investment Tax 

Credit (ITC)

30% of eligible tax basis 

At end of first tax year 

after in-service date Yes

In service before 

1/1/2014

10% of eligible tax basis In service before 

1/1/2017

Treasury Cash 

Grant***

30% of eligible tax basis of 

property 

60 days after completion 

of application (after in 

service)

No

Unless otherwise 

extended, under 

construction by 

12/31/2011 to qualify 

and in service by 

1/1/2014

10% of eligible tax basis of 

property 

Unless otherwise 

extended, under 

construction by 

12/31/2011 to qualify 

and in service by 

1/1/2017

Modified 

Accelerated 

Cost Recovery 

System 

(MACRS)

Accelerated depreciation over 

5-6 years instead of asset life

At end of each of the first 

6 tax years Yes None at this time

DOE Loan 

Guarantees

Guarantee for up to 80% of 

project loan amount

Backstop provided at time 

of financing No Under construction by 

9/30/2011 to qualify

* Refers to ability of the project owner to make use of tax credits or deductions.

**The recipient of a tax credit can reduce the amount of taxes they owe to the government by the amount of their credit. Further 

information about the PTC, ITC, and Treasury Cash Grant incentive programs is included in Appendix A.

***The 1603 Program administered by the U.S. Department of the Treasury is commonly referred to as the “cash grant” or “cash 

grant program.” In actuality, however, the 1603 Program is a “Payment for Specified Energy Property in Lieu Of Tax Credits” and 

not a grant. For consistency with industry convention, the term “Treasury Cash Grant” is used herein. Note that the relevent dates of 

the Treasury Cash Grant program reflect the one year extension granted within the Tax Relief, Unemployment Insurance 

Reauthorization, and Job Creation Act of 2010. For more information, see www.ustreas.gov/recovery/1603.shtml.

In addition, geothermal property that meets the eligibility for both the PTC and the ITC may elect either the 30% Treasury Cash Grant 

or the 10% Treasury Cash Grant but not both. The determining factor for electing one or the other is the in-service date. 
9

For a given project investment, investors 

must choose whether to pursue the PTC, 

the ITC, or the Treasury Cash Grant. 

Analysis comparing the value of these 

three incentives indicates that the PTC has 

a higher discounted cash value than the 

ITC or Treasury Cash Grant for 

geothermal projects in the vast majority of 

cases (Bolinger et al. 2009). However, 

comments from industry representatives 

indicate that other benefits of the Treasury 

Cash Grant cause geothermal developers 

to choose the Treasury Cash Grant over 

the PTC or ITC. Specifically, many 

project owners do not have enough 

taxable income to take advantage of tax 

credits and must sell them at a discount to 

other investors while they can use the 

Treasury Cash Grant right away to pay off 

construction loans or term loans. This 

reduces the amount of debt on their 

corporate balance sheets, which can 

improve developers’ access to capital at 

the corporate level for other projects. 

3.1.2 Inter-agency Coordination and Streamlining of Federal Permitting and Land 

Lease Processes

Various federal processes are important to geothermal project development because roughly 90% 

of all conventional hydrothermal resource sites in the United States (as identified by the U.S. 

Geological Survey) are located on federal lands (U.S. DOE 2010(a)). Provisions of EPAct 2005 

mandated that the Bureau of Land Management (BLM), the U.S. Forest Service (USFS), DOE, 

and other government agencies take a number of steps to reduce barriers to geothermal 

development. 

Key outcomes and the related policy requirements are highlighted in Figure 3-2. These outcomes 

reduce a project’s financial risk and non-equipment costs. Additional details on these processes 

are included in Appendix A.

Timelines for Federal Policies and 

Geothermal

The relative short-term availability of valuable 

incentives (e.g., the Treasury Cash Grant, the 

PTC, and the 30% ITC) can limit their ability to 

drive new geothermal projects. Unless otherwise 

extended, the Treasury Cash Grant is available to 

projects that begin construction in 2009, 2010, or 

2011, and that are placed in service prior to 

January 1, 2014. For projects that miss the 

January 1, 2014, in-service deadline, a 10% 

Treasury Cash Grant is available provided the 

project began construction in 2009, 2010, or 

2011, and is placed in service by January 1, 

2017. Projects must be in service on or before 

December 31, 2013, to qualify for the PTC and 

the 30% ITC. Given the 4- to 8-year project 

development timeline for geothermal, these 

incentives are supporting projects already in the 

pipeline; newer projects are proceeding with 

more relative risk since it is uncertain that they 

will meet the deadlines for these incentives.
10

Figure 3-2. EPAct 2005 provisions for geothermal2

Source: Navigant 2010

3.1.3 Renewable Portfolio Standards

Renewable Portfolio Standards (RPS), which exist in 29 states, constitute the most robust statelevel policy driver for geothermal electricity project development (DSIRE 2010(d)); an 

additional seven states have non-binding renewable energy goals (DSIRE 2010(d)). An RPS 

mandate, as differentiated from a renewable portfolio goal (which is voluntary), requires 

regulated entities (which are frequently load serving entities) to secure a percentage of their 

electricity from renewable sources. 

To fulfill the RPS requirements, many load serving entities (LSEs) enter into long-term contracts 

for renewable energy using power purchase agreements (PPAs) or contracts for renewable 

energy certificates (RECs) only; the PPAs provide additional revenue certainty, which is needed 

to obtain financing. RECs represent the green attributes of renewable energy and can be sold as a 

product separate from the underlying power produced by a renewable energy facility. 

Two approaches to pricing RECs are common: 

• In some markets, the REC is priced separately in a PPA for geothermal resources, even if 

the PPA is for both the conventional power and the REC. These PPAs can be structured 

so that the conventional power price component is based on a power market index, such 

as NP15 in Northern California, while the REC is priced at a flat or increasing value over 

the contract period. 

• Depending on the specific contract, the plant’s RECs may be able to be sold separately

from the “conventional power” generated by the geothermal resource.3

 2 Further information about the EPAct 2005 provisions that pertain to geothermal can be found in 

Doris et al. 2009. Information about the WREZ Initiative can be found at the Western Governors 

Association Web site at 

This would make 

www.westgov.org/index.php?option=com_content&view=article&id=311&Itemid=81. 

1. Streamlined 

Access to Land

•Programmatic 

Environmental 

Impact Statement 

(PEIS)

•Competitive 

bidding

•More land 

available, more 

frequent sales

•Eliminated backlog

2. Resource 

Assessment Update

•2008 resource 

assessment by U.S. 

Geological Survey 

covering 13 western 

states

3. Transmission 

Planning

•Western Renewable 

Energy Zones 

(WREZ) Initiative 

providing data to 

inform decisionmaking processes

4. Unitization 

•Holders of federal 

leases for the same 

geothermal 

resource coordinate 

to reduce overall 

investment and 

ensure optimal use 

of resource
11

sense financially, if, for example, the developer has a purchaser for the conventional 

power and a separate purchaser for the REC, either to meet requirements for voluntary 

REC sales or in a state that allows unbundling of the REC from the green power source.

Appendix A presents additional details on capitalizing on this revenue stream for geothermal 

projects.

3.1.4 Greenhouse Gas Emissions Reduction Policies

Greenhouse gas emissions (GHG) regulations may assist geothermal project developers in 

securing PPAs. If implemented, GHG regulations could increase the price of power from 

conventional sources by internalizing the cost of GHG emissions, potentially making geothermal 

power more cost-competitive because GHG emissions from geothermal plants are minimal.

Energy from geothermal resources may serve as a risk mitigation strategy because there is 

limited GHG regulatory risk associated with energy from geothermal sources. 

A number of states with strong geothermal resources have pursued GHG emissions reduction 

policies, including California, Oregon, and Colorado (Pew Center 2010(b)). Notable among 

these states is California, where a cap-and-trade program is scheduled to be implemented in 2012 

(California Air Resources Board 2010). Seven Western states participate in the Western Climate 

Initiative, a regional effort launched in 2007 to facilitate a coordinated approach to climate action 

among Western states and Canadian provinces. See Appendix C for more details on the Western 

Climate Initiative. 

The Environmental Protection Agency (EPA) has taken some initial steps toward regulating 

GHGs. Using its authority under the Clean Air Act, the EPA proposed its first federal emissions 

standards for GHGs in September 2009; these standards address emissions from light-duty 

vehicles. In 2009, EPA also introduced a rule requiring the largest emitters of GHGs to report 

GHG emissions annually starting in 2011. In December 2009, the EPA found that the 

concentrations of six different types of GHGs in the atmosphere threaten the health and welfare 

of current and future generations. This “endangerment finding” may require regulation of 

additional GHG sources by the EPA in the future (U.S. Department of State 2010). At the time of 

this writing, litigation is expected; it is unclear when this regulation could go into effect (Nelson 

2010).

Actions by Congress in recent years indicate that some form of comprehensive federal GHG 

regulation may be considered in the future. The House passed the American Clean Energy and 

Security Act in 2009 (ACES), which included an economy-wide cap-and-trade program. A 

variety of bills that build on provisions of ACES are under consideration in the Senate (Pew 

Center 2010(a)). 

The market for RECs (used for compliance with RPSs) and the market for GHG compliance 

units (both allowances and offsets used for compliance with GHG regulations) are separate and 

 3 If the RECs are sold separately from the power, the unbundled energy is no longer considered 

renewable.
12

distinct. A geothermal generator operating in a state with both an RPS and a GHG cap-and-trade 

program would sell RECs to entities responsible for complying with the RPS. The generator 

itself would be responsible for surrendering enough GHG emission allowances to cover any 

GHG emissions of its own. Any additional allowances owned by the generator could be sold.4

3.2 Roles of Key Policy Considerations 

Key policies that affect geothermal project development process and project economics are 

classified into four categories. These policy categories and related issues that are considered 

during the project development cycle are highlighted in Table 3-3 on the next page. 

Table 3-3. Roles of Four Policy Types in the Project Development Process

Policy Type Key Considerations During Project Development

Leasing policies, 

permitting 

requirements, 

and transmission 

planning

» Review state procedures for permitting and consult industry players to gauge 

permitting timeframe for that state.

*

» Track BLM lease auction schedules.

» Review geothermal development areas prioritized in BLM PEIS (for access to land) 

and WREZ (for easier access to transmission). 

Tax incentives

» Ensure project meets detailed eligibility requirements, particularly timing of project 

construction and completion. 

» Review all IRS forms and requirements to ensure value of the incentive is properly 

captured in the pro forma. 

» For most tax-related incentives, developers must secure tax equity investors with 

sufficient tax appetite to monetize the value of the incentives. (State tax incentives 

require tax appetite in that state.)

RPS 

requirements

» Carefully review RPS requirements and evaluate market value for RECs during PPA 

contract period.

» Track ongoing RPS developments in-state and in other neighboring states; RPSdriven PPA opportunities may change over time and may emerge in other states.

» Explore whether value of offtake agreements could be enhanced by selling RECs and 

commodity energy separately (“unbundling”).**

GHG regulations » Track timing and details of existing and future greenhouse gas regulations at the 

regional level, by the EPA, and through new Congressional actions/mandates.

* A state’s classification of geothermal resources will affect which agencies are involved with permitting activities in that state. 

A state may classify geothermal as a groundwater resource, a mineral resource, or both, and classification may vary depending

on the specific type of geothermal resource developed.

** In March 2010, the California Public Utilities Commission (CPUC) issued a decision allowing unbundling of RECs, with 

some limitations during the first two years. On May 6, 2010, the CPUC voted to delay the implementation of its decision on this 

matter (CPUC 2010). 

Note: GTP also plays an important role as manager of RD&D funding efforts. RD&D indirectly impacts project development by 

reducing technology risk and reducing technology cost over time.

Source: Navigant 2010

 4 There is some potential overlap between REC and GHG markets for generators that wish to sell 

RECs into voluntary GHG offset markets. 
13

Figure 3-3 summarizes the effects of these policies on a project income statement. The income 

statement is one of the three key financial reports that are used to evaluate the value of a project. 

It is based on accounting principles rather than on cash flow, and it captures the financial 

position of a project at a given point in time. The income statement uses a basic formula to 

determine the “net income” to the firm: Revenue (or income) – Expenses (or costs). 

Figure 3-3. Effect of key policies on geothermal project income statement

Source: Navigant 2010

Note: Not all incentives are applicable to every project. Consult with tax and legal advisors for 

specifics. Additional detail on these incentives is available in Appendix A.

Revenue

- Operating 

Expenses

- Depreciation

- Interest Expenses

- Tax Expense

Accelerated 

depreciation reduces 

taxable income in 

early years

Tax Expense reduced 

by PTC or ITC

RPS improves 

ability to obtain 

PPA, reducing 

revenue risk.

RPS increases 

value of green 

power or RECs, 

increasing 

revenue

Increased 

certainty of 

revenue reduces 

cost of debt and 

related Interest 

Expense

Reduced 

permitting 

costs reduce 

Operating 

Expenses

Shorter permitting, 

leasing timeframes 

accelerate time to 

revenue and reduce 

uncertainty

GHG 

regulations 

may increase 

price of power, 

increasing 

revenue 

Net Income

Key

Tax 

Incentive

RPS

Leasing, 

Permitting, 

Transmission 

GHG 

Regulation

Cash Grant 

serves as 

additional form 

of revenue

DOE Loan 

Guarantees 

reduce cost of 

debt, related 

Interest Expense

Cash 

Incentive / 

Revenue 

Enhancement

Income Statement 

Calculation

Potential Financial Effect(s) of Key Policies
14

4 Financing Geothermal Projects

Geothermal resource development is critically dependent on access to financing under attractive 

conditions. As a result of the global economic contraction that began in 2008, access to financing 

in general became more challenging, though recent indications are that both access and financing 

terms are improving. 

This chapter begins with a summary of the changes in the market for geothermal project finance 

that resulted from the 2008 downturn. Next, Section 4.2 highlights the unique aspects of 

geothermal energy projects relative to other renewable energy projects. Section 4.3 summarizes 

the sequence of investment needed to complete a geothermal project and the financial and nonfinancial requirements for each stage. Finally, the last part of this chapter identifies some 

common missteps made by those seeking project financing. 

This section largely reflects the results of interviews with market participants complemented by 

selected Internet-based research. Interviews were conducted between April 2010 and June 2010 

with 15 developers, financiers, and other industry experts. These interviewees were asked to 

comment on the following topics:

• Availability of financing for renewable energy projects in general and specifically for 

geothermal projects

• How geothermal project financing differs from other renewable energy resources

• Providers of different types of geothermal project financing and their investment 

requirements at each stage of project development

• The importance of federal, state, and local incentives in project financing

• Common pitfalls for those seeking financing

4.1 The New World of Renewables Financing 

The global credit crunch and economic contraction, which began in 2008, impacted many 

financial institutions, and this impact was felt across the renewable energy financing spectrum. 

Loan losses and bankruptcies removed many financing providers from the market at least 

temporarily. Financial losses reduced the availability of tax equity by wiping out taxable income 

against which investors could apply tax credits, taking most investors out of the market. In 

addition, these shocks eliminated a major source of specialist geothermal project financing:

Iceland-based Glitnir Bank. Lenders and investors still in the market became considerably more 

risk averse and were operating with less capital than before the contraction. Consequently, 

lenders were willing to lend less to a given project for shorter periods of time and at higher 

interest rates (Schwabe et al. 2009). Increased perceived risk also resulted in many private equity 

funds cutting back on their investment in general and renewable energy investment in particular. 

At the same time, the private equity investors demanded significantly higher projected returns or 

higher ownership shares in the investment.

Today, there are fewer institutions actively providing financing for renewable energy projects 

than there were before 2008 (Chadbourne and Parke 2009). Prior to 2008, many investment 

banks provided the tax appetite that many renewable energy project developers lacked; that “tax 
15

appetite” was a tax liability sufficient to absorb the tax incentives for investment in renewable 

energy projects. With the economic contraction, some of these institutions failed or were 

acquired by other banks that were less active in tax equity. In addition, the banks’ tax appetite 

shrank due to decreased earnings and increased perceived risk. According to market actors, large 

insurance companies and pension funds remained somewhat active in lending to renewable 

energy projects, but other investors, such as investment banks, limited their involvement in the 

market.

Market participants say that financing is now becoming more widely available than during either 

of the past two years, though it is not yet at levels seen pre-2008. Loan tenors and risk tolerance 

are increasing; the mix of investors is shifting and interest rates and expected returns are 

declining. While the recession has taken some bank lenders out of the market, the appetites of 

those that remain are growing. There has also been strong growth in appetite from fixed-rate 

insurance company lenders in financing renewable energy projects; to date, 2010 has witnessed

large syndicated financing at tenors of 20 and 25 years. As of late 2010, the unprecedented low 

yields on Treasuries and tight spreads on high-quality credit have taken the all-in cost for these 

sources of financing to historic lows. At the same time, the Treasury Cash Grant has made tax 

equity less essential for moving forward projects that meet the requirements discussed in Section 

3.1.1.

4.2 Financing Geothermal Projects 

Geothermal projects have one significant difference in their energy production profile compared 

to most other renewable energy technologies: they provide relatively constant power using a 

technology that has been operating at utility scale for over 50 years (CEC 2009). According to 

the California Energy Commission, some geothermal power projects may operate with capacity 

factors of in excess of 90% - typically higher than other renewable energy technologies that use 

intermittent resources (CEC 2009).

On the other hand, geothermal projects are less attractive than other renewable energy 

technologies in ways that make obtaining financing more challenging. The significant investment 

required to find and prove the geothermal resource, an activity akin to oil and gas exploration, is 

unique to geothermal among renewable energy resources. This facet substantially changes the 

power project’s level of certainty in its early stages as well as the development time required 

relative to other renewable energy resources. Renewable energy projects compete with lowincome housing for tax equity financing due to similar investor tax benefits (Schwabe et al. 

2009); yet, geothermal market participants report that only geothermal is also competing for 

capital (and drilling rigs) with other underground resource-oriented investments, such as mineral, 

coal, and oil and gas exploration. In the early project stages, geothermal developers must target 

investors who are comfortable with higher levels of risk and longer development time horizons. 

The difficulty (and cost) of proving a geothermal resource significantly increases the risk of 

investing in a geothermal project in its early stages. 

At the same time, permitting can be more challenging because multiple permits may be required 

due to the nature of the resource and the location of the plant (The Wilderness Society 2008). 

Additionally, according to interviewees, development of that resource can take three to four 

years, while plant construction can take another 18 months to four years. 
16

The higher overall project risk of geothermal has recently led to limited utility investment in 

geothermal project development. Currently, utilities own and operate only 170 MW of 

geothermal power plants, all of which were developed in the early 1980s (SNL Financial 2010). 

At this time, investor-owned utilities (IOUs) are not in the process of building utility-owned 

geothermal plants that use conventional technology (SNL Financial 2010). Some municipal 

utilities, including the Snohomish Public Utilities District (Snohomish, Washington), are 

considering geothermal investments, but none of these projects are moving toward construction 

at this time (SNL Financial 2010; Sheets 2010). Four main challenges persist for utilities to move 

forward with geothermal project investment and construction, according to market participants, 

as shown in Figure 4-1.

Figure 4-1. Reasons for lack of utility activity in geothermal project development and ownership

Source: Navigant interviews with market actors 2010

Historically, larger scale geothermal resources were developed by natural resource companies, 

with utility involvement typically limited to power plant construction and power production. The 

earliest utility-scale geothermal field development in the United States occurred in the Geysers 

field in Northern California (U.S. DOE 2006(c)). The steam field was developed in the 1960s 

and 1970s by a partnership of Union Oil Company of California, Magma Energy Company, and 

Thermal Power Company to serve Pacific Gas & Electric’s (PG&E) geothermal power plants 

(Geysers Geothermal Association 2005). PG&E sold its interest in its Geysers plants (it did not 

own the steam fields) as part of the California power market deregulation in 1998 (Geysers 

Geothermal Association 2005). Other geothermal resources saw limited development until the 

late 1990s and thereafter with the growing interest and market support for renewable power.

4.3 The Staging of Geothermal Project Financing 

Different sources of financing are tapped in series at each stage of geothermal project 

development. Each source earns a return commensurate with the risk accepted at that point in the 

project life cycle. At later stages, some of the new financing pays off a portion of the existing 

debt from previous stages. Figure 4-2 depicts an estimation of the probability a project will be 

built at each stage of geothermal project development along with the relative investment 

magnitude for a 50 MW plant; in addition, the bottom part of the figure captures the type of 

financing that is available for each stage. FamiliarityUtilities are 

unfamiliar with 

the technology.

Similarly, 

regulators are not 

familiar with the 

technology.

Investment MetricsUtilities’ approved 

rates of return are 

not sufficient to 

accommodate the 

early-stage risk.

RegulatorsWithout a 

mechanism to 

hedge risk, 

regulators hesitate 

to commit 

ratepayer funds to 

risky development 

(20% to 50% dry 

holes).

CompetitionBy the time 

utilities’ rates of 

return are 

sufficient to 

warrant 

investment (i.e., 

construction), 

other entities offer 

financing at more 

attractive rates.
17 

 

Figure 4-2. Geothermal project development and financing by stage 

Source: Deloitte 2008 

The following sections discuss the types of, and potential sources for, financing in the various 

stages of project development noted in Figure 4-2 as well as the investors’ financial and nonfinancial requirements. The information in this section is based on interviews with industry 

experts unless otherwise noted. 

4.3.1 Early-Stage Financing 

The three earliest and highest risk development phases for geothermal are the most difficult for 

raising capital. These are the project phases that differentiate geothermal from other renewable 

resources and the phases that have strong similarities to oil and gas exploration. Financing in 

these phases presents the greatest challenge because of its uncertain opportunity for returns and 

the lack of familiarity with the technology in the renewable energy financing market. 

Before the 2008 market downturn, assembling a group of private investors to support the early 

stages of a geothermal (or any generation) project was done regularly. A developer would have 

started with a relatively small amount of seed capital raised from “angel investors.” The 

developer would have then turned to private equity firms for Series A financing, the first 

financing after their seed capital investment. Because of the credit crisis, however, market 

participants report that both of those sources of capital have largely dried up; limited to no 

project equity is available at this stage. 

Resource 

Identification

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Evaluation Test Well Drilling Production Well Drilling Plant Construction Plant Operation
18

Three approaches to raising early-stage funding have been used since the 2008 market downturn:

• Private equity placements of a portfolio of projects

• Exchange-traded corporate equity financing

• Balance sheet financing (effectively a combination of corporate debt and retained 

earnings) by more established companies

4.3.1.1 Private Equity Financing of a Portfolio of Projects

A strong cadre of companies has successfully raised private equity during these early and higherrisk development stages by offering a portfolio of projects. For example, Vulcan Power

Company raised a second round of private equity in early 2010 from Denham Capital Partners 

(RenewableEnergyWorld.com 2010). Vulcan has a portfolio of five projects in advanced 

development and another five projects in earlier development stages (Jennejohn 2010). In 

addition, Toronto Stock Exchange (TSX)-listed U.S. Geothermal successfully executed two 

private placements within the last nine months (U.S. Geothermal 2009; U.S. Geothermal 2010).

Other private equity companies with geothermal investment include ArcLight Capital Partners 

through its Terra-Gen subsidiary, and U.S. Renewables. The last of these has been notably active 

in the geothermal space recently (U.S. Renewables 2010). ArcLight actually reduced its 

investment in its renewable portfolio in late 2009 by selling up to a 40% convertible preferred 

interest in Terra-Gen to international infrastructure fund Global Infrastructure Partners (PR 

Newswire 2009).

Given the similarity in development risks to oil and gas exploration and production, private 

equity funds with experience in this arena may be more comfortable than others in taking on the 

risks of geothermal development. Some private equity providers that fit this mold include 

Riverstone Holdings, First Reserve, and Energy Capital Partners.

4.3.1.2 Exchange-Traded Corporate Equity

One of the most common sources of early-stage funding since the 2008 market downturn has 

been corporate equity financing according to market participants. Considerable development of 

North American geothermal projects has been financed by companies with expertise in 

geothermal power that filed for their initial public offering (IPO). Companies seeking to list on 

the public exchanges have three important competitive advantages that may enable them to raise 

equity at the corporate level:

• Technology expertise and experience that improves the likelihood of success of any 

individual project.

• Project portfolios that reduce the risk of an individual project by spreading the risk across 

an entire investment portfolio; the broader portfolio may include diverse investments 

beyond geothermal projects and/or multiple geothermal projects in various stages of 

development.

• Expectations of success in the project portfolio, which may be justified by projects 

located in proven fields or by receiving favorable resource reports by well-respected 

engineering firms.
19

Many younger geothermal companies have succeeded in raising capital through public 

exchanges. These younger companies have followed the path of larger companies that have been 

in the publicly-traded market for an extended period of time. Examples of such companies with 

long histories of public equity include Calpine Corporation, Rocky Mountain Power, ENEL, and 

Ormat. CalEnergy, a subsidiary of Mid-American Energy, also has geothermal expertise and a 

substantial portfolio of geothermal plants, but has not been that active in project development 

recently. More recent market entrants that raised capital through public exchanges include U.S. 

Geothermal (U.S. Geothermal 2008) and Nevada Geothermal Power (Nevada Geothermal 2010). 

The U.S. stock exchanges have been less receptive to listing geothermal power development 

companies than the Canadian and Australian exchanges. The Canadian stock exchanges are 

known to have more investors who are comfortable with resource development risks, which are 

common to the oil, gas, and mining companies that are listed on these exchanges. The TSX is 

one of the major North American exchanges and typically caters to larger, more established 

companies; however, companies such as Ram Power, discussed below, have succeeded in listing 

there. An alternative source of capital for smaller and higher risk companies is the TSX Venture 

Exchange, which is the combination of the former Alberta and Vancouver exchanges. Many 

smaller geothermal companies in North America are listed on this exchange. In addition, the 

Australian Stock Exchange is more familiar and comfortable with resource development risks 

because of the considerable number of mining companies traded on those exchanges. Of 

particular note in Australia is the rapid growth in EGS investment due to strong government 

investment (Biello 2008). 

Ram Power’s story demonstrates how public equity has become a more important source of 

equity since the economic downturn and how receptive the Canadian markets are to small 

geothermal companies. Initially, according to interviewees, Ram Power attempted to raise 

development equity from private sources while depleting its seed capital. Private equity 

investors, however, were uncomfortable committing significant funding to a company with a 

portfolio of geothermal projects in development and with the drilling risk profile surrounding its 

business plan, including its plans for success and exit strategy. When that approach proved 

unsuccessful, Ram Power broadened its project portfolio by combining with two small 

geothermal companies listed on the TSX and TSX Venture Exchange: Polaris Geothermal and 

Western GeoPower (eMedia World 2009). The combined firm, bearing the Ram Power name, 

then raised over $180 million (Can) in subscription receipts (equity) financing on the TSX in 

2009, where the capital markets were receptive to resource-based investments (ThinkGeoEnergy 

2009). Effectively, with the Ram Power merger and TSX listing, investors were offered three 

benefits relative to the pre-merger company: (1) a broader portfolio that reduced risk, (2) a 

potential return of multiple times their initial investment, and (3) a means to liquidate their 

investment relatively rapidly whenever desired.

Conversely, in April 2010, Colorado-based Standard Steam Trust called off an IPO that was 

planned for December 2010 on the TSX (Richter 2010). Weak market demand for exchangetraded investments in emerging companies with small market capitalization, short operating 

history, and low earnings drove the Standard Steam Trust decision (Richter 2010). Similar 

thinking derailed IPOs around the world in the second quarter of 2010, in large part due to the 

uncertainty related to the European sovereign debt crisis (Cowan 2010). As of late 2010, it is too 

early to predict the long-term effects on the market for geothermal company IPOs. 
20

4.3.1.3 Balance Sheet Financing

Companies with a long track record of geothermal project development have used both internal 

funds and raised corporate debt to fund early-stage project development. Investing internal funds 

requires strong positive cash flow to make funds available. Providers of corporate-level debt 

have recourse to a company’s other assets, reducing the risk of this type of investment. The 

investments are evaluated by considering the financial stability and strength of the company as a 

whole, rather than the characteristics of any specific project. Companies with low levels of 

existing debt are in a strong position to raise additional capital at attractive prices through the 

debt markets. Once the corporation receives the debt, it is able to apply the funds to any existing 

needs, including early-stage project development. Ormat has used both corporate debt and lines 

of credit to fund early-stage projects (Ormat Technologies 2010).

4.3.1.4 Requirements for Investment: Early Stage Financing

Market participants report that investors in the earliest stages of geothermal financing are 

interested in the higher returns associated with ownership (equity). Lenders are not typically 

interested in project-level debt at this stage because of the high risk, although corporate-level 

debt can be acceptable as discussed above. As shown in Table 4-1, private and public investors 

are buying small company equity with expectations of returns in the 2x to 5x range. They require 

a well-thought-through development and financial plan, as well as a proven management team. 

Established corporations with strong balance sheets and a diverse asset portfolio that includes 

geothermal power plants have very different return expectations for new geothermal projects 

according to market participants. While they are looking for marginally higher returns from 

geothermal projects than from wind, market participants have stated they prefer a return on 

equity (ROE) greater than 13%, but their minimum ROE would be as low as 10%. The diversity 

of their asset portfolio, the related lower cost of capital, and their familiarity with the technology 

enable them to accept lower rates of return from their geothermal investments when compared to 

other investors in geothermal projects.
21

Table 4-1. Early-Stage Equity Financing Requirements

Sources Financial Metrics Non-Financial Requirements

Public 

Exchanges 

and Private 

Equity

» 2x to 5x multiple on 

investment 

» Reasonable financial plan 

including wells costing $2 

to $5 million each and 

anticipation of 2 to 5 failed 

wells for 10 producing wells

» Experienced management team 

» Qualified management team: ability to raise 

capital and carry out business plan

» Risk mitigation strategies, e.g., drilling in a proven 

field

Corporate 

Balance 

Sheet 

(establishe

d market 

investors)

» ROE minimum 10%, 

preferably 13+% 

» ROE 100 to 200 basis points 

higher than wind

Source: Navigant interviews with market actors 2010

4.3.2 Late Development Financing 

Later in the early development stage, after the initial production wells are drilled, mezzanine debt 

financing may be available. Mezzanine financing is debt financing that also includes an “equity 

kicker,” which allows the provider to benefit from a portion of the equity upside of the projects. 

Similar to construction financing, the debt is secured by liens on the project’s assets, allowing 

the mezzanine provider to take possession of the project should the developer default on the debt. 

The lender does not, however, have recourse to the company’s other assets. While the cost is 

relatively high for debt, it is lower than that for traditional equity. According to market actors, 

mezzanine financing is usually put in place about 12 to 18 months before construction financing

is obtained. Mezzanine financing is typically repaid with proceeds from a senior loan used for 

construction of the plant. 

Because mezzanine financing is relatively high risk and requires deep knowledge of geothermal 

project development, its historical availability has been limited and during the financial crisis 

was non-existent. The largest U.S. provider of geothermal project mezzanine financing, 

Islandsbanki (Glitnir Bank until 2008), was forced to withdraw from the U.S. market following 

the Icelandic banking crisis in 2008 (Mortished 2008), leaving a gap in the market. In 2010, 

however, Islandsbanki stated its intention to re-enter the U.S. market for geothermal project 

mezzanine financing. West LB, an experienced global asset-backed lender to power plant 

developers, may be a newer market participant interested in this arena. Combined, however, 

these providers will only cover a small number of projects each year according to market 

participants.

4.3.2.1 Requirements for Investment: Mezzanine Debt

Mezzanine financing providers offer high-cost debt. This early debt is secured by the project’s 

assets, allowing the lender to take control of the assets if there is a default on the debt. 

Resource 

Identification

Resource 

Evaluation Test Well Drilling Production Well Drilling Plant Construction Plant Operation
22 

Mezzanine debt typically also requires an equity component ranging from 10% to 30% of the 

project’s equity, as part of financial return to the lender. Market participants report that 

requirements for lending at this stage include a contribution of at least 25% of project costs by 

the developer, a signed PPA, a significantly proven resource (usually by at least one production 

well drilled), and the fulfillment of other requirements listed in Table 4-2. 

Table 4-2. Mezzanine Financing Requirements 

Sources Financial Metrics 

Non-Financial 

Requirements 

» Historical mezzanine debt 

or bridge loan providers 

» Potentially project 

financiers seeking new 

markets

» Developers able to provide 20% 

to 25% of the equity themselves 

» ROE usually in the 25%-29% 

range, 30+% preferable, typically 

including debt priced at 15% plus 

10% to 30% of project equity 

» At least one production hole 

drilled 

» Experienced management 

team 

» A resource assessment by wellrespected firm 

» PPA with creditworthy 

counterparty 

» Drilling contract in place 

Source: Navigant interviews with market actors 2010 

4.3.3 Construction & Operation Financing 

Once a substantial amount of the resource has been proven, project developers are able to seek 

project-level debt to finance construction and operation of the facility. Developers seek the least 

expensive capital. Since mid-2009, this has reportedly meant debt financing at this stage of the 

project if it is feasible given their project funding requirements and internal finances; it is more 

readily available at this stage than at earlier stages. In some cases, however, it is necessary to 

bring in an additional equity investor as well as lenders. As with the other types of financing 

discussed in this guidebook, the market for financing at these stages has changed since the 

market downturn. This section outlines the major changes in this market, highlights an 

innovative structure recently employed, discusses the role of federal incentives, and identifies 

companies with interest in investing at these later stages of project development. 

4.3.3.1 Changes Since the Downturn 

Perhaps the most significant change in project-level financing since the economic downturn is 

the percentage of resources that are required be proven to secure financing according to market 

actors. This change essentially translates into an up-front equity investment of greater magnitude 

before construction financing can be obtained. Historically, project developers report that they 

had to prove (that is, drill production wells capable of generating) as little as 25% of the resource 

to obtain construction financing, according to market experts. With the current market risk 

aversion, however, market participants indicate that proof requirements have risen to as much as 

80%, although this appears to be loosening along with other market factors; at least two 

developers report that they recently obtained construction financing with 50% to 60% of the 

resource proven. 

The 2008 economic downturn also affected the type, sources, and terms of available financing at 

this stage. Market actors report that the current preference regarding lending structure during this 

Resource 

Identification

Resource 

Evaluation Test Well Drilling Production Well Drilling Plant Construction Plant Operation
23

stage is for conversion of construction financing to term loans, with the term loan used to pay off 

the construction loan. This is a more recent phenomenon and appears largely to be the result of 

the availability of the Treasury Cash Grant in place of the ITC or PTC. With the Treasury Cash 

Grant being used to pay down some of the debt at the conclusion of construction, lenders are 

willing to finance the project using term loans as opposed to the tax equity structure. Prior to the 

establishment of the Treasury Cash Grant, project developers most commonly used tax equity, 

which was priced similarly to many debt products because it was very low-risk equity (Harper et 

al. 2007). The tax equity approach may become more common in the future with the expiration 

of the Treasury Cash Grant.5

At present, no sale-leaseback transactions and very little tax equity financing are occurring in the 

geothermal sphere. Prior to the 2008 downturn, the tax equity flip structure was quite common,

and some sale-leaseback transactions occurred with renewable energy plants. Essentially, the tax 

equity flip structure has the same key feature as a sale-leaseback arrangement: both allow the 

monetization of the tax benefits of the investment. With the partnership flip structure, the 

ownership of the project flips among partners (including a tax equity investor) at negotiated 

stages of the arrangement. Historically, the flip typically occurred at 11 years with the PTC and 6

years with the ITC (U.S. DOE 2007). Market actors report that previous tax equity providers 

were primarily investment and commercial banks, but some insurance companies were also 

active. JP Morgan has reportedly been active in this arena recently. Under a sale-leaseback 

transaction, the developer sells the plant to a bank, and then leases it back from the purchaser. As 

of September 2010, industry experts report that John Hancock is working on lending into a saleleaseback project finance transaction for wind, though not for geothermal at this time. 

As indicated previously, in the current market, construction 

financing providers are commonly locking in the term loan as well. 

4.3.3.2 Innovative Lending Structure

A recent example of construction finance indicated a shift in the terms of construction finance. 

Previously, financing at the construction stage typically was funded by 80% debt, which was 

refinanced once the plant had reached production with either a more permanent long-term senior 

debt facility or a tax equity investment. The May 2010 financing of the 49.9 MW Hudson Ranch 

geothermal project in the Salton Sea Known Geothermal Resource Area raised $300 million in 

debt and $100 million in additional equity. Further, the debt comprised two components:

• A $95 million cash grant bridge loan for the two-year construction period plus 120 days 

afterward, which will be repaid with the proceeds from the Treasury Cash Grant 

(calculated using the ITC)

• A $205 million “mini-perm” loan (Power Finance & Risk 2010)

A “mini-perm” loan is a senior debt facility with a term that is longer than typical bank debt but 

shorter than long-term “permanent” facilities. These facilities are typically payable over five to 

seven years and include a balloon payment at the end of the facility. In this case, the facility has 

a 7-year term: 2 years of construction and 5 years of production. This structure, according to an 

 5 Unless otherwise modified, the Treasury Cash Grant eligibility rules require that a plant must 

be under construction by December 31, 2011.
24

interviewee familiar with the transaction, then enables the lender to reduce its risk (through the 

shorter loan tenor) while allowing the developer time to obtain a longer term loan after building 

an operational track record, thereby lowering the “permanent” loan’s cost to the developer.

The Hudson Ranch 5-year term loan reflects another recent post-2008 financing market

development: shorter loan tenors. For the last couple of years, in contrast to 15- to 20-year 

financing available before 2008, term loans from banks have generally been running only five to 

seven years. This has been slowly increasing again, according to market participants, and now 

some loans are going out 15 years. Insurance companies generally have the longer-term horizon 

that developers prefer – 18 to 20 years on a 20-year PPA – and they have reportedly become 

more active in the market in recent months.

4.3.3.3 Role of Federal Incentives

Many geothermal power plant developers also seek a loan guarantee from the DOE (GEA 2010)

in addition to taking advantage of the PTC, ITC, or Treasury Cash Grant. The DOE Loan 

Guarantee for renewable energy projects is designed to help lower the cost of borrowing during 

both the construction and the operation phases of project financing (U.S. DOE 2010(a)). It 

includes both a fully-guaranteed experimental technology program (section 1703) and a 

partially-guaranteed conventional technology program (section 1705). Developers report facing 

some challenges in meeting the necessary conditions for these programs and taking advantage of 

the tax-based incentives at the same time: 

• The first challenge is timing the initial ground-breaking after the necessary federal 

environmental review under the National Energy Policy Act (NEPA) and before the 

expiration of the Treasury Cash Grant eligibility at the end of 2011, which is more 

valuable to developers than the Loan Guarantee according to market experts interviewed. 

The ITC would be available if the initiation of project construction slips beyond 2011

when the Treasury Cash Grant eligibility would no longer be available (unless otherwise

extended). 

• If the project misses the potential 2011 construction start date deadline, the second 

challenge is then to bring the project on-line before the end of 2013 to be able to take 

advantage of the 30% ITC, which has a deadline for the construction start date. 

Completing construction between January 1, 2012 and December 31, 2013 may be a 

challenge for projects with construction timelines closer to 4 years than to 18 months. 

Because of these two timing-related challenges, industry sources report that the project pool has 

been limited. Applications to the DOE Loan Guarantee program under section 1705 have been 

dominated by projects that were completing NEPA compliance certifications anyway as part of 

being located on federal land or having another permitting interaction with a federal agency as 

part of their project. Industry sources report that projects that did not previously have the NEPA 

process incorporated into their project timelines would generally be unable to meet the timelines 

for the Treasury Cash Grant or 30% ITC.

Industry experts report that, while the DOE Loan Guarantee can be difficult and expensive to 

obtain, it can have a very beneficial impact on project cost of capital. According to interviewees, 

the DOE Loan Guarantee can reportedly reduce the debt cost by 100 to 200 basis points (bps). 

John Hancock has filed loan guarantee applications under section 1705 of the program for five 
25

geothermal projects. One of these, Blue Mountain, was the first geothermal project to be 

approved by DOE under the conventional technology / Financial Institution Partnership Program

(Pettit 2010).

Looking forward, with the potential expiration of eligibility for the Treasury Cash Grant 

alternative to the ITC and PTC at the end of 2011, it is possible that historical financing 

structures like tax equity and sale-leaseback deals will regain their place in the market. It is 

difficult to project at this point what terms providers will seek or how they will structure their 

transactions; no such transactions for geothermal projects have occurred since the 2008 credit 

crunch (transactions have occurred for wind and solar), and many of the traditional market 

players have left the market. Tax equity investors in the solar and wind space have focused their 

resources on only the best projects with the most proven management teams, leading a “flight to 

quality” to help mitigate risk (Schwabe et. al 2009).

Based on recent financing activity at other investment stages it appears likely that two changes 

will occur: (1) there will be new financing structures; and (2) the new financing structures will be 

designed to reduce the lenders’ risk from the level they assumed before 2008. Without recent 

geothermal tax equity financing activity, it is difficult to suggest any likely investor 

requirements. It is probable, however, that these financiers will be looking for the same nonfinancial characteristics as are providers of term loans detailed in Table 4-3.

4.3.3.4 Interested Providers of Construction and Operations Debt

Geothermal construction financing presently is being offered by a number of insurance 

companies and pension funds with such construction financing typically convertible to term 

loans at the end of construction, according to market actors. Companies who have been active in 

this market recently include Manulife (through U.S. subsidiary John Hancock), MetLife, 

Prudential Life Insurance, and larger North American pension funds. Others active in the justclosed Hudson Ranch project financing include ING, WestLB, Société Generale, Union Bank, 

CIBC, Investec of South Africa, and Siemens (Power Finance and Risk 2010). The additional 

Hudson Ranch equity financing was provided by three investors: GeoGlobal Energy (GGE) 

backed by Mighty River Power (a state-owned New Zealand utility), Hannon Armstrong (a small 

investment bank), and Catalyst (a biomass developer) (interviewees and Power Finance and Risk 

2010). The latter two private equity providers were prior owners of Hudson Ranch; GGE will 

become a 20% investor in EnergySource, a new company that will oversee Hudson Ranch and 

develop additional resources in Imperial County, California (Power Finance and Risk 2010).

4.3.3.5 Construction and Operations Equity

Developers currently seeking financing identified only one active provider of equity in the later 

stages of project development: GGE. When lenders required additional equity injections, 

interviewed developers all raised the funds internally. JP Morgan was identified as one market 

participant seeking tax equity opportunities, but no geothermal deals of this type are currently 

public knowledge.

4.3.3.6 Requirements for Investment: Project Financing

Construction financing providers require that considerably more of the resource be proven than 

for mezzanine financing. In the recent economic downturn, market experts report that the 

requirement rose as high as 80%. More recently, market experts indicate that this requirement is 
26

in the range of 50% to 60%; this requirement varies at least in part with the nature of the steam 

field. Pre-2008, this figure could have been as low as 25% according to market actors. Developer 

equity requirements have also risen to 40% to 45%, as shown in Table 4-3.

Once geothermal projects meet the current investment requirement for 50% to 80% of 

geothermal resources to be proven, financing risk is currently considered on par with that for 

gas-fired plants, according to one financier involved with both types of development. Market 

experts provided data from two different perspectives:

• Borrower Data Point: In late spring 2010, a borrower reported that banks were offering 

interest rates on project-specific loans that could be as low as 10-year U.S. Treasuries

plus 250 to 300 bps with a PPA. 

• Financier Data Point: In late summer 2010, a financier reported that insurance 

companies were offering interest rates on these project-specific loans on the order of 10-

year U.S. Treasuries plus 325 to 375 bps for projects with a PPA.

These differences are to be expected, given that the financier’s target project type may differ 

from the types of projects in the borrower’s portfolio. Both data points are reported to provide 

some perspective on the variability in the market for geothermal project finance across time and 

project definitions. The rates for the Hudson Ranch project were at London Interbank Offered 

Rate (LIBOR) plus 325 escalating to 375 bps (Power Finance and Risk 2010; LCD News 2010).

While typically lenders at this stage will expect a signed PPA with a creditworthy counterparty, 

there is at least one market, according to interviewees, where a PPA may not be necessary to 

obtain financing: California. The RPS of 33% in California is so stringent that lenders perceive 

minimal risk of failure to sell the energy. At the same time, market participants indicated that 

lenders would expect to see more equity in the project if no PPA were in place.
27

Table 4-3. Possible Construction Financing Requirements

Sources: Navigant interviews with market actors 2010

* LCDNews 2010

Current lenders are taking advantage of the availability of the Treasury Cash Grant in place of 

the ITC and PTC to lend under a traditional term loan structure. Equity requirements are still 

relatively high, reflecting the current risk-averse investment environment. Table 4-4 summarizes 

these and other requirements for investors during the operational stage of project development.

Sources Financial Metrics Non-Financial 

Requirements

For Debt

» Insurance 

companies

» Large pension 

funds

» Selected banks

» Previous debt (lending) to equity 

(ownership) of 75%:25%, now requiring 

40% to 45% equity 

» DOE Loan Guarantee program can 

require a minimum of 20% equity

» Debt service coverage ratio of 1.5 to 

1.75. (Previously 1.4 to 1.5.)

» Borrower data point: Interest rates (as of 

May 30, 2010) above 10-year Treasuries 

plus 250 to 300 bps with a PPA

» Financier data point: Interest rates from 

insurance companies (late August 2010) 

10-year Treasuries plus 325 - 375 bps

with a PPA

OR

» 7-year mini-perm (two years 

construction and five years operation) 

priced in May 2010-at LIBOR plus 325 

escalating to plus 375*

» PPA usually required, though 

exceptions are made in 

California (more developer 

equity would be required 

without a PPA)

» Engineering, procurement, 

construction (EPC) contract 

that wraps around the entire 

plant must be in place

» Engineers’ report stating that 

available resources can 

support a 20-year financing

» Experienced management 

team

» At least 50% to 80% of 

production wells need to be 

drilled

Private equity 

investors

» 20+% returns
28

Table 4-4. Possible Post-Construction Project Financing Requirements

Sources Financial Metrics

Non-Financial 

Requirements

» Insurance 

companies

» Large pension 

funds

» Selected banks

» Construction loan typically paid down with

Treasury Cash Grant

» DOE Loan Guarantee program requires a 

minimum of 20% equity and, if getting the 

30% ITC or Treasury Cash Grant, they want 

14% equity after the 30% ITC

» Previously required debt to equity of 

75%:25%, now 40% to 45% equity 

» Debt service coverage ratio (DSCR) of at 

least 1.5 

» Experienced management 

team

» Typically require a PPA with a 

creditworthy counterpart

» Engineers’ report stating that 

the resources are available to 

support a 20-year financing

Source: Navigant interviews with market actors 2010

4.4 Common Pitfalls in Obtaining Geothermal Financing

For developers interested in financing their projects, there are a number of common pitfalls to be 

aware of and avoid in the process. Perhaps the most common pitfall is excessive optimism. 

Investors need to have confidence that the developer knows what they are doing; developers that 

neglect to plan for the inevitable dry hole or to adequately account for production wells in their

financial forecast are setting themselves up for failure. The best case is inability to raise capital; 

the worst case is undercapitalized and comprehensive losses. It is essential to incorporate 

adequate contingencies to protect all investors and demonstrate a thorough understanding of 

project development risks and requirements. Some specific areas to pay particular attention to 

include the following:

• Adequate production well drilling funding that assumes a credible rate of dry holes

• A reasonable drilling cost per well that reflects the required well depth and hydrothermal 

geology

• Funding to cover an adequate number of injection wells

• Time and investment to obtain all necessary permits

• A reasonable all-in cost of plant construction assuming use of an EPC contractor

• Reasonable development and construction time horizon

A second common pitfall is seeking funding from the wrong sources for the particular project’s 

stage of development. An insurance company is not going to be interested in providing capital 

early in the resource identification and valuation stages. A private equity investor would be an 

unnecessarily expensive funding source in the later project development stages when 

construction and term loans are available. 

Another frequent mistake is seeking financing before the project development is mature enough. 

It is important to understand the risk parameters, financial metrics, and non-financial 

requirements of prospective lenders before they are approached. This includes making sure the 

property and resource rights are all secured and that those rights are fully understood – as are the 

permitting and approval processes. Additionally, the developer needs to have a good engineering 

analysis of the resource available. 
29

5 Conclusion

Investment in conventional geothermal projects on the utility side of the meter has evolved 

dramatically since the economic downturn began in 2008. Developers and investors identified 

innovative approaches to address the capital constraints that permeate the entire market and to 

take advantage of new policy incentives that emerged. These innovations were especially 

important in the early stages of project development, when capital providers must be comfortable 

with the risk associated with resource identification and test well drilling. Innovations later in the 

project development process responded to changes in the way that projects took advantage of 

federal incentives including the Section 1603 Treasury Cash Grant Program that reduced the 

need for tax equity in 2009 – 2011 and possibly beyond.

Looking ahead, uncertainty dominates the market for geothermal project finance:

• Potential expiration of the Treasury Cash Grant as construction must begin by the end of 

2011 for project eligibility (unless the program is otherwise extended).

• Potential expiration of the PTC is soon enough that new projects are not certain to 

complete construction in time to meet the December 31, 2013, deadline.

• Potential federal regulation of GHGs could have a dramatic effect on the electricity 

market as a whole, but the timing and content of such policies are in doubt.

As these uncertainties are worked out in the marketplace, it is unclear if pre-2008 conditions will 

return or if the market has entered a new, more conservative paradigm for a longer period.

Despite these risks, several positive developments are currently underway:

• Both access to capital and financing terms have improved. This is evident in the 

anticipated return of mezzanine finance to the U.S. geothermal project finance market 

and in the loosening of construction financing.

• Innovative structures have been developed to facilitate deals. Groups of investors are 

pooling resources to create risk profiles in line with their objectives. Construction and 

term loans are being bundled, reducing transaction costs and streamlining investment.

• The tax appetite that is needed to facilitate tax equity transactions is anticipated to return, 

though continuing the “flight to quality.” A return to profitability for many institutional 

investors is a critical input to successfully monetizing the federal tax credits that will 

remain intact following the expiration of the Treasury Cash Grant program. 

Figure 5-1 summarizes the main concepts discussed in this report: the risk profile of geothermal 

projects, key stages in project finance, types of capital available at each stage, and key investor 

requirements at each phase of project development. Appendix D provides additional resources 

for tracking project development.
30

This guidebook is intended to facilitate further investment in conventional geothermal projects in 

the United States. Using the information provided, developers and investors may innovate in new 

ways, developing partnerships that match investors’ risk tolerance with the capital requirements 

of geothermal projects. The marketplace is dynamic and will continue to evolve. 
31

Figure 5-1. Summary of this guidebook’s key information for financing geothermal projects

Source: Navigant interviews with market actors 2010

Resource 

Identification

Resource 

Evaluation Test Well Drilling Production Well Drilling Plant Construction Plant Operation

Early-Stage Financing Late Development Construction and Project Finance

Public Exchanges and 

Private Equity Corporate Balance Sheet Mezzanine Debt Construction Loan Term Loan

» Financial plan with reasonable 

assumptions about well costs 

and failed wells

» 2x to 5x multiple on 

investment 

» ROE of minimum 10%, 

preferably 13+%

» ROE 100 to 200 basis points 

higher than wind

» ROE usually in the 

25-29% range, 

30+% preferable,

typically includes 

debt priced at 15% 

plus 10-30% of 

equity 

» Developers able to 

provide 20 to 25% 

of the equity

» Debt to equity 

ratio of 55%:45% 

or less

» DOE Loan 

Guarantee 

requires at least

20% equity

» DSCR of 1.5 to 1.75

» Interest rates at 

10-year U.S. 

Treasuries plus 

325-375 basis 

points with PPA

» Debt to equity 

ratio of 

55%:45% or less

» DOE Loan 

Guarantee 

requires at least 

20% equity

» DSCR of at least 

1.5

» Construction 

loan typically 

paid down with 

Treasury Cash 

Grant 

» Experienced and qualified management team 

» Risk mitigation strategies planned and implemented » PPA with creditworthy counterparty (exceptions for California)

» Resource 

assessment from a 

well-respected 

firm

» Drilling contract in 

place

» At least one 

production well 

drilled

» Engineers’ report affirming resource 

availability to support 20-year financing

» At least 50-80% of 

production wells 

drilled

» EPC contract in place

Financial Requirements Non-Financial Requirements

Risk Profile
32

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the Twenty-First Century. Produced by Massachusetts Institute of Technology for the U.S. 

Department of Energy. http://www1.eere.energy.gov/geothermal/pdfs/future_geo_energy.pdf.

(Accessed July 1, 2010).

The Wilderness Society. (2008). “Geothermal Development on Public Lands.”

http://wilderness.org/files/WebsiteGeothermal%20Development%20On%20Public%20Lands.pdf. (Accessed July 1, 2010).

ThinkGeoEnergy. (2009). “Merger Between Ram Power, Polaris Geothermal and Western 

GeoPower Complete.” http://thinkgeoenergy.com/archives/2758. (Accessed July 1, 2010).
37

U.S. Department of Energy. (1992). “The U.S. Geothermal Industry: Three Decades of Growth.” 

http://geothermal.id.doe.gov/publications/articles/mclarty/mclarty-reed.pdf. (Accessed July 1, 

2010).

U.S. Department of Energy (DOE). (2006(a)). “U.S. Geothermal Resource Map.” Office of 

Energy Efficiency and Renewable Energy, Geothermal Technologies Program. 

http://www1.eere.energy.gov/geothermal/geomap.html. (Accessed July 1, 2010).

U.S. Department of Energy (DOE). (2006(b)). “How an Enhanced Geothermal System Works.” 

Office of Energy Efficiency and Renewable Energy, Geothermal Technologies Program. 

http://www1.eere.energy.gov/geothermal/egs_animation.html. (Accessed July 1, 2010).

U.S. Department of Energy (DOE). (2006(c)). “A History of Geothermal Energy in the United 

States.” Office of Energy Efficiency and Renewable Energy, Geothermal Technologies Program. 

http://www1.eere.energy.gov/geothermal/history.html. (Accessed July 1, 2010).

U.S. Department of Energy (DOE). (2007). Wind Project Financing Structures: A Review and 

Comparative Analysis. Office of Energy Efficiency and Renewable Energy, Geothermal 

Technologies Program. http://eetd.lbl.gov/ea/emp/reports/63434.pdf. (Accessed July 1, 2010).

U.S. Department of Energy (DOE). (2008(a)). “Hydrothermal Power Systems.” Office of Energy 

Efficiency and Renewable Energy, Geothermal Technologies Program. 

http://www1.eere.energy.gov/geothermal/powerplants.html. (Accessed July 1, 2010).

U.S. Department of Energy (DOE). (2008(b)). Geothermal Technologies Program Multi-Year 

Research, Development and Demonstration Plan: 2009-2015 with program activities to 2025. 

Office of Energy Efficiency and Renewable Energy, Geothermal Technologies Program. 

http://www1.eere.energy.gov/geothermal/plans.html. (Accessed July 1, 2010).

U.S. Department of Energy (DOE). (2010(a)). Federal Interagency Geothermal Activities. Office 

of Energy Efficiency and Renewable Energy, Geothermal Technologies Program. 

http://www1.eere.energy.gov/geothermal/pdfs/ngap.pdf. (Accessed July 1, 2010).

U.S. Department of Energy (DOE). (2010(b)). Annual Energy Outlook 2010. Energy Information 

Administration. DOE/EIA-0383(2010). http://www.eia.doe.gov/oiaf/aeo/index.html. (Accessed 

September 13, 2010).

U.S. Department of State. (2010). U.S. Climate Action Report 2010. Washington: Global 

Publishing Services. http://www.state.gov/documents/organization/140636.pdf. (Accessed May 

1, 2010). 

U.S. Geothermal. (2008). “Now Trading on the American Stock Exchange.” 

http://www.usgeothermal.com/NewsReleases/Apr-16-2008.pdf. (Accessed June 29, 2010).

U.S. Geothermal. (2009). “U.S. Geothermal Announces C$10.9 Million Private Placement 

Financing.” http://www.usgeothermal.com/NewsReleases/2009-August-17.pdf. (Accessed July 

1, 2010).
38

U.S. Geothermal. (2010). “U.S. Geothermal Closes $8.6 Million Private Placement Financing.” 

http://www.usgeothermal.com/NewsReleases/March-09-2010.pdf. (Accessed July 1, 2010).

U.S. Renewables. (2010). “Power Generation.” http://www.usregroup.com/powergeneration.html. (December 14, 2010).

Western Climate Initiative Cap Setting and Allowance Allocation Committee. (2009). Draft 

Guidance for Developing Partner Allowance Budgets.

http://www.westernclimateinitiative.org/component/remository/Cap-Setting--and--AllowanceDistribution-Committee-Documents/Draft-Guidance-for-Developing-WCI-Partner-AllowanceBudgets/. (Accessed July 1, 2010).

Western Climate Initiative. (2008). Design Recommendations for the WCI Regional Cap-andTrade Program. http://www.westernclimateinitiative.org/the-wci-cap-and-trade-program/designrecommendations. (Accessed July 2, 2010).

Williams, C. F.; Reed, M.J.; Mariner, R.H.; DeAngelo, J.; Galanis, S.P. Jr. (2008). “Assessment 

of Moderate- and High-Temperature Geothermal Resources of the United States.” U.S. 

Geological Survey Fact Sheet 2008-3082. http://pubs.usgs.gov/fs/2008/3082/. (Accessed 

September 14, 2010).

Wiser, R.; Barbose, G. (2008). Renewable Portfolio Standards in the United States: A Status 

Report with Data through 2007. LBNL-154E. Berkeley, CA: Lawrence Berkeley National 

Laboratory. http://eetd.lbl.gov/ea/emp/reports/lbnl-154e-revised.pdf. (Accessed July 2, 2010).
39

Appendix A. Additional Detail on Relevant Policies

Several current policies and incentives supporting geothermal electricity development are 

iterations of earlier programs first introduced during the 1970s. RD&D funding and PURPA 

requirements for utility purchases of renewable energy are credited with driving a surge in 

geothermal project development from the late 1970s through the mid 1980s. PURPA has become 

a less significant driver, largely due to a decrease in utility avoided costs (Doris et al. 2009). 

However, RD&D funding continues to play a critical role in advancing the market for 

geothermal electricity today as newer types of geothermal technology, such as EGS, could 

dramatically increase the amount of geothermal resource potential in the United States. Key 

areas of current policy and incentive support for geothermal electricity development are 

summarized here.

Federal Tax Incentives, Grants, and Loan Guarantees

Developers depend on tax incentives to provide financial returns sufficient to attract project 

investment. The PTC has functioned as a key project development driver since it became 

available to geothermal projects in 2004. This performance-based incentive provides a tax credit 

of 2.2 cents (2010$)/kWh to geothermal electric projects for the first 10 years of project 

operations (DSIRE 2010(c)). A project must be put in service by December 31, 2013, to qualify. 

Given the 4- to 7-year development timeline for geothermal projects, the incentive may be 

limited in its ability to spur development of projects that are not already in the development 

pipeline unless it is extended. 

Since 2004, geothermal project investors have been able to choose between the PTC and an ITC 

worth 10% of qualified expenditures. The Recovery Act increased this ITC to 30% for 

geothermal projects placed in service through December 31, 2013. After that date, geothermal 

projects will continue to be eligible to receive a 10% ITC; there is no sunset date for the 10% 

ITC level. 

Following passage of the Recovery Act in February 2009, project investors can opt to take a 

Treasury Cash Grant in lieu of the PTC or ITC. The applicability of the Treasury Cash Grant for 

geothermal projects is complex and can be challenging to understand. During the appropriate 

eligibility timeframe, projects can take either the ITC or the PTC in the form of the Treasury 

Cash Grant. However, because of the way the ITC defines property eligible for the incentive,6

 6 For the ITC (26 USC § 48) equipment used to produce, distribute, or use energy derived from a 

geothermal deposit (also defined according to section 613(e)(2)) is eligible for the 10% incentive 

level, and this only applies to equipment “up to (but not including) the transmission stage.” For 

the PTC (26 USC § 45), “geothermal energy" is defined as energy derived from a geothermal 

deposit (within the meaning of section 613(e)(2). See Doris et al. 2009 for additional discussion 

of the issues surrounding eligibility for the PTC, ITC, and Treasury Cash Grant. 

different components of the geothermal project qualify for different incentive levels; the power 

plant equipment is eligible for the 30% incentive level while the equipment used to derive the 
40

energy from the deposit (e.g., wells) is only eligible for the 10% incentive level (Doris et al. 

2009). 7

Industry representatives report that the majority of geothermal projects that have come online 

since the Treasury Cash Grant has been available have opted to take this incentive (personal 

communications with industry experts, May 2010). The grant is attractive to project investors 

because: 1) the full value of the grant is paid out quickly (within 60 days of the receipt of a 

complete application and only after the project is operational)8

Unless otherwise extended, the 30% Treasury Cash Grant is available to projects that begin 

construction in 2009, 2010, or 2011, and that are placed in service prior to January 1, 2014; a 

10% Treasury Cash Grant is available to projects that begin construction in 2009, 2010, or 2011, 

and that are placed in service prior to January 1, 2017.

and 2) the value is not limited by 

a recipient’s tax liability. These features of the Treasury Cash Grant mean that developers can 

avoid the need to seek out tax equity investors with sufficient tax appetite, and can reap balance 

sheet benefits since the full value of the grant is realized so quickly. 

9

Inter-Agency Coordination and Streamlining of Federal Permitting and Land 

Lease Processes

Developers have had an easier time gaining access to federal lands recently than in past years. 

This is due both to improvements in the process for obtaining leases and a reduction in the 

environmental review process necessary for many development sites. Leases are now issued by 

BLM through a fully competitive bidding process, and a greater volume of land is available for 

lease. BLM has also processed its backlog of lease applications, and offers leases for sale on a 

more frequent schedule (Doris et al. 2009). 

Completion of a PEIS by BLM in 2008 also improved the lease process substantially. The PEIS 

involved an analysis of the environmental impacts of potential geothermal development on 

federally owned land in areas of the western United States with strong resource availability. Use 

of this analysis, as well as best practices defined in the PEIS, will help reduce lease and permit 

processing times.10

 7 26 U.S.C. § 613(3)(2) defines a geothermal deposit as “a geothermal reservoir consisting of 

natural heat which is stored in rocks or in an aqueous liquid or vapor (whether or not under 

pressure).” 8 Applications deemed incomplete are sent back to the applicants, restarting the 60-day clock.

9 Per U.S. Treasury Department guidance, “Construction begins when physical work of a 

significant nature begins. Work performed by the applicant and by other persons under a written 

binding contract is taken into account in determining when construction begins.” Treasury 

Department guidance also notes that an applicant may also make use of a safe harbor provision 

for purposes of determining when construction begins. 

10 Further information on the BLM’s PEIS process for geothermal can be found at: 

http://www.blm.gov/wo/st/en/prog/energy/geothermal/geothermal_nationwide.html. Accessed 

June 29, 2010. 
41

In 2008, the U.S. Geological Survey completed an assessment of geothermal resources that 

covered moderate- and high-temperature resources in 13 states. Providing access to these data 

will help lower project costs and risk for project developers by shortening the early resource 

identification phase of project development (U.S. DOE 2010(a)).11

Improved transmission infrastructure is essential to geothermal project development, since 

geothermal resources are typically located in remote areas far from load centers. Further, proof 

of transmission access can be necessary in order to line up project financing. Federal agencies 

are collaborating with numerous stakeholders in the WREZ Initiative. The WREZ Initiative 

seeks to facilitate efficient, environmentally sound development of transmission infrastructure to 

enhance development opportunities in renewable energy resource zones.12

Renewable Portfolio Standards 

Binding RPSs exist in 29 states, while seven states have non-binding targets for renewable 

energy (DSIRE 2010(d)). These constitute the most robust state-level policy drivers for 

geothermal electricity project development (DSIRE 2010(d)). The potential revenue impacts are 

discussed in the main body of the report in Section 3.1.3 and in section 4.3.2. Additional detail 

on the use of RECs in geothermal project finance is provided in Appendix B. Table A-5 includes 

more detail on the RPS policies in the states with conventional, electricity-generating geothermal 

projects already installed or in the pipeline.

 11 The assessment produced GIS data available to the public. Further information about the 

USGS geothermal resource assessment is available at http://pubs.usgs.gov/fs/2008/3082/

(accessed June 29, 2010), and GIS data files can be obtained at 

http://www.blm.gov/wo/st/en/prog/energy/geothermal/geothermal_nationwide/Documents/GIS_

Data.html. Accessed June 29, 2010. 

12 Additional detail about the WREZ process can be found on the Western Governors 

Association Web site: 

http://www.westgov.org/index.php?option=com_content&view=article&id=219&Itemid=81
42

Table A-5. Summary of State RPS Policies

State Installed 

Hydrothermal 

Capacity (MW)

Hydrothermal 

Capacity in 

Development 

(MW) (MinMax)

Current RPS 

Target

Year of First 

Requirement

California 2,565.5 1,609.7 – 1,997.7 20% by 2010; 33% 

by 2030

2003

Nevada 426.8 2,120.43 – 3,686.43 25% by 2025 2006

Utah 42 628 – 883 No RPS (Goal: 20% by 2025)

Hawaii 35 8 40% by 2030 2010

Idaho 15.8 413 – 676 No RPS

Alaska 0.73 80 No RPS

Oregon 0.28 342 – 473 Large Utilities 25% 

by 2025; Small 

Utilities 10% or 5% 

by 2025 depending 

on size

2011

Wyoming 0.25 0.28 No RPS

New Mexico 0.24 35 IOUs 20% by 2010; 

Co-ops 10% by 

2020

2002

Washington 0 Undefined 15% by 2020 2012

Arizona 0 2 – 20 15% by 2025 1999

Colorado 0 10 IOUs 

(Coops/munis): 

30% (10%)* by 2020

2007

Florida** 0 0.2 – 1 No RPS

Total 3,086.6 5,249-7,840

* Co-ops and municipal utilities with >40,000 customers are subject to RPS requirements

Sources: Roberts 2010; DSIRE 2010(a); Jennejohn 2010
43

Other State Incentives

A number of states offer other policies and incentives aimed at driving geothermal project 

development. Notable among these are California’s funding for research, development, and 

commercialization efforts, and Oregon’s significant investment tax credit and direct project 

funding.13

Though often funded by federal dollars, state universities can also play an important role in 

resource assessment and data-sharing activities. For example, research findings from the 

University of Nevada-Reno’s Great Basin Center for Geothermal Energy have played an 

important role in the industry (Fleishmann 2007). Access to these data can reduce resource 

identification costs for project developers. A number of states also offer sales tax and property 

tax abatement; the impacts of these policies are small relative to RPSs but can improve project 

economics.

California’s Geothermal Resources Development Account (GRDA) provides 

substantial industry development support and is funded with royalties the state receives from

federal leases (CEC 2010). Energy Trust of Oregon makes funding available to geothermal 

projects in Oregon that draw on dollars collected through customers’ utility bills (DSIRE 

2010(b)). 

State policies that limit greenhouse gas emissions also favor geothermal development. Strong 

geothermal states with such policies include California, Oregon, and Colorado (Pew Center 

2010(b)). A state’s electric industry regulatory framework can also influence project finance to 

the extent that it encourages or discourages utility ownership of generation assets. More detail on 

these policies is provided in Appendix C.

Federal Research, Development, and Demonstration Funding

DOE’s GTP manages RD&D funding efforts. GTP funds activities across the full range of 

geothermal technologies, including EGS demonstration. GTP is working to demonstrate EGS 

technology readiness by 2015, and recent expenditures reflect this commitment; industry experts 

report that many of these EGS-driven activities also benefit conventional geothermal 

technologies. GTP’s numerous and wide-ranging activities include, but are not limited to the 

following: site selection, reservoir characterization and creation, system demonstrations (U.S. 

DOE 2008). Exploratory drilling occurs as a component of some of these activities. In addition 

to supporting industry and research institutions, GTP works to facilitate effective inter-agency 

collaboration to support geothermal industry advancement. These R&D efforts provide indirect 

benefits to project developers by helping to reduce technology risk, which drives down the cost 

of capital.

 13 Direct project funding is available through the Energy Trust of Oregon.
44

Appendix B. Renewable Energy Certificate Value in Geothermal 

Project Finance

A REC, or “green tag,” represents the value of the environmental attributes associated with a unit 

of energy produced by a renewable energy facility. RECs are the unit of trade in two key 

markets: 1) RPS compliance markets and 2) the voluntary green power market. In both of these 

markets, RECs are used for accounting purposes to document that an entity has secured a 

specific amount of renewable energy resources. RECs can represent a significant revenue stream 

for geothermal projects. Potential investors will pay careful attention to whether or not a project 

has secured a long-term REC buyer when considering a commitment to the project.14

REC values vary substantially across markets, and are determined by the balance between supply 

and demand for RECs in a given market. One key driver of the demand for RECs is the rules 

established for any given RPS market. These rules also affect the amount of liquidity in the 

market (e.g., the number of buyers and sellers, and the amount of opportunity for trading to 

occur). RPS rules with a strong influence on REC value include the following: 

• Project eligibility (e.g., geographic area, date in-service, technologies allowed)15

• Borrowing (i.e., the extent to which RECs generated in a given year may be applied to 

compliance obligations in previous years)

• Banking (i.e., the extent to which RECs generated in a given year may be applied to 

compliance obligations in future years)

• Penalty/alternative compliance payment (ACP) levels for non-compliance (i.e., the fee 

that must be paid if a regulated entity fails to meet its compliance obligation)

• RPS carve-outs or special treatment of a particular technology (e.g., several RPSs include 

specific percentage requirements for solar or distributed generation sources)16

Table B-6 provides indicative ranges for three different types of REC markets. Because there is 

no shortage of RECs in voluntary markets (due largely to the lack of geographical constraints on 

eligibility), REC values in the voluntary markets are typically much lower than in RPS 

compliance markets. 

 14 RECs are often included in PPAs for commodity energy and may either have a separate, 

distinct value as a revenue stream, or will increase the overall price paid in the PPA (i.e., it will 

be higher than the price of an electricity-only PPA). However, in some cases they can be sold 

separately, or “unbundled” from commodity energy.

15 In California, for example, RECs used for compliance currently must be bundled with 

electricity that serves California customer load (CPUC 2010). 

16 No states include a carve-out for geothermal at the time of this writing. 
45

Table B-6. REC Pricing Across Markets 17

REC Market REC Pricing

Voluntary $1-10/MWh

RPS $3-60/MWh

RPS Shortage $48-56/MWh 

(or $25-65/MWh based on ACP levels – applicable in DE, MA)

Note: Pricing data for the RPS and RPS shortage markets is becoming more difficult to obtain. The ranges 

are intended to demonstrate the variability across states’ markets due to differences in policy provisions 

rather than serve as precise pricing data

Sources: Evolution Markets (2010), Wiser and Barbose 2008, DSIRE 2010(e), DSIRE 2010(f)

These policy provisions combine with market forces to determine the ultimate REC price. Figure 

B-1 summarizes the policy provisions and the market forces that significantly impact REC prices 

in any given market. The inner ring summarizes the components of an RPS that can affect the 

supply or demand for RECs in a given market. The outer ring captures the market forces, those 

outside of RPS mandates, that affect the finances (i.e., costs and revenues) of a project. 

 17 Values exclude solar RECs in markets with solar carve-outs in their RPSs. Values are based on 

a combination of historic REC price ranges reported in Wiser and Barbose 2008, along with 

market prices presented in Evolution Markets’ February 2010 Monthly REC market report. 

Evolution Markets’ reporting is based on data from transactions by that REC brokerage, one of 

the largest in the United States. Shortage prices are based on alternative compliance payment 

levels that exist in some RPS markets, as well as the highest REC prices reported by Evolution 

Markets. 
46

Figure B-1. Policy provisions and market forces that shape REC prices

Source: Navigant 2010

REC PRICES

Market Forces

Policy Provisions  Compliance Targets

 Bundling Requirements

 Delivery Requirements (e.g., 

in-state or in-service territory)

 Banking

 Borrowing

 Penalty / ACP

 Technology Carve-Outs

Development 

Costs

Supply-Demand 

Balance for RECs

Robustness of 

Resource

Capital 

Structure

Monetization of 

Tax Benefits

REC Prices

REC Prices

Cost of 

Capital

GHG 

Market

Energy 

Prices
47

RECs may help acceptable returns for renewable energy projects. The revenue that can be 

generated from RECs serves as an additional revenue source, in addition to energy sales revenue 

and monetized tax benefits. Together, these revenue streams must achieve a desireable rate of 

return on the costs incurred throughout the life of the project, from resource exploration through 

operation and maintenance. In some cases, long-term contracts for the sale of RECs are a piece 

of the financial equation; in order to consider the REC revenue as a reliable source of revenue, 

the contracts must be signed with a creditworthy counterparty.

The threshold level of return on investment (ROI) is established by the investors in a project.18

RECs are considered the premium that a project may or may not need to receive in order for it to 

meet the target ROI. At a fundamental level, investors evaluate the other revenues and expenses 

that make up a project’s economics to determine the premium necessary to achieve the ROI. 

RECs are the last piece of the financial package for renewable energy. 

Each investor will establish a ROI commensurate with the risk it assumes through its capital 

contribution and through the anticipated repayment. These rates of return are then weighted 

according to the share of overall capital contributed by each investor respectively. This overall 

ROI is then set as the minimum return that will be accepted in order for the project to move 

forward. 

Figure B-2 presents a theoretical example of how REC revenue streams can help determine the 

success of a theoretical renewable energy project. Revenue from energy sales and the monetized 

tax benefits would not be sufficient to achieve sufficient returns in this example. In this example, 

the REC revenue provides additional revenue, enabling the project owners to receive an adequate 

return on their investment. These values are provided for illustrative purposes only.

 18 The discussion of the role of RECs in a specific project’s financial returns is extracted from 

Summit Blue Consulting 2009. Additional details on the factors driving the supply and demand 

of RECs can be found in that report.
48

Figure B-2. Example of the role of REC revenue in project finance

Source: Navigant 2010

Note: These values are provided for illustrative purposes only. No actual project or market is represented in this 

figure.

Formal REC tracking systems have emerged across North America to support RPS compliance 

processes and to add credibility to REC markets. Ten regional tracking systems existed as of 

June 2009, as depicted in Figure B-3.

19

 19 The Environmental Tracking Network of North America (ETNNA) has produced publications 

on a variety of issues related to REC tracking systems, including information about trading 

across systems and logistics of the transactions. Their publications page can be found at 

http://www.etnna.org/publications.html. 

$0 

$20 

$40 

$60 

$80 

$100 

$120 

Revenue Required Project Revenue Streams

Revenue ($/MWh)

Revenue Required Energy Sales Revenue

Monetized Tax Benefits REC Revenue
49

Figure B-3. Map of North American REC tracking and trading systems

Source: ETNNA 2010
50

Appendix C. Greenhouse Gas Policy

This appendix provides a brief overview of key state, regional, and federal GHG policy activity, 

as well as a discussion of the implications of GHG regulations for geothermal and other 

renewable energy generators. 

Current Status of GHG Regulation

This section provides a brief overview of the status of GHG regulation in four areas: California, 

the Western Climate Initiative (WCI), other regions of the United States, and the federal level. 

California 

California has been a leader in climate change policy in the United States. The goals and 

principles underlying this leadership are set forth in an Executive Order signed in 2005 

(Executive Order S-3-05) and Assembly Bill 32 (AB32) signed into law in 2006. The state is 

pursuing an overarching goal of reducing the state’s emissions to 1990 levels by 2020, and to 

80% below 1990 levels by 2050. 

California’s Air Resources Board (CARB) is the lead implementer of AB32 and is tasked with 

establishing a plan for achieving the GHG reduction goals cost-effectively. In 2008, CARB 

approved a scoping plan for implementing AB32. The plan calls for introducing a cap-and-trade 

system starting in 2012 that would cover about 85% of all GHG sources in the state, including 

electricity generation. 

Preliminary draft regulations for the cap-and-trade program were released for comment in 

November 2009 (CARB 2009). Based on these draft regulations, electricity generators would be 

required to register and report compliance data to the state starting in the first compliance period 

in 2012. The draft regulations establish a declining cap on the amount of allowances that will be 

issued over time. The way in which the value of allocations will be distributed across entities 

covered under the regulations has yet to be determined, though some combination of auctions 

and free allocations will be used. CARB intends to reward entities for early action to the extent 

possible and is still considering options for allocating proceeds of allowance auctions. Those 

proceeds may be used to support additional renewable energy generation. Final regulations must 

be promulgated by 2011. 

WCI

The WCI was established in 2007 in an effort to facilitate a coordinated approach to GHG 

emissions reductions among Western states. The regional effort built on existing state-level 

efforts underway in California and other states. The seven states and four Canadian provinces 

currently participating in WCI are Arizona, British Columbia, California, Manitoba, Montana, 

New Mexico, Ontario, Oregon, Quebec, Utah, and Washington. WCI’s target is to reduce 

regional GHG emissions by 15% below 2005 levels by 2020; as of this writing, it is not a 

legally-binding target. A cap-and-trade program is the primary tool WCI plans to use to achieve 

this target. The proposed program design assigns a penalty for any regulated entity that fails to 

meet its compliance target; the non-compliant entities will be required to obtain and surrender 

three allowances for every ton of carbon dioxide equivalent that was not covered by an 

allowance at the compliance deadline (WCI 2008). 
51

WCI released a recommended cap-and-trade program design in 2008. The program design is 

generally consistent with the design that is taking shape in California. Electric generators and 

other major industrial sources of emissions are required to comply starting in 2012, the 

beginning of the first three-year compliance period. The types of entities required to comply 

expands during the second compliance period, which starts in 2015. The recommended program 

design is expected to cover nearly 90% of GHG emissions in partner states and provinces. 

The WCI cap-and-trade program is intended to complement rules in place in any of the partner 

jurisdictions. Each jurisdiction will be given an allowance budget, and the jurisdiction will 

determine how to allocate the value of those allowances. Such allocation specifications may 

include the share of allowances to be auctioned in each year and the distribution of free 

allowances (WCI 2009). 

Other Regional Initiatives 

Other major GHG initiatives in the United States and Canada exist in states and provinces with 

resources that are not ideal for conventional hydrothermal development. The Regional 

Greenhouse Gas Initiative (RGGI) and the Midwest Greenhouse Gas Reduction Accord 

(MGGRA) are the two most prominent efforts. 

RGGI is the first mandatory cap-and-trade program in the United States. RGGI partners include 

10 participating states in the Northeast and Mid-Atlantic (Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and 

Vermont). When the cap-and-trade program began in 2009, these states capped their GHG 

emissions and set a target to reduce emissions by 10% by 2018. The majority of allowances are 

auctioned, and RGGI had completed eight allowance auctions as of July 2010 (RGGI 2010). 

The MGGRA was signed in 2007. This collaborative effort to reduce GHG emissions in the 

Midwest and Canada includes seven member jurisdictions: Iowa, Illinois, Kansas, Manitoba, 

Michigan, Minnesota, and Wisconsin. A working group operating through the Midwest 

Governors’ Association is designing a cap-and-trade system for use by MGGRA members; as of 

this writing, it is not a legally binding system. An initial straw version of the program rules 

released in May 2009 called for a 20% reduction below 2005 levels by 2020 (MGGRA 2009). 

Federal Legislation 

The House passed ACES in June 2009, which included an economy-wide cap-and-trade 

program. A variety of bills that build on provisions of ACES are under consideration in the 

Senate (Pew Center 2010(a)). Six different Senate committees have jurisdiction over climate 

legislation, making timing and coordination issues complex. 

As of June 2010, two bills have been passed by Senate committees. The American Clean Energy 

Leadership Act of 2009 (S.1462), sponsored by Jeff Bingaman (D-NM), was passed in June 

2009 by the Senate Energy and Natural Resources Committee. The Clean Energy Jobs 

and American Power Act of 2009 (S.1733), sponsored by Barbara Boxer (D-CA) and John Kerry 

(D-MA), was passed by the Senate Environment and Public Works Committee in November 

2009. S.1462 addresses a host of clean energy issues, while S.1733 focuses more specifically on 

GHG reductions. Senators Kerry (D-MA), Graham (R-SC), and Lieberman (I-CT) have worked 

outside the committee process to draft a Framework for Climate Action and Energy 
52

Independence in the U.S. Senate in December 2009. The Framework outlines principles for 

developing comprehensive GHG policy. 

State and regional GHG cap-and-trade programs would either link with or transition to a national 

system if and when comprehensive federal GHG regulations are in place. 

What GHG Regulations May Mean for Renewable Energy 

The implications of GHG regulations for renewable energy and geothermal resources 

specifically depend on the details of the regulations. Key design principles include the level of 

the cap (e.g., how dramatic a reduction in emissions is sought) and the approach to allocating 

allowances (e.g., the balance between auctions and free allocations). In principle, the types of 

effects of a cap-and-trade program on renewable energy should remain the same regardless of the 

details. The magnitude of the effects, however, will vary depending on design details. 

In general, GHG regulations are anticipated to increase conventional energy prices. Many power 

plants will need to secure allowances to comply with cap-and-trade regulations. It is possible that 

the generators will pass along these cost increases to consumers. Consumers may be buffered 

from the cost impacts felt by the generators by various allowance allocation design strategies.20

Many cap-and-trade programs also include provisions that allocate allowances and/or proceeds 

from allowance auctions to fund programs that support renewable energy and energy efficiency. 

Some federal climate legislation is also coupled with other clean energy policies that would 

support geothermal development. For example, the ACES bill passed in the House would include 

a national RPS. 

The market for RECs (used for compliance with RPSs) and the market for GHG compliance 

units (both allowances and offsets used for compliance with GHG regulations) are separate and 

distinct. A geothermal generator operating in a state with both an RPS and a GHG cap-and-trade 

program would sell RECs to load-serving entities responsible for complying with the RPS, and 

the generator itself would be responsible for surrendering enough allowances to cover GHG 

emissions generated by the facility (if any). Any additional allowances owned by the generator 

could be sold. 

There is some potential overlap between REC and GHG markets for generators that wish to sell 

RECs into voluntary GHG offset markets.21

 20 For example, the House’s ACES bill stipulates that over 20% of allowances would initially be 

allocated to local electric and gas distribution companies, and that the value of these allowances 

would need to be passed along to consumers (Pew Center on Climate 2010). 

In general, RECs are considered to include all 

environmental attributes, including GHG attributes associated with a unit of energy. However, 

some RECs would fail the “additionality” test needed to secure certification as a high-quality 

offset. That is, the generator would be unable to demonstrate that the RECs sold are in addition 

to what would have been produced in the absence of a REC market. 

21 Additional details on the potential for overlap between GHG and REC markets can be found in 

Bird et al. 2007.
53

Appendix D. Additional Resources

Many resources are available to supplement the information in this report. A listing of some of 

the most relevant resources follows in alphabetical order.

Database of State Incentives for Renewables and Efficiency (DSIRE): http://www.dsireusa.org/. 

Geothermal Energy Association: http://www.geo-energy.org/.

Investopedia ULC: http://www.investopedia.com/. 

Lawrence Berkeley National Laboratory, Electricity Market and Policy Program: 

http://eetd.lbl.gov/ea/emp/re-pubs.html. 

Midwest Regional Greenhouse Gas Reduction Accord Advisory Group. (2009). Executive 

Committee Straw Proposal.

http://www.midwesternaccord.org/Meeting%20material%20pages/GHG-meeting-10_509.html. 

National Renewable Energy Laboratory. Geothermal Policymakers’ Guidebooks: 

http://www.nrel.gov/geothermal/guidebooks/. 

National Renewable Energy Laboratory, Strategic Energy Analysis Center: 

http://www.nrel.gov/analysis/.

Pew Center on Global Climate Change: http://www.pewclimate.org/. 

ThinkGeoEnergy Blog: http://thinkgeoenergy.com/. 

U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Geothermal 

Technologies Program: http://www1.eere.energy.gov/geothermal/. 

U.S. Treasury Department, Office of the Fiscal Assistant Secretary. (2010) Payments for 

Specified Energy Property in Lieu of Tax Credits under the American Recovery and 

Reinvestment Act of 2009: http://www.treas.gov/recovery/docs/guidance.pdf .

Western Climate Initiative (WCI): http://www.westernclimateinitiative.org/documents. 

Western Governors' Association: http://www.westgov.org/. 

Western Renewable Energy Generation Information System (WREGIS): http://www.wregis.org/. 

Western Renewable Energy Zones (WREZ) Transmission: 

http://www.westgov.org/index.php?option=com_content&view=article&catid=102:initiatives&i

d=220:wrez-transmission-model-page&Itemid=81. 

In addition, a set of guidebooks to help project developers navigate the permitting process is 

under development through funding from the U.S. DOE. Check NREL’s Geothermal Web site 

for the posting when it becomes available: http://www.nrel.gov/geothermal/.
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Guidebook to Geothermal Power Finance -- Draft

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This guidebook is intended to facilitate further investment in conventional geothermal projects in the United States. It 

includes a brief primer on geothermal technology and the most relevant policies related to geothermal project 

development. The trends in geothermal project finance are the focus of this tool, relying heavily on interviews with 

leaders in the field of geothermal project finance. Using the information provided, developers and investors may 

innovate in new ways, developing partnerships that match investors’ risk tolerance with the capital requirements of 

geothermal projects in this dynamic and evolving marketplace.

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geothermal; geothermal electricity generation; investing; developers; policy

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