Geothermal Technologies Program

Geothermal Tomorrow

08

GTP Vision and Mission

EGS: A New Strategy

National Laboratory Activities

Price of Geothermal Power

Financing Projects

International Efforts

Utility Geothermal Working Group

State Geothermal Policies

Injection Well

Reservoir

Production Wells
On the cover: Calpine’s 35 megawatt Sonoma Geothermal 

Power Plant at The Geysers field in Northern California.

Courtesy of Calpine Corporation
1

Contents

Geothermal’s Potential for Domestic Energy

 DOE Geothermal Technologies Program Vision and Mission 2

 Enhanced Geothermal Systems: A New Strategy for a Renewed Program 4

 Activities in Geothermal Research and Development 

 at the DOE National Laboratories 6

 The Price of Geothermal Power 15

 Financing Geothermal Projects 18

 International Geothermal Efforts—2008 21

 Utility Geothermal Working Group Update 24

 State Policies Provide Critical Support for Renewable Electricity 27

About “Geothermal Tomorrow”

Geothermal power is a renewable, low-carbon 

option for producing base load electricity across 

the United States. Improved technologies have 

the potential to access vast untapped geothermal 

energy sources, which experts estimate to 

contain 50,000 times the energy of all oil and gas 

resources in the world. Increased development of 

geothermal energy can help address the critical 

issues of global warming, pollution, and energy 

independence, as well as give people better 

control of their local energy resources and a 

secure, safe, domestic source of energy.

The U.S. geothermal industry leads the world in 

online capacity of geothermal energy. The potential 

for growth is substantial, with the international 

market for geothermal power possibly exceeding 

$25 billion over the next 10 to 15 years. Currently, 

U.S. technology and industry are at the leading 

edge of this international growth.

Many technical challenges, however, must still 

be addressed and resolved if the United States 

is to unlock the full potential of geothermal 

energy. Achieving next-generation geothermal 

power requires advances in basic science and 

applied technology, with a strong focus on 

developing enhanced geothermal systems that 

can expand the available resource base and 

strengthen the economic viability of production. 

The U.S. Department of Energy’s Geothermal 

Technologies Program is committed to supporting 

the geothermal industry with research and 

development to help geothermal energy fulfill 

its potential. This publication brings together 

contributors from the Program and the geothermal 

community to highlight the current status and 

activities around the growth of this global resource.
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Geothermal Tomorrow 2008

 I

am delighted to have recently taken over the Geothermal Technologies Program (the Program) in the U.S. 

Department of Energy’s Office of Energy Efficiency and 

Renewable Energy. I join the Program at a very exciting 

time; it has been awarded a $30 million dollar budget from 

the Senate and $50 million from the House for the 2009 

fiscal year after a two year struggle with limited funds. The 

budget increase demonstrates a tremendous surge of public 

support for geothermal energy and speaks volumes about 

the fantastic work the Program has accomplished. With 

this year’s increased funding I am certain that the Program 

will continue to grow exponentially. 

Our team has produced some great resources for the geothermal industry. We are currently developing a Multi-Year 

Plan to outline specific goals to accelerate commercialization. We are also producing a National Geothermal Database 

that will catalog temperature, depth, seismicity, hydropressure, and permeability throughout the United States. This 

will be a great resource that will mitigate risk and facilitate 

investment. This is going to be an asset for the geothermal community—so feel free to let us know what you feel 

should be included in the National Geothermal Database.

The Program has refocused on Enhanced Geothermal 

Systems (EGS)—a technology we see as the future of not 

just the geothermal industry, but of the renewable energy 

industry as a whole. Natural geothermal systems depend on 

three factors to produce energy: heat, water, and permeabilDear readers and colleagues: ity. Although heat is present virtually everywhere at depth, 

water and permeability are less abundant. Previously, geothermal energy sources were limited to sites where all three 

of these factors were favorable. EGS, however, consist 

of engineered reservoirs created to produce energy from 

geothermal resources deficient in economical amounts of 

water and/or permeability. With EGS, we can transform 

geothermal from an energy source useful only in a select 

few areas to a viable source of base load energy for much 

of the United States.

An EGS is created by first digging a well into hot basement 

rock, then injecting water into the well at a high pressure 

so as to promote fracturing deep within the rock, creating a 

reservoir. A second well is drilled to intersect the resulting 

reservoir, allowing water to be circulated so this heat can 

be extracted. Multiple wells may be drilled into the field 

to increase yield. The resulting energy is clean, renewable, 

domestic, reliable, and may be used as a source of base load 

power. DOE sponsored a study completed by experts from 

the Massachusetts Institute of Technology which found that 

100,000 megawatt electrical (MWe) of geothermal energy 

could be produced in the United States by 2050 with significant investment in EGS technologies.

Despite great potential, geothermal energy faces several 

barriers to growth. These issues include limited geothermal siting opportunities, inadequate technology, and high 

startup costs. It is my goal to lead the Program in mitigating 

these barriers and in developing technology that will allow 

geothermal resources to be explored in regions previously, 

and erroneously, deemed unsuitable. It is my hope that geothermal energy will no longer be tethered to a small number 

of naturally occurring sites, but that we will lead in finding 

the potential wherever it may exist. Additionally, we are 

working hard to develop strategic partners in government 

DOE Geothermal Technologies Program Vision and Mission: 

A Letter from the Program Manager
3

Geothermal Tomorrow 2008

and industry to help accelerate commercialization opportunities in EGS technologies that will lower costs and expand 

potential. Partnered with industry and academia, the Program will continue to promote this great, clean, renewable, 

domestic resource: geothermal energy. 

Currently, the United States has 2,930 MWe of installed 

geothermal capacity and about 2,900 MWe of new geothermal power plants under development in 74 projects. Geothermal energy generated 14,885 gigawatt-hours (GWh) of 

electricity in 2007, which accounted for 4% of renewable 

energy-based electricity consumption in the United States 

(including large hydropower). These statistics are a great 

start, but we need to think bigger. We need to move beyond 

incrementalism and start considering growth of hundreds of 

megawatt units rather than 5-10 MWe.

Policy is an important tool for getting more geothermal 

energy into the market. We need technology-neutral, 

carbon-weighted, long-term incentives that account for 

externalities and level the playing field for renewables in 

today’s competing power markets. The Program is working 

with Western Governors to support new energy corridors 

that will bring clean, renewable energy resources into our 

energy portfolio. EERE is currently evaluating options to 

support the development of transmission infrastructure that 

will further remove geothermal investment barriers.

As high energy costs and environmental concerns force us 

to reevaluate our energy use, the nation looks for solutions 

and alternatives. There is no silver bullet that will solve our 

problems, but an integrated portfolio of energy alternatives 

will help the nation to successfully navigate the coming 

years. Geothermal energy, through the work and support of 

the Program, has the promise to play a critical role in the 

solution. We have entered a new era in government support for geothermal energy. Our new goals are bigger and 

braver than ever—but we’re more confident than we have 

been in the past. The geothermal industry has reached a 

turning point—we’re going to help restore geothermal to its 

rightful place in the portfolio of alternative energy sources 

to help enhance our security, better our environment, and 

stimulate our economy.

Sincerely,

Ed Wall

Program Manager

Geothermal Technologies Program

U.S. Department of Energy

Energy Efficiency and Renewable Energy

Desert Peak Geothermal Plant, 

65 miles northeast of Reno, Nevada.

Sierra Pacific
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Geothermal Tomorrow 2008

Enhanced Geothermal Systems: 

A New Strategy for a Renewed Program

A U.S. Department of Energy-sponsored 

study by a panel of independent experts led 

by the Massachusetts Institute of Technology 

(MIT), The Future of Geothermal Energy

examined the potential of geothermal 

energy to meet the future energy needs of 

the United States. The MIT study calculated 

the tremendous amounts of heat present 

at depths of 3 to 10 km below the Earth’s 

surface (Figure 1). The panel concluded that 

geothermal energy could provide 100,000 

MW or more in 50 years by using Enhanced 

Geothermal Systems (EGS). 

An alternative to dependence on naturally occurring hydrothermal reservoirs involves engineering hydrothermal reservoirs in hot rocks for commercial use. This alternative is 

known as EGS. 

The Promise of EGS

To achieve the goals outlined in the MIT study of large 

scale (100,000 MW) use of cost-competitive geothermal 

energy, significant advances are needed in site characterization, reservoir creation, well field development and 

completion, and system operation, as well as improvements 

in drilling and power conversion technologies. These technology improvements will also support ongoing development and expansion of the hydrothermal industry. To realize the promise of EGS as an economic national resource, 

researchers will have to create and sustain a reservoir over 

the economic life of the project. 

EGS reservoirs are made by drilling wells into hot rock 

and fracturing the rock sufficiently to enable a fluid 

(water) to flow between the wells. The fluid flows along 

permeable pathways, picking up heat from the rocks, and 

exiting the reservoir via production wells. At the surface, 

the fluid passes through power plant turbines where electricity is generated. Upon leaving the power plant, the 

fluid is returned to the reservoir through injection wells 

to complete the circulation loop (Figure 2). If the plant 

 H

eat is naturally present everywhere within the Earth 

and is inexhaustible for all intents and purposes. 

Water is not nearly as abundant within the Earth as 

heat, and most subterranean fluids are derived from surface 

waters that have seeped into the Earth along porous pathways such as faults in rock. The permeability of rock—a 

measure of the ease of fluid flow—results from pores, 

fractures, joints, faults, and other openings that allow fluids 

to move. High permeability implies that fluids can flow rapidly through the rock. Permeability and, subsequently the 

amount of fluids, tend to decrease with depth as openings in 

rocks compress from the weight of the earth above.

At shallow depths, typically less than 5 kilometers (km), 

the presence of heat, water, and porous rock can result in 

natural hot water reservoirs. These hydrothermal reservoirs 

have impermeable or low-flow boundaries that impede the 

movement of fluids. Often, hydrothermal reservoirs have 

an overlying layer that bounds the reservoir and serves as a 

thermal insulator, allowing greater heat retention. If hydrothermal reservoirs contain sufficient fluids (water or steam) 

at high temperatures and pressures, those fluids can be 

extracted through wells to generate electricity and/or heat.

Figure 1. Potential of EGS development in the United States.

EGS Development Potential Shown

Thermal Energy (106 EJ)

2% Conservative

Total U.S. Energy

Consumption in 2005

= 100 EJ

2.8 x 105

 EJ

2.8 x 106

 EJ

5.6 x 106

 EJ

United States EGS Resource 14 x 106

 EJ

20% Midrange 40% Upper Limit

16

14

12

10

8

6

4

2

0
5

Geothermal Tomorrow 2008

uses a closed-loop cycle to generate electricity, none of 

the fluids vent to the atmosphere. The plant will have no 

greenhouse gas emissions other than water vapor that may 

be used for cooling. 

EERE Strategy

In order to achieve the maximum potential of EGS, the 

U.S. Department of Energy’s Office of Energy Efficiency 

and Renewable Energy plans to advance and build from 

current geothermal technology to develop the sophisticated 

technologies required, while at the same time generating 

benefits in the near-, mid-, and long-term. This will require 

a systematic, sustained research and development effort by 

the federal government and a strong partnership with industry and academia to ensure full development.

A broad knowledge base about reservoir creation and 

operation will be essential for the eventual commercialization of EGS on a scale envisioned by the MIT study. 

This knowledge can be gained only by experience with 

field demonstrations in a variety of geologic environments 

reflecting a range of reservoir conditions. Immediate technology improvements are needed in reservoir predictive 

models, zonal isolation tools, monitoring and logging tools, 

and submersible pumps. These improvements and others 

stemming from the evaluation are essential for reaching the 

long-term potential of EGS.

The MIT study provides a firm basis for bringing the 

vision of commercialization of EGS technology to fruition. 

The process goal is to create an EGS reservoir that can 

operate economically.

EGS Future 

The authors of the MIT study based their technical assumptions on results from available field tests, published reports, 

and well-established theory. The study’s findings are credible, in particular the conclusion that 100,000 MW from 

EGS technology can be achieved within 50 years. As the 

study points out, significant constraints exist in creating 

sufficient connectivity between wells to meet economic 

requirements for reservoir productivity and lifetime. Overcoming these constraints will require substantial reservoir 

testing in a number of different geothermal environments 

as well as research-driven improvements in technology. Investments in excess of over $1 billion over 15 

years will most likely be required to encourage sufficient 

deployment of EGS technology to produce 100,000 MW. 

Figure 2. EGS Development Sequence

Step 1: Locate Site

Charcterize and

Select Site

Drill and Log

Exploratory Well

The ultimate process goal for 

EGS is to bring the vision of 

commercialization to fruition 

while creating an EGS reservoir 

that can operate economically.

Step 4-5: Operate System

Complete and Verify

Circulation Loop

Install

Operating System

Steps 2-3: Create Reservoir

Drill

Injection Well

Stimulate/Create

Reservoir

Drill 

Production Well
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Geothermal Tomorrow 2008

Geothermal Technologies Program Activities at the 

National Renewable Energy Laboratory

 T

he National Renewable Energy Laboratory (NREL) 

supports DOE in renewing and expanding its efforts 

to move geothermal energy forward. NREL staff 

has participated in and continues to lead and participate in 

activities related to Enhanced Geothermal Systems (EGS) 

technology validation and integrating outcomes into 

program plans. 

Evaluation Workshops

NREL was an active participant and leader in a series of 

workshops in 2007 that evaluated the assumptions, analytical methods, and conclusions presented in the 2006 report 

by the Massachusetts Institute of Technology, The Future of 

Geothermal Energy. This report provides a strong argument 

that with appropriate and reasonable investment from the 

public and private sectors, geothermal energy could make a 

substantial contribution to the nation’s energy portfolio. 

The workshops included discussion on reservoir creation, 

reservoir management and operations, and well field construction, and led to the publication of the DOE report, An 

Evaluation of Enhanced Geothermal Systems Technology.

These efforts set the stage for the renewal of the geothermal 

program with an emphasis on EGS development. 

With this renewal, NREL has initiated 13 projects to help 

GTP reach its objectives. These projects support systems 

demonstration projects and meet program needs in systems 

integration, energy analysis, strategic planning, field program support, and communications and outreach. 

Activities in Geothermal Research and 

Development at the DOE National Laboratories

The U.S. Department of Energy (DOE), through its 

Geothermal Technologies Program (GTP), works closely 

with the geothermal community to advance geothermal 

technologies and the U.S. geothermal industry. This includes 

partnering with industry, universities and colleges, research 

facilities, and, especially, the DOE national laboratories. 

Three national laboratories are particularly active in support 

of GTP’s endeavors and have the expertise and technology 

in place to provide leadership where needed in research 

and development projects to help realize the full potential 

of geothermal energy. In this article, National Renewable 

Energy Laboratory, Lawrence Livermore National Laboratory, 

and Idaho National Laboratory review their activities and 

future plans in support of GTP.

Installation of a PPS-coated steam vent at Cove Fort in Utah.
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Geothermal Tomorrow 2008

Systems Demonstration Support

For GTP’s field demonstrations of EGS, NREL is contributing expertise in developing site selection criteria and 

solicitation strategies, as well as participating in the industry proposal merit reviews. NREL provides oversight and 

technical monitoring of field projects and management of 

field-related subcontracts. 

Strategic Planning and Analysis

NREL supports GTP in developing strategic plans, including the Geothermal Technologies Program Multi-Year 

RD&D Plan for Enhanced Geothermal Systems, which 

will guide program activities for 2010-2020. This plan 

addresses the near-term priorities for cost-shared research 

with industry, as well as field projects for achieving EGS 

technology readiness for commercialization. NREL has 

participated in several internal program meetings to develop the plan and has the lead in developing the key technical 

section. This plan will guide GTP in fulfilling aggressive 

goals for making geothermal a significant contributor to the 

energy portfolio of the United States. NREL is also assisting the program in developing a GTP Management and 

Operations Plan to achieve EGS technology readiness for 

commercialization. 

National Geothermal Action Plan

NREL has responsibility for assisting GTP with the development of a comprehensive National Geothermal Action 

Plan (NGAP) for conventional hydrothermal production 

and EGS. NREL has developed and placed a subcontract 

with Deloitte to complete this action plan. NGAP will 

serve to inform the Inter-Governmental Panel on Climate 

Change and the public of the qualities, capabilities, progress, and goals of geothermal energy and GTP. NGAP will 

analyze the current state of geothermal energy as a viable 

energy source and its current and potential contribution 

to the national grid, and discuss the short-, mid-, and 

long-term potential development scenarios of geothermal 

energy including an evaluation of transmission infrastructure requirements. 

The plan will also describe geothermal energy in relation to 

DOE’s strategic goals— energy security, scientific discovery and innovation, and environmental responsibility—and 

examine the environmental benefits and impacts of geothermal energy as it relates to climate change, water, land use, 

and air quality. In addition, the plan will develop visionary 

goals and strategies that mitigate the risk for geothermal 

energy in aiding national energy diversity and reliability.

Program Systems Integration Support

NREL has initiated its systems integration role in GTP’s 

activities to help it reach the goal of developing EGS. 

NREL is developing an integrated baseline that will 

address technical scope, and will define, initiate, and manage systems-related subcontracts and integrate with inhouse efforts. 

Analysis, Evaluation, and Modeling

Of the 13 projects NREL is initiating in support of GTP, 

seven are focused on analysis, evaluation, and modeling 

activities that address critical program needs for assessment 

of geothermal and EGS markets:

•	 Macro modeling of the potential geothermal energy 

contribution

•	 Techno-economic modeling of EGS

•	 Analyses of program risk

•	 Integrated energy modeling for budget support

•	 Analysis of geothermal CO2 impact

•	 Assessment of power conversion technologies

•	 Assessment of data requirements for accelerating EGS 

commercialization. 

NREL analysis is working to improve the representation 

of geothermal to address renewable energy technologies 

in evolving new energy market models. There are many 

energy market models that have been used to assess the 

potential of geothermal power and other technologies in the 

United States, but two shortcomings remain that are especially acute for geothermal power: 1) Regional aggregation 

doesn’t allow for the consideration of more local transmission constraints; and 2) uncertainties in future fuel prices, 

technology improvements, and policies will continue to 

drive the energy sector. 

A model now exists at NREL for capacity expansion in 

the U.S. electric sector—the Regional Energy Deployment 

System—with more than 350 regions in the United States 

that explicitly consider transmission issues. A second 

model—the Stochastic Energy Deployment System—is 
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Geothermal Tomorrow 2008

under development and led by NREL with a team from six 

national labs that explicitly addresses future uncertainties in 

technology performance, cost, fuel prices, and policies. 

Presently, a rudimentary representation using supply 

curves for hydrothermal power is included in each of these 

models. This task will improve that representation and 

conduct analysis of geothermal power market potential 

within the models.

Geothermal Market, Policy, and 

Technology Analysis

NREL developed the initial concept for gaining a firm 

understanding of the technical, economic, and market 

potential of all geothermal technologies (hydrothermal, 

EGS, heat pumps). Such an understanding is required to 

inform decision-makers in the identification of the most 

efficient use of resources. Both historical and projected 

metrics will be gathered to determine technology improvements and commercialization opportunities. The project 

will conduct analyses of market, policy, and technology 

status by evaluating of the impacts of research and testing 

options. Additionally, results of the analyses will provide 

information to researchers, policy-makers, and investors 

on areas to target for greater cost-reduction and market 

transformation.

Geothermal CO2

Impact Analysis

This NREL project is assessing the 

CO2 impact of deploying geothermal energy, specifically for EGS. 

The project objective is to assess 

the projected CO2 impact of geothermal generation in general, and 

the component estimated to be the 

result of planned program activities, based on published studies and 

modeling of the geothermal representation used for the fiscal year 

2010 benefits estimation process.

CO2 emission reduction is a key 

element of DOE’s strategic environmental goal and an increasingly 

important metric for assessing the 

value of program activities in the 

budget formulation process.

Power Conversion Technology Evaluation

NREL is also supporting GTP’s EGS field experiment program by evaluating the current state of power conversion 

technology and assessing R&D requirements in this area. 

NREL is performing a detailed assessment of the needs for 

EGS power conversion and evaluating the ability of current 

technologies to meet those needs with the primary purpose 

of identifying gaps in technology that must be addressed 

for long-term EGS viability. 

Growth to Assist and Represent GTP

To meet the needs of the renewed geothermal program, 

NREL has transitioned to a new geothermal technology 

manager with a strong geoscience and energy background 

who is adding positions to the laboratory’s capabilities in 

support of GTP. NREL has added two energy analysts and 

a systems integration engineer. Staff have provided support 

to GTP by making or participating in presentations to key 

stakeholders in the geothermal community including Al 

Gore and the Alliance for Climate Protection, the Google 

Foundation, the X-Prize Foundation, and the leaders of the 

Hawaii Energy Initiative.

Keith Gawlick, of the National Renewable Energy Laboratory, field testing coatings at the Mammoth Pacific 

Geothermal Power Plant in the Sierra Nevada Mountains.
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Geothermal Tomorrow 2008

Geothermal Technologies Program Activities at 

Lawrence Livermore National 

Laboratory

 L

awrence Livermore National Laboratory (LLNL) has 

a long history of R&D work in support of geothermal power. Key areas of research include advances 

in scaling and brine chemistry, economic and resource 

assessment, direct use, exploration, geophysics, and geochemistry. For example, a high-temperature, multi-spacing, 

multi-frequency downhole electromagnetic (EM) induction 

logging tool (GeoBILT) was developed jointly by LLNL 

and EMI to enable the detection and orientation of fractures 

and conductive zones within a reservoir. LLNL researchers also conducted studies on the use of geothermal energy 

for desalination to stave off increased salinity in the Salton 

Sea, an important aquatic ecosystem in California.

Since 1995, funding for LLNL’s geothermal research has 

decreased, but the program continues to make important 

contributions to sustain the nation’s energy future. Current efforts, as well as future research, focus on developing 

Enhanced Geothermal Systems (EGS) and improving technologies for exploration, monitoring, characterization, and 

geochemistry. 

Techniques to Assess Geothermal Resources

Most known geothermal resources in the Basin and Range 

geological province of the western United States are associated with active fault systems. Studies show that hydrothermal fluids in active fault systems circulate from deep underground through high permeability fractures to relatively shallow levels where they can be accessed for production. For 

example, at the Dixie Valley field, hydraulically conductive 

fractures within the Stillwater fault zone are oriented so that 

fractures are critically stressed for normal shear failure under 

the regional tectonic stress field.1 In general, the expectation 

is that geothermal resources occur in areas where seismic 

strain across faults is extremely high and where faults are 

favorably oriented with respect to the regional strain tensor. 

In the Basin and Range, these faults would strike perpendicular to the direction of maximum extension. Geothermal 

resources may also occur in areas where fault-normal extension associated with shear strain is the greatest.2

GeoBILT EM Induction logging tool being deployed at Dixie Valley.
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Geothermal Tomorrow 2008

Until recently, mapping ground displacements of less than 

1 centimeter (cm) was extremely difficult. LLNL is applying a new technique called repeat-pass Interferometric 

Synthetic Aperture Radar (InSAR), and refining it for geothermal applications. InSAR uses radar imaging of Earth’s 

surface to identify potential geothermal resources. Satelliteborne synthetic aperture radar images the Earth’s surface 

during two orbits, recording data at the surface position 

and using the same viewing geometry during both orbits. 

The maximum separation (spatial baseline) between the 

two orbital positions is generally 1 kilometer (km) or less, 

depending on the radar frequency. The difference between 

the phases of the two radar returns is proportional to any 

change in the range from the ground to the radar caused 

by a subsurface displacement that occurs between orbits. 

The topographic contribution is subtracted using a digital 

elevation model or additional orbits. The displacement 

contributions are then mapped over the entire radar scene 

to produce a phase difference map, or interferogram, that 

can be converted to a range-change map (Figure 1). Under 

favorable conditions, InSAR can measure displacements 

as small as a few millimeters. Displacement maps of geothermal regions using InSAR detect changes in elevation 

that can be used to manage geothermal systems and locate 

regions of high strain that are favorable for drilling. 

The Stochastic Engine

Geophysical data are difficult to acquire and, once 

obtained, are often hard to interpret. Computer models can 

be made more meaningful when they take the uncertainty 

in those measurements into account and combine multiple 

measurements into one analysis. Stochastic models often 

require large numbers of calculations to evaluate many different descriptions of a problem. These evaluations allow 

us to understand how a small amount of data can result in 

a range of interpretations. Using high-performance supercomputers such as Thunder and Atlas, LLNL scientists 

explore groundbreaking ideas in statistical theory to develop quantitative stochastic descriptions that provide a more 

complete picture of the subsurface.

This technology, called a stochastic engine, links predictive models, advanced statistical methods, and refined 

search methods. Using this technology, scientists can 

incorporate a proposed subsurface configuration into a 

computer model and produce a geophysical simulation. 

The simulated result is compared to actual data. If the 

result is consistent with observed data, it becomes part 

of the final analysis, leading to a clear understanding of 

which outcomes are very likely, less likely, and where 

more information could best be used.

The stochastic engine concept uses techniques developed 

at LLNL and has been applied to a number of research 

areas, including environmental remediation, CO2 sequestration, and geothermal exploration. The power of the stochastic engine stems from its ability to refine a model by 

successively narrowing possible configurations of a hypothetical model with the refinement done over progressive 

layers of data.

For example, suppose an area of interest is known to 

be composed of seven distinct rock layers that could be 

either highly fractured or intact. Geophysical measurement such as EM induction, seismic velocities (Vp/Vs), 

or gravity of that volume, gives an observed value of 

11. The stochastic approach calculates which configurations of rock layers, and in which positions, give values 

close to 11. Each case with a value near 11 is passed to 

the next stage of analysis. There, the model will continue 

to restrict possible configurations but base its decisions 

on other data types such as water, temperature, or pressure. For the simple case cited here, scientists can easily 

compile and compare all possible configurations. For a 

large area, however, the possibilities are far too numerous 

Figure 1. InSAR is used to investigate the role strain concentration plays 

in localizing geothermal resources in the western Basin and Range.
11

Geothermal Tomorrow 2008

and we rely on computational techniques. The stochastic 

engine helps narrow the solutions by performing an efficient intelligent search through the collection of possible 

reservoir configurations, rapidly identifying the configurations that most closely match all the data. The stochastic 

engine is designed to choose system configurations that 

are consistent with observed data, allowing much more 

tightly constrained answers than conventional methods. 

The goal is to find not a single answer, but many answers. 

The objective is to adapt the stochastic engine to jointly 

invert multiple geothermal exploration data sets for better 

defined drilling targets to improve the success rate in finding economic geothermal resources.

EGS—Evolution in Controlling 

Fracture Permeability 

EGS is a technology that can be used to improve the energy 

recovery from a reservoir that has insufficient permeability 

or fluid. The use of EGS has the potential to increase geothermal electrical generation to more than 100,000 MWe in 

the United States by 2050.3 One technical challenge limiting 

our ability to utilize enhanced geothermal energy recovery 

is the changing nature of fracture permeability. Mechanisms 

such as mineral precipitation and dissolution, flow rate, 

and stress can affect the underground environment, causing 

subsurface flow to slow over time or stop completely. EGS 

research performed at LLNL is aimed at understanding the 

mechanisms and rate of change to predict the evolution of 

fracture permeability and to evaluate strategies to enhance 

and maintain permeability in a given location. 

To develop EGS, geophysicists and geochemists in 

LLNL’s Geothermal Program combined laboratory 

experiments and computer modeling to characterize the 

hydraulic and geochemical properties of various soil 

samples (Figure 2). As part of this project, they assessed 

how effective stress, fluid chemistry, and temperature will 

affect permeability in natural and artificial fractures. They 

also used current technologies to analyze data from past 

field experiments, allowing them to separate the physical 

and chemical processes that affect fracture evolution. Statistical analysis of fracture 

apertures for two core samples demonstrated that EGS 

produced fractures with 

similar aperture distribution 

and spatial correlation will 

have different rates of permeability evolution depending on fluid composition 

and flow rate. Preliminary 

results from hydraulic modeling indicate that variations 

in particle residence times 

will affect local geochemical reaction rates.

LLNL’s expertise in geochemical modeling is critical to the success of EGS 

and other geothermal technologies. These models help 

researchers interpret experimental data and extrapolate 

Figure 2. Top: Schematic showing an enhanced geothermal reservoir. Permeability is increased in the hot region, 

and fluids are pumped into the reservoir. Bottom: Integrated laboratory-scale experimental/computational investigations (fracture aperture, flow streamlines, model showing development of channeling, left-to-right) lead to better 

models of mechanisms that alter transmissivity in EGS and provide insights into the scaling of important coupled 

hydraulic/mechanical/chemical/thermal processes that aid in creating and maintaining fracture permeability.
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Geothermal Tomorrow 2008

the results to a broader range of expected conditions. For 

example, geochemical modeling can simulate the physical 

changes occurring in a fractured system during fluid transport and predict how different injection fluids will affect 

permeability during the average fluid residence period. 

Numerical models of representative geothermal reservoirs 

can also be used to optimize production and maximize reservoir lifetime.

A common problem in geothermal recovery is that minerals 

such as silica and lithium precipitate through flow channels, 

reducing fracture permeability. Removing the minerals is 

an expensive, time-consuming process that limits the usefulness of enhanced geothermal recovery. To improve the 

long-term effectiveness of an EGS reservoir, researchers 

need to reduce the costs for maintaining fracture permeability. One approach, developed by a team of LLNL geochemists and an industrial partner, is to extract commodity 

metals from the reservoir for use in other applications. This 

work recently led to technology licensing for a proprietary 

process to convert extracted lithium to lithium carbonate, a 

key component in batteries for electric vehicles and energy 

storage technology.

Geothermal Research to Improve Energy Security

Energy security is a pressing challenge for the United 

States—one that offers tremendous opportunity for scientific innovation. Energy recovery through EGS could help 

reduce the nation’s dependence on imported oil. However, 

more work is needed before EGS can be successfully 

deployed on a nation-wide scale. In particular, the lifetime 

of EGS reservoirs is not long enough to make it a costeffective approach for geothermal recovery. In addition, 

researchers need improved tools to locate the optimum sites 

for geothermal production and new technologies to access 

the energy trapped deep underground. 

LLNL offers a unique combination of computational, theoretical, modeling, and experimental capabilities that directly address many of the nation’s energy problems, including 

geothermal energy. LLNL’s Geothermal Recovery Program, together with other national laboratories, industry 

and industrial partners, is building on its past successes in 

exploration technologies, geochemical analysis, and EGS 

processes to develop integrated geophysical approaches for 

geothermal energy production. Future research activities 

will focus on enabling technologies for better site selection, 

reservoir management, and EGS.

Geothermal Technologies Program Activities at 

Idaho National Laboratory

 I

daho National Laboratory (INL) currently provides technical support to the U.S. Department of Energy’s (DOE) 

Geothermal Technologies Program (GTP) to develop 

analytical tools that provide insight into how DOE’s geothermal research can impact the cost of generating electrical power. This work is being done in support of the Strategic Planning and Analysis Project area that is managed by 

Arlene Anderson at DOE Headquarters.

Geothermal Evaluation Model

In 2005, a spreadsheet model referred to as the Geothermal 

Electricity Technologies Evaluation Model (GETEM) 

was developed to provide DOE with insight into how its 

research could affect the cost of producing geothermal 

energy. Based upon user input, model estimates are developed for costs associated with exploration, well field 

development, and power plant construction that are used 

with GETEM’s estimate of operating costs to predict a 

levelized cost of electricity (LCOE). The model then allows 

its user to evaluate how technology improvements could 

impact those projected power generation costs. Results help 

DOE prioritize research areas and identify where research 

is needed. The model also aids GTP in conforming to Government Progress and Results Act (GPRA) requirements 

for annual assessment and reporting of improvements in 

geothermal electric systems. 

GETEM was developed by a team consisting of personnel 

from DOE, national laboratories, and industry, with the 

lead role in the development shared by Dan Entingh from 

Princeton Energy Resources International and Gerry Nix 

from NREL. A requirement for GETEM’s development was 

that there is a referenced basis of the LCOE projections. 

Ideally these projections would be based upon actual cost 

data; unfortunately little actual data is in the public domain 

and, when available, frequently lacks the detail necessary 

to adequately characterize both cost and performance. In 

lieu of actual data, published engineering studies were used 

to develop the cost and performance correlations used in 

GETEM. The correlations used to characterize the energy 

conversion systems were based largely upon the information reported in Electric Power Research Institute’s (EPRI) 
13

Geothermal Tomorrow 2008

1995 Next Generation Geothermal Power Plant (NGGPP) 

study. The correlations for well costs were based on Sandia 

National Laboratory’s analysis of historical geothermal 

drilling costs. These costs were reported by Mansure at the 

2005 Geothermal Resources Council Annual Meeting.

Recent Development

During Fiscal Year 2008 (FY08), DOE has supported modifications to GETEM to address limitations in the model 

that have been identified since its original development. 

These changes to the model are largely being made by personnel at INL.

One of the premises in the original development of 

GETEM’s correlations was that the costs reported in the 

1995 EPRI NGGPP study were representative of the conversion system costs in 2004. Given the dramatic increases 

in steel costs that have since occurred, estimates using 

GETEM’s original correlations are no longer representative 

of commercial plant costs. The model’s LCOE projections 

were further limited by its use of correlations to predict 

plant performance and cost as functions of the resource 

temperature only; they did not account for the functional 

relationship between the plant cost and performance. Plants 

that are designed to more efficiently convert geothermal 

fluid energy into electrical power are more expensive. Generally, more efficient (and expensive) plants are used when 

a resource has higher well field development costs, while 

less efficient plants are used with resources that are less 

expensive to develop.

To address these shortcomings, in 2008, GETEM was 

modified to improve the conversion system correlations, 

with a focus on air-cooled binary plants. Based on prior 

work done at INL, correlations were developed that predict 

the cost of the plant as a function of the plant performance 

for a given resource temperature. Prior work at INL also 

provided an indication of relative contributions of labor and 

material to the cost of major equipment items. These relative cost contributions provided a means to make adjustments to the predicted equipment costs to account for the 

changes in costs of fabrication materials and labor with 

time. This was accomplished by using the Producer Price 

Index (PPI) and Consumer Price Index (CPI) reported by 

the U.S. Department of Labor for the different materials 

and equipment found in the plants. The model can go either 

forward or backward in time from the reference year costs 

(2002) using these PPIs to predict equipment and plant 

capital costs for the desired year. 

With the inclusion of the relationship between plant cost 

and performance, a macro was incorporated into the 

spreadsheet model that varies the plant performance (and 

cost) until the LCOE is minimized. The model now trades 

off the additional cost of a more efficient plant with either 

the additional power that can be produced from a given 

well field or the reduced well field size (and cost) for a 

fixed power output. An example of this trade-off is shown 

in Figure 3. The lower line in this figure shows the plant 

contribution to the LCOE as a function of its performance. 

At lower performance levels, the cost of the well field necessary to support the 15 MW plant output increases due to 

the cost for added wells and increased geothermal pumping 

requirements (which also affects the plant cost contribution 

at lower levels of performance). The results in this figure 

illustrate that the minimal LCOE does not necessarily occur 

at conditions that produce the minimal plant contribution to 

generation costs.

Figure 3. Effect of plant performance on LCOE for a 15 MW binary plant.

Contributions to LCOE in 15 MW Binary Plant

Levelized Cost

of Electricity

O&M and

Royalty

Well Field

Minimum

Power Plant

Performance, w-h/lb,gf

14

12

10

8

6

4

2

0 0 1 2 3 4 5 6 7
14

Geothermal Tomorrow 2008

These changes to GETEM have been completed along with 

some initial changes that were made to facilitate the evaluation of EGS resources. A beta version of the model has 

been distributed to solicit comments and feedback on the 

reasonableness of the estimates produced.

GETEM’s Future

Ongoing efforts are focused on modifying the GETEM 

model so it better represents the generation of power from 

EGS resources. Initially, work has focused on developing a model that characterizes the performance of the 

total system, including a subsurface EGS heat exchange 

system and production and injection wells. The production well model being incorporated predicts the necessary 

setting depth for the production pump based on the user’s 

postulated hydraulic performance of the subsurface heat 

exchange system.

In addition, a simple model is being included for the subsurface heat exchange process. Based on a postulated fracture system, production fluid temperatures are predicted as 

a function of time and flow. These fluid temperatures are 

used to estimate the degradation in plant output with time 

and to establish when it is necessary to replace the EGS reservoir and/or drill additional wells. Options are also being 

included that allow the user to establish a stimulation cost 

as a function of the size of the reservoir. This model does 

not realistically depict a subsurface heat exchange system; 

however, the trends it predicts are expected to be representative of how different parameters defining the subsurface 

system will affect produced fluid temperature.

Estimates for pump settings, well flows, production fluid 

temperatures, and stimulation cost all affect the project 

cost and the LCOE. Incorporating these parameters into the 

recent version of the model allows users to vary the different postulated scenarios for the subsurface heat exchange 

system (including reservoir depth) and assess how these 

changes affect the power generation costs from EGS 

resources, as well as hydrothermal resources. 

These modifications to the model are currently in progress; 

it is anticipated that the initial changes (for the binary conversion system) will be completed by the end of FY08. At 

that time there will be a limited distribution of the revised 

model for beta testing. Once those changes have been 

incorporated, efforts will focus on providing a means of 

updating the well costs. 

Although most of the changes described will likely be 

completed by the end of FY08, as more insight is gained, 

and the important parameters for EGS development are better defined, further modifications will probably be needed. 

At some point in 2009 it is expected that the model with the 

revisions now in progress will be made generally available 

to the public. Those parties interested in receiving a copy of 

the model should forward their requests to: 

Arlene Anderson, U.S. Department of Energy

E-mail: arlene.anderson@ee.doe.gov

Greg Mines, Idaho National Laboratory

E-mail: gregory.mines@inl.gov

Charles Visser, National Renewable Energy Laboratory

E-mail: charles_visser@nrel.gov

Idaho Operations Office Contract DE AC07 05ID14517

References

1. Barton, C.A.; Hickman, S.; Morin, R.; Zoback, M.D.; Finkbeiner, T.; Sass, 

J.; and Benoit, D. “In-Situ Stress and Fracture Permeability Along the Stillwater Fault Zone, Dixie Valley, Nevada.” Presented at the Twenty-Second 

Workshop on Geothermal Reservoir Engineering. Stanford University. Stanford, California. January 27–29, 1997.

2. Blewitt, G.; Coolbaugh, M.; Holt, W.; Kreemer, C.; Davis, J.; and Bennett, 

R. “Targeting of Potential Geothermal Resources in the Great Basin from 

Regional Relationships Between Geodetic Strain and Geological Structures.” 

GRC Transactions; Vol. 26, 2002; pp. 523-526.

3. Tester, J.W. et al. “The Future of Geothermal Energy: Impact of Enhanced 

Geothermal Systems (EGS) on the United States in the 21st Century.” 

Presented in an assessment by an MIT-led interdisciplinary panel. MIT. 

Cambridge, Massachusetts. 2006.

The work discussed in this section was performed with the support of 

the U.S. Department of Energy Office of Energy Efficiency and Renewable 

Energy (EERE), under National Renewable Energy Laboratory Contract 

DE AC36-99GO10337, Lawrence Livermore National Laboratory Contract 

DE AC52-07NA27344, and Idaho National Laboratory Contract DE AC07-

05ID14517.
15

Geothermal Tomorrow 2008

 G

eothermal power plant developers are seeking ways 

to supply attractively priced renewable energy to 

utilities. The price that a geothermal power plant 

developer can offer to a utility in a power purchase agreement (PPA) largely depends on a number of factors, including the power conversion technology used to generate the 

electricity, power plant size, and four additional factors:

1. Development costs

2. Financing charges

3. Operating and maintenance (O&M) costs

4. Resource credits. 

Development costs—costs to get the plant sited, constructed, 

and put online—are significantly higher than those of 

fossil-fueled power plants. The development cost to build a 

natural gas power plant is about one third of the total costs. 

Development costs of a geothermal facility, in contrast, 

represent two thirds or more of total costs.

Financing charges—Customer owned utilities such as 

municipalities and electric cooperatives have interest rates 

of about 5%-6%. Independent power producers may have 

interest rates of 15% and higher.

O&M costs—cover charges for running the power plant and 

servicing and replacing equipment. 

Resource credits—provide incentives for renewable energy 

projects.

Development Costs

Development costs include all expenditures 

associated with exploration, drilling, permitting, 

construction, and ancillary investments such 

as transmission costs. The development costs 

for a typical 20 MW power plant are shown in 

Table 1. These costs are rules of thumb. Actual 

costs can vary based on factors such as time 

delays, geology, environmental restrictions, 

project size, and transmission access.

The cost of time delays is significant, sometimes adding $10 to $20 or more per MWh 

or more to the cost of power. The time delays 

typically occur in the first two stages of development where the risks are higher and the cost 

of capital is greater than the last two stages.

Table 1. Typical Geothermal Power Plant Development Costs

Development Stage Cost ($/kW)

Exploration and resource assessment $ 400

Well field drilling and development $ 1,000

Power plant, surface facilities, and transmission $ 2,000

Other development costs (fees, working capital, and 

contingency)

$ 600

Total development cost $ 4,000

Exploration and Resource Assessment

Successful exploration results in the discovery of a geothermal resource capable of providing geothermal fluid to run a 

power plant and produce electricity. Exploration activities 

include regional reconnaissance and district exploration, 

and encompass prospecting, acquisition of rights, and field 

analysis. The activities are not linear, that is, developers 

may start acquiring land and mineral rights even before significant prospecting has begun.

Regional reconnaissance screens a large area of hundreds 

of square miles. The reconnaissance narrows prospecting 

efforts and involves geologic studies, analysis of available 

geophysical data, and geochemical surveys to identify more 

limited areas for detailed exploration.

District exploration uses geophysical surveys and temperature 

gradient measurements and focuses on smaller areas of 5,000 

acres or more to site the first production well. Activities could 

include gravity surveys, ground magnetic surveys, magnetotelluric surveys, electrical resistivity surveys, and seismic 

surveys. The final step in district exploration is its most 

expensive activity—drilling the first deep exploration well.

The Price of Geothermal Power
16

Geothermal Tomorrow 2008

Well Field

Well field drilling and development includes siting and 

drilling exploration, and production injection wells, testing 

well flow rates and reservoir engineering. Ideally, exploration wells can be also used as production or injection wells. 

A successful set of wells results in high fluid temperatures 

and flow rates. According to the Geothermal Energy Association, exploration wells have an average success rate of 

20%–25%, while production and injection wells have an 

average success rate of 60%–90%. Reservoir engineering 

determines the best location for injection wells and the flow 

rates that result in the most stable production.

Power Plant, Surface Facilities, and Transmission

These expenditures embrace the cost of the power plant and 

the geothermal fluid piping system, grid connection, ancillary infrastructure, and pollution abatement systems and 

environmental compliance work that include engineering, 

regulatory, documentation, and reporting activities. 

The power plant consists of a series of unit operations and 

equipment such as pumps and motors, turbines, cooling 

towers, and transformers. The piping system connects the 

power plant with all production and injection wells. Grid 

connection includes the substation and transmission lines 

needed to move the output to the market and, if needed, 

to the well pumps. Ancillary infrastructure includes office 

buildings, roads, utilities, and other structures.

Pollution abatement systems and environmental compliance 

work is a large umbrella—geothermal power projects have 

to comply with federal, state, and local regulatory requirements, which vary according to location. For example, 

National Environmental Policy Act requirements apply if 

the project is on federal land. 

State and local agencies, such as air and water boards, may 

require air and water discharge permits, and each agency 

may also have reporting requirements. Beginning in the 

exploration phase, there may be a need to consult with the 

state historic preservation office or Native American tribes 

if cultural resources are affected, and the U.S. Fish and 

Wildlife Service if plant or animal species of concern may 

be affected. Other federal regulatory agencies involved in 

the process include the Bureau of Land Management, the 

U.S. Forest Service, and the Federal Energy Regulatory 

Commission.

Other Development Costs

During geothermal development, legal services are needed 

to ensure quality in contract, performance, and reporting 

documents. A contingency reserve is necessary to provide 

working capital and to cover unexpected costs due to delays 

and unforeseen requirements. It also covers any margins 

required by the developer or owner.

Financing Charges

Financing charges are affected mainly by the amount of 

upfront capital needed to cover the first two development 

stages, the time line of these two stages, and the loan terms 

that allow the developer to repay the upfront costs and 

finance the second two development stages. The costs of 

the first two stages, exploration and well drilling and development, generally are not financed by utilities, banks, or 

other lending institutions. Venture and equity capital or inhouse reserves are sources for funding the first two development stages.

Geothermal well drilling at the Long Valley Exploratory Well near 

Mammoth Lakes, California.
17

Geothermal Tomorrow 2008

For the purpose of this article, an 18% return is assumed 

for the investment in the first two development stages over 

a four-year period. Investors correctly interpret geothermal 

investments as high risk due to historical delays in having 

a project sited, developed, and online. For example, exploration at the Glass Mountain Known Geothermal Resource 

Area in Northern California began over 20 years ago. The 

exploration resulted in discovering a resource that could be 

commercially viable, but there is still no power plant. 

Different types of utilities and lending institutions have 

varying interest rates and terms. For the purpose of this 

article a developer can compare two scenarios: 

•	 10% and 15 years (bank financing) 

•	 6% and 30 years (utility financing). 

Each scenario assumes that the plant life is the same as 

the loan term and there is no salvage value to the plant 

afterwards. Zero salvage value may be a harsh assumption. 

However, in 15 years, the technology may have advanced 

to where the existing plant may need upgrading to meet 

new requirements.

If these two scenarios cover the boundaries of reality, the 

developer would expect to pay $48 to $87 per MWh for the 

project financing, assuming a 92% plant factor. Plant factor 

is defined as the rated capacity and the percentage of the 

year that the power plant is producing electricity.

O&M Costs

Fuel costs for geothermal power plants are insignificant. 

Expenses are costs for steam field management and geothermal fluid impacts on equipment and are covered in the 

power plant design costs and operations and management 

(O&M) costs.

O&M costs include those charges for employee salary and 

benefits, equipment replacement reserves, utilities, and 

administration. Most new geothermal power plants coming online are going to be closed loop, air cooled, binary 

cycle plants. The O&M costs are assumed to be at a level of 

about $15 per MWh—lower than the typical plant. 

Resource Credits

Geothermal power and other renewable resources may use 

rapid depreciation or other incentives such as the Production 

Tax Credit (PTC) to reduce the final costs to supply output 

to the market. The PTC currently is $9 per MWh. Other 

incentives such as pollution credits may apply in the future.

The Bottom Line

The cost of geothermal power, based on the above discussion and assumptions, is likely to be in the range of $63 to 

$102 per MWh, excluding any reduction due to resource 

credits. One caveat, a major impact on geothermal power 

cost is the local, regional, national, and global competition 

for commodities such as steel, cement, and construction 

equipment. Geothermal power is competing against other 

renewable and non-renewable power development, building construction, road and infrastructure improvements, 

and all other projects that use the same commodities and 

services. Until equipment and plant inventories rise to meet 

the increase in demand for these commodities and services, 

project developers can expect the costs to rise well above 

the background inflation level.

Warren Gretz
18

Geothermal Tomorrow 2008

Financing 

Geothermal 

Projects

 I

n principle, the financing of geothermal power projects 

is not much different from the financing of other energy 

projects. It is about the allocation and management of 

risks among the various parties, with a few notable exceptions. The need to secure a fuel supply is essential to any 

energy project; whether the source of fuel is geothermal 

brine or conventional fuels. A distinct difference between 

geothermal and other energy technologies, though, is 

that the developer “pre-pays” the fuel cost in exploration 

and drilling expenses. Developers new to geothermal are 

sometimes surprised by the cost, lead time, and complexity 

involved in permitting and developing geothermal resources. Ensuring that the technology selected is compatible with 

the available resource is essential to long-term success. 

Finally, the geothermal industry has attracted a long list of 

developers and entrepreneurs who usually come in from 

other industries, often with the idea that developing a geothermal project is relatively simple compared to other, more 

traditional, energy projects. Some of these new developers 

lack the experience, skills, and capital required to deal with 

the considerable challenges they will undoubtedly face 

in the process. By employing the services of a team with 

geothermal experience, these “newcomers” may avoid the 

pitfalls that can derail potentially successful projects. 

Project Financing 

Classic energy-project financing involves a developer raising funds (usually through a special purpose subsidiary 

created and incorporated for the specific project) through 

various mechanisms from financing institutions, usually in 

the form of equity, debt, or a combination of the two. 

The participation of the financial entities may be attained 

through various business structures such as partnerships, 

leases, corporate investments, and combinations of the 

three. Issues of tax, cost accounting, and of course economics are the drivers in the process, but the underlying fundamentals are clear: risk versus reward. The more confident 

the investors feel that there is “real” credit support behind 

the project, the better the financial terms they will agree to 

provide with their investment. 

The elements that are analyzed in the financing process 

are those that may affect the financial performance of the 

project over time. Typically, the main elements are: 

•	 Power Purchase Agreements (PPA) are a major financing 

support element. But for specific terms and conditions 

such as pricing, indexing, termination clauses, and term, 

the reality of the last years requires that the power purchaser have a solid credit position.

•	 Fuel supply availability (brine or steam), cost, and projected longevity of the supply. Developers should be 

prepared to pay a significant risk premium when trying to 

finance projects with unproven or undeveloped geothermal resources. The up-front cost of developing the geothermal resource means that the overall efficiency of the 

power plant strongly influences the return on investment.

•	 Site control for the entire resource, including the ability 

to preclude competing interests. Competition for leases 

and geothermal rights is often intense.

Jets shown prior to being 

attached to a geothermal 

system at The Geysers 

Geothermal Power Plant 

in California.

David Parsons
19

Geothermal Tomorrow 2008

•	 Field performance experience of the technology which 

will produce the power. Few manufacturers have a longterm track record for utility-scale geothermal systems.

•	 Experience and credibility of the developer.

•	 Other elements such as structure of the deal, regulatory 

issues, and electricity transmission issues. 

The Geothermal Resource 

Geothermal projects are attractive because they produce 

base-load power and thus geothermal projects can generally 

qualify for firm long-term contracts with utilities. Despite 

these advantages, developing a geothermal power project is 

a complicated process that new developers must approach 

carefully. Geothermal projects have distinctly different 

challenges than other, more traditional, renewable technologies such as wind, solar, and biomass. Geothermal projects 

require subsurface exploration and well field development and have greater upfront risk because the geothermal 

resource is not confirmed without drilling.

The geothermal resource is key to the success of a geothermal project and has a profound effect on financing terms. 

Resource critical parameters (temperature, permeability, 

fluid production, brine chemistry, etc.) include the ability to 

support power production on a sustainable long term basis. 

Other details that need to be addressed include: 

•	 Land ownership issues

•	 Permitting and other regulatory issues

•	 Transmission issues.

Financial institutions usually come on board once the geothermal resource has been fully explored and at least partially developed. At this stage, financial investors will have 

to be satisfied that the resource has the potential to deliver 

energy (and revenue) over a long period of time. 

Nearly as important as the resource is the ability of the 

developer to demonstrate their team has the talent required 

to acquire, develop, and manage the geothermal field effectively. The major geothermal operators in the geothermal 

industry, such as Ormat, have an in-house talent base, which 

includes land teams, geologists, reservoir engineers, and 

other technical personnel. The ability of the developer’s 

team to communicate freely among all these disciplines, 

on a continuous and near instantaneous basis, ensures that 

issues and problems in resource development and management are addressed expeditiously and effectively. 

Financing partners will seek assurances that the developer has:

•	 Critical mass of skilled, talented, and experienced 

personnel 

•	 Sufficient funds to address any resource related contingencies that may arise over the term of the financing. 

Power Plant Technology

There is no standard approach to geothermal technology. 

Rather, the developer must adapt the plant to the available 

resource. For decades, premier geothermal resources were 

developed using standard steam turbines. These standard 

steam turbines are compatible with high temperature geothermal resources, but not with cooler geothermal resources 

that produce mostly hot fluid and not much steam. Because 

the geothermal resource base in the United States is mostly 

composed of these cooler geothermal resources, power 

Condensers being retrofitted with direct contact condensers at The 

Geysers Geothermal Power Plant in California.

David Parsons
20

Geothermal Tomorrow 2008

plant technology has advanced to capture this resource base. 

Today’s developers will find that steam technology is not 

applicable for most present-day projects; they will find that 

binary cycle plants will be the preferred solution. Binary 

cycle plants typically utilize an Organic Rankine Cycle 

(ORC). The ORC operates by exchanging heat between geothermal fluid and a secondary working fluid, which is typically an organic fluid (such as pentane or isobutene) with 

a low boiling point. The organic fluid is vaporized to drive 

the turbine. Although the need for an integrated solution 

drives many developers to binary plants using the ORC, one 

size does not fit all. The temperature, flow, and chemistry of 

the resource require specific technological and engineering 

solutions in order to maximize return on investment.

Financial institutions may be reluctant to provide nonrecourse financing for a power plant technology that was not 

field proven and tested over many years in different resource 

areas. The reality is that geothermal power plants are 

expected to be of “utility grade.” Developers selecting nonutility scale technologies such as Kalina cycle and reversed 

refrigeration may find it difficult to secure financing. 

Developers 

The following are key issues a lender or investor considers 

before financing a project: 

•	 Committed developer. One of the most important elements in putting together a geothermal power plant 

is a long term process. Our experience shows that the 

development of a geothermal project takes three to five 

years from site acquisition to commercial operation. One 

needs the capital and the commitment to go through the 

process, which many times does not yield a project at 

all. This commitment is required for the long term, as all 

projects have implementation issues that begin only after 

the financing closes.

•	 Management team with the proper disciplines. As the 

development and operation of a geothermal project are 

very challenging, the financial parties will look for developers who are astute enough to secure the services of the 

most experienced technical personnel in the field. 

•	 Well capitalized developer. Geothermal power plants may 

present financial challenges during the operational phase. 

Geothermal projects may have long term issues with the 

well field and power plant. These unforeseen elements 

may require a temporary injection of capital on short 

notice. 

Summary

The geothermal industry is unique within the energy market, and as such the financing process of geothermal projects contains certain unique key elements that determine 

the ability of a geothermal plant developer to reach successful completion.

Based on Ormat’s experience, we identified the main elements to support non-recourse project financing, as discussed in this article: 

•	 Availability of the geothermal resource

•	 Proven technology used in the geothermal power plant

•	 Credibility and record of the developer. 

When all of these elements are present, a geothermal project is likely to be successfully financed. 

Drilling exploration crew performing initial well logging tests at the 

Desert Peak site in Nevada.

Patrick Laney
21

Geothermal Tomorrow 2008

International Geothermal Efforts – 2008

Introduction

As the global demand for clean, reliable, renewable energy 

increases, geothermal energy is becoming an attractive 

solution. This is true not only in the United States, where 

current production is approaching 3,000 MWe, but at 

numerous locations on six continents. An area of increased 

emphasis is Enhanced Geothermal Systems (EGS). 

Some of the most integrated and profound policy developments have been occurring in Australia, where significant governmental commitment and financial support 

are advancing the country’s EGS Hot Dry Rock efforts. 

Another notable development can be found in Europe, with 

the ENhanced Geothermal Innovative Network for Europe 

(ENGINE) project. 

What follows is an incomplete and brief survey of geothermal developments outside of the United States in 2008.

Australia and New Zealand

Australia and New Zealand have been consistent developers of geothermal energy and continue to advance their 

interests in development. 

Australia’s state and federal governments have been supportive of developing EGS infrastructure and have set forth 

ambitious plans to expand geothermal development as part 

of the country’s renewable energy portfolio. But, there has 

been a perceived minor setback—the latest federal budget 

presented a deferral of access to the A$50m geothermal 

fund until approximately July 2009.2

Australia has engaged in the Onshore Energy Security Program (OESP) and has committed A$58.9m over five years 

to Geoscience Australia (formerly the Australian Bureau of 

Mineral Resources). The Otway Basin along the Limestone 

Coast in South Australia is a region of interest. Three sites 

for development have been identified, possibly producing 

1,600 MWe for 30 years.3

Mighty River Power in New Zealand plans to invest more 

than NZ $1 billion to develop 400 MWe of new geothermal 

generation by 2012 in the Taupo Volcanic Zone on the North 

Island.3 The Kawerau plant is scheduled for completion by 

the end of 2008 and is expected to generate 90 MWe. 

The Wairakei Geothermal Power Plant in New Zealand.

Table 1. Estimated Production of Geothermal Energy by 

Country and MWe in 20101

Country MWe Country MWe

United States 3,000 Russia 185

Philippines 1,991 Kenya 164

Indonesia 1,192 Nicaragua 143

Mexico 1,178 Turkey 83

Italy 910 Papua New Guinea 56

New Zealand 590 France 5

Iceland 580 Portugal 35

Japan 535 China 28

El Salvador 204 Germany 8

Costa Rica 197 Ethiopia 7

The Creation of a New International 

Geothermal Partnership.

A delegation from the U.S. Department of Energy (DOE) traveled to 

Reykjavik, Iceland in August 2008 for the signing and initial workshop 

of the International Partnership on Geothermal Technology (IPGT), 

a new agreement between geothermal technology leaders Iceland, 

Australia, and the United States. The DOE’s Acting Assistant Secretary 

for Policy and International Affairs, Katharine Fredriksen, Australia’s 

Ambassador to Iceland, Sharyn Minahan, and Iceland’s Minister of 

Industry Energy and Tourism, Ossur Skarphedinsson signed the Charter 

document on August 28, 2008. New Zealand attended as an observer. 

The signing countries signaled their commitment to aggressively pursue advanced geothermal technologies, such as Enhanced Geothermal 

Systems (EGS), as part of a solution to energy security and global climate change concerns. “EGS has the potential to be the world’s only 

ubiquitous form of baseload renewable energy,” said Acting Assistant 

Secretary Fredriksen. “This partnership will bring together countries 

with expertise in geothermal energy to accelerate the development of 

EGS, bringing this technology to the market in the near-term to confront the serious challenges of climate change and energy security.”
22

Geothermal Tomorrow 2008

Europe

In 2007, the European Commission (EC) began funding the 

ENGINE program. ENGINE’s main objective is to coordinate research and development initiatives for unconventional geothermal resources and EGS and aspires to develop up 

to 20 demonstration sites.4 ENGINE sets forth four research 

areas for geothermal development: 

•	 Exploration: finding access to potential reservoirs at 

depth

•	 Geothermal wells: improving drilling and completion 

technologies

•	 Reservoir engineering: stimulating fluid flow 

underground

•	 Exploitation: improving efficiency. 

In June 2008, the pilot plant of Soultz-sous-Forêts in Alsace, 

France, was inaugurated by the French Prime Minister François Fillon. The first installed Organic Rankine Cycle (ORC) 

module of 1.5 MWe is providing electricity to the grid. This 

European project, mainly funded by France, Germany, and 

the EC (with collaboration of several other countries including the UK and Switzerland), started in 1987. Much of the 

technology was adopted from the Rosemanowes site in 

Cornwall, which benefited from earlier DOE experiments 

at Fenton Hill. Shell and Enel were also involved with this 

project. The first successful, commercially-funded EGS 

project is in Landau, Germany. The project was completed 

in 3.5 years and is producing up to 3.6 MWe.

5

Asia

Exploration is taking place in several regions including 

India, the Kyrgyz Republic, China, Indonesia, and the 

Philippines. 

In India, GeoSyndicate Power Private is working in collaboration with Panax Geothermal from Australia to exploit 

“wet” projects in the Godavari rift in Andhra Pradesh and 

the Himalayan Geothermal Province in Ladakh where there 

are high-heat flows. 

High-heat flows have been detected in the Kyrgyz Republic and exploration licenses have been issued for several 

groups seeking high-heat producing granites in the Inylchek 

region of the republic. 

Researchers have been assessing thermal resources in several regions of China and notable surveillance work has 

been conducted in Yunnan Province for the Rehai (Hot Sea)

geothermal field of Tengchong County, where more than 

815 thermal springs have been identified; 354 of which 

were measured at temperatures above 113°F (45°C).3 An 

additional 105 MWe could be developed in Gu’an County, 

Hebei Province.3

At the time of this writing, 17 companies (including Chevron) are planning to bid for geothermal projects in West 

Java, Indonesia, possibly generating as much as 315 MWe.6

The three power plants are Tangkuban Perahu (220 MWe), 

The 120 megawatt Nesjavellir Geothermal Power Plant in Iceland.

Table 2. Preliminary List of ENGINE EGS Demonstration 

Projects by Country and Site Name 

Country Project

France Roquette, Rhine Graben

Germany Bruschal

Groß Schönebeck

Landau

Unterhaching

Hungary Fábiánsebestyén 

Zala County

Iceland Icelandic Deep Drilling Program

Poland Podhale

Slovakia Košice

Turkey Green Campus Izmir
23

Geothermal Tomorrow 2008

Cisolok Sukarame (45 MWe), and Tampomas (50 MWe). 

The Philippines is allowing the Philippine National Oil 

Company-Energy Exploration Corporation to drill geothermal wells in a restricted buffer zone adjacent to the Mt. 

Kanlaon Natural Park.

North America and the Caribbean

Geothermal development has been acute in Mexico and 

Central America. Notable developments have been producing geothermal energy in El Salvador, Nicaragua, and Costa 

Rica for many years. Canada has begun exploration with an 

eye to development with the Canadian Geothermal Energy 

Association regrouping in 2007. 

Nicaragua developed a 35 MWe operation on the Momotombo reservoir in 1983. Over the years production 

decreased dramatically and, by 1999, power-plant generation stood at 9 MWe. Reinjection was initiated and currently the plant is producing 30-35 MWe.3

Interest has been developing in the Caribbean, and drilling 

began on Nevis at the Spring Hill site in 2008; steam was 

located later that year at 3,720 feet. 

Africa

Another region of interest for geothermal development 

has been the East African Rift Valley. The United Nations 

estimates this region may be able to produce more than 

400 MWe. In 2007, the World Bank had committed up to 

$13 million to the African Rift Geothermal fund, which 

will operate in six countries: Kenya, Uganda, Tanzania, 

Ethiopia, Eritrea, and Djibouti. Kenya was the first of these 

countries to develop geothermal energy and has the largest 

geothermal plant in Africa—near Naivasha (Olkaria), yielding 130 MWe.3,7 Kenya Electricity Generating Company 

plans to install an additional 1,260 MWe by 2018 from four 

potential geothermal areas in the Kenya Rift—Olkaria, 

Menengai, Longonot, and Eburru—and also plans to develop at least 300 production and 60 reinjection wells over the 

next 10 years.3

South America

The International Geothermal Association shows no production of electricity in South America. A report indicates 

Bolivia may have the capacity to produce 280-370 MWe. 

Chile has become interested in exploring its geothermalresource potential after the abrupt curtailment of natural gas 

shipments from Argentina. 

Summary

As stated in the introduction, this is neither a comprehensive nor a complete survey of international geothermal 

development—it is merely a snapshot that provides a 

sample of efforts and initiatives across the globe. What is 

important to note is that there is an increased interest in 

geothermal development in 40 or more countries and all 

indications show this interest will be persistent and durable 

in light of international energy demands and the need to 

develop clean, renewable, baseload energy.

References

1. Bertani, R. “Geothermal Power Plants Commissioned in the Third Millenium.” IGA News; Vol. 72, April-June 2008; pp. 5-10.

2. HDRPL Geothermal Newsletter. Issue 20, June 2008.

3. GRC Transactions; Vol. 32 (preprint), 2008. 

4. Robertson-Tait, A.; Ledru, P.; Goldstein, B.; and Nathwani, J. “Current EGS 

Funding Initiatives in Europe, Australia, and the United States.” GRC Bulletin; Vol. 37/3, May-June 2008; pp. 18-24. 

5. Baria, R.Personal communication by e-mail. 18 June 2008.

6. “Chevron, Medco to Tap RI Geothermal Potential.” The Jakarta Post online 

http://old.thejakartapost.com/headlines.asp. Accessed June 7, 2008.

7. “UN to Ensure Geothermal Explorers in East Africa.” EcoEarth.Info online 

http://www.ecoearth.info/. Accessed March 22, 2007.

Gretar Ivarsson
24

Geothermal Tomorrow 2008

Utility Geothermal 

Working Group Update

 T

he Utility Geothermal Working Group (UGWG) 

was formed in September 2005, at the Geothermal Resources Council’s annual meeting in Reno, 

Nevada. It is a group of utilities and ancillary associations 

formed under the U.S. Department of Energy’s Geothermal Technologies Program. UGWG is supported by six 

organizations:

•	 American Public Power Association (APPA)

•	 Bonneville Power Administration (BPA)

•	 Geothermal Resources Council (GRC)

•	 National Rural Electric Cooperative Association 

(NRECA)

•	 U.S. Department of Energy (DOE)

•	 Western Area Power Administration (Western).

The Working Group’s mission is to accelerate the appropriate integration of three geothermal technologies into 

mainstream applications: power generation, direct use, and 

geothermal heat pumps (GHP). In addition to 

the six support organizations listed above, the 

UGWG members include: 

•	 Arizona Public Service

•	 Ormat Technologies, Inc.

•	 Palo Alto Utilities

•	 Redding Electric Utility

•	 Salt River Project

•	 Sandia National Laboratories

•	 Seattle City Light

•	 South San Joaquin Irrigation District 

•	 Springfield Utility Board

•	 State Working Groups

•	 Idaho National Laboratory.

Webcasts and Workshops

To help accomplish its mission, the UGWG 

conducts periodic training events in the form 

of Webcasts and workshops. Events focus on 

geothermal and other renewable applications, technologies, 

and issues. Since its formation, the Group worked with its 

members and GRC staff to shape utility training sessions at 

the 2006 and 2007 GRC meetings. These training sessions 

provided an opportunity for more utilities to attend the 

high quality meetings. Other workshops and Webcasts have 

focused on topics such as:

•	 Power Generation

•	 Direct Use

•	 Geothermal Heat Pumps

•	 Transmission Issues

•	 Project 25x25

•	 Renewable Energy Credits

•	 Coal Fired Power Plants

•	 Public Participation

•	 Clean Renewable Energy Bonds

•	 Geothermal Heat Pump Economics.

Power Generation and Direct Use Findings

Utilities are continuing on the path of integrated resource 

planning (IRP) to provide energy services to their customers. IRP demonstrates that energy efficiency remains the 

first choice in a utility resource portfolio and that direct 

use is an application that utilities continue to avoid. On 

the other hand, geothermal power generation is of interest 

to utilities. Geothermal power plants are capital-intensive, 

requiring most of the funding up front before the project 

The Creamery Brewpub and Grill is one of the case histories described in UGWG workshops. 

It uses geothermal energy from the Klamath Falls, Oregon, geothermal district heating system 

for all its heating purposes. Uses of geothermal energy include space heating of approximately 

11,000 ft 2 (1,022 m2) of restaurant/pub space, snow-melting of about 1,000 ft2 (93 m2) of 

sidewalks, and generation of hot water for the brewing process. In cold months the brewery 

saves about $1,100 in space heating expenses and saves around $300 per month in energy 

used to brew the beer. 

UGWG

OIT Heat Center
25

Geothermal Tomorrow 2008

produces any revenue. Utilities are more confident in the plants and are willing to negotiate a 

financeable power purchase agreement (PPA) 

with a developer, if the following five conditions are met:

•	 Delineated geothermal resource with a bankable report that defines probable long term 

performance

•	 Defined permitting path without pitfalls

•	 Credible developer with a proven project 

management track record

•	 Control of entire geothermal resource to 

preclude competing interests for same fluid/

steam supply

•	 Use of proven technologies.

Utilities are willing to enter into PPAs if the 

output compares favorably with the “default 

power plant”, which is currently a gas-fired combined cycle 

plant. Utilities estimate purchasing power from the default 

choice in the range of $65 to $90 per MWh, which includes 

capital, O&M, and fuel costs.

The price that a geothermal power plant developer can offer 

to a utility in a PPA largely depends on 1) the exploration, 

drilling, and development costs of getting the project online 

and 2) the financing charges associated with the costs. Costs 

for a typical 20 MW power plant are shown in Table 1.

Table 1. Costs For a Typical 20 MW Power Plant

Development Stage Cost (Millions of $)

Exploration and resource assessment $ 8

Well field drilling and development $ 20

Power plant, surface facilities, and 

transmission

$ 40

Other costs (fees, operating reserves, and 

contingencies)

$ 12

Total cost $ 80

Using the above costs as a basis, a typical geothermal power plant has a capital cost of $4,000/kW. This capital cost 

is translated to a MWh cost by applying an annual factor 

reflecting interests rates for financing the total capital cost.

•	 At an annual factor of 0.2, reflecting an interest rate of 

18% – 20%, capital costs are $104/MWh.

•	 At an annual factor of 0.15, reflecting an interest rate of 

13% – 1 5%, capital costs are $ 76/MWh.

There are no fuel costs and the typical O&M cost for a 

plant is about $15/MWh. The O&M costs assume that the 

power plant uses Organic Rankine Cycle (ORC) technology 

for energy conversion with air to air cooling towers. ORC 

technology uses a moderately high molecular mass organic 

fluid such as butane or pentane to absorb the heat from geothermal fluid and drive the turbine. The technology has the 

benefits of high-cycle and turbine efficiencies, low turbine 

mechanical stress, reduced turbine blade erosion, and the 

fact that a full time operator need not be present. 

If the power plant uses a different technology or water to 

air cooling towers, the O&M costs are likely to be higher. 

Using these two annual factors and adding the O&M cost 

to the annualized capital costs, the developer may be able 

to offer a utility output in the range of $91 to 119/MWh. 

This price could be lowered if the utility were to finance the 

power plant construction.

Geothermal Heat Pump Findings

GHPs represent an energy-efficient technology making 

strong gains as a viable alternative heating and cooling 

system, both in the United States and around the world.1

Although this technology has been in existence since the 

1940s, it still has not realized its full market potential, but 

the technology is gaining ground. The UGWG and one of 

its four major support organizations, Western, developed a 

report that describes the reasons why geothermal heat pump 

technology appeals to electric utilities and end users, and 

explains why this appeal has not been enough to sustain a 

national market.

The UGWG conducts several geothermal technology workshops each year.

Bruce Green
26

Geothermal Tomorrow 2008

Western also developed two worksheets that provide the 

economics of GHP versus other heating, ventilation, and air 

conditioning (HVAC) options from the customer and utility 

perspective. This report and the spreadsheets help readers to:

•	 Understand the benefits geothermal heat pumps offer customers and electric utility providers

•	 Describe market potential and appeal of geothermal heat 

pumps

•	 Document tactics and strategies that some electric utilities have used to develop sustainable and effective geothermal heat pump programs. 

Twelve utility programs with successful geothermal heat 

pump installations were selected to be included in this report. 

These are not all the utilities currently offering geothermal 

heat pump programs. Nor are they some of the geothermal 

“pioneers” that first established utility programs. Rather, 

these are the utilities still committed to selling and promoting 

this technology. The selected utilities featured in this report 

have found the right alchemy of program elements to create 

innovative and successful geothermal programs. 

The report identifies one major barrier to expanding GHP 

applications –costs that the customer must incur without 

utility financing. The GHP typically has a 20% premium 

when compared to traditional air-source heat pump system 

installations.2 Cost premiums are associated with designing 

and installing ground loop systems that operate year-round 

without auxiliary back-up units. According to one Energy 

Information Administration (EIA) report, these systems 

have a payback period of two to 10 years when energy and 

maintenance costs are accounted for.3 Other reports have 

indicated simple payback periods of five to eight years. The 

large variance in payback discourages implementing these 

systems. Typically, businesses and individuals look for a 

return on an investment within a two to three year payback, 

and a longer payback is highly unattractive for consumers 

and businesses alike.

If the utility were to step in and finance all or part of the 

GHP system for customers, the customers may likely enjoy 

a positive cash flow from the start of the system operation. 

The utility could place a lien on the customers’ properties and charge an interest rate, in the form of a loop lease, 

which is digestible for the customer and financially prudent 

for the utility.

To illustrate a typical residential application, the following 

assumptions are used and compare to a GHP system with a 

conventional HVAC system that uses a natural furnace for 

heating and electrically served air conditioning for cooling. 

Sources for assumptions are DOE and EIA. If the conventional source is propane, oil, or electric resistance for heating, GHP economics are better.

•	 Electric Rate = 10¢ per kWh

•	 Electric AC Use = 1,660 kWh per year

•	 Gas Rate = $1.50 per therm

•	 Gas Heating Use = 900 therms per year

•	 GHP System Cost = $10,000

Using the above assumptions, conventional HVAC costs 

$1,516/yr. The GHP costs are $1,390/yr, assuming that a 

loop lease is available to finance the GHP system costs. 

Loop leases vary due to loan terms. If the utility offers 6% 

financing and 30 year terms, the loop lease is $330/yr.

Does it make sense for a utility to offer a GHP program that 

includes a loop lease to the customer? Utility economics 

are less straight forward than customer economics. The utility needs to assess how the program affects its peak period 

(summer vs. winter), including the impact of the default 

heating option (electric resistance vs. other fuel sources 

such as natural gas or propane.

If the GHP system is replacing electric resistance heating, 

the utility saves about 40% in peak demand in the summer 

and winter, and loses about 70% of revenues from kWh 

sales. GHP makes sense if the peak demand savings and 

interest revenues from the loop lease more than offset the 

revenue losses and any other losses resulting from implementing the program. Other revenue losses include actions 

such as rebates, rate reductions, or lower interest rates.

Conclusions

The UGWG finds utility members are interested in two of 

the three geothermal technologies—power generation and 

geothermal heat pumps. Direct use appears to be too far 

afield from their core business to pursue at this time. Based 

on the results of training and interaction with the members 

over the past year, the UGWG plans to continue promoting 

the two geothermal technologies of interest to its members. 

The focus will be on workshops, training programs, and 

field assessments that cause more geothermal power plants 

to be developed and more geothermal heat pumps to be put 

into the ground.

References

1. Johnson, K. Geothermal Heat Pump Guidebook. 3rd Edition. 2007; p. 3

2. “Geothermal Heat Pumps.” Sacramento Municipal Utility District. January 

2007. 

3. Kavanaugh, S. Ground-Coupling with Water Source Heat Pumps. 2004; 

p.10. 
27

Geothermal Tomorrow 2008

State Policies Provide Critical Support 

for Renewable Electricity

 G

rowth in renewable energy in the United States over 

the past decade has been propelled by a number of 

forces, including rising fossil fuel prices, environmental 

concerns, and policy support at the state and federal levels. 

Arguably, the two most-important types of state policies for 

supporting electricity generation from geothermal and other 

forms of renewable energy are renewables portfolio standards (RPS) and utility integrated resource planning (IRP) 

requirements. Within the western United States, where the 

vast majority of the nation’s readily-accessible geothermal 

resource potential resides, these two types of state policies 

have been critical to the growth of renewable energy and 

promise to continue to play a fundamental role for the foreseeable future. 

Renewables Portfolio Standard 

A renewables portfolio standard (RPS) requires utilities and 

other retail electricity suppliers to produce or purchase a 

minimum quantity or percentage of their generation supply 

from renewable resources. RPS purchase obligations generally increase over time, and retail suppliers typically must 

demonstrate compliance on an annual basis. Mandatory RPS 

policies are backed by various types of compliance enforcement mechanisms, although most states have incorporated 

some type of cost-containment provision, such as a cost cap 

or a cap on retail rate impacts, which could conceivably 

allow utilities to avoid (full) compliance with an RPS target.

Currently, 27 states and the District of Columbia have mandatory RPS requirements. Within the 11 states of the contiguous western United States all but three (Idaho, Utah, and 

Wyoming) now have a mandatory RPS legislation (Utah has 

a voluntary renewable energy goal), covering almost 80% 

of retail electricity sales in the region. Although many of 

these state policies have only recently been established, the 

impact is already evident: almost 1,800 MW of new renewable capacity has been installed in Western states following 

the implementation of RPS policies. To date, wind energy 

has been the primary beneficiary of state RPS policies, 

representing approximately 83% of RPS-driven renewable 

capacity growth in the West through 2007. Geothermal 

energy occupies a distant second place, providing 7% of 

RPS-driven new renewable capacity in the West since the 

late 1990s, though geothermal’s contribution on an energy 

(MWh) basis is higher because the nameplate capacity of a 

generator (essentially its maximum instantaneous output) 

is expressed in units of megawatts, while the amount of 

energy produced by a generator over some period of time is 

expressed in megawatt-hours.

Looking to the future, a sizable quantity of renewable capacity beyond pre-RPS levels will be needed to meet state RPS 

mandates: about 25,000 MW by 2025 within the Western 

United States (Figure 1). Geothermal energy is beginning 

to provide an increasingly significant contribution, as evidenced by the spate of new projects recently announced to 

meet state RPS requirements. Most of this activity has been 

driven by RPS policies in California and Nevada, where 

the Geothermal Energy Association has identified 47 new 

geothermal projects, in various stages of development, totaling more than 2,100 MW.1

 Additional geothermal projects 

in Arizona, New Mexico, Oregon, and Washington are also 

under development to meet those states’ RPS requirements.

Integrated Resource Planning 

The other major state policy driver for renewable electricity growth, particularly in the West, is IRP. (IRP is also 

alternatively referred to as least-cost planning, long-term 

procurement planning, and default supply resource procurement planning). IRP was first formalized as a practice 

in the 1980s, but the practice was suspended in some states 

as electricity restructuring efforts began. A renewed interest in IRP has emerged in the past several years with three 

Figure 1. New renewable capacity needed by 2025 to meet western RPS 

requirements (beyond pre-RPS levels).

Nameplate Capacity (MW)

Montana

Nevada

New Mexico 

Colorado

Oregon

Washington

Arizona

California

0 2,000 4,000 6,000 8,000 10,000
28

Geothermal Tomorrow 2008

western states (California, Montana, and New Mexico) reestablishing IRP. Other states are developing new rules to 

strengthen their existing processes.

In its barest form, IRP simply requires that utilities periodically submit long-term resource procurement plans in 

which they evaluate alternative strategies for meeting their 

resource needs over the following 10 to 20 years. However, 

many states have developed specific requirements for the 

IRP process that directly or indirectly support renewable 

energy. The most general of these is an explicit requirement 

that utilities evaluate renewables, and that they do so on an 

equivalent or comparable basis to conventional supply-side 

generation options. Many states also require that utilities 

include various types of risk analyses within their IRP. For 

example, utilities are often required to evaluate fuel price 

risk within their resource plan, which can reveal the value 

of renewables as a hedge against rising fuel prices.

Of particular importance for supporting renewable energy 

is the increasingly common requirement that utilities evaluate the potential costs and risks associated with future 

greenhouse gas regulations. Virtually all of the major western utilities that prepare IRPs incorporated future carbon 

dioxide regulations in their analyses of alternative resource 

strategies in their most recent resource plans. Some state 

public utility commissions (California, New Mexico, and 

Oregon) have even specified particular carbon dioxide emission allowance prices utilities are required to include in their 

analyses, or have established other requirements related to 

how utilities undertake analysis of carbon regulation risk.

The impact of IRP on renewable energy development is 

most apparent in states without an RPS, where the IRP 

process has often led directly to procurement or construction of new renewables. For example, in its 2004 

IRP, Idaho Power selected a preferred resource portfolio 

containing new geothermal resources, and subsequently 

issued a Request for Proposals for 100 MW of geothermal 

energy that has since culminated in the signing of at least 

one power purchase agreement (for the output from a 

new geothermal unit at the 

Raft River Project in Idaho). 

Similarly, many of the Washington and Oregon utilities 

were actively procuring new 

renewable resources prior 

to enactment of those states’ 

recent RPS laws, in part as a 

result of IRP. Even in states 

with an RPS, IRP has played 

an important role in supporting renewables development, 

in some cases leading utilities to pursue greater levels 

of renewables than is strictly 

required for compliance with 

the RPS. For example, in 

its most recent IRP, Public 

Service Company of Colorado opted for a resource portfolio—including 20 MW of new geothermal power—that 

far exceeded the quantity of renewables needed to meet the 

state’s RPS requirements. 

Conclusion 

Together, state RPS policies and IRP requirements are creating strong demand for new renewable electricity generation capacity, which is driving the development of new geothermal resources in the Western United States. Both types 

of policies are relatively stable and are therefore likely to 

continue to support new renewable electricity generation 

for the foreseeable future. The extent to which geothermal 

energy ultimately benefits from these policies will depend 

largely on how well it can compete against other renewable 

resource options.

References

1. “Developing Plants in the U.S.” The Geothermal Energy Association online 

http:www.geo-energy.org/information/developing.asp. 

Renewable Portfolio Standards by state.

ME: 40% by 2017

WI: 10% by 2015

NV: 20% by 2015

TX: 5,880 MW by 2015

PA: 8.5% by 2020

NJ: 22.5% by 2021 CT: 23% by 2020

MA: 4% by 2009 +1%/yr

NM: 20% by 2020 (IOUs) 

10% by 2020 (co-ops)

CA: 20% by 2010

MN: 25% by 2025

Xcel: 30% by 2020

IA: 105 MW by 1999

DC: 11% by 2022

RI: 16% by 2019

HI: 20% by 2020

AZ: 15% by 2025

NY: 24% by 2013

CO: 20% by 2020 (IOUs) 

10% by 2020 (co-ops and munis)

MT: 15% by 2015

DE: 20% by 2019

MD: 20% by 2022

WA: 15% by 2020

NH: 23.8% by 2025

OR: 25% by 2025 (large utilities)

5-10% by 2025 (smaller utilities)

NC: 12.5% by 2021 (IOUs)

10% by 2018 (co-ops and munis)

IL: 25% by 2025

Mandatory RPS

VT: 20% by 2017

ND: 10% by 2015

MO: 11% by 2020 VA: 12% by 2022

OH: 12.5% by 2024

SD: 10% by 2015

UT: 20% by 2025

Non-Binding

Berkeley Lab
Contributors

Roger D. Aines H

Lawrence Livermore National Laboratory

Cynthia E. Atkins-Duffin 

Lawrence Livermore National Laboratory

Galen Barbose

Lawrence Berkeley National Laboratory

Mark Bolinger

Lawrence Berkeley National Laboratory

Bill Foxall

Lawrence Livermore National Laboratory

David Hicks

National Renewable Energy Laboratory

Nalu Kaahaaina

Lawrence Livermore National Laboratory

Greg Mines

Idaho National Laboratory

Guy Nelson

Utility Geothermal Working Group 

Jihan Quail

Sentech, Inc.

Jeffery J. Roberts

Lawrence Livermore National Laboratory

Curt Robinson, Ph.D.

Geothermal Resources Council

Charles Visser

National Renewable Energy Laboratory

Ed Wall

U.S. Department of Energy

Ryan Wiser

Lawrence Berkeley National Laboratory

John J. Zucca

Lawrence Livermore National Laboratory
Produced for the

1000 Independence Avenue, SW, Washington, DC 20585

By the National Renewable Energy Laboratory,

a DOE National laboratory

DOE/GO-102008-2633

September 2008

Printed with renewable-source ink on paper containing at least 

50% wastepaper, including 20% postconsumer waste

A Strong Energy Portfolio for a Strong America 

Energy efficiency and clean, renewable energy will mean 

a stronger economy, a cleaner environment, and greater 

energy independence for America. Working with a wide array 

of state, community, industry, and university partners, the 

U.S. Department of Energy’s Office of Energy Efficiency and 

Renewable Energy invests in a diverse portfolio of energy 

technologies. 

Produced for the

1000 Independence Avenue, SW, Washington, DC 20585

By the National Renewable Energy Laboratory,

a DOE National laboratory

DOE/GO-102008-2633

September 2008

Printed with renewable-source ink on paper containing at least 

50% wastepaper, including 20% postconsumer waste

A Strong Energy Portfolio for a Strong America 

Energy efficiency and clean, renewable energy will mean 

a stronger economy, a cleaner environment, and greater 

energy independence for America. Working with a wide array 

of state, community, industry, and university partners, the 

U.S. Department of Energy’s Office of Energy Efficiency and 

Renewable Energy invests in a diverse portfolio of energy 

technologies.