Renewable Energy: Increased Geothermal Development Will Depend on Overcoming Many Challenges
Published: 2006-05-24T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: The Energy Policy Act of 2005 (Act) contains provisions that address a variety of challenges that face the geothermal industry, including the high risk and uncertainty of developing geothermal power plants, lack of sufficient transmission capacity, and delays in federal leasing. Among the provisions are means to simplify federal royalties on geothermal resources while overall collecting the same level of royalty revenue. The Act also changes how these royalties are to be shared with local governments (disbursements). This report describes: (1) the current extent of and potential for geothermal development; (2) challenges faced by developers of geothermal resources; (3) federal, state, and local government actions to address these challenges; and (4) how provisions of the Act are likely to affect federal geothermal royalty disbursement and collections.
section_title: What GAO Found
paragraphs: Geothermal resources currently produce about 0.3 percent of our nation's total electricity and heating needs and supply heat and hot water to about 2,300 direct use businesses, such as district heating systems, fish farms, greenhouses, food-drying plants, spas, and resorts. Recent assessments conclude that future electricity production from geothermal resources could increase by 25 to 367 percent by 2017. The potential for additional direct use businesses is largely unknown because the lower temperature geothermal resources that they exploit are abundant and commercial applications are diverse. One study has identified at least 400 undeveloped wells and hot springs that have the potential for development. In addition, the sales of geothermal heat pumps are increasing. Developers of geothermal electricity plants face many challenges including a capital intensive and risky business environment, developing technology, insufficient transmission capacity, lengthy federal review processes for approving permits and applications, and a complex federal royalty system. Direct use businesses face unique business challenges, remote locations, water rights issues, and high federal royalties. The Act addresses many of these challenges through tax credits for geothermal production, new authorities for the Federal Energy Regulatory Commission, and measures that streamline federal leasing and that simplify federal royalties, which totaled $12.3 million in 2005. In addition, the Department of Energy and the state of California provide grants for addressing technology challenges. Furthermore, some state governments offer financial incentives, including investment tax credits, property tax exclusions, sales tax exemptions, and mandates that certain percentages of the electricity within the state be generated from renewable resources. Under the Act, federal royalty disbursement will significantly change because half of the federal government's share will now go to the counties where leases are located. Although the Act directs the Secretary of the Interior to seek to maintain the same level of royalty collections, GAO's analysis suggests this will be difficult because changing electricity prices could significantly affect royalty revenues. Also, MMS does not collect sales data that are necessary to monitor these royalty collections.

section_title: Letter
paragraphs: American families and businesses rely heavily on electricity and natural gas  to heat and light homes and buildings, to power appliances, to manufacture  goods, and to supply services. Increasing demand and rising prices for  electricity and natural gas have increased interest in alternative forms of  energy, including geothermal energy. Geothermal energy is a unique type of  renewable resource in that it can provide power that is independent of  weather and climate, thereby enabling a consistent and uninterrupted  supply of heat and electricity. Geothermal energy also creates fewer  environmental impacts than the production of natural gas and other  conventional fossil fuels that are used to generate electricity. Because  many areas that have the potential to produce additional geothermal  energy are located on federal lands, the federal government is a major  participant in the future development of geothermal energy.
Geothermal energy is literally the heat of the earth. This heat is abnormally  high where hot and molten rocks exist at shallow depths below the earth’s  surface. Water, brines, and steam circulating within these hot rocks are  collectively referred to as geothermal resources. Geothermal resources  often rise to the surface naturally along fractures to form hot springs,  geysers, and fumaroles. For centuries, people have used naturally  occurring hot springs as places to bathe, swim, and relax. More recently,  some individuals have constructed buildings over these springs,  transforming them into elaborate spas and resorts, thereby establishing the  first direct use of geothermal resources for business purposes. Businesses  have also established other direct uses of geothermal resources by drilling  wells into the earth to tap the hot water for heating buildings, drying food,  raising fish, and growing plants. Where the earth’s temperature is not high  enough to supply businesses with geothermal resources for direct use,  people have made use of the ground’s heat by installing geothermal heat  pumps. Geothermal heat pumps consist of a heat exchanger and a loop of  pipe extending into the ground to draw on the relatively constant  temperature there for heat in the winter and air conditioning in the  summer.
Geothermal resources can also generate electricity, and this is their most  economically valuable use today. Only the highest temperature geothermal  resources, generally above 200 degrees Fahrenheit, are suitable for  electricity generation. When companies are satisfied that sufficient  quantities of geothermal resources are present below the surface at a  specific location, they will drill wells to bring the geothermal fluids and  steam to the surface. Upon reaching the surface, steam separates from the  fluids as their pressure drops, and the steam is used to spin the blades of a  turbine that generates electricity. The electricity is then sold to utilities in a  manner similar to sales of electricity generated by hydroelectric, coal-fired,  and gas-fired power plants.
Geothermal resources are found throughout the world. In the United  States, geothermal resources are concentrated in Alaska, Hawaii, and the  western half of the country, primarily on public lands managed by the  Bureau of Land Management (BLM). The Congress set forth procedures in  the Geothermal Steam Act of 1970 for leasing these public lands,  developing the geothermal resources, and collecting federal royalties.  Today, BLM leases these lands and sets the royalty rate, and the Minerals  Management Service (MMS)—another agency within the Department of the  Interior (DOI)—collects the federal geothermal royalties and disburses to  the state governments its share of these royalties as required by law. In  2005, the most recent year for which data are available, MMS collected  $12.3 million in geothermal royalties, almost all of which was derived from  the production of electricity.
Since 1970, determining the amount of royalty payments has become  increasingly complex due to restructuring in the geothermal industry and  changing economic conditions. Government and industry representatives  formed a task force in late 2004 to devise a simpler royalty system that  would address these changes. During deliberations on the Energy Policy  Act of 2005 (Act), we briefed you on the findings of this task force and on  challenges facing geothermal development. Shortly thereafter, the  Congress passed the Act, which contains provisions to simplify the federal  royalties on electricity generation and reduce royalties on direct use. The  Act also contains other provisions designed to encourage the development  of geothermal resources. This report formalizes the content of our briefings  and our work since then, including: (1) the current extent of and potential  for geothermal development; (2) challenges faced by developers of  geothermal resources; (3) federal, state, and local government actions to  address these challenges; and (4) how provisions of the Act are likely to  affect federal geothermal royalty disbursements and collections.
In responding to these objectives, we reviewed key studies on the extent  and potential of geothermal development and interviewed BLM and  industry officials in California, Nevada, and Utah. To identify the challenges  facing geothermal developers and to assess actions taken by federal, state,  and local governments, we interviewed a variety of government and  industry officials, reviewed substantial supporting documentation and the  Act, and toured geothermal electricity plants in California and Nevada and  direct use facilities in Idaho, Nevada, and Oregon. To assess how provisions  within the Act will affect federal geothermal royalties, we interviewed MMS  and BLM employees; reviewed a report authored by the Royalty Policy  Committee; and analyzed geothermal royalty, production, and sales data  from January 2000 through December 2004. We performed our work  between May 2005 and May 2006 in accordance with generally accepted  government auditing standards. A more detailed description of our  objectives, scope, and methodology is provided in appendix I.
subsections: section_title: Background
paragraphs: The temperature of geothermal resources generally dictates their use. Low  temperatures from 40 to 70 degrees Fahrenheit (F) that occur in the ground  at shallow depths are best used for geothermal heat pumps. Geothermal  heat pumps, also known as ground-source heat pumps, are devices that  take advantage of the relatively constant temperature immediately beneath  the earth’s surface to provide heat in the winter and air conditioning in the  summer. During the winter, a heat pump transfers the heat of the ground to  a fluid filled set of coils and then pumps this fluid to the building. A heat  exchanger then transfers the heat to another set of coils filled with a  refrigerant that boils. The resulting gas is then compressed and pumped to  a condenser, where it gives up its heat as a fan blows over the condenser  coils. During the summer, heat pumps work in reverse, extracting heat  from the building and transferring it to the ground. Although heat pumps  run on electricity, they produce three to four times the energy that they  consume. As a result, they can reduce energy consumption by 20 to 70  percent relative to conventional electrical heating and cooling systems.  They also can produce hot water for free during the summer and for about  half price during the winter.
Direct use applications begin with geothermal resources that have  temperatures as low as 70 degrees F and can include geothermal resources  as hot as 300 degrees F. Geothermal waters can be mixed with groundwater  or surface water to achieve the most desirable temperature for the specific  application. Geothermal waters with temperatures between about 70 and  125 degrees F are best used in spas and resorts for recreational swimming  and bathing, in aquaculture operations for raising fish and other aquatic  animals (fig. 1), and within sidewalks and roads for melting snow.  Geothermal resources between about 125 and 300 degrees F can be used  for various applications, each of which has optimal temperature ranges.  Specific applications include food processing; fruit and vegetable drying;  space and district heating; raising flowers, plants, and trees in greenhouses;  processing pulp and paper; drying lumber, cement, and aggregate; curing  concrete blocks; pasteurizing milk; dyeing fabric; making ice; and providing  refrigeration.
Electricity generation requires geothermal resources of at least 200 degrees  F, with higher generation capacity coming from temperatures above 350  degrees F. Geothermal power plants extract geothermal fluids—hot water,  brines, and steam—from the earth by drilling wells to depths of up to  10,000 feet (fig. 2). The geothermal resources are then used, in lieu of  running water or the burning of fossil fuels, to produce a vapor that turns  the blades of a turbine that spins a generator to produce electricity.  Geothermal resources with temperatures from about 200 to 350 degrees F  are best suited for binary power plants. In a binary plant, the geothermal  fluids are passed through a heat exchanger to heat a secondary fluid, like  isopentane, that vaporizes at a lower temperature than water and spins the  power-producing turbines. The fluid is then condensed back into a gas and  recycled, and the geothermal resources are injected back into the reservoir.  When geothermal resources have temperatures over about 350 degrees F,  flash plants are most appropriate. In flash power plants, highly pressurized  hot water is brought to the surface, where the pressure decreases and part  of the water explosively boils, or “flashes,” into steam. The steam is then  separated from the remaining hot water and used to turn the turbines.  Residual water is injected back into the reservoir. In some rare geothermal  systems with temperatures above 455 degrees F, as at an area known as  The Geysers Geothermal Field (The Geysers) in northern California, the  geothermal resources may consist entirely of steam within the reservoir.  Dry steam power plants use the steam directly to spin the turbines.  Although some of the steam condenses back to water that can be injected  back into the reservoir, much water is lost to evaporation in this process.  Flash and binary power plants can also be combined in sequence for the  most efficient generation of electricity. In these hybrid power plants, hot  water is first flashed within a flash plant and then the steam is condensed,  combined with the lower temperature water, and routed to a binary plant  for further generation of electricity.
The leasing of federal lands for geothermal resources is governed by the  Geothermal Steam Act of 1970, as amended. To explore and develop  geothermal resources on federal lands, developers must first obtain a  federal lease from BLM. The lease is a contract between the federal  government and the lessee that specifies certain terms for development  and payment of rents and royalties. Regardless of the federal agency  managing the lands where the geothermal resources are located, BLM has  responsibility for issuing these leases after obtaining concurrence from the  federal land managing agency. Before passage of the Act, BLM designated  certain areas that it believed to have a reasonable potential for the  commercial development of geothermal resources as “known geothermal  resource areas (KGRA).” Within a KGRA, BLM was required to lease lands  to the highest qualified bidder under a formal competitive bidding process,  as long as the highest bid equaled or exceeded fair market value. For land  outside of a KGRA, BLM was required to issue a lease noncompetitively to  the first qualified buyer applying for the lease. Under provisions of the Act,  BLM no longer establishes KRGAs, but instead accepts nominations from  parties interested in leasing available lands and holds a competitive auction  at least once every 2 years. If bids are not received for lands offered in the  sale, the Secretary is to make them available for 2 years for noncompetitive  leasing. BLM issues geothermal leases for 10 years and requires lessees to  pay an annual rental of at least $1 per acre until commercial production is  established. Thereafter, lessees pay a royalty from 10 to 15 percent of the  value of production.
BLM will not issue federal geothermal leases until the federal land  management agency completes an extensive environmental review  process. The leasing and development of these lands must be consistent  with the management objectives for the lands as documented in the  appropriate resource or forest management plan. Should these plans not  adequately address exploration and development of geothermal resources,  the appropriate agency personnel may need to amend or rewrite the plans.  Prior to leasing, agency officials must also comply with provisions of the  National Environmental Policy Act of 1969, as amended (NEPA). NEPA  requires federal agencies to prepare an environmental impact statement  (EIS) for major federal actions that may have a significant affect on the  quality of the human environment. When an agency is not sure whether an  activity will have significant impact on the environment, the agency  prepares a less detailed environmental assessment (EA). If an EA  determines that the activity will significantly affect the environment, the  agency then prepares an EIS. During these analyses, agency personnel  analyze potential impacts of geothermal leasing to various resources such  as air and water quality, vegetation, wildlife, threatened and endangered  species, and visual and cultural resources. In California, state laws also  require a similar environmental review. Agency personnel may also need to  comply with provisions of other federal legislation, such as the Endangered  Species Act of 1973, as amended, and the National Historic Preservation  Act, as amended.
Under the Geothermal Steam Act of 1970, as amended, calculating  geothermal royalties was relatively simple because the developers of the  geothermal fields sold steam and hot water to power plants, establishing a  sales price upon which royalties could be based. The statutory royalty rate  specified in the lease, which was from 10 to 15 percent, was multiplied by  the sales value of the geothermal resource each month to yield royalties  due. In the 1980s, the developers sold the fields to the power plants, and  this basis for valuing the geothermal resource was lost. In 1991, MMS  issued new regulations that were in effect until passage of the Act. These  regulations established the value of the geothermal resource based on the  value of the electricity sold. The regulations called for subtracting, or  “netting back” from the electricity’s sales revenues, the costs of generation  and transmission. Formulas for netting back these costs were complex due  to different methods of accounting for depreciation, uncertainty over  which costs qualified for deduction, and commingling of federal and  nonfederal resources. The Act contains provisions aimed at simplifying this  process by allowing lessees the option on existing leases to pay royalties  based on a percentage of gross sales revenue and by prescribing a set  schedule of royalty rates for future leases. In addition, royalties due on  direct use facilities prior to passage of the Act were based on the price of  natural gas, which has risen substantially in recent years, making the direct  use of federal geothermal resources unattractive. The Act provides for  replacing this system of direct use royalties with a schedule of fees that  encourages the development of geothermal resources.
section_title: Current Geothermal Development Is Limited, and Estimated Potential for Additional Development Varies
paragraphs: Electricity generated from geothermal resources is small, about 0.3 percent  of the total electricity produced in the United States, with about half of this  amount coming from federal resources. Recent estimates of the potential  for additional electricity generated from geothermal resources vary from  an increase of about 25 percent by 2015 to 367 percent by 2017. There were  over 2,300 businesses and heating districts that used geothermal resources  for heat and hot water in the United States in 2005, with only two  businesses using federal geothermal resources. The total potential for  direct use applications is largely unknown because of the widespread  occurrence of lower temperature geothermal resources and the many  diverse applications.
subsections: section_title: Electricity Generation from Geothermal Resources Is Small and Relies on Federal Resources
paragraphs: Geothermal resources currently produce about 0.3 percent of the annual  electricity in the United States, or 2,534 megawatts—enough electricity to  supply 2.5 million homes. Even though the percentage of electricity  generated from geothermal resources is small nationwide, it is locally  important. For example, geothermal resources provide about 25 percent of  the Island of Hawaii’s electricity, 5 percent of California’s electricity, and 9  percent of northern Nevada’s electricity. As of January 2006, companies  were constructing geothermal power plants in California, Nevada, and  Idaho that collectively will produce another 390 megawatts of electricity.
Table 1 shows the number, location, and capacity of geothermal power  plants that currently produce electricity or are under construction.
Over half of the nation’s electricity generated from geothermal resources,  about 1,275 megawatts, comes from geothermal resources located on  federal lands. Of the 54 geothermal power plants, 26 are located on federal  lands managed by BLM, and 28 are located on private or state lands. As of  January 2006, there were 50 federal geothermal leases from which  electricity was produced—48 on BLM lands, and 2 on Forest Service lands.  Twelve of these leases are located in The Geysers in northern California,  and they account for over one-third of the electricity produced from federal  geothermal resources. The other 44 producing federal geothermal leases  are located in and near the Sierra Nevada Mountains of eastern California,  near the Salton Sea in the southern California desert, in southwestern Utah,  and scattered throughout Nevada.
section_title: Estimates of the Potential for Additional Electricity Generation from Geothermal Resources Vary Widely
paragraphs: Industry and government estimates of the potential for electricity  generation from geothermal resources vary widely, due to differences in  the date by which forecasters believe the electricity will be generated, the  methodology used to make the forecast, assumptions about electricity  prices, and the emphasis placed on different factors that can affect  electricity generation. Five estimates published since 1999 indicate that the  potential for electrical generation from known geothermal resources over  the next 9 to 11 years is from about 3,100 to almost 12,000 megawatts. By  2025, two of these sources estimate that electrical generation from these  known resources will increase to between 6,800 and 13,000 megawatts. The  difference in estimates could also be due to the different methodologies  used to make the forecasts, such as surveys of experts in the geothermal  industry and/or detailed economic modeling. Placing different emphasis on  geothermal development costs, electricity prices, natural gas prices, and/or  reservoir characteristics also probably led to differences in the estimates.  Table 2 summarizes the estimates of potential electricity generation from  geothermal resources.
A detailed comprehensive study of electricity generation from all  geothermal resources in the United States has not been undertaken since  1978, when the U.S. Geological Survey (USGS) published Circular 790,  “Assessment of Geothermal Resources of the United States—1978.” This  assessment, based on the amount of thermal energy in place, estimated that  known geothermal resources could generate 23,000 megawatts if all of  them were developed, significantly more than that estimated by the five  other studies. The other five estimates in table 2 differ from the USGS  estimate in that they attempt to estimate how much electricity could be  economically produced from known resources, given competing  commercial sources of electricity, and they are based on more extensive  reservoir, production, and economic data. In addition, none of the five  estimates include undiscovered resources; the USGS estimated that  undiscovered resources could generate an additional 72,000 to 127,000  megawatts.
section_title: Direct Use Applications Are Numerous and Diverse, and Few Are Located on Federal Land
paragraphs: Over 2,300 businesses and heating districts in 21 states used geothermal  resources directly for heat and hot water in 2005. About 85 percent of these  users are employing geothermal resources to heat homes, businesses, and  government buildings (table 3). While most users heat one or several  buildings, some users have formally organized heating districts that pipe  hot water from geothermal wells to a central facility that then distributes it  to heat many buildings more economically than other available sources of  energy. The largest concentration of geothermal heating districts occurs in  Boise, Idaho, where four heating districts distribute geothermal waters to  over 50 buildings, including the Capitol and City Hall (fig. 3). Geothermal  heating districts supply heat to about 20 commercial and government  buildings in Klamath Falls, Oregon, and to 400 homes in Reno, Nevada. The  next most plentiful direct use applications are resorts and spas, accounting  for over 10 percent of sites. About 244 geothermal resorts and spas offer  relaxation and therapeutic treatments to customers in 19 states. Spas and  resorts can be as primitive as an unsheltered hot spring in the backcountry  to an elaborate resort with multiple soaking pools, an Olympic-sized  swimming pool, a 100-room hotel, and gourmet restaurants. Two percent of  geothermal direct use applications consist of heated greenhouses in which  flowers, bedding plants, and trees are grown. Idaho leads the nation with  the most geothermally heated greenhouses—13, and New Mexico leads the  nation with the largest geothermally heated greenhouse—covering 32  acres. Another 2 percent of geothermal direct use applications are for  aquaculture operations that heat water for raising aquarium fishes for pet  shops; catfish, tilapia, freshwater shrimp and crayfish for human  consumption; and alligators for leather products and food (fig. 4). Other  direct use geothermal applications include dehydrating vegetables, like  onions and garlic, and melting snow on city streets and sidewalks.  Geothermal direct use applications are summarized in table 3.
Nearly all direct use businesses and heating districts are currently located  on private lands. Only two direct use businesses that use federal  geothermal resources are currently in operation. One of these businesses,  located at Honey Lake in northern California, uses geothermal resources to  preheat a boiler in which biomass is burned to create electricity. Four  additional businesses—a nursery, a food processing plant, and two mines— have also used federal resources at one time in direct use applications. A  nursery in New Mexico used federal geothermal resources for heating  greenhouses, but the owner reported that he stopped using the federal  geothermal resources because he considered the federal royalties to be  excessive. Two gold and silver mines also used geothermal waters from  BLM lands in Nevada to enhance their cyanide heap leeching operations  but suspended these operations, due in part, to high federal royalties. The  owner of the food processing plant, which dried garlic, reported being  forced out of business by lower priced imports from China.
section_title: The Potential for Developing Additional Direct Use Is Uncertain
paragraphs: The potential for additional direct use of geothermal resources in the  United States is uncertain due to the geographically widespread nature of  low-temperature geothermal resources and the many different types of  applications. The USGS performed the first national study of low- temperature geothermal sites in 1982 and estimated the amount of heat in- place that could be available for direct use applications across the United  States. However, this study was neither specific enough to identify  individual sites for development, nor did it estimate the amount of heat that  could be recovered and converted into energy savings for homes or  businesses. In 2005, the Geo-Heat Center at the Oregon Institute of  Technology identified 2,211 geothermal wells and springs with  temperatures appropriate for direct use. The Geo-Heat Center estimated  that 404 of these wells and springs might be commercially developed  because they are within 5 miles of communities. The study estimated the  minimum amount of heat that could be produced at each site but did not  assess the economics or business climate of the various direct use  applications.
section_title: Geothermal Heat Pumps Show Increasing Use
paragraphs: Geothermal heat pumps have become a major growth segment of the  geothermal industry by making use of the earth’s warmer temperature in  the winter to heat buildings and using the earth’s cooler temperature in the  summer for air conditioning. The Geothermal Heat Pump Consortium  estimated that 1 million units were in operation in all 50 states as of  January 2006. The number of geothermal heat pumps has steadily  increased over the past 10 years. Because geothermal heat pumps are  effective where ground temperatures are between 40 and 70 degrees F, they  can be installed in almost any location in the United States and, therefore,  are the most widespread geothermal application and have the greatest  potential.
Until 1999, few geothermal heat pumps were installed in federal facilities.  The annual federal investment in geothermal heat pumps has increased  substantially since then, from $6 million in 1999 to $74 million in 2001—the  latest year for which data are available. As of November 2005, federal  facilities had installed over 25,000 individual heat pumps—over 24,000 of  them in military bases. The other 1,000 heat pumps were installed by the  Department of Housing and Urban Development, DOI, the U.S. Postal  Service, and the Environmental Protection Agency.
section_title: Geothermal Development Faces Many Challenges
paragraphs: The development of geothermal resources for electricity production faces  major challenges, including high risk and financial uncertainty, inadequate  technology, and insufficient transmission capacity. Developers of  geothermal power plants face additional challenges when operating on  federal lands. These challenges include: (1) a lengthy review process for  the approval of leases and permits,(2) insufficient resources at BLM to  conduct the necessary reviews, (3) different priorities between the BLM  and the Forest Service when lands under their jurisdiction occur within a  project area, (4) fragmented lease holdings that make it difficult to develop  an economically viable project, and (5) a complex federal royalty system.  Developers of geothermal resources for direct uses also face a variety of  other business challenges, remote locations, water rights issues, and higher  federal royalties over the past few years. The recently passed Act addresses  some of these challenges and is discussed in the next section of this report.
subsections: section_title: Geothermal Power Plants Face High Risk, Financial Uncertainty, and Technological Impediments
paragraphs: Geothermal development for the production of electricity is a risky,  expensive, and lengthy process. Geothermal groups reported that most  attempts to develop geothermal resources are unsuccessful, that costs to  develop geothermal power plants can surpass $100 million, and it can take  3 to 5 years for plants to first produce and sell electricity. The development  of geothermal resources for electricity generation follows a series of  phases, starting with finding the geothermal resources through exploration,  then confirming the magnitude and extent of the resource, and ending with  full field development and power plant installation. Although some  resources are easy to find because they produce telltale signs such as hot  springs or fumaroles, most resources are buried deep within the earth—at  depths sometimes exceeding 10,000 feet—and finding them often requires  an in-depth knowledge of the area’s geology, geophysical surveys, remote  sensing techniques, and at least one test well. The Geothermal Energy  Association estimates that average wells cost from $2 million to $5 million  and that only about 25 percent of the initial test wells are successful in  finding commercial geothermal fields. Companies must then drill  additional wells to assess the extent, temperature, pressure, and  productivity of the reservoir, thereby allowing companies to confirm the  magnitude and extent of the resource and decide whether it is  economically viable. Estimates of failure rates for wells drilled during this  phase run as high as 60 percent. According to the Geothermal Energy  Association, developers typically spend about 10 percent of the total cost  for this phase. It costs $75 million to develop a typical 25 megawatt power  plant. Such a plant can produce enough electricity for 19,000 homes. The  drilling of additional wells to produce and manage the reservoir, installing  the power plant, and connecting the wells to the plant with pipes generally  account for another 23 percent, 54 percent, and 7 percent of the total costs  of the plant, respectively. In addition, operating and maintenance costs for  a plant of this size could be about another $5 million per year.
The risks and high initial costs associated with geothermal development  limit financing and make financing more difficult. Energy consultants told  us that few companies, including venture capitalists, are willing to provide  funding for geothermal projects, particularly for the initial phases of  exploration and confirmation. Industry officials who do provide funding for  geothermal development told us that they would only fund projects that are  either fully confirmed or are in areas of well-known geothermal potential.  Even when fully confirmed, moreover, few lenders will finance a  geothermal project until a contract has been signed by a utility or energy  marketer to purchase the expected electricity. Geothermal industry  officials describe the process of securing a contract as complicated and  costly, especially for small geothermal developers who are generally  unfamiliar with the various bidding mechanisms that utilities use to  establish electricity prices. Officials with a large utility expressed their  reluctance to purchase more costly electricity from geothermal plants and  cited an inability to pass on the additional cost to ratepayers. Electricity  from geothermal resources may also be unavailable during time frames  specified by the contract because of delays due to environmental litigation  or lack of available transmission. In addition, an energy consultant told us  that most utilities are unfamiliar with geothermal resources, and they are  unlikely to invest the necessary time to assess geothermal projects because  geothermal electricity would make up a small percentage of their total  energy portfolio.
Inadequate technology adds to the high costs and risky nature of  geothermal development. Since geothermal systems are geologically more  complex than oil and gas systems, exploration tools commonly used in the  oil and gas industry, such as geophysical surveys, are less effective. In  general, geothermal reservoirs are located in very hard and fractured rocks  that make drilling difficult. Operators often experience difficulty in drilling  because drill bits wear quickly and because the medium used to lubricate  the borehole and remove rock fragments, called drilling fluid, is commonly  lost into the many fractures in the rock. Compared with oil and gas wells,  the temperatures encountered when drilling are considerably higher and  the geothermal resources are more corrosive, resulting in corrosion of  drilling equipment and production casing and the failure of electronic  components. Geothermal wells are also larger in diameter than oil and gas  wells drilled to the same depth, which drives up drilling costs. The recent  boom in oil and gas drilling has added to the scarcity and higher costs for  drilling rigs and equipment.
section_title: Lack of Adequate Electrical Transmission Hinders Geothermal Development
paragraphs: Lack of available transmission creates a significant impediment to the  development of geothermal resources for electricity production. To send  electricity produced at geothermal power plants to utilities, geothermal  companies often need to construct new transmission lines from their plant  to existing lines. In the West, however, many geothermal resources are  located far from existing transmission lines, making the construction of  additional lines economically prohibitive, according to federal, state, and  industry officials. For example, there are no significant transmission lines  between the geothermal resources in northern Nevada and the populated  area of Las Vegas in southern Nevada. In California, there is a need for new  or upgraded transmission to access renewable resources in Nevada and in  the Imperial Valley of southern California, which has significant geothermal  potential. Even when geothermal resources are near major transmission  lines or developers can fund the construction of an additional transmission  line, adequate transmission capacity may still be unavailable. Many existing  transmission lines are operating at or near capacity and may not be able to  transmit electricity without significant upgrades.
Paramount among transmission concerns is who will pay for the needed  transmission capacity. Transmission costs can be very large. In Nevada, a  BLM official told us that transmission lines there cost over $500,000 per  mile. The California Energy Commission said in a June 2005 report that  new transmission lines with interconnections cost between $375,000 and  $3.3 million per mile for single circuit lines, depending on their voltage. In  the summer of 2005, FERC denied a request from a utility to pass the costs  for transmission lines on to ratepayers. According to utility officials, this  reaffirms that developers must pay for the costs since utilities will not  voluntarily absorb the costs directly. Under current rules, when a developer  requests new transmission capacity, the bulk of the costs are assigned to  the project that first pushes the transmission system beyond its existing  capacity. In addition, federal, state, and industry officials note that small  geothermal plants are discouraged from connecting to these large  transmission lines because utilities do not want to bother with the small  amounts of electricity unless there are many of them in the same area.
Cumbersome planning and permitting processes have hindered the  addition of necessary transmission capacity. In a July 2005 report, a  consultant for the Edison Electric Institute noted that nationally the task of  getting a transmission project planned, approved, permitted, and financed  remained daunting. The authors stated that the investment climate for  transmission remained fragmented by different procedures, incentives, and  constraints from one region of the country to another. The California  Energy Commission noted in a November 2005 report that the state’s  inefficient transmission planning and permitting processes were  contributing to worsening the state’s transmission problems. Addressing  the same issue, an official of a large California utility told us that obtaining  agreement on where to construct transmission lines, addressing  environmental issues, obtaining approvals, and a “not in my backyard”  philosophy, contributed to the uncertainty and long lead times in building  additional transmission capacity. In addition, a geothermal developer  complained about extensive hearings and an inability to determine  jurisdictions between the state and the federal government and between  agencies within California.
section_title: Geothermal Power Plants on Federal Lands Face Delays in Processing Applications, Fragmented Lease Holdings, and a Complex Royalty System
paragraphs: Geothermal developers state that the process for approving leases and  issuing permits to drill wells and construct power plants has become  excessively bureaucratic. BLM and Forest Service officials often have to  amend or rewrite resource or forest management plans, which can add up  to 3 years to the approval process, depending upon the complexity of the  proposal and when the last plan was written. Delays in finalizing resource  and forest management plans and in conducting environmental reviews  have resulted in a backlog of 31 lease applications in California, with an  average age of 7.4 years, and 136 lease applications in Nevada, with an  average age of about 2 years. Despite the high backlog in Nevada, BLM  officials noted that they processed 177 lease applications from January  2001 through June 2005. In contrast, during the same period, BLM did not  process any lease applications in California. Nevada BLM officials reported  that they can generally make decisions on whether to allow leasing and  development faster because the public raises fewer issues and BLM  documents its decision within a shorter document known as an EA. In  California, however, the public raises more environmental issues and  concerns involving Native American spirituality so BLM often prepares a  more detailed document called an EIS, which typically takes 2 years to  complete. While geothermal developers told us that they support  environmental analyses, they complained about the duplication of federal  and state documentation in California and of the appeals and lawsuits filed  by groups opposing the federal and state decisions, citing that it often takes  years for their resolution. The California Energy Commission reported in a  June 2005 report that the entire process from exploration to the first  production of electricity can take more than a decade and that it was not  unusual to redo environmental documents because they became outdated.
Geothermal applications, permits, and environmental reviews are also  delayed because of a lack of staff and budgetary resources at the BLM state  and field offices that conduct the necessary work. Nevada and California  BLM officials noted that lack of funding and dedicated staff to work on  lease applications was a constant problem. Lack of funding in California  has slowed completion of BLM resource management plans and EISs  necessary for lease approvals and drilling permits. BLM officials noted in  California that they received only $90,000 to conduct two extensive EISs  for which staff had requested $1.2 million while Nevada BLM received a  one-time allocation of $700,000 for processing a backlog of lease  applications and writing several less extensive EAs, which generally cost  $80,000 to $90,000 each.
Approvals for leases and permits may also be delayed when BLM must  coordinate with the Forest Service, which manages land in some project  areas. The Forest Service manages significant lands on geothermal projects  in Oregon, Washington, California, and Nevada. Although BLM is the lead  federal agency for geothermal development, the Forest Service must  concur with leasing and development, and it has its own permitting  process. BLM and industry officials report that there can be a lack of  coordination between the Forest Service and BLM because of differing  objectives and directives. While both agencies manage their lands  according to the multiple use doctrine, they may have different priorities  for land use and the public often submits more negative comments  concerning geothermal development on Forest Service lands. A Forest  Service official noted that it is important to balance the competing issue of  geothermal development with other land uses such as preservation and  recreation. He cited a limited budget for updating forest management  plans, which can lead to delays, and noted that since geothermal  development generates far less revenue than logging and coal mining on  Forest Service Lands, geothermal development receives less priority.
Companies may also encounter difficulties in developing geothermal  resources for electricity production due to a patchwork of lease ownership.  Geothermal resources within a project area may be owned by the federal  government, state government, or private entities. Even when all resources  within a project are under federal lease, several lessees with competing  interests and objectives may own these leases. Some BLM officials noted  that some developers have reported difficulty in consolidating the various  geothermal leases into an economically viable project that can recover the  costs of the power plant and transmission line. These developers,  according to these BLM officials, say that speculators often lease  geothermal resources not for development purposes but rather to resell the  leases at a significant profit, running up the cost of the project.
Geothermal developers, BLM officials, and MMS officials concur that the  complex federal royalty system in effect before passage of the Act was a  challenge to the development of geothermal electricity plants. While  developers did not consider this royalty system to be a major obstacle in  constructing a geothermal power plant, some described calculating royalty  payments as burdensome and reported expending considerable time and  expense on royalty audits. Several industry officials cited the complex  royalty system as a reason for advocating revisions to the Geothermal  Steam Act of 1970, as amended.
section_title: Direct Uses of Geothermal Resources Face Business Challenges, Remote Locations, Water Rights, and Royalty Issues
paragraphs: The small business owners, operators of heating districts, and individuals  who commonly develop geothermal resources for direct use face a variety  of business challenges. Foremost among these challenges are obtaining  capital, overcoming specific challenges unique to their industry, containing  costs, and securing a competitive advantage. While the amount of capital to  start a business that relies on geothermal resource is small compared with  the amount of capital necessary to build a geothermal power plant, this  capital can be large relative to the financial assets of the small business  owner or individual. Unforeseen problems in well construction, piping, and  water disposal can also increase original funding estimates. Obtaining  funding is difficult as commercial banks are often reluctant to loan money  for unproven projects and ideas that appear risky. Even district heating  systems that are operated by municipalities have encountered financing  difficulties as city or state legislatures may be reluctant to provide funding  or customers may be reluctant to pay for modifications that are necessary  to use geothermal resources in their current heating systems. We observed  a number of business challenges unique to various industries that the  successful owners of direct use businesses were able to overcome. They  used their extensive knowledge of their respective industries to combat  diseases in fish farms; to combat corrosive waters used in space heating;  and to control temperature, humidity, and light according to the  specifications of the various plant species they grew in nurseries.
Escalating costs also pose a challenge to direct use operations. Rising labor  costs and cheaper imports closed a food processing plant in Nevada.  Greenhouses in Idaho and Oregon remained profitable by shifting from  high-cost natural gas to cheaper geothermal resources for heating.  Successful operators of direct use businesses have secured competitive  advantages by entering specialty niches (see figs. 5 and 6). For example,  the operators of two aquaculture facilities in Idaho and Oregon sell  alligator meat, tilapia, and freshwater shrimp to restaurants. Also, a resort  operator in Alaska that relies on geothermal resources constructed and  markets an “ice museum” where guests can spend the night with interior  furnishings sculptured from ice. We noticed that some greenhouse  operators gained a marketing advantage by selling from their retail outlet  rather than selling at a lower price to wholesalers.
The remote location of many geothermal resources hampers their  development for direct use. Geothermal direct use is constrained because  the geothermal waters cannot be economically transported over long  distances without a significant loss of heat. An official with the Geo-Heat  Center noted that for space heating, spas, and resorts, the geothermal  resources should be located within 5 miles of the location where they will  be used. While some greenhouses, aquaculture operations, and food  processors that rely on geothermal resources have successfully produced  their products far from consumers, they still need access to adequate  transportation and a cheap labor market, both of which are generally  dependent on proximity to population centers. The distant location from  major population centers of geothermal resources on federal lands  contributes to their unattractiveness for direct use applications.
Obtaining water rights can be a significant challenge to direct use  development. Western states are not uniform in classifying geothermal  resources, considering them legally to be mineral, water, or having  characteristics of both minerals and water. Depending sometimes on the  depth and/or the temperature at which they occur, geothermal resources  can be subject to state water laws in the western states and are then  managed by the state agency responsible for protecting groundwater. Even  when not legally classified as water, the production of geothermal  resources for direct use applications may still fall under regulations  enforced by a state agency responsible for groundwater protection. In  areas of high groundwater use, the western states generally regulate  geothermal water according to some form of the doctrine of prior  appropriations, under which specific amounts of water are appropriated to  users in the order when they first made beneficial use of the water.  Additional amounts, if available, are appropriated in the future to  applicants on a first-come basis. Those that have more senior rights have  priority in using the water when use exceeds supply, such as during a  drought. Western states that generally follow the prior appropriations  doctrine when managing the production of geothermal water for direct use  include Utah, Idaho, Oregon, New Mexico, and Nevada. Developers of  geothermal resources for direct use would face problems obtaining  appropriations in the Snake River Basin of Idaho, which consists of much  of the state below the panhandle, because groundwater is fully  appropriated there and used predominantly for irrigation. Over half of the  state of Utah also includes areas in which geothermal resources for direct  use would be excluded or restricted due to prior appropriations, and the  state water engineers in Nevada and New Mexico may also restrict  appropriations in some areas of their states. In addition, applications for  development of geothermal resources for direct use on federal lands may  also be subject to state water laws. Unless the federal government has  reserved water rights on land in which a geothermal developer is interested  and the geothermal development fulfills the specific purpose of the federal  reservation, the development may still be subject to restrictions under state  water laws.
Developers interested in using federal geothermal resources for direct use  were concerned about high federal royalties prior to passage of the Energy  Policy Act of 2005. Royalties were computed according to a formula that  relies on the amount of heat extracted from the resource and the cost of a  reasonably available alternative form of energy. Since most inquiries into  the use of federal resources have been by operators of greenhouses, this  alternative form of energy—natural gas—has been the source generally  used to heat greenhouses. Average wellhead natural gas prices in recent  years have increased about two and a half times from $3.68 per million  British thermal units in 2000 to $9.50 in September 2005. Operators of  greenhouses have told us that heating greenhouses with natural gas is no  longer economically feasible as the costs of raising plants would exceed  the price they obtain for these plants. During meetings between BLM, MMS,  state, and industry officials, general consensus was reached that natural  gas was too expensive an energy source upon which to base royalties, and  a working group was formed to propose an alternative energy source. In  the report they drafted, the group proposed Powder River Basin coal,  which averages about 30 cents per million British thermal units—a fraction  of the price of natural gas. The report states that lower royalties on direct  use may encourage development and result in higher royalty revenues in  the long run. However, based on other challenges facing the development  of direct use applications, the lowering of federal royalties alone is unlikely  to stimulate the direct use of federal geothermal resources.
section_title: Efforts by Federal, State, and Local Governments to Address Challenges Show Promise
paragraphs: The Act includes a variety of provisions designed to help the geothermal  industry address numerous challenges, including the high risk and financial  uncertainty of developing renewable energy projects, lack of sufficient  transmission capacity, delays in federal leasing, and complex federal  royalties. Although these efforts show promise, it is too early to assess their  effectiveness. Through the Department of Energy (DOE) and the California  Energy Commission, the federal government and the state of California are  attempting to overcome technical challenges by awarding cost-share grants  for research and development. State and local governments have also made  efforts to address challenges to geothermal development. Chief among  these efforts are financial incentives, such as tax credits for production  from renewable energy sources, sales and property tax exemptions, and  mandates that certain percentages of the electricity generated within the  state come from renewable energy sources, such as geothermal resources.
subsections: section_title: Financial Incentives Are Used to Address the High Risk and Uncertainty of Geothermal Development
paragraphs: Provisions within the Act address the high risk and financial uncertainty of  producing renewable energy by providing tax credits and other incentives  for renewable energy producers, including the producers of geothermal  electricity. Starting on January 1, 2005, section 1301 of the Act extends for  10 years a tax credit on the production of electricity from geothermal  resources for already existing plants and for any new plants producing by  December 31, 2007. The credit is now 1.9 cents per kilowatt-hour and has  future adjustments for inflation. Although government and industry  officials praised this provision, they told us that for the credit to be more  effective, the date by which plants must produce electricity needs to be  extended. They explained that since it can take 3 years or longer for the  construction of geothermal electricity plants, plants probably will not  qualify unless they are ready to break ground immediately. The Act also  provides a financial incentive for tax-exempt entities that cannot take  advantage of the production tax credit. Section 1303 of the Act permits the  issuance of clean renewable energy bonds by tax-exempt entities, such as  municipalities and rural electric cooperatives, for the construction of  certain renewable energy projects, including geothermal electricity plants.  Investors can purchase the bonds, which pay back the original principal  and also provide a federal tax credit instead of an interest payment. The  Department of the Treasury will manage the issuance of these bonds and  the setting of credit rates. The total issuance of bonds cannot exceed $800  million, and the bonds are to be issued between December 31, 2005, and  December 31, 2007.
The Act also extends the federal government’s Renewable Energy  Production Incentive, which expired on September 30, 2003. This incentive  entitled eligible electric production facilities, including not-for-profit  cooperatives, public utilities, and various government entities who sell  renewable electricity, including that generated from geothermal resources,  annual financial incentive payments from the federal government.  Additionally, section 1333 of the Act makes a $300 tax credit available to  purchasers of geothermal heat pumps who place them in service in 2006  and 2007.
Another provision in the Act may decrease the uncertainty inherent in  geothermal exploration. The Act directs the Secretary of the Interior, acting  through the USGS, to update the 1978 Assessment of Geothermal  Resources made by the USGS. This assessment, published as Circular 790,  is widely considered to be out of date and in need of revision. USGS  officials reported that, since 1978, there have been significant  advancements in technology that are not reflected in Circular 790. Now,  electricity can be generated from lower temperature resources and from  resources located deeper within the earth. Today, according to USGS  officials, scientists and engineers can make more accurate resource  estimates because they are more knowledgeable of reservoir  characteristics and have benefited from the knowledge gained during the  27 years of exploration and development that has occurred since the  original study.
State governments are also offering financial incentives to the geothermal  industry by creating additional markets for their electricity through  Renewable Portfolio Standards (RPS). An RPS is a state policy directed at  electricity retailers, including utilities, that either mandates or encourages  them to provide a specific amount of electricity from renewable energy  sources, which may include geothermal resources. To date, 22 states plus  the District of Columbia have RPSs, and three other states have set RPS  targets. Requirements for the program vary by state as each RPS is unique,  and not all states have significant geothermal resources. California and  Nevada, which have large geothermal production and potential, have each  established an ambitious RPS. California law mandates that retailers must  supply 20 percent of their electrical energy from renewable energy by 2017,  and the state is currently seeking to move this date up to 2010. Nevada  requires certain percentages of its electricity to be generated from  renewable energy each year, with 20 percent by 2015. Since California and  Nevada requirements were implemented, one 20 megawatt-geothermal  plant in Nevada, which has gone on line, and geothermal developers have  signed contracts for three plants in California for as much as 260  megawatts of future geothermal power, which can be attributed to RPSs.  Nevada utilities currently are not meeting their annual RPS requirements.  Officials from two large California utilities told us that they are interested  in purchasing electricity generated from geothermal resources specifically  because of RPS and noted that the RPS may be instrumental in  constructing a new transmission line from the Imperial Valley to utilities in  southern California.
Additional state programs also provide tax credits and other financial  incentives for renewable energy development, including electricity  generation from geothermal resources. These incentives include property  tax incentives, sales tax incentives, and business tax credits. For example  in California, eligible geothermal developers can be awarded supplemental  energy payments from the state if they have a contract for electricity at  above market costs with one of California’s three investor-owner utilities.  In Nevada, state law exempts from local sales and use taxes the sale,  storage, and consumption of products or systems designed to generate  electricity from renewable resources. In Utah, the purchases of equipment  to generate electricity from renewable resources are excluded from state  sales tax. Both Nevada and Oregon do not count the value added by  renewable energy systems when assessing property taxes. Oregon also  offers a business energy tax credit of up to 35 percent of the cost of certain  renewable energy projects, including geothermal systems.
section_title: Federal and State Grants Are Addressing Technology Challenges
paragraphs: DOE and the state of California provide financial assistance and grants to  the geothermal industry in trying to overcome technical challenges. At  DOE, the Geothermal Technologies Program’s mission is to work in  partnership with U.S. industry to establish geothermal energy as an  economically competitive contributor to the U.S. energy supply. Several  goals of the program include reducing the cost of geothermal development  to 5 cents per kilowatt-hour by 2010 and increasing electrical capacity from  geothermal resources to 40,000 megawatts by 2040. The program seeks to  accomplish these goals by competitively awarding cost-shared grants to  industry for research and development. The program’s budget was $25.3  million in fiscal year 2005. In the past, program funds have been used to  pioneer new drill bits, demonstrate the large scale use of binary technology,  produce new seismic interpretation methods, commercialize geothermal  heat pumps, develop slimhole (reduced diameter) drilling for exploration,  and produce a strategy for reinjection at The Geysers. Within the program,  an initiative called GeoPowering the West provides technical and  institutional knowledge on opportunities to use geothermal resources and  on how to overcome challenges. Goals of this initiative are to increase the  number of homes using geothermal energy to 7 million by 2010 and to  double the number of states producing geothermal electricity to eight by  2006.
California provides financial and technical support for geothermal  development through grants under two programs administered by the  California Energy Commission. Under the Geothermal Resources  Development Account, grants are competitively awarded to promote  research, development, demonstration, and commercialization of  geothermal resources in California. Funding is provided from a portion of  the federal geothermal royalties disbursed to the state. The program’s costs  are shared with awardees. One noteworthy project funded by the program  was the piping of treated wastewater from Santa Rosa, California, to The  Geysers, where it was injected into the geothermal reservoir, increasing  reservoir pressure and boosting electricity production by an estimated 10  percent. For California’s fiscal year 2006, $3.9 million in funding is available  for 12 to 15 projects. The state’s Public Interest Energy Research Program  also funds awards for renewable resource projects, including geothermal  projects. Money comes from a surcharge on California residents’ electricity  bills. Of the $62 million collected by the state in 2005, $2 million was  available for geothermal projects.
section_title: Expanded FERC Authority and Planning Initiatives Are Aimed at Transmission Challenges
paragraphs: The Act may also address transmission challenges by providing FERC with  new authorities in permitting transmission facilities and in developing  incentive-based rates for electricity transmission in interstate commerce.  FERC can now approve new transmission lines in certain instances in a  “national interest electric corridor” when a state fails to issue a permit  within 1 year of a company’s filing of an application. The Act also  authorizes companies that obtain FERC permits for transmission facilities  to acquire rights of way through eminent domain proceedings. In addition,  the Act directed FERC to develop incentive-based rates for transmission of  electricity in interstate commerce to promote increased investments in  transmission. Within 1 year of passage of the Act, FERC is to issue a rule  establishing incentive based rates. In November 2005, FERC initiated the  rulemaking process for establishing these rates.
Several planning initiatives are aimed at addressing challenges to  transmission. In the West, a number of regional entities composed of state  public utility commissions, local governments, utilities, and others are  working on transmission planning. These entities include Southwest  Transmission Expansion Planning, the Northwest Transmission  Assessment Committee, and the Rocky Mountain Area Transmission Study.  Certain utilities are also being proactive. The Los Angeles Water and Power  District is proposing that the City of Los Angeles spend $240 million to help  construct or upgrade a transmission line from the Salton Sea, an area rich  in geothermal resources near the Mexican border, to the Los Angeles area.  Similarly, San Diego Gas and Electric is proposing a new transmission line  from the Imperial Valley to its service area.
section_title: Provisions within the Energy Policy Act and BLM Planning Efforts May Address Leasing and Royalty Issues
paragraphs: Provisions within the Act are aimed at streamlining or simplifying the  federal leasing system, principally by mandating competitive geothermal  lease sales every 2 years, by combining prospective federal lands into a  single lease, and by improving coordination between DOI and the  Department of Agriculture, which manages lands in the National Forest  System. Since companies can nominate tracks of federal land for sale,  some geothermal companies see the competitive sale provision as a  mechanism to jump start leasing in areas where it has stalled in recent  years. BLM officials speak positively of both this provision and the  provision that allows combining prospective lands into a single lease,  saying that these provisions make it more likely that companies with the  financial resources to develop the lands can do so. The Act also requires  the Secretary of the Interior and the Secretary of Agriculture to enter into a  memorandum of understanding that establishes an administrative  procedure for processing geothermal lease applications and that  establishes a 5-year program for leasing of Forest Service lands and  reducing its backlog of lease applications, as well as establishing a joint  data retrieval system for tracking lease and permit applications. A senior  official with the Forest Service’s Geothermal Program said that, since the  Forest Service already has a memorandum of understanding with BLM,  drafting the new memorandum should not be difficult.
The Act also contains provisions that simplify federal geothermal royalties  on resources that generate electricity and simplify and or reduce royalties  on resources put to direct use. For electricity production, the Act defines  three types of leases and provides different incentives for each. For the  first type—leases that currently produce electricity—the Act allows lessees  to negotiate a royalty rate equal to a percentage of gross sales revenues,  instead of using the significantly more complex process known as  “netback.” For the second type of lease—those that were issued prior to  the Act and will first produce electricity within 6 years following the Act’s  passage—lessees can elect for the first 4 years of production to pay 50  percent of the royalties that would have been due. For the third type of  lease—those that have not yet been issued—lessees will pay according to a  schedule in which royalties are equal to certain percentages of gross sales  revenues. In addition, the Act significantly changes royalties due in the  future on direct use applications. The Act directs the Secretary of the  Interior to establish a schedule of fees, in lieu of the current complicated  system, that encourages the development of direct use resources.
BLM’s 5-year strategic plan for its geothermal program also attempts to  address some challenges to federal leasing. The plan calls for annual  workforce planning documents to reflect the skills and staffing necessary  to implement an active geothermal program. A BLM official within the  Geothermal Program said that this provision will allow the state and field  offices to identify current budgetary needs so that they can process  geothermal applications and permits in a timely manner. The strategic plan  also calls for BLM to develop an inspection and enforcement plan, which it  currently does not have. Such a program could help in ensuring that the  federal government collects the correct royalty revenues from the sale of  electricity generated from geothermal resources.
section_title: Geothermal Royalty Disbursements Will Change Significantly, and Changes in Electricity Prices Could Alter Total Royalty Collections
paragraphs: Under provisions of the Act, geothermal royalties retained by the federal  government will be cut in half because half of the royalties that originally  were retained by the federal government will now have to be disbursed to  the counties in which the federal leases are located. Although provisions  within the Act may change the royalties due on specific types of leases, the  overall revenue impact of these provisions should be minor if electricity  prices remain relatively stable and if the Secretary of the Interior relies on  past royalty histories in determining future royalties. However, it is not  possible to predict with reasonable assurance how electricity prices will  change in the future, and price changes could significantly impact future  royalty collections if they are not accounted for in royalty calculations.
subsections: section_title: The Energy Policy Act Redistributes a Greater Portion of Federal Royalties
paragraphs: A royalty provision of the Act redistributes the federal royalties collected  from geothermal resources—cutting in half the overall geothermal  royalties previously retained by the federal government. Set by the  Geothermal Steam Act of 1970, as amended, the prior distribution provided  for 50 percent of geothermal royalties to be retained by the federal  government and the other 50 percent to be disbursed to the states in which  the federal leases are located. The Act changes this disbursement. While  the Act provided that 50 percent of federal geothermal royalties will  continue to be disbursed to the states in which the federal leases are  located, an additional 25 percent will now be disbursed to the counties in  which the leases are located, leaving only 25 percent to the federal  government.
The Act also changes how the federal government’s share of geothermal  royalties can be used. Prior to passage of the Act, 40 percent of the federal  government’s share was deposited into the reclamation fund created by the  Reclamation Act of 1902, and 10 percent was deposited into the general  fund of the Department of the Treasury. For the first 5 fiscal years after  passage of the Act, the federal government’s share is now to be deposited  into a separate account within the Department of the Treasury that the  Secretary of the Interior can use without further appropriation and fiscal  year limitation to implement both the Geothermal Steam Act and the Act.  DOI officials explained that some of these funds could be used for activities  such as issuing geothermal leases, conducting environmental reviews,  collecting geothermal royalties, and inspecting geothermal leases.
section_title: Provisions of the Energy Policy Act Are Likely to Have Little Impact on Overall Royalty Revenues Only if Electricity Prices Remain Relatively Constant
paragraphs: Despite several provisions of the Act that alter the amount of royalties due  on both the generation of electricity and direct use operations, federal  geothermal royalties could remain about the same, but only if electricity  prices remain stable. However, electricity prices are not possible to predict  with certainty, and price changes could significantly impact royalty  revenues on electricity sales, which account for about 99 percent of total  geothermal royalty revenues. The Act contains provisions for each of three  specific types of leases that generate electricity: (1) leases that currently  produce electricity, (2) leases that were issued prior to passage of the Act  and will first produce electricity within 6 years following the Act’s passage,  and (3) leases that have not yet been issued. There is also a provision in the  Act that replaces the current method of calculating royalties due on direct  use operations with a schedule of fees that shall encourage the  development of geothermal resources. Since direct use royalties accounted  for less than 1 percent of total geothermal royalties from 2000 through  2004, the financial impact of the switch to a schedule of fees is likely to be  minimal.
For leases that currently produce electricity, the Secretary of the Interior is  to seek to collect the same level of royalties over the next 10 years but  under a simpler process. Prior to passage of the Act, lessees of 13 of the 15  geothermal electricity projects paid federal royalties according to a  provision within MMS’s geothermal valuation regulations referred to as the  “netback process.” To arrive at royalties due under this process, lessees are  to first subtract from the electricity’s gross sales revenue their expenses  for generation and transmission and then multiply that figure by the royalty  rate specified in the geothermal lease, which is from 10 to 15 percent. The  Act simplifies the process by stating that within the 18 months after the  effective date of the final regulations issued by DOI, lessees who were  producing electricity prior to passage of the Act have the option to request  a modification to their royalty terms. This modification allows for royalties  to be computed as a percentage of the gross sales revenues from the  electricity so long as this percentage is expected to yield total royalty  payments equal to what would have been received for comparable  production under the royalty rate in effect before passage of the Act. MMS  has already implemented a procedure similar to this provision for the two  projects that produce electricity at The Geysers, setting their future  royalties equal to a percentage of gross sales revenues based largely on  past royalty histories and future projections.
Royalty revenues from a geothermal lease currently producing electricity  will remain the same if the lessee elects not to convert to the new provision  within the Energy Policy Act. In this case, the lessee will continue to  calculate and pay royalties just as the lessee did before passage of the Act.  Royalty revenues from a geothermal lease currently producing electricity  should also remain about the same if the lessee does convert to the simpler  method of calculating royalties in the Act, provided that DOI negotiates  with the lessee a future royalty percentage based on past royalty history  and provided that electricity prices remain relatively constant. This  situation is illustrated in table 4, which uses data based on actual royalty  data from a geothermal project on federal lands. According to table 4, the  lessee pays royalties equal to $20,000 under the netback process. Royalties  are equal to the production of 8,000 megawatt hours times the sales price of  $100 per megawatt hour less $600,000 in expenses times the statutory  royalty rate of 10 percent. Figures in table 4 represent averages over a 5- year period and show that royalties are equal to 2.5 percent of gross sales  revenue. If production remains the same and if electricity prices average  $100 per megawatt hour, future royalty revenues will remain the same  whether royalties are calculated under the netback process or if royalties  are calculated at 2.5 percent of gross sales revenues.
However, if electricity prices increase and royalties are based on historic  percentages of gross sales revenues, royalty revenues will actually  decrease relative to what the federal government would have collected  prior to passage of the Act. More revenue would have been received under  the netback process because expenses for generation and transmission do  not increase when electricity prices increase and the higher 10 percent  statutory royalty rate would have applied to all of the increase in sales  revenues. This impact is illustrated in table 5. Using the historic average of  2.5 percent computed in table 4, the royalties will actually be $12,000 less  than what would have been collected under the netback process when the  average price increases by $20 per megawatt hour. On the other hand, if  average electricity prices drop by $20 per megawatt hour, royalty revenues  will increase by $12,000 relative to what would have been collected under  the netback process.
For the second type of lease—leases that were issued before the Act and  that will first produce electricity within 6 years after the Act’s passage— royalty revenues are likely to drop somewhat because lessees are likely to  take advantage of an incentive within the Act. The Act allows for a 50  percent decrease in royalties for the first 4 years of production so long as  the lessee does not elect to pay royalties based on a percentage of gross  sales revenues and continues to use the netback process. Because of the  substantial reduction in royalties, it is likely that lessees owning leases  issued before passage of the Act will elect to pay only 50 percent of the  royalties due on new production for the 4-year period allowed by the Act.  This incentive also applies to sales revenues from the expansion of a  geothermal electricity plant that exceeds 10 percent. Owners of geothermal  electricity plants currently paying royalties under the netback process may  elect to take the production incentive for new plant expansions if they  perceive that the royalty reduction is worth the additional effort and  expense in calculating payments under the netback process and worth the  possibility of being audited. BLM officials said that leases in Utah,  California, and Nevada may become subject to the royalty reduction  provisions within the Act for new production and new plant expansions.
It is difficult to predict exactly how royalty revenue from the third type of  lease—leases that have not yet been issued—will change, but it appears  that revenue impacts are likely to be minor, based on our review of historic  royalty data. The Act specifies that the Secretary of the Interior should seek  to collect the same level of royalty revenues over a 10-year period as before  passage of the Act, but it will be difficult for DOI to compare an estimate of  what royalty revenue would have been without the Act with royalty  revenues after the Act because the production and expenses of future  plants could vary substantially due to their unique geological, engineering,  and economic attributes. The Act provides that, for future leases, royalties  on electricity produced from federal geothermal resources should be not  less than 1 percent and not greater than 2.5 percent of the sales revenue  from the electricity generated in the first 10 years of production. After 10  years, royalties should be not less than 2 percent and not greater than 5  percent of the sales revenue from the electricity.
We attempted to analyze the revenue impact on future leases by using  historic royalty data maintained by MMS and sales revenue data maintained  by BLM. A detailed description of our methodology is in appendix II. First,  we attempted to analyze revenue impacts on the first 10 years of electricity  production, but we had difficulty obtaining relevant royalty data so we  could not complete this analysis. Next, we examined the impact on  royalties after the first 10 years of production by analyzing data for seven  geothermal projects from 2000 through 2004. In analyzing royalty data, we  found that MMS did not maintain gross sales revenue data so we used data  that BLM supplied to MMS. We also found that 40 percent of the royalty  data maintained by MMS was erroneous or missing so we corrected or  obtained these data as necessary. We then calculated royalties paid as a  percentage of gross sales revenues for each project. This analysis showed  that lessees were paying a wide range of percentages—from 0.2 to 6.3  percent. Three of the seven projects paid under the minimum 2 percent  royalty rate prescribed in the Act, suggesting that some projects in the  future could pay more under the Act’s new provisions than they would  otherwise have paid. On the other hand, one project paid greater than the  maximum 5 percent prescribed in the Act, suggesting that it is possible for  a plant to pay less in the future than it would otherwise have paid.  However, both the royalty revenue that the one plant would have overpaid  and the total of the royalty revenues that the three plants would have  underpaid are small—about 0.2 percent and 0.01 percent, respectively, of  all geothermal royalties reportedly paid during the period of our analysis.
Even though provisions within the Act may decrease royalties on direct use  applications, the impact of these provisions is likely to be small because  total royalty collections from direct use applications are minimal. In fiscal  years 2000 through 2004, MMS reported collecting annually about $79,000  from two direct use projects, or less than 1 percent of total geothermal  royalties. In addition, MMS reported collecting an additional $222,000  during this period in settlement for royalties owed on a direct use project  from 1987 through 2003. While a provision within the Act may encourage  the use of federal geothermal resources for direct use by lowering the  federal royalty rate, we believe based on challenges facing developers that  it is unlikely that this royalty incentive alone will stimulate substantial new  revenues to compensate for the loss in revenue due to the lower royalty  rate. We believe that, in order to substantially increase the development of  federal direct use applications, developers must overcome the relatively  high capital costs for investors, unique business challenges, and water  rights issues.
section_title: MMS Does Not Routinely Collect the Royalty Data Necessary to Maintain the Same Level of Royalty Collections
paragraphs: MMS does not routinely collect meaningful data on the revenue from  electricity sales. Since the Act requires the Secretary of the Interior to seek  to achieve the same level of royalty revenues when issuing new royalty  regulations, these data are necessary to know how future royalties will  compare with what would have been collected before passage of the Act.  To make these comparisons, MMS needs to calculate the percentage of  gross sales revenues that lessees pay in royalties. MMS requires royalty  payors to record sales revenue data on Form MMS-2014 under the data field  “sales value.” MMS’s Geothermal Payor Handbook instructs royalty payors  using the netback method to record in this field its net sales revenue, which  is equal to gross sales revenues less deductions for expenses such as  generation and transmission. As such, this sales value cannot be used as  one of the factors to calculate the percent of gross sales revenues paid in  royalties.
In preparing an analysis for the Royalty Policy Committee, MMS obtained  gross sales revenue data from BLM for many of the geothermal projects.  While BLM regulations require geothermal plant operators to report to BLM  the amount of electricity produced, these regulations do not require the  reporting of gross sales revenues. Nevertheless, BLM officials said that they  collect the sales revenue data. BLM officials in Nevada and southern  California reported examining the production and gross sales revenue data  for reasonableness and patterns in order to check on the accuracy of  royalty reporting. A BLM official also reported collecting sales revenue and  production data at The Geysers in northern California, but he said that BLM  lacked the resources to examine these data and was unable to compile  these data either for MMS or for us. These data from The Geysers are  important because they represent about 61 percent of total federal  geothermal royalties. Some royalty data from The Geysers were obtained  and audited by the state of California, but an MMS official said that it would  be more efficient and timely if MMS collects gross sales revenue data  directly, rather than having to ask BLM or the states for these data. The  official also said that MMS could use the gross sales revenue data in the  future to conduct general compliance audits by comparing the percent of  gross sales revenue paid in royalties with percentages prescribed within  the Act and by examining trends in the data, without having to undertake  lengthy and expensive on-site visits to the geothermal plants.
section_title: Conclusions
paragraphs: The Energy Policy Act of 2005 addresses a wide variety of challenges facing  developers of geothermal resources. The Act incorporates many of the  lessons learned by state governments and federal agencies in an attempt to  make federal processes more efficient and provide financial incentives for  further development. However, the Act is new and insufficient time has  passed to assess its effectiveness. Several of the Act’s major provisions will  be left to the federal agencies within DOI for implementation, and the  drafting and public comment period for regulations that implement these  provisions will take time. Agencies will also need to spend considerable  time and effort in working out the details for implementation and securing  the necessary budgets to implement the new system. To assist in these  efforts, the Congress has authorized the agencies to use the federal  government’s share of royalty collections to implement the geothermal  program for 5 years.
All the while, the Act directs the Secretary of the Interior to seek to  maintain the same level of geothermal royalty revenues over the next 10  years as would have been collected prior to the Act. This is a tall mandate,  as one of the factors that can most affect geothermal royalty revenue—the  price of electricity—is outside the control of the managing agencies.  Although it is impossible to predict with reasonable assurance how these  prices will change in the future, the federal agencies must make their best  effort to mitigate the impact of changing prices if federal royalty revenue  are to remain the same. This mitigation can only be achieved if there is  timely and accurate knowledge of the revenues that lessees collect when  they sell electricity. Without such knowledge, MMS will have difficulty  collecting the same level of royalties from lessees that elect to use the new  royalty process.
section_title: Recommendation for Executive Action
paragraphs: To assist in achieving the same level of geothermal royalties as would have  been collected prior to the Energy Policy Act of 2005, we recommend that  the Secretary of the Department of the Interior instruct the appropriate  managers within the Minerals Management Service to take the following  two actions:   Correct erroneous and missing royalty data, when necessary, so that it  will have an accurate baseline of royalty collections for each payor; and   Routinely collect from royalty payors the gross sales revenues for  electricity sold in order to compare these revenues with past royalty  collections and to verify compliance with the percentages prescribed  within the Act for leases to be issued in the future.
section_title: Agency Comments and Our Evaluation
paragraphs: We provided a draft of this report to the Department of the Interior for  review and comment. DOI provided written comments, which are  presented in appendix II. DOI agreed with our recommendations and  emphasized the importance of correct and relevant data in fulfilling the  requirement to collect the same level of geothermal royalties as would have  been collected prior to the Energy Policy Act of 2005. Specifically, DOI  stated that MMS plans to take steps to correct erroneous and missing  royalty data, including initiating an audit and directing payors to correct  data. DOI also stated that MMS is drafting new geothermal regulations as  part of implementing the Act and that these regulations will refer to  instructions that require payors to report to MMS the gross sales revenues  for electricity sold. MMS also provided several technical comments that we  have incorporated in the report.
As agreed with your office, unless you publicly announce the contents of  this report earlier, we plan no further distribution until 15 days from the  report date. At that time, we will send copies to other interested  congressional committees. In addition, we will send copies of this report to  the Secretary of the Interior, the Director of BLM, the Director of the  Minerals Management Service, the Secretary of the Department of  Agriculture, the Chief of the Forest Service, and the Secretary of Energy.  We also will make copies available to others upon request. In addition, the  report will be available at no charge on the GAO Web site at  http://www.gao.gov.
If you or your staff have any questions about this report, please contact me  at (202) 512-3841 or WellsJ@gao.gov. Contact points for our Offices of  Congressional Relations and Public Affairs may be found on the last page  of this report. Key contributors to this report are listed in appendix III.
section_title: Objectives, Scope, and Methodology
paragraphs: In this report, we discuss (1) the current extent and potential for  geothermal development; (2) challenges faced by developers of geothermal  resources; (3) federal, state, and local government actions to address these  challenges; and (4) how provisions of the Energy Policy Act of 2005 (Act)  are likely to affect federal geothermal royalty collections.
To describe the current extent and potential for geothermal development,  we reviewed key studies on the extent and potential of geothermal  development that were published by the Department of Energy, the  California Energy Commission, the U.S. Geological Survey, the Western  Governors’ Association, the Geo-Heat Center at the Oregon Institute of  Technology, the Geothermal Energy Association, and the state of Utah. We  contacted and visited the authors of the studies prepared by the  Department of Energy in Golden, Colorado; the California Energy  Commission in Sacramento, California; and the Geo-Heat Center in  Klamath Falls, Oregon. We also visited the Geothermal Resources Council  in Davis, California. We obtained statistics on federal geothermal leases  from the Bureau of Land Management (BLM) and data on geothermal heat  pumps from the Geothermal Heat Pump Consortium, the Department of  Energy’s Geothermal Technologies Program, and the General Services  Administration.
To identify the challenges facing geothermal developers and to assess  actions taken by federal, state, and local governments, we interviewed a  variety of government and industry officials, reviewed substantial  supporting documentation and the Act, and visited geothermal facilities.  We interviewed BLM officials in Washington, D.C.; California; Nevada; and  Utah, as well as Forest Service officials in Washington, D.C.; Minerals  Management Service (MMS) officials in Lakewood, Colorado; and  Department of Energy officials in Washington, D.C.; and Golden, Colorado.  We contacted state officials in California, Nevada, and Idaho. We also  interviewed geothermal industry representatives in Washington, D.C.;  California; Nevada; and New Mexico and toured geothermal electricity  plants in California and Nevada and direct use facilities, including heating  districts, food processing plants, greenhouses, aquaculture operations, and  a spa in Idaho, Nevada, Oregon, and Colorado. Specifically to assess  financial challenges faced by the geothermal industry, we also interviewed  officials with public utilities and officials who specialize in arranging  financing for geothermal plants. In assessing challenges specific to federal  lands, we also reviewed processes for approving lease applications and  conducting environmental analyses under the National Environmental  Policy Act of 1969; examined federal regulations addressing leasing,  geothermal operations, and royalty valuation for both electricity  production and direct use; and read the 148-page Geothermal Valuation  Handbook.
To assess how provisions within the Act will affect federal geothermal  royalties, we interviewed MMS employees in Lakewood, Colorado, and  BLM employees in California, Utah, and Nevada and reviewed a report  authored by the Royalty Policy Committee. We reviewed in detail how  provisions of the Act address the disbursement of federal geothermal  royalties and specifications for geothermal royalty collections from leases  that are currently producing electricity, leases that will first start to  produce electricity within the 6 years following passage of the Act, and  leases that have not yet been issued.
To assess how provisions of the Act could impact royalty revenue from the  sale of electricity, we started by trying to obtain monthly geothermal  royalty data and sales revenue data from MMS for January 2000 through  December 2004 for 10 geothermal projects paying royalties according to  the netback process. We discovered that MMS does not require payors to  submit gross sales revenue data but instead collects these data from BLM.  We assessed whether MMS’s royalty data and BLM’s sales revenue data  were complete enough and accurate enough for MMS to determine what  percentage of gross sales revenues is equivalent to the current level of  royalties being paid, should lessees elect to convert to paying a percentage  of gross sales revenues, as allowed by the Act. We reviewed MMS’s and  BLM’s data for reasonableness and completeness. While we found BLM’s  data to be reasonably complete and accurate for the 10 geothermal  projects, we found that BLM could not furnish us with sales revenue data  for the 2 steam projects at The Geysers Geothermal Field in northern  California. We also found that about 40 percent of the monthly royalty data  maintained by MMS for the 10 projects was missing or erroneous. The most  common error, accounting for 73 percent of erroneous and missing data,  was not paying the 0.1 percent minimum royalty required by MMS  regulations. This error did not result in significant monetary  underpayments; monthly underpayments for this type of error generally  amounted to less than $500. After assuming that the correct royalty due  was 0.1 percent of net sales revenue for those months in which  underpayments were less than the minimum royalty calculation, we  determined that royalty data was reasonably accurate and complete for  January 2000 through December 2004 for 6 of the projects and for January  2003 through December 2004 for one additional project.
In assessing revenue impacts from leases that were currently issued and  producing electricity, we considered MMS’s past history of approving  royalty calculations based on a percentage of gross sales revenues at The  Geysers. We also reviewed MMS’s calculations of the percentages of gross  sales revenues that appear in the report to the Royalty Policy Committee.  Based on these considerations, we assumed that MMS could determine a  percentage of gross sales revenues equal to what would have been  collected prior to the Act if electricity prices do not change. We also  determined the impact of changing prices on royalty revenues as illustrated  in table 5. In assessing revenue impacts from leases that were currently  issued and not producing, we contacted BLM officials to ascertain the  likelihood for these leases to first start producing in the next 6 years and  the likelihood of producing leases to expand their production by more than  10 percent. We also discussed with industry officials their opinions on  paying royalties according to the netback process.
To assess how royalty collections from future leases could be impacted, we  began to examine royalty data from the first 10 years for the 15 federal  geothermal projects, all of which first started producing prior to 1987. We  abandoned this attempt after conversing with MMS officials. MMS officials  noted that contracts for the sale of electricity prior to 2000 were different  and would probably not be representative of future situations. In addition,  sales in the 1980s often involved the sale of geothermal resources such as  steam and hot water rather than electricity, complicating the use of MMS’s  royalty data. Although some industry officials said that their projections  suggest that royalties during the first 10 years of a project’s life are  substantially less than the royalties during the remainder of the project’s  life, we could not verify this estimate without actual royalty data.
To assess how royalty collections from future leases could be impacted 10  years after they first produce, we proceed with examining royalty data for 7  of the projects from our original sample of 10 geothermal projects. We  calculated royalties as a percentage of gross sales revenues from January  2000 through December 2004 and compared their range with the range of  percentages prescribed within the Act for production after the first 10  years. We also compared royalties as the percentages of gross sales  revenues for five of the flash plants with royalties as a percentage of gross  sales revenues for two of the binary plants. We found that flash plants paid  royalties from 0.6 to 6.3 percent of gross sales revenues while binary plants  paid from 0.2 to 2.6 percent of gross sales revenues. It appeared to us that  each project, whether flash or binary, faces unique geological, economic,  and engineering situations that can combine to yield different percentages  of gross sales revenues. In addition, the small number of observations and  the significant overlap in range of the data indicated to us that  generalizations about the difference in percentages between the two types  of plants would be inaccurate.
To determine the impact of the Act on royalties from direct use of  geothermal resources, we obtained direct use royalty data from MMS and  reviewed the calculations on an alternative to the current calculation of  direct use royalties that appears in the report to the Royalty Policy  Committee.
section_title: Comments from the Department of the Interior
section_title: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
section_title: Staff Acknowledgments
paragraphs: In addition to the individual named above, Dan Haas, Assistant Director;  Jeanne Barger; Ron Belak; John Delicath; Randy Jones; Frank Rusco; Anne  Stevens; and Barbara Timmerman made key contributions to this report.