THE COMPANY AND ITS BUSINESS

Business Development

U.S. Geothermal Inc. (or “GTH”) is a Delaware corporation. GTH was originally incorporated in the province of British Columbia, Canada, under the name “Mango Resources Ltd.” on September 14, 1987. It immediately began trading on the Vancouver Stock Exchange under the symbol “MRH.” On October 7, 1999, the company changed its name from “Mango Resources Ltd.” to “Consolidated Mango Resources Ltd.” and its share capital was consolidated on the basis of ten pre-consolidation common shares for one post-consolidation common share.

On March 13, 2000, the company moved to and began trading on the TSX Venture Exchange (which is the successor to the Vancouver Stock Exchange as well as some other provincial exchanges) under the name “US Cobalt Inc.” and under the symbol “USC” and continued to trade under that symbol until trading was halted on April 3, 2002, in accordance with TSX Venture Exchange policy, in anticipation of and pending completion of the company’s merger with Geo-Idaho. Upon completion of the merger, the company again began trading on the TSX Venture Exchange, under its current symbol, “GTH.”

Historically, GTH, first as Mango Resources and Consolidated Mango Resources and then as U.S. Cobalt, operated in the resources sector and held interests in various mining properties. Mango conducted initial mineral exploration for base metals (nickel and zinc) of four mineral claims situated in Voisey Bay, Labrador, Canada. Exploration activities in Voisey Bay were unproductive and concluded by the end of 1996, with the mineral claims written off in 1997. Additionally, Mango acquired interests in two gold properties in South East Asia: a property in Kalimantan, Indonesia, in 1996 and a property on the island of Java, Indonesia, in 1997. Neither property yielded significant gold deposits and, due to the adverse gold market during the period, gold exploration activities were also concluded, with activities on the Kalimantan property terminated in 1998 and the Java gold property agreement terminated in July 1999. At that point, Mango had no significant assets and became inactive.

USC Colorado was incorporated on April 27, 1998, to conduct cobalt exploration. In March 2000, the company completed a plan of arrangement with USC Colorado, continuing its incorporation from British Columbia to Delaware, under Delaware corporate law, as U.S. Cobalt Inc. A “plan of arrangement” and “continuation” are Canadian law concepts, whereby a Canadian provincial corporation may, practically speaking, become a Delaware (or other U.S. jurisdiction) corporation, similar to a state-to-state reincorporation under U.S. law. As part of the plan of arrangement, our authorized capital was changed from 100,000,000 common shares without par value to 100,000,000 shares of common stock with a par value of US $0.001 per share. USC Colorado became a subsidiary of the company, and conducted the cobalt exploration activities. The company held an exploration lease and conducted mineral exploration on property in Missouri. By March of 2002, the company concluded that its then current cobalt exploration project was no longer promising, and determined it would refocus its business efforts on renewable, “green” energy projects. The exploration lease of the Missouri property was terminated in July 2002.

Geo-Idaho was formed as an Idaho corporation in February 2002 to conduct geothermal resource development. On March 5, 2002 Geo-Idaho entered into a letter agreement with Vulcan Power Company, pursuant to which Geo-Idaho agreed to acquire from Vulcan all of the real property, personal property and permits that comprised Vulcan’s interest in the Raft River project. We generally refer to Vulcan’s real and personal property interests as the “Vulcan Property”. On December 3, 2002 the letter agreement was replaced by a formal agreement with Vulcan (the “Vulcan Agreement”), which provided for the acquisition, in stages, of 100% of the Vulcan Property in consideration for shares and warrants of Geo-Idaho and cash payments to or on behalf of Vulcan of up to $600,000 (for 100% of the Vulcan Property). Geo-Idaho also agreed that, as a condition to completing the purchase of and as an owner of the Vulcan Property, it would work to advance the Raft River Project by expending at least $200,000 for a work

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program (which has since been completed). By March 31, 2004, Geo-Idaho had paid Vulcan $492,000 in securities and cash payments, to bring its percentage ownership in the Vulcan Property to 75%. GTH may acquire the remaining 25% interest for a payment of $125,000 at any time prior to construction of the initial power plant, and intends to do so once construction financing is available.

The following table reflects the consideration paid to date to Vulcan for the Vulcan Property (which does not include the $200,000 paid by the company to third parties for the work program on the Property):

*Value of securities issued to Vulcan for accounting purposes

The opportunity to be involved in the geothermal business as presented by Geo-Idaho was attractive to GTH’s board of directors and subsequently approved by its shareholders. Messrs. Glaspey, Kunz and Larkin were each directors, officers and shareholders of both Geo-Idaho and GTH. Therefore, an independent fairness opinion was provided to GTH by MCSI Consulting Services Inc., an independent firm of corporate finance advisors. The company and Geo-Idaho entered into a merger agreement on February 28, 2002, which was amended and restated on November 30, 2003.

In December 2003, in accordance with the merger agreement, we acquired Geo-Idaho through the merger of Geo-Idaho with a wholly-owned subsidiary, EverGreen Power Inc., an Idaho corporation formed for that purpose. Geo-Idaho is the surviving corporation and the subsidiary through which GTH conducts operations. As part of this acquisition, we changed our name to U.S. Geothermal Inc. Because the former Geo-Idaho shareholders became the majority holders of GTH, the transaction is treated as a “reverse takeover” for accounting purposes.

Business

Geo-Idaho was incorporated for the sole purpose of acquiring one or more geothermal projects and more particularly, entering into the agreement with Vulcan Power Company to acquire up to a 100% interest in the Raft River project. Prior to the incorporation of Geo-Idaho, its founding shareholders had been actively pursuing a potential acquisition of a geothermal project in Idaho since early 2001. The company acquired Geo-Idaho in order to pursue geothermal energy development, and particularly the development of the Raft River project. Since the acquisition of Geo-Idaho, GTH has continued to seek and acquire additional property interests with geothermal resources.

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Geothermal Energy

Geothermal energy is natural heat energy stored within the earth’s crust at accessible depth. In certain areas of the earth, economic concentrations of heat energy result from a combination of geological conditions that allow water to penetrate into hot rocks at depth, become heated, and then circulate to a near surface environment. In these settings, commercially viable extraction of the geothermal energy and its conversion to electricity become possible and a “geothermal resource” is present.

There are four major components (or factors) to a geothermal resource:

Exploration. In order to assess the potential of a geothermal resource, a variety of geological, geochemical and geophysical investigation techniques are employed. For example, subsurface temperatures are measured by drilling; detailed gravity and magnetic measurements yield models of the underground geologic structure; and measurements of the earth’s electrical resistivity assist in defining possible zones of hot water and/or the hydrothermally altered rocks that typically overlie a thermal aquifer.

Production. The energy necessary to operate a geothermal power plant is typically obtained from at least several production wells which are drilled using established technology similar to that employed in the oil and gas industry. Production wells are typically located within one mile of the power plant. Wells are also needed to inject most of the spent and cooled geothermal water back underground.

Geothermal Power Plants. Geothermal power plants fall into two general categories. A direct-steam plant uses steam directly (either from dry steam wells or separated from water under pressure) to drive turbines connected to generators. A binary power plant uses a heat transfer system to transfer the heat energy from hot water (and/or steam) to a working fluid with a lower boiling temperature than water. Binary systems are mostly employed at medium-grade resources (with temperatures below about 180°C). Some projects employ combinations of direct-steam and binary systems.

Environmental Benefits. Geothermal energy is a clean renewable energy with almost zero emission of greenhouse and acid rain gases. Practically no waste is generated in a binary power plant such as that planned at the Raft River project. After extraction of heat energy from geothermal fluids, all remaining gases and liquids are re-injected to the ground. Geothermal energy projects involve minimum disturbance to the surface and the underground rock formation.

The Raft River Project

Location and Property Description of Raft River Project.

The Raft River project is in south-central Idaho, approximately 55 miles southeast of Burley, the county seat of Cassia County. Burley, population 8,300, is the local agricultural and manufacturing center for the area, providing a full range of light to heavy industrial services.

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A commercial airport is located 90 miles to the northeast in Pocatello, Idaho. Pocatello, population 53,000, is a regional center for agriculture, heavy industry (mining, phosphate refining), technology and education with Idaho State University. Malta, a town with a population of 180, is 12 miles north of the project site where basic services, fuel, and groceries are available. Year-round access to the project from Burley is via Interstate Highway 84 south to State Highway 81 south, then east on the Narrows Canyon Road, an improved county road.

The Raft River project currently consists of seven parcels (generally referred to as the Vulcan Property, the Crank Lease, the Newbold Lease, the Jensen Lease, the Jensen Investments Lease, the Stewart Lease and the Elena Property) comprising 660 acres of fee land and 3,496.79 acres of contiguous leased geothermal rights located on private property in Sections 23, 24, 25, 26, 27, 28, 33, 34 and 35, Township 15 South, Range 26 East Boise Meridian, and Sections 17, 18, 19, 29, and 30, Township 15 South, Range 27 East Boise Meridian, Cassia County, Idaho. All parcels are defined by legal subdivision or by metes and bounds survey description. The seven parcels are as follows:

The Vulcan Property. The Vulcan Property includes both surface and geothermal rights and consists of two units. The first unit has a total area of 240 acres and is comprised of the East half of the South-East quarter of Section 22, plus the South-West quarter of Section 23, Township 15 South, Range 26 East Boise Meridian. Three geothermal wells (RRGE-1, RRGP-4 and RRGP-5) are located on this parcel. The second unit has a total area of 320 acres, and is comprised of the South half of the North-West quarter, the South half of the North-East quarter, and the entire South-East quarter of Section 25, Township 15, South, Range 26 East Boise Meridian. Three additional geothermal wells (RRGE-3, RRGI-6 and RRGI-7) are located on this parcel. A fourth well, RRGE-2, although located on the property covered by the Crank lease, was acquired by the company as part of its purchase of the Vulcan Property.

The Crank Lease. The Crank lease covers 160 acres of mineral and geothermal rights, with right of ingress and egress. The lease is comprised of the NE quarter of Section 23, Township 15 South, Range 26 East Boise Meridian.

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The Newbold Lease. The Newbold lease covers 20 acres of both surface and geothermal rights. The lease is comprised of the NE quarter of Section 23, Township 15 South, Range 26 East Boise Meridian.

The Jensen Lease. The Jensen lease covers 2,954.75 acres of geothermal rights only. It is contiguous with the Vulcan property and the Crank lease with land parcels located in Sections 24, 25, 26, 27, 33, and 34, Township 15 South, Range 26 East Boise Meridian, and in Sections 18, 19, 20, 29, and 30, Township 15 South, Range 27 East Boise Meridian.

The Jensen Investments Lease. The Jensen Investments lease covers 44.5 acres of surface and geothermal rights in Section 35, Township 15 South, Range 26 East Boise Meridian, and is contiguous with the Jensen lease.

The Stewart Lease. The Stewart Lease covers 317.54 acres in two adjoining parcels; Parcel 1 includes the N half of the SE quarter of the SE quarter, the SE quarter of the SE quarter of the SE quarter, and the SW quarter of the SE quarter of the SE quarter of Section 23, and the W half of the SW quarter, the SE quarter of the SW quarter and part of the SE quarter of the SW quarter of Section 24, Township 15 South, Range 26 East Boise Meridian, contains 159.04 acres and includes surface and geothermal rights, Parcel 2 contains 158.50 acres in the NE quarter of Section 26, Township 15 South, Range 26 East Boise Meridian and only covers surface rights. The underlying geothermal rights for Parcel 2 are subject to the Jensen Lease.

The Elena Property. The Elena Property is a parcel of approximately 100 acres, excluding the oil and gas rights to the property. The property is in the W half of the SE quarter, and the W half of the NE quarter of the SE quarter of Section 23, Township 15 South, Range 26 East Boise Meridian, and is contiguous to other properties owned and leased by the company.

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Lease/Royalty Terms

The Crank lease, the Newbold lease, the Jensen lease and the Jensen Investments lease have royalties payable under the following terms:

The Stewart lease has production royalties payable under the following terms:

No production royalties have been paid to date under any of the leases. All of the leases may be extended indefinitely if production is achieved during the primary term, so long as production is maintained. For each lease other than the Crank Lease (see below), once production is achieved the amounts due annually will be the greater of the production royalty and the minimum payment for the last year of the primary term. All payments under the leases are made annually in advance on the anniversary date of the particular lease. In addition, the following lease and other royalty terms apply to the individual leases:

The Crank Lease. The lease agreement with Janice Crank was originally entered into June 28, 2002, and had a primary term of 5 years. After GTH provided evidence to the lessor that the well (RRGE2) located on lessor’s property is not owned by the lessor (but instead is included in the Vulcan Property), a new lease was entered into on June 28, 2003, with a four-year initial term. Advance production royalties (on a June to June basis) are payable under the Crank lease as follows:

Payments for years 2002 through 2006 are advances against future production royalties. For later years, during commercial production, there is a minimum annual production royalty of US $18,000. The minimum amount that will be payable over the course of the leases is $45,000. Maximum amounts payable will depend on production from the property.

The Newbold Lease . The company leases this property pursuant to a lease agreement with Jay Newbold dated March 1, 2004. The Newbold lease has a primary term of 10 years (through February 28, 2014) and

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is extended indefinitely so long as production from the geothermal field is maintained. Lease payments are as follows:

•                 Years 1-5: $10.00 per acre or $200 per year (Year 1 paid on signing)

•                 Years 6-10: $15.00 per acre or $300 per year

The minimum amount that will be payable over the course of the lease is $2,500. Maximum amounts payable will depend on production from the property.

The Jensen Lease. The Jensen lease, with Sergene Jensen, lessor, is dated July 11, 2002, has a primary term of 10 years. Lease payments (on a July to July basis) are as follows:

•                 Years 1-5: US $2.50 per acre or $7,386.88 per year (Years 1-3 paid for a total of $22,160.64)

•                 Years 6-10: US $3.00 per acre or $8,864.25 per year

The minimum amount that will be payable over the course of the lease is $81,255.65. Maximum amounts payable will depend on production from the property.

The Jensen Investments Lease. The Jensen Investments lease, with Jensen Investments, Inc., is dated July 12, 2002, and has a primary term of 10 years. Lease payments (on a July to July basis) are as follows:

•                 Years 1-5: US $2.50 per acre or $111.25 per year (Years 1-3 paid for a total of $333.75)

•                 Years 6-10: US $3.00 per acre or $133.50 per year

The minimum amount that will be payable over the course of the lease is $1,223.75. Maximum amounts payable will depend on production from the property.

The Stewart Lease. The Stewart lease, with Reid and Ruth Stewart, is dated December 1, 2004, and has a term of 30 years. Lease payments are as follows:

•                 Year 1: US $8,000 (paid on signing).

•                 Year 2: US $5,000.

•                 Year 3-30: $5,000 plus an annual increase of 5% per year.

The minimum amount that will be payable over the course of the lease is $319,614.00. Maximum amounts payable will depend upon production from the property.

The total minimum amount payable under all of the leases during their primary terms is $449,593.43. All of the above listed lease payments are payable annually in advance, and are current through lease years beginning in 2004.

History of the Raft River Project

Much of the historical information set forth is from the August 2002 report of GeothermEx Inc. “Technical Report On The Raft River Geothermal Resource, Cassia County Idaho.” A copy of the report is available for review at the company’s principal office, or a copy may be obtained for the cost of shipping and handling on written request. A geothermal resource in the Raft River valley was first identified before

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1950 at two shallow agricultural wells that produced boiling water (the “Crank” well and the “Bridge” well). Interest in exploring and developing the geothermal resource of the Raft River valley began in the early 1970s, first by the U.S. Geological Survey, which undertook reconnaissance geochemical and geological work in 1972. One of the most significant results of this work was that chemical geothermometry of samples from the two boiling wells indicated a resource temperature of about 300°F.

In 1971, the Raft River Rural Electric Cooperative began preliminary investigations into the possibility of generating electric power from this resource. Supported by the U.S. Energy Research and Development Administration (ERDA), the predecessor to the U.S. Department of Energy (DOE), investigations focused on using binary technology, which was experimental at that time, to generate electric power. In late 1973, the U.S. Geological Survey began an integrated geological, geophysical, geochemical and hydrological analysis of geothermal resources in general, and the Raft River geothermal resource specifically. Drilling activities in the Raft River area included 34 auger holes of 100-foot depth, an offset to the Bridge well (one of the two shallow boiling wells mentioned above), and five core holes (also referred to as “intermediate holes”) ranging in depth from 250 to 1,423 feet. These core holes were drilled to provide information to test geophysical interpretations of the subsurface structure and lithology, and to provide hydrologic and geologic data on the shallow part of the geothermal system.

The next phase of drilling consisted of seven deep, full-diameter wells: RRGE-1, RRGE-2, RRGE-3, RRGP-4, RRGP-5, RRGI-6 and RRGI-7. These were completed during 1975 to 1978, and were the subject of extensive testing. All of these wells are located on the lands comprising the Raft River project.

Well RRGE-1 was located between the Bridge and Crank wells, and targeted the Bridge Zone (an inferred north-northeast-trending fault zone in the area near the boiling shallow wells) at depth. Completed in April 1975, the well was a success, although there was no evidence that it had penetrated a fault. Well RRGE-2, located about 3,000 feet northeast of RRGE-1, also targeted the Bridge Zone, but deeper, in the basement rock. Completed in June 1975, it too was a successful producer, but again, there was no evidence of fault penetration. These two wells were flow tested for several months, and RRGE-2 was injection tested. After the injection testing, well RRGE-2 was deepened by about 500 feet in March 1976.

Further investigation of the postulated Bridge Zone was dropped in 1976; instead, the focus of drilling shifted to evaluating the extent and capacity of the geothermal reservoir. Well RRGE-3, located more than a mile southeast of RRGE-1, was drilled for this purpose and was deliberately side-tracked three times (legs A, B, and C), with modest displacements (< 500 feet) of the bottomhole locations relative to the surface location in all three legs. The purpose of drilling the side-tracks was to determine if additional production could be obtained from a multi-legged well at less cost than drilling an additional well or wells; however, the flow rate from the three legs was lower than that of either of the first two wells. The well was completed in May 1976.

The fourth well was to be an injection well, and was therefore named RRGI-4. Located about 1,800 feet south of well RRGE-1, this well was completed in May 1977. Seven monitoring wells (MW-1 through MW-7) were drilled to depths ranging from 500 to 1,300 feet in 1978. Injection testing of well RRGI-4 in early 1978 revealed a hydraulic connection to nearby monitoring wells (MW-1, USGS-3 and the BLM Offset of the Bridge well). In November 1978, RRGI-4 was deepened and completed as a producer with two legs, and its name was changed to RRGP-4. However, it produced only a small amount of fluid under artesian (or natural pressure) flow.

The next well to be drilled was RRGI-6, located about 3,500 feet E of well RRGE-3. Completed in May 1978, this well was a moderately successful injector. Moving back to the eastern flank of the Jim Sage Mountains, the next well to be drilled was RRGP-5, located about 2,800 feet southwest of RRGE-1. The target for this well was the Bridge Zone or the Horse Well Zone (a second north-northeast-trending structure closer to the mountains). Completed in September 1978, this well produced artesian flow at lower rates than RRGE-1 or RRGE-2.

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Finally, well RRGI-7 was completed in August 1978. RRGI-7 is located about 2,000 feet southwest of RRGI-6, and achieved similar results.

In 1979, well RRGP-4 (leg B) was hydraulically fractured; this apparently improved its production rate somewhat. A fracture treatment was also performed on well RRGP-5 in November 1979.

Limited testing was undertaken during or immediately after the drilling of each well; however, these tests were not instrumented and few data are available. All of the production wells were artesian, and self- flow tests of each well were conducted to enable later pump tests to be designed. Pulse tests (a series of tests of each well at different flow rates for relatively short duration, with pressure recovery recorded between each rate step) were also conducted by pumping. Longer-term pump tests were also conducted, using either submersible or line-shaft pumps. Relatively short-term injection tests were conducted. Finally, interference tests, in which one or more wells were produced while pressure data were collected in monitoring wells, were conducted.

Based on the early drilling results from RRGE-1 and RRGE-2, design of a 5 MW binary pilot power plant began in 1976 and was completed by the end of 1978. Plant construction began in August 1979 and was completed in September 1981. The plant was operated in September, October and November 1981. Repairs and modifications were then made, and the plant operated again from March 1982 through June 1982. The output of the plant was about 4 MW, and the project confirmed the technical feasibility of binary plant operation with a geothermal fluid source. Wells RRGE-1, RRGE-2 and RRGE-3 were used to supply the plant during its periods of operation, while wells RRGI-6 and RRGI-7 were used for injection. Fluid from well RRGP-5 was used to heat the flow lines after long periods of shut-down. After an expenditure of nearly US $40,000,000, final reports were written and the entire project was officially shut down at the end of September 1982.

As described above, in the 1970s and early 1980s, the Raft River area, including the Raft River project, was under development by agencies of the United States government, beginning with ERDA and concluding with the successor organization to ERDA, the DOE. U.S. government-sponsored activities at Raft River concluded in 1982. In 1983, Hydra-Co Enterprises, a firm based in Syracuse, New York, purchased the Raft River geothermal site and associated equipment, and moved the geothermal power plant to the Brady’s Hot Springs geothermal field in Nevada. Hydra-Co sold the property in l993 to Vulcan. Vulcan did not perform any work on the property.

Work Completed by GTH

Since acquisition of the company’s initial interest in the Vulcan Property, additional geothermal leases have been negotiated with landowners adjacent to the Vulcan property and the five leases described above were signed. The Crank lease covers 160 acres of geothermal rights under a production steam well (RRGE-2) that is part of the Vulcan Property and was drilled by the Department of Energy during its tenure on the site. The Newbold lease covers 20 acres of geothermal rights in the area, the Jensen lease covers 2,954

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acres of geothermal rights in the area, the Jensen Investments lease covers 44.5 acres of both surface and geothermal rights, and the Stewart Lease covers 317.54 acres in two adjoining parcels. The Elena Property, which is contiguous with other properties owned and leased by the company, was purchased in March 2005 and is an approximately 100 acre parcel, excluding oil and natural gas rights.

GeothermEx, Inc. was again hired in May 2002 to prepare the technical report for the Raft River project previously referred to. A detailed review of all technical data available for the site was undertaken and a comprehensive report was completed in August 2002 (a copy is available for review at the company’s principal office, or a copy may be obtained for the cost of shipping and handling on written request). GeothermEx. also estimated energy reserves using a US Geological Survey volumetric reserve estimation method. The reserve calculation estimated the most likely MW capacity for the project is 15.6 MW per square mile, and that there is a greater than 99% probability that at least 10MW of reserves exist per square mile. The nearly 6 square miles of geothermal rights controlled by GTH may amount to as much as 90MW if the entire leasehold proves as productive as the area developed to date. Finally, GeothermEx concluded that if all five existing production wells can be restored to full productivity, it should be possible to supply a 14 to 17MW(net) power plant with the addition of one to three new injection wells. A 30MW(net) plant could be supported by a total of 9 to 10 production wells and 7 to 9 injection wells.

A Department of Energy Geothermal Resource Exploration and Definition II (GRED II) cost-sharing grant was awarded to Geo-Idaho in September 2002. The grant request, “Resource Confirmation Testing and Demonstration of Generating Capacity, Raft River Project, Cassia County, Idaho”, covered the phase one well testing program as recommended by GeothermEx. The total phase one program cost which qualified for the grant is US $265,096.00 of which 80 percent (US $212,077) has been reimbursed by DOE to GTH.

GeothermEx also reviewed a cash flow model prepared by GTH for a single 10 MW power facility, and, based on its review, estimated the net present value of such a project with a 25-year lifetime to be US $1,224,000, net of projected capital and based on a selling price of US $0.05 per kilo watt hour of electricity. This geothermal energy reserves report is also available for review upon request of the company.

In early June, 2003, the wellhead valves on the production and injection valves were overhauled and lubricated in preparation for well investigation operations. A high temperature video camera was lowered down in to each well to conduct a downhole camera investigation and inspection of the integrity of the wellbore and determine, if possible, whether the wells were open. The video inspection revealed that four of the production wells had Baker Packers (devices used to control water flow in a well) with flapper valves installed downhole to restrict artesian flow and that two of the four wells had either debris or flow stingers left in the wells. One well, RRGE-2, could not be entered due to the master valve not closing. The two injection wells and production well RRGE-4 were inspected to full depth and found to be open and in good condition.

Due to the discovery of the Baker Packers and the debris, flow testing could not be accomplished without either the removal of the packers or placement of new stingers to open the flapper valves. An updated plan was submitted to the Department of Energy GRED II program to resolve the packer and debris problems and prepare the wells for flow testing. The amended plan was approved by DOE on September 15, 2003, with a total budget of $396,521. GTH will be reimbursed for 80% of the budget (estimated at approximately $317,217). Subsequently, the program was expanded to include an interference test, which helps determine the impact of production pumping on the well field as a whole, and the GRED II program cost was increased to approximately $700,000 with a plan of phased expenditures.

The well workover program began on April 13, 2004, and by May 14 had successfully removed the debris, placed new stingers, and prepared all of the production wells for flow testing. Flow testing and the downhole investigation (pressure and temperature surveys) began on May 18 and were completed on June 21. Each production well was allowed to self- flow for 24-48 hours while fluid flow, temperature and pressure measurements were collected. Thereafter, data from the well testing program was provided to GeothermEx Inc. for analysis. In October 2004, GeothermEx issued a report, “Results From The Short-

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Term Well Testing Program At The Raft River Geothermal Field, Cassia County, Idaho” (a copy is available for review at the company’s principal office). The report concluded that four of the five production wells at Raft River produced commercial amounts of geothermal fluid, and that those four wells could produce a net power capacity (after subtracting the pumping load) of 13.8 MW. Further, for development of the project, GeothermEx estimated that at least one additional injection well would be needed for the project and that a make-up production well will be required after one or two years of operation.

Under federal and state law, GTH is considered to be a “Qualifying Facility.” A Qualifying Facility (or QF) is an electrical power generating plant (as defined by the Federal Regulatory Energy Commission) that qualifies under the Public Utility Regulatory Policy Act (or PURPA). Under PURPA, utility companies are required to purchase at a negotiated rate up to 80 MW facilities from independent power producers which are QFs. Under Idaho law, if a QF does not exceed 10 MW, the power purchase contract will be at the “avoided cost” rate – that is, the rate calculated based on the full cost of power as if the utility were to build a 230 MW combined cycle, natural gas fired power plant. On December 29, 2004, GTH executed a power purchase agreement with Idaho Power Company for a 10 MW power project. The contract is for the electrical output from the first phase of the Raft River Project and has a 20-year term. The electricity price was determined by the Idaho Public Utility Commission (IPUC) under federal PURPA law, using the “avoided cost” rate. Please see the next section entitled “Current Activities” for a more complete discussion of the power purchase agreement and related matters.

A point-to-point transmission request was submitted to Bonneville Power Administration – Transmission for 30 MW of transmission capacity on the 138 kV transmission line that crosses the Raft River property. This request provides the transmission required to deliver power to Idaho Power Company at the Minidoka substation approximately 40 miles north of the project site. Bonneville Power Administration is preparing an interconnect study for the project, which will determine the equipment requirements and cost for our power plant to connect to the transmission system at the Bridge substation, approximately 1.5 miles from the plant site.

Current Activities

Resource Utilization. For the first phase of development at Raft River, the company will commercialize the existing production wells and energy field by construction of a 10 MW geothermal power plant that will provide the energy to be delivered under the power purchase agreement (“PPA”) with Idaho Power Company. The company has extended the period for receipt of final EPC and other construction-related bids (see Engineering/EPC Contract and Project Design , below) from which it intends to finalize construction plans and develop a final term sheet for financing of a power plant by the end of May 2005. A draft term sheet has been provided to potential financing sources to initiate discussions regarding financing structure, and the company anticipates that financing will be completed and initial construction activities can begin by July or August, 2005. Construction is anticipated to take approximately 14 to 16 months (assuming no significant or unusual delays from weather, supply issues or similar events), and the initial power plant would begin production by the late fall or winter of 2006.

Once the initial power plant is completed and achieves commercial operations, the company will seek additional power purchase agreements for future phases, which will involve drilling new wells and determining the production capacity of those wells for additional plant construction. At this time, it is not possible to determine if or when future wells will be drilled. Future phases may involve additional PPA’s with Idaho Power or other utilities in the service area and may or may not include terms similar to the first phase PPA. While the ultimate capacity of the energy resource is not known at this time, the original GeothermEx report suggested that 90 MW of capacity may be possible from GTH’s current land interests in the Raft River project.

Engineering / EPC Contract and Project Design. The first phase plant design will be finalized to meet the requirements of the PPA and form the basis for a request for proposal from engineering and/or engineering-procurement-construction (“EPC”) contractors. GTH is finalizing project design plans for a conventional

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10 MW facility to support the PPA. In addition, GTH is exploring the feasibility of using an advanced power generation process, the ammonia absorption power cycle (AAPC) process, which is a new application of refrigeration technology.

This technology should be more efficient in producing energy from the existing wells, which would provide the ability to obtain energy from the existing wells for a longer period of time, and possibly reduce the number of additional wells that would be necessary for the first phase project and future phases. The U.S. Department of Energy awarded the company a $2.2 million grant in February 2005 to construct a power plant that uses the AAPC process. While very promising and proven in other applications, the AAPC technology is unproven in this application. In order to obtain financing, adequate performance guarantees would be needed from qualified engineering and/or construction companies. The grant would be used to help mitigate the cost of these guarantees. Because the plant and equipment incorporating the advanced power generation process and the conventional technology are approximately 90% the same, the company is able to pursue both paths concurrently. The company expects to receive final bids based on its request for proposal, decide whether to pursue the AAPC technology or the conventional technology, and finalize its plans accordingly, by the end of May 2005. The DOE grant will not be used unless and until the AAPC process is adopted. If conventional technology is used for the power plant, the DOE grant would be terminated.

Power Purchase Agreement. The company signed a power purchase agreement (“PPA”) as a Qualifying Facility on December 29, 2004 with the Idaho Power Company. The PPA forms the basis for the economic development of the first phase of the Raft River project and allows for the arrangement of a financing package to construct the facilities, including the power plant. The PPA has a 20-year term and includes annually adjusted electric power prices based on the avoided cost method, which the company believes will be adequate for the successful development of a 10 MW power plant. Because the PPA is pursuant to PURPA, the total output of the plant must be limited to a maximum of 10MW average each month. In order to protect Idaho Power from unanticipated material fluctuations in supply, the PPA requires GTH to forecast its monthly electrical output in advance (12 months in advance initially, and on a rolling three-month basis thereafter), and if the actual plant output is below 90% or above 110% of the forecasted output, reduced power prices apply. Because the forecasts are done very three months, the company anticipates that it will generally be able to forecast appropriately.

As a “green” power producer, environmental-related credits, such as renewable energy credits or carbon credits, may become available for sale to power companies (to allow them to meet their “green” power requirements) or to businesses which produce carbon based pollution. If available, these credits will belong exclusively to GTH, and may provide an additional source of revenue. Please see the discussion above for further information on PURPA and “Qualifying Facility.”

The company will seek additional power purchase agreements for future phases, which will involve drilling new wells and determining the production capacity of those wells for additional plant construction. At this time it is not possible to estimate if or when future wells will be drilled. Future phases may involve additional PPA’s with Idaho Power or other utilities in the service area and may or may not include terms similar to the first phase PPA.

Transmission / Interconnect Agreement. An updated request for a firm, point-to-point transmission contract for 12 MW was sent to Bonneville Power Administration- Transmission Business Line (TBL) on March 7, 2005 and a contract is expected by the end of May 2005. Preliminary evaluations were completed by TBL and no problems were identified for up to 30 MW of transmission capacity to the delivery point. TBL has preliminarily estimated the cost of the interconnect at $538,000, which is consistent with the company’s estimate. A detailed Interconnection Facility Study is underway by TBL, which will provide final engineering and construction cost for the interconnect. We expect this study to be finalized by the end of 2nd quarter 2005.

Permitting. The company has begun permitting activities, which will be ongoing throughout the execution of the project. Most of the project is on private land and GTH believes the project does not require a federal

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National Environmental Policy Act (“NEPA”) action if conventional technology is used for the power plant. If the AAPC process is used, the DOE grant requires an environmental assessment, which the company has already begun. By so doing, the company anticipates it will minimize any delay that might otherwise result from the permitting activities.

During the Department of Energy’s development of the Raft River project in the early 1980’s, a multi-year survey of land, plant, animal, archeological, weather, and human health survey was undertaken. The DOE published an extensive report in 1982. GTH contacted the Department of the Interior Fish and Wildlife Service regarding any plants or animals in the region that are listed as threatened or endangered species, and received a reply stating that there are no issues identified for the project that require consultation under Section 7 of the Endangered Species Act of 1973, as amended.

TBL has issued a categorical exclusion for modification of the existing substation from the requirements of NEPA. This exclusion fulfills federal environmental permitting requirements for the substation work.

An application for a Conditional Use Permit for construction of the power plant was submitted to the Cassia County Planning and Zoning Commission on February 17, 2005. A hearing before the Commission on the permit is scheduled for April 7, 2005 and the company does not anticipate opposition to the permit. If we use conventional technology for the power plant, only minor air quality permits are anticipated to be necessary. If the AAPC process is used, additional studies to support a permit may take 60 to 90 days, but the company does not anticipate that there will be any problem in obtaining the necessary permits.

Project Financing. Total capital expenditures for the initial power plant are currently projected to be between $24 and $30 million. We expect we will finance the plant through a combination of debt and equity, with the equity portion being up to 50% of the total. We anticipate that some or all of the equity portion may be raised through the exercise of outstanding warrants. Discussions for both construction and long-term financing for the initial facility are currently taking place with potential lending institutions that specialize in power plant project debt financing, as well as investment banking firms interested in raising the equity portion of the capital cost for the project, and with potential participants who may be interested in utilizing tax credits that may be available to the project.

Potential Acquisitions. GTH intends to continue its growth through the acquisition of ownership or leasehold interests in properties that it believes will add to the value of the company’s geothermal resources, and through possible mergers with or acquisitions of operating power plants and advanced geothermal or other renewable energy properties.