US Geothermal Inc.: Form 10-K - Prepared by TNT Filings Inc.

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934
For the fiscal year ended March 31, 2009

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934
For the transition period from ______ to ______

U.S. GEOTHERMAL INC.
(Exact name of Registrant as specified in its charter)

Indicate by check mark if the registrant is well-known seasoned issuer, as defined in Rule 405 of the Securities Act £ Yes Q No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. £ Yes Q No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for at least the past 90 days. Q Yes £ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). £ Yes £ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Q

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). £ Yes Q No

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of June 8, 2009: $110,420,310

Number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date.

This report contains forward-looking statements, including, but not limited to, our statements on strategy, operating forecasts, and our working capital requirements and availability. In addition, from time to time, the company or its representatives have made or may make forward-looking statements, orally or in writing. Such forward-looking statements may be included in, but are not limited to, various filings made by the company with the Securities and Exchange Commission (the “SEC”), press releases or oral statements made by or with the approval of an authorized executive officer of the company. Forward-looking statements consist of any statement other than a recitation of historical fact and can be identified by the use of forward-looking terminology such as “may”, “expect”, “anticipate”, “estimate”, or “continue” or the negative thereof or other variations thereon or comparable terminology. Actual results could differ materially from those projected or suggested in any forward-looking statements as a result of a wide variety of factors and conditions, including, but not limited to, the factors and conditions described in the discussions of “Risk Factors” and “Management’s Plan of Operations” in this report and in other documents the company files from time to time with the Securities and Exchange Commission. The reader is cautioned that the Company does not have a policy of updating or revising forward-looking statements and thus the reader should not assume that silence by management of the Company over time means that actual events are bearing out as estimated in such forward-looking statements.

All references to “dollars” or “$” are to United States dollars and all references to CDN$ are to Canadian dollars.

U.S. Geothermal Inc. (the “Company,” “GTH” or “we” or “us” or words of similar import) is in the renewable “green” energy business. Through its subsidiary, U.S. Geothermal Inc., an Idaho corporation (“Geo-Idaho,” although our references to the Company include and refer to our operations through Geo-Idaho), we are engaged in the acquisition, development and utilization of geothermal resources in the Western Region of the United States of America. Geothermal energy is the natural heat energy stored within the earth’s crust. In some 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.

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 the previous owner, pursuant to which Geo-Idaho agreed to acquire all of the real property, personal property and permits that comprised the owner’s interest in the Raft River project located in southeastern Idaho.

The Company and Geo-Idaho entered into a merger agreement on February 28, 2002, which was amended and restated on November 30, 2003, and closed on December 19, 2003. In accordance with the merger agreement, GTH acquired Geo-Idaho through the merger of Geo-Idaho with a 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.

We currently operate two power plants that include, Raft River Unit I in Idaho (through our joint venture with Raft River I Holdings, LLC, a subsidiary of Goldman Sachs) and a plant located in the San Emidio Desert in Nevada. We also have several other properties under development or exploration. Raft River Unit I commenced commercial operations on January 3, 2008. Raft River Unit I is currently selling between 9.6 and 11.7 megawatts of power to Idaho Power Company under a net 13 megawatt power purchase agreement (“PPA”) which expires in 2032. Management is currently evaluating alternatives to bring the Raft River Unit I plant operations to its nameplate capacity of 13 megawatts.

In May 2008, we acquired the geothermal assets, including a 3.6 net megawatt nameplate generating capacity power plant, from Empire Geothermal Power LLC and Michael B. Stewart, located in Washoe County, Nevada for approximately $16.6 million. The plant currently generates an approximate average net output of 2.5 megawatts, which is sold to Sierra Pacific Power Corporation. With the recent downturn in the economy we have been focusing our efforts on maximizing the available leverage to our existing equity investments and pursuing a development plan with lower risks by avoidance of exploration drilling of production wells. As a result we are planning a “repower” facility at San Emidio which will use the existing geothermal fluid feeding the existing plant to feed a new plant. The plant size is estimated to be 9.4 megawatt and currently is expected to be on line in mid 2011. This plan replaces our original intention to begin development drilling and planning related to the construction of a 27 megawatt facility utilizing twin 13.5 megawatt plants, similar to the 13 megawatt plant at Raft River Unit I, near the existing San Emidio geothermal plant in the third calendar quarter of 2008. When construction of the repower facility is complete, the existing 3.6 megawatt plant may be decommissioned.

Our management examines different factors when assessing potential acquisitions or projects at different stages of development, such as the internal rate of return of the investment, technical and geological matters and other relevant business considerations. We evaluate our operating projects based on revenues and expenses, and our projects under development, based on costs attributable to each project.

We have additional exploration and development properties, Raft River Units II and III in Idaho, Neal Hot Springs in Oregon, potential additional development at San Emidio and energy rights within the Gerlach Known Geothermal Resource Area in Nevada, which we recently entered.

Our business strategy is to identify, evaluate, acquire, develop and operate geothermal assets and resources economically, safely and efficiently. We intend to execute this strategy in several steps outlined below:

We believe our cash and liquid investments at March 31, 2009 are adequate to fund our general operating activities through March 31, 2010. Additional funding will be needed to finance the expansion of production volumes at Raft River, Idaho and the development of the San Emidio, Nevada and Neal Hot Springs, Oregon projects. We anticipate that the additional funding may be raised through the issuance of shares and/or through the sale of ownership interest in tax credits and equity benefits.

The current financial credit crisis is not anticipated to impact the ability of our customers, Idaho Power Company and Sierra Pacific Power, to pay for their power. This power is sold under long-term contracts at fixed prices to large utilities. Projections for 2009 indicate that both projects, Raft River and San Emidio, will generate positive cash flows to the Company. However, the current status of the credit and equity markets could delay our project development activities while the Company seeks to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities. The Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels. We are also pursuing available DOE loan guarantees in order to reduce interest costs for any debt instruments the Company may require. At the current market price for the Company’s stock, we do not anticipate that additional funding will result from the exercise of current stock options or warrants.

In these difficult times, the Company has also implemented procedures to conserve cash, reduce costs and maximize revenue. At the corporate level, we have suspended drilling activities, cancelled non-essential consulting contracts and are reducing all non-critical expenditures. At the project level, Raft River and San Emidio are increasing efforts to reduce operating costs and will continue to find additional cost savings. The Company has instituted a wage and salary freeze for all employees effective January 1, 2009. The wage and salary freeze means that we will not be granting merit pay increases until economic conditions improve and we are able to finance the Company in the equity markets. In addition, the Company has required that employees contribute a share of the medical insurance premiums for dependent coverage. The Company will continue to pay 100% of the insurance premiums for the employees.

We have acquired the geothermal assets of Empire Geothermal Power, LLC and Michael B. Stewart (“Empire Acquisition”) for approximately $16.6 million. This purchase was completed on May 1, 2008. The transaction included an operational geothermal power plant with production and injection wells and a transmission line, ground water rights, and geothermal energy rights to properties in two locations: the San Emidio and the Granite Creek assets. The San Emidio assets are located in the San Emidio Desert, Washoe County, Nevada and include the geothermal power plant project, approximately 22,944 acres (35.9 square miles) of geothermal leases, and associated ground water rights used for cooling water. The Granite Creek assets are comprised of approximately 5,414 acres (8.5 square miles) of BLM geothermal leases located approximately 6 miles north of Gerlach, Nevada along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser. This plant is our second operating geothermal power plant and is owned by a subsidiary of U.S. Geothermal Inc. The power plant sells an annual average of approximately 2.5 megawatts. The plant is approximately 21 years old and employs four binary cycle units. We have conducted a review of the information regarding the project, and we believe that the existing production wells can provide 4,500 to 5,000 gallons per minute of 290 to 300°F fluid to the current power plant. We believe this flow rate and temperature has the potential to generate approximately 10 megawatts using a modern binary cycle power plant.

An independent resource assessment report prepared by Black Mountain Technology in 2008 shows a potential for 44 megawatts of power generation per year for over 30 years. Based on the known 21 year historical production data from this reservoir we believe that the resource can be significantly expanded with the addition of a number of new production and injection wells. The resource is shallow relative to other properties under development by us, which we believe will allow us to utilize this property economically.

The San Emidio plant sells its output to Sierra Pacific Power Corporation pursuant to a power purchase agreement (“PPA”). We have suspended pursuit of a development plan for the San Emidio geothermal resource area for the production of 27 megawatts of power generation due to the current economic slowdown and potential lack of access of capital on terms favorable to the Company. The current plan calls for the construction of a single 9 megawatt plant, similar to the 13 megawatt plant at Raft River Unit I. We expect the existing well field will be able to provide 100% of the plants fuel requirements. We expect to revive the original 27 megawatt plan in the future based on acceptable funding arrangements and will plan to begin drilling a new well field at that time.

Management is currently reviewing alternatives and believes project financing will be available for the 9 megawatt repower development and construction. The method of financing the construction of the new power plant has not yet been determined. We believe the construction cost of the project will be approximately $26 to $28 million.

Neal Hot Springs is a promising geothermal resource located in Eastern Oregon. We acquired the Neal Hot Springs geothermal energy and surface rights in September 2006. The Neal Hot Springs resource is currently under development and no construction decision has been made at this time. Drilling of the first well has been completed. We are currently seeking permits to drill two additional production wells and one injection well. Drilling on the first production well began in April 2008 and was completed in June 2008. The productivity status of the well has been determined by Richard Holt, an independent reservoir engineer, who has calculated the well to be a highly productive single well with a potential to deliver 7.3 MW of power net. As part of our current development plan we expect to drill the two additional production wells and one injection well before being able to confirm the reservoir capacity.

To date, a total of approximately $2.3 million has been expended on the Neal Hot Springs project. We expect additional expenditures of approximately $5 to $6 million to complete drilling of the planned three additional wells and associated flow testing.

While a geothermal resource discovery has been verified, a commercial geothermal reservoir has not yet been proven to exist at Neal Hot Springs. Teplow Geologic performed a preliminary assessment of Neal Hot Springs based on data prepared by Chevron Minerals from drill records from the late 1970s. Teplow concluded that a potential commercially viable geothermal resource exists and recommended a geophysical and geological mapping program. The mapping and geophysical program was completed by Teplow and MWH Geo-Surveys Inc. in February 2007. The geophysical program included use of gravimetric and magnetic mapping to produce a subsurface map of the area’s faults and irregularities. Additionally, water samples from the surface hot springs were analyzed by Thermochem, Inc., and a geothermometer (a chemical based estimate of resource temperature) was calculated which estimated the potential production temperature at 311ºF to 347ºF.

We have prepared a development plan for the Neal Hot Springs geothermal resource area for the target production of 22 megawatts of net power generation. The plan calls for the construction of three modular units each with a 7.33 megawatt capacity. The technology employed in the plant will be different from our Raft River Energy Unit I plant in that the binary cycle will be a supercritical cycle using R134 a refrigerant as the working a fluid. The technology is similar to a refrigeration cycle operating in reverse.

Drilling of the first well was completed in June 2008. This well is located adjacent to the discovery well drilled by Chevron Resources in l979. We have applied for the necessary permits for three more drilling locations that include two more production wells and one injection well. Based on our current understanding of the energy potential at the Neal Hot Springs discovery, we expect that 3 to 4 production and 4 to 5 injection wells with an average depth of about 2,500 to 4,000 feet will be required for the 22 megawatt development. The total drill program for all 7 to 9 wells is expected to take 17 months. Our current plan, assuming successful drilling, finalizing a PPA, signing an EPC contract, and closing of project finance activities, it is possible to start construction by the fourth quarter of 2009 and be online in late 2011. We believe the construction cost of the project, including full financing and other related costs, will be approximately $106 million.

The Company has been selected by the U.S. Department of Energy (“DOE”) to enter into due diligence review on an $85 million project loan for the Neal Hot Springs project located in eastern Oregon. If awarded, the loan is expected to provide 80% of the $106 million estimated total capital cost. The new plant, designed to deliver 22 megawatts of power net to the grid, is scheduled to begin commercial operations in late 2011.

We plan to seek additional PPAs for future phases, which would 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 PPAs with Idaho Power Company or other utilities in the service area and may or may not include terms similar to other PPAs.

The Company purchased the right to a 1,252 acre Bureau of Land Management (“BLM”) geothermal lease for $300,000 in October of 2007. In May of 2008, the Company entered into a joint venture agreement with Gerlach Green Energy LLC of Nevada (“GGE”). The target of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. The joint venture is located near the Company’s Granite Creek leases that were recently acquired as part of the San Emidio geothermal power plant arrangement.

The joint venture agreement establishes a limited liability company named Gerlach Geothermal LLC. The agreement provides the Company with a 60 percent ownership interest in the joint venture through a subsidiary of the Company and provides GGE a 40 percent ownership interest in the joint venture. The Company is required to expend $2,000,000 toward the joint venture, of which $300,000 has already been made by a property contribution of the 1,252 acre BLM geothermal lease. GGE has contributed to the joint venture one BLM geothermal lease and one private geothermal lease. These leases have all had previous geologic work performed including geophysical studies and drilling. The joint venture agreement provides GGE an option to maintain its 40 percent ownership interest by making additional capital contributions as required. If GGE elects to dilute to below a 10 percent interest, their ownership position in the joint venture will be converted to a 10 percent net profits interest. The Company serves as the joint venture manager and will receive a reasonable fee for the services.

The combined joint venture property totals 3,615 acres (5.6 square miles) with 3,415 acres of BLM leases and 200 acres in a private property lease that contains the Great Boiling Springs thermal feature. The geothermal system near Gerlach is well known, with an extensive database from previous studies and exploration drilling and the Company believes the area has significant exploration potential. Gerlach was ranked as the No. 3 top resource in Nevada by the United States Geological Survey in Circular 726, “Assessment of Geothermal Resources of the United States; 1975”, and has estimated potential resource temperatures from geochemical analysis of 338º F to 352º F (USGS Circulars 726 and 790).

At March 31, 2009, the Company had 28 full-time and one part time employee (11 administrative and project development, and 17 field and plant operations). The Company continuously considers acquisition opportunities, and if the Company is successful in making acquisitions, additional management and administrative staff may be added.

The Company did not experience any labor disputes or labor stoppages during the current fiscal year.

The principal product is based upon activities related to the production of electrical power from the utilization of the Company’s geothermal resources. The primary product will be the direct sale of power generated by our interests in our geothermal power plants. Currently our principal revenues consist of energy sales, consulting and management fees, and lease income. All power plants currently being considered and currently under construction are for sites located in the Western Region of the United States of America.

Geothermal energy is natural heat energy stored within the Earth’s crust at economically accessible depth. In some 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.

Electrical power is directly produced through the utilization of geothermal resources; however, these resources are not a direct component of the final product.

Raft River Energy Unit I, located in Idaho is a proven geothermal resource, and has a 13 megawatt geothermal power plant in operation. San Emidio, Nevada is a proven geothermal resource, and has a 3.6 megawatt geothermal plant in operation. Unless major geological changes occur that impact the geothermal reservoirs, the condition of the existing resources is expected to remain consistent over time. Each power plant constructed will have an impact on the temperature and pressure of the tapped reservoir. The extent of this impact and the results of future drilling exploration to determine the actual extent of the reservoir will be a limiting factor on the number of plants that can be constructed at a particular reservoir.

Raft River. Five significant permits are in place for the Raft River project and are necessary for continued operations:

San Emidio. The San Emidio project has five significant permits in place necessary for continued operations:

Generally, the Company’s operations are not significantly impacted by seasonality factors. The Company’s binary geothermal plants can operate more efficiently in cooler temperatures. Cooler temperatures facilitate the cooling process of the secondary fluid that is used to power the turbines. Plant drilling and construction activities could be negatively impacted by inclement weather that can occur, primarily, during the winter months.

The Company is heavily involved in development operations; therefore high levels of working capital are committed, either directly or indirectly to the construction efforts. After a plant becomes commercially operational, the needs of working capital are expected to be low. This assumption is primarily based upon the projected revenues and operational expenses, as well as the actual operating results of the Raft River Unit I for the calendar year ended December 31, 2008. The Company is expecting to be significantly involved in development activities for the next 5 to 10 years.

Ultimately, the market for electrical power is vast; however, the number of entities that can physically, logistically and economically purchase the commodity in large quantities in our area of operations are limited. The Company currently collects revenues from two major sources that include the Idaho Power Company (through the Company’s major subsidiary Raft River Energy Unit I) and Sierra Pacific Power Company. Even at planned levels of operation, it is expected that the Company and its interests will have a small number of direct customers that may amount to less than 4 or 5.

Although the market for different forms of energy is large and dominated by very powerful players, we perceive our industrial competition to be independent power producers and in particular those producers who provide “green” renewable power. Our definition of green power is electricity derived from a source that does not pollute the air, water or earth. Sources of green power, in addition to geothermal, include wind, solar, biomass and run-of-the river hydroelectric. A number of states have instituted renewable portfolio standards (“RPS”) that require utilities to purchase a minimum percentage of their power from renewable sources. For example, RPS statutes in California and Nevada require 20% renewable. On November 17, 2008, the Governor of California signed executive order which mandated a RPS of 33% by 2020 which sits in addition to the 20% order. Acording to the Department of Energy’s Energy Efficiency and Renewable Energy department, utilities in 34 states nationwide are providing their customers with the opportunity to purchase green, renewable power through premium pricing programs. As a result, we believe green power is a niche sub-market, in which many power purchasers are increasing or committing to increase their investments. Accordingly, the conventional energy producers do not provide direct competition.

In the Pacific Northwest there is currently only one geothermal facility (Raft River Energy Unit I). There are a number of wind farms, as well as biomass and run-of-the river hydroelectric facilities. However, the Company believes that the combination of greater reliability and baseload generation from geothermal, access to infrastructure for deliverability, and a low "full life" cost will allow it to successfully compete for long term power purchase agreements.

Factors that can influence the overall market for our product include some of the following:

As the Company’s design and permitting activities have progressed, it has further refined and clarified the environmental issues for which it will have to demonstrate compliance in the construction and operation of a geothermal facility at Raft River. The relevant legislation includes: Clean Air Act, Endangered Species Act, Clean Water Act, Rivers and Harbors Act, National Historic Preservation Act, National Pollutant Discharge Elimination System, Resource Conservation and Recovery Act, Idaho Solid Waste Facilities Act and the IDAPA Drilling for Geothermal Resource Rules.

In preparation for project financing, Raft River Unit I Environmental Site Assessment was completed by Kleinfelder on October 21, 2005. The Unit I assessment identified two underground storage tanks, which have since been removed.

The Raft River project is currently in compliance with all environmental permits and water quality monitoring requirements. The most significant investment in environmental compliance in terms of time and cost was associated with water quality monitoring which had been required on a weekly basis. The Company’s second petition to the Idaho Department of Water Resources (IDWR) to reduce the monitoring obligations was accepted. We anticipate a favorable response from the IDWR. IDWR has concurred that there is no impact from the Company’s operations on adjacent aquifers.

The Raft River project is ideally suited in a rural agricultural area. The nearest full time resident is located over one mile south of the plant. The nearest part time resident is located approximately one half mile north of the plant. Additionally, there are no unique plant or animal communities in the area and no unique cultural or environmental constraints.

As described in detail in the Property section, the Company’s interest in the Raft River Unit I power plant, located in the southeastern part of the State of Idaho, became operational on January 3, 2008. Similar plants are in the planning stages at the same location as well as locations in Nevada and Oregon. The Company acquired a 3.6 megawatt geothermal plant and geothermal rights in San Emidio, Nevada. Land acquisitions and rights have been obtained to explore the development and construction of power plants in the southeastern part of the State of Oregon.

The Company’s revenues for the three most recent fiscal years ended March 31, 2009, 2008 and 2007 were $1,796,387, $184,242, and $90,206; respectively. All of these revenues were attributable to customers in the United States.

We make available, free of charge through our Internet website at http://www.usgeothermal.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Information on our website is not incorporated into this report and is not a part of this report.

U.S. Geothermal Inc. is subject to federal and state regulation in respect of the production, sale and distribution of electricity. Federal legislation includes the Energy Policy Act of 2005, the Federal Power Act, and the Energy Policy Act of 1992. GTH is defined as an independent power producer under the rules and regulations of the Federal Energy Regulatory Commission (“FERC”). As an independent power producer, GTH’s operations are supported by the Public Utility Regulatory Policies Act (“PURPA”) which encourages alternative energy sources such as geothermal, wind, biomass, solar and cogeneration. The State of Idaho also regulates electricity through the Idaho Public Utility Commission (“IPUC”). Regulated utilities have the exclusive right to distribute and sell electricity within their service area. They may purchase electricity in the wholesale market from independent producers like GTH. The IPUC, has the authority to establish rules and regulations governing the sale of electricity generated from alternative energy sources. Regulated utilities are required to purchase electricity on an avoided cost basis from renewable energy facilities, or they may acquire purchased power through bids or negotiated procedures.

On May 8, 2006, GTH submitted proposals to Idaho Power in response to their “Request for Proposal for Geothermal Power.” GTH was the preferred respondent and entered power purchase contract negotiations with Idaho Power. The Raft River Unit I Geothermal Power Plant started up under a contract based on avoided costs which limited the output of the plant to 10 average mega watts per month. Through subsequent contract negotiations, GTH reduced the long-term price of power to Idaho Power, and is now allowed to deliver as much power in any month as the plant is capable of producing, up to a maximum hourly output of approximately 16 mega watts. The annual average output is expected to be on the order of 13 mega watts. This 30 percent increase in plant output would be achieved without major additional power plant capital investment and is expected to decrease the operating cost per kilowatt-hour. Some additional production and injection capacity will have to be developed in order to meet the output targets.

Because carbon regulation is anticipated to increase the cost of power sourced from coal and because there are limited opportunities to purchase baseload geothermal power, GTH has found that utilities across the Western United States are eager to discuss PPAs with GTH.

On February 28, 2008, U.S. Geothermal Inc. and Eugene Water and Electric Board (“EWEB”), from Eugene, Oregon signed a power purchase agreement (“PPA”) for the planned Unit II power plant at Raft River. The PPA allows for variable electrical output up to a maximum of 16 megawatts with a term of 25 years. The PPA is subject to successful drilling and resource development at Raft River. The power will be delivered to BPA’s customer load in Idaho.

The combined sales from the Idaho Power Raft River Unit I contract and the EWEB Unit II contract is anticipated to be 26 megawatts from two plants. Before the burgeoning interest in geothermal power, the Company had originally planned 30 megawatts from three plants. The construction of only two larger plants will result in substantial capital and operating cost savings through improved economy of scale.

In addition to the EWEB agreement, the strong regional interest in geothermal power has resulted in numerous utilities inquiring with GTH to purchase the electrical power output of Unit III at Raft River, for the output of the Neal Hot Springs power plants, and for any expanded output at the company’s San Emidio, NV project. All future plants will be developed under PPAs that do not restrict the output of the project.

GTH will be required to obtain various federal, state and county approvals for construction of future geothermal facilities. These approvals are issued by entities such as the U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency, State (NV, OR, ID) Departments of Environmental Quality, Water Resources, State Historic Preservation Offices, the applicable land management agency, and County Commissioners.

For project development in Idaho and Oregon, David Evans & Associates of Boise, Idaho is providing consulting and engineering services for transmission and interconnection issues. Centra Consulting, Inc. of Boise, Idaho has been retained to assist with State of Idaho air quality and cooling water reuse permitting, and we have retained various environmental engineering firms and regulatory consultants to advise and assist GTH with regard to siting, design and regulatory compliance.

For project development in Nevada, U.S. Geothermal is retaining similar consulting firms to supplement in-house staff.

In the past several years, there has been increased demand for energy generated from geothermal resources in the United States as production costs for electricity generated from geothermal resources have become competitive relative to fossil fuel generation. This is partly due to newly enacted legislative and regulatory incentives, such as production tax credits and state renewable portfolio standards. State renewable portfolio standards laws require that an increasing percentage of the electricity supplied by electric utility companies operating in states with such standards will be derived from renewable energy resources until certain pre-established goals are met. We expect increasing demand for energy generated from geothermal and other renewable resources in the United States as additional states adopt or extend renewable portfolio standards.

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 us, and may provide an additional source of revenue.

We expect the following key incentives to influence our results of operation are:

Production Tax Credits and Investment Tax Credits. Production tax credits provide project owners with a federal tax credit for the first ten years of plant operation. At present, unless extended, facilities constructed after December 31, 2012 will not be eligible to use this production tax credit. The federal production tax credit available for geothermal energy in 2009 was 2.1 cents per kilowatt-hour. For projects under construction before the end of 2010 and online before the end of 2014, a project can elect to take a 30% investment tax credit in lieu of the PTC. The ITC may be converted into a cash grant within the first 6 months of operation of the plant.

Renewable Energy Credits. Renewable Energy Certificates, or RECs, are tradable environmental commodities that represent proof that 1 megawatt-hour of electricity was generated from an eligible renewable energy resource. In states that have a REC program, a renewable energy provider is credited with one REC for every 1,000 kilowatt-hours or 1 megawatt-hour of electricity it produces. The renewable energy is then fed into the electrical grid and the accompanying REC can then be sold on the open market providing the renewable energy producer with an additional source of income.

On July 29, 2006, U.S. Geothermal, Inc. signed a $4.6 million renewable energy credits purchase and sales agreement with Holy Cross Energy, a Colorado cooperative electric association. The agreement is capped at 10 megawatts. Holy Cross Energy began purchasing the renewable energy credits associated with the Raft River Unit I power production on October 2007, and is expected to continue purchasing through 2017. We retain the renewable energy credits associated with power production from Raft River Unit I after 2017. We expect to receive a majority of the annual revenue from the ten-year renewable energy credits sales arrangement with Holy Cross Energy.

Our future performance depends on our ability to establish that the geothermal resource is economically sustainable. Geothermal resource exploration and development involves a high degree of risk. The recovery of the amounts shown for geothermal properties and related deferred costs on our financial statements, as well as the execution of our business plan generally, is dependent upon the existence of economically recoverable and sustainable reserves. Expansion of the production of power from our interests is not certain and depends on successful drilling and discovery of additional geothermal hydrothermal resources in quantities and containing sufficient heat necessary to economically fuel future plants.

We have a need for substantial additional financing and will have to significantly delay, curtail or cease operations if we are unable to secure such financing. The Company requires substantial additional financing to fund the cost of continued development of the Neal Hot Springs (Oregon), San Emidio, Gerlach, and Granite Creek Ranch (Nevada) projects. Also, the Company requires funds for other operating activities, and to finance the growth of our business, including the construction and commissioning of power generation facilities. We may not be able to obtain the needed funds on terms acceptable to us or at all. Further, if additional funds are raised by issuing equity securities, significant dilution to our current shareholders may occur and new investors may get rights that are preferential to current shareholders. Alternatively, we may have to bring in joint venture partners to fund further development work, which would result in reducing our interests in the projects.

We may be unable to obtain the financing we need to pursue our growth strategy in the geothermal power production segment, which may adversely affect our ability to expand our operations. When we identify a geothermal property that we may seek to acquire or to develop, a substantial capital investment will be required. Our continued access to capital, through project financing or through a partnership or other arrangements with acceptable terms is necessary for the success of our growth strategy. Our attempts to secure the necessary capital may not be successful on favorable terms, or at all.

Market conditions and other factors may not permit future project and acquisition financings on terms favorable to us. Our ability to arrange for financing on favorable terms, and the costs of such financing, are dependent on numerous factors, including general economic and capital market conditions, investor confidence, the continued success of current projects, the credit quality of the projects being financed, the political situation in the state in which the project is located and the continued existence of tax laws which are conducive to raising capital. If we are unable to secure capital through partnership or other arrangements, we may have to finance the projects using equity financing which will have a dilutive effect on our common stock. Also, in the absence of favorable financing or other capital options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospects and financial condition.

We may not be able to fully develop the geothermal resource within the Raft River Unit I joint venture boundaries which would increase development costs for Raft River Unit II and result in delays. Raft River Unit II is currently anticipated to be located within the Raft River Unit I joint venture boundaries. Without the agreement and consent of our Raft River Unit I joint-venture partner, Raft River Holdings, we cannot fully develop the geothermal resource within the Raft River Unit I joint venture boundaries without incurring increased development costs and delays.

It is very costly to place geothermal resources into commercial production. Before the sale of any power can occur, it will be necessary to construct a gathering and disposal system, a power plant, and a transmission line, and considerable administrative costs would be incurred, together with the drilling of additional wells. For Raft River Energy Unit I, capital contributions of approximately $52 million were needed. Future expansion of power production at Raft River, Idaho and San Emidio, Nevada and development of new power production capability at Neal Hot Springs may result in significantly increased capital costs related to increased production and injection well drilling and higher costs for labor and materials. To fund expenditures of this magnitude, we may have to find a joint venture participant with substantial financial resources. There can be no assurance that a participant can be found and, if found, it would result in us having to substantially reduce our interest in the project.

We may be unable to realize our strategy of utilizing the tax and other incentives available for developing geothermal power projects to attract strategic alliance partners, which may adversely affect our ability to complete these projects. Part of our business strategy is to utilize the tax and other incentives available to developers of geothermal power generating plants to attract strategic alliance partners with the capital sufficient to complete these projects. Many of the incentives available for these projects are new and highly complex. There can be no assurance that we will be successful in structuring agreements that are attractive to potential strategic alliance partners. If we are unable to do so, we may be unable to complete the development of our geothermal power projects and our business could be harmed.

Our participation in the joint venture is subject to risks relating to working with a co-venturer. Raft River Energy I LLC is the Unit I project joint venture company with Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group Inc. Raft River I Holdings, LLC has contributed a total of $34.2 million in cash and we have contributed over $16.4 million in cash and approximately $1.5 million in production and injection wells and geothermal leases to Raft River Energy I LLC. We are subject to risks in working with a co-venturer that could adversely impact Unit I of the Raft River project as well as anticipated development of Raft River Unit II. We anticipate that the Raft River Unit II power plant may utilize the geothermal resource within the Raft River Unit I joint venture boundaries. Further, our contribution to the joint venture may exceed returns from the joint venture, if any.

We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the projects they operate. We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow. Our subsidiaries and projects may be restricted in their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses or debt service.

We may not be able to manage our growth due to the commencement of operations of the Raft River and San Emidio power plants and exploration activities in Neal Hot Springs which could negatively impact our operations and financial condition. Significant growth in our operations will place demands on our operational, administrative and financial resources, and the increased scope of our operations will present challenges to us due to increased management time and resources required and our existing limited staff. Our future performance and profitability will depend in part on our ability to successfully integrate the operational, financial and administrative functions of Raft River and San Emidio and other acquired properties into our operations, to hire additional personnel and to implement necessary enhancements to our management systems to respond to changes in our business. There can be no assurance that we will be successful in these efforts. Our inability to manage the increased scope of operations, to integrate acquired properties, to hire additional personnel or to enhance our management systems could have a material adverse effect on our results of operations.

If we incur material debt to fund our business, we could face significant risks associated with such debt levels. We will need to procure significant additional financing to construct, commission and operate our power plants in order to generate and sell electricity. If this financing includes the issuance of material amounts of debt, this would expose the Company to risks including, among others, the following:

In such event, we cannot assure you that we would have sufficient funds available or could obtain the financing required to meet our obligations, including the repayment of outstanding principal and interest on such indebtedness.

We may not be able to successfully integrate companies that we may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow. Our strategy is to continue to expand in the future, including through acquisitions. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:

If any of our acquired companies suffers performance problems, the same could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.

The success of our business relies on retaining our key personnel. We are dependent upon the services of our President and Chief Executive Officer, Daniel J. Kunz, our Chief Financial Officer, Kerry D. Hawkley, our Chief Operating Officer, Douglas J. Glaspey, and Kevin R. Kitz, our Vice President – Project Development. The loss of any of their services could have a material adverse effect upon us. As of the date of this report, the Company has executed employment agreements with these persons, except Mr. Kunz, but does not have key-man insurance on any of them.

Our development activities are inherently very risky. The high risks involved in the development of a geothermal resource cannot be over-stated. The development of geothermal resources at our Raft River, Idaho; San Emidio, Nevada and Neal Hot Springs, Oregon projects are such that there cannot be any assurance of success. Exploration costs are high and are not fixed. The geothermal resource cannot be relied upon until substantial development, including drilling, has taken place. The costs of development drilling are subject to numerous variables such as unforeseen geologic conditions underground which could result in substantial cost overruns. Drilling for geothermal resource at Raft River is relatively deep with the average depth of wells some 6,000 feet. Drilling at Neal Hot Springs, Raft River and San Emidio may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.

Our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond our control, including economic conditions, mechanical problems, title problems, weather conditions, compliance with governmental requirements and shortages or delays of equipment and services. If our drilling activities are not successful, we could experience a material adverse effect on our future results of operations and financial condition.

In addition to the substantial risk that wells drilled will not be productive, or may decline in productivity after commencement of production, hazards such as unusual or unexpected geologic formations, pressures, downhole conditions, mechanical failures, blowouts, cratering, explosions, uncontrollable flows of well fluids, pollution and other physical and environmental risks are inherent in geothermal exploration and production. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations.

The impact of governmental regulation could adversely affect our business by increasing costs for financing or development of power plants. Our business is subject to certain federal, state and local laws and regulations, including laws and regulations on taxation, the exploration for and development, production and distribution of electricity, and environmental and safety matters. On a Federal level, the most important tax rule that affects our business is the Production Tax Credit (“PTC”), which was extended to December 31, 2012. Recent legislation enacted as part of the stimulus funding has also provided an election to take 30% investment tax credit in lieu of the PTC for certain qualified investments being initiated before the end of 2010 and being placed in service before the end of 2014. The loss of the PTC or ITC is a risk that could result in making future expansions at Raft River, San Emidio and at Neal Hot Springs uneconomic. New rules recently adopted by the Bureau of Land Management, as directed by the Energy Policy Act of 2005, require competitive auction of all geothermal leases on Federal lands. Competitive leasing is significantly increasing the cost of obtaining leases on Federal land, is adding to the capital costs needed to develop geothermal projects, is increasing the total electrical power prices needed to make a geothermal project viable and is making it more difficult to acquire additional adjacent lands for reservoir protection and exploration.

If Federal lands or any Federal involvement are included in any geothermal development, requirements of the National Environmental Policy Act ("NEPA") will be triggered. Most of the geothermal resource in the United States is located in the western states, where the Federal Government often is the largest landowner. If a NEPA action is triggered, such as an Environmental Impact Statement or Environmental Assessment, a project delay of one to two years and a cost of $1,000,000 to $2,000,000 or more may be incurred while the environmental permitting process is completed. NEPA not only can impact the property where the geothermal resource is located, but includes the siting and construction of transmission lines. Environmental legislation is evolving in a manner that means stricter standards, and enforcement, fines and penalties for non-compliance are more stringent. Environmental assessments of proposed projects carry a heightened degree of responsibility for companies and directors, officers and employees. The cost of compliance with changes in governmental regulations has a potential to reduce the profitability of operations.

In the states of Idaho, Nevada and Oregon, drilling for geothermal resources is governed by specific rules. In Nevada drilling operations are governed by the Division of Minerals (Nevada Administrative Code Chapter 534A); in Idaho by the Idaho Department of Water Resources (IDAPA 37 Title 03 Chapter 04); and in Oregon by the Division of Oil, Gas and Mineral Industries (Division 20 Geothermal Regulation). These rules require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters, and, may not allow or may restrict drilling activity, or may require that a geothermal resource be unitized (shared) with adjoining land owners. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our geothermal wells, the power plant and other facilities. State environmental requirements and permits, such as the Idaho Department of Environmental Quality, Air Quality Permit to Construct, include public disclosure and comment. It is possible that a legal protest could be triggered through one of the permitting processes that would delay construction and increase cost for one of our projects. The state of Oregon has an Energy Facility Siting Council that must issue a site certificate for any geothermal energy facilities of 35 megawatts or higher which could affect the Neal Hot Spring project by adding additional cost and delay construction.

Because of these state and federal regulations, we could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil or water, including responsibility for remediation costs. We could potentially discharge such materials into the environment:

Because the requirements imposed by such laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business by increasing cost and the time required to explore and develop geothermal projects. In addition, because the Vulcan Property at Raft River was previously operated by others, we may be liable for environmental damage caused by such former operators.

Industry competition may impede our growth and ability to enter into power purchase agreements on terms favorable to us, or at all, which would negatively impact our revenue. The electrical power generation industry, of which geothermal power is a sub-component, is highly competitive and we may not be able to compete successfully or grow our business. We compete in areas of pricing, grid access and markets. The industry in the Western United States, in which the Raft River and San Emidio projects are located, is complex as it is composed of public utility districts, cooperatives and investor-owned power companies. Many of the participants produce and distribute electricity. Their willingness to purchase electricity from an independent producer may be based on a number of factors and not solely on pricing and surety of supply. If we cannot enter into power purchase agreements on terms favorable to us, or at all, it would negatively impact our revenue and our decisions regarding development of additional properties.

Some of our leases will terminate if we do not achieve commercial production during the primary term of the lease, thus requiring us to enter into new leases or secure rights to alternate geothermal resources, none of which may be available on terms as favorable to us as any such terminated lease, if at all. Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as we achieve commercial production or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet achieved commercial production of the geothermal resources. Leases that cover land which remains undeveloped and does not achieve commercial production and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable project is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from, or inject geothermal resources into, such premises or secure rights to alternate geothermal resources or lands suitable for injection, all of which may not be possible or could result in increased cost to us, which could materially and adversely affect our business, financial condition, future results and cash flow.

Claims have been made that some geothermal plants cause seismic activity and related property damage. There are approximately two-dozen geothermal plants operating within a fifty-square-mile region in the area of Anderson Springs, in Northern California, and there is general agreement that the operation of these plants causes a generally low level of seismic activity. Some residents in the Anderson Springs area have asserted property damage claims against those plant operators. There are significant issues whether the plant operators are liable, and to date no court has found in favor of such claimants. While we do not believe the areas of the Raft River, Idaho, San Emidio, Nevada and Neal Hot Springs, Oregon will present the same geological or seismic risks, there can be no assurance that we would not be subject to similar claims and litigation, which may adversely impact our operations and financial condition.

Actual costs of construction or operation of a power plant may exceed estimates used in negotiation of power purchase and power financing agreements. The Company’s initial power purchase contract is under rates established by the Idaho Public Utility Commission, using an “avoided-cost” model for cost of construction and operating costs of power plants. If the actual costs of construction or operations exceed the model costs, the Company may not be able to build the contemplated power plants, or if constructed, may not be able to operate profitably. The Company’s financing agreements provide for a priority payback to our partner. If the actual costs of construction or operations exceed the model costs, we may not be able to operate profitably or receive the planned share of cash flow and proceeds from the project. The actual costs of operating the Raft River power project are higher than the original estimate due to several factors including the need to filter the ground water for cooling to remove harmful and unanticipated chloride levels in the water, the need to purchase production pump power from a third party to provide maximum plant output, and increased general costs related to labor and management.

Payments under our initial power purchase agreement may be reduced if we are unable to forecast our production adequately. Under the terms of our initial power purchase agreement, and starting with the third year of operation, if we do not deliver electricity output within 90% to 110% of our forecasted amount, which requires us to submit a forecast every three months, payments for the amount delivered will be reduced, possibly significantly. For example if the plant produces more than 110% of the power as forecasted then we would not receive any revenue for the amount over the forecast figure. If the plant produces less than 90% of the forecast amount for unexcused reasons, such as normal plant breakdowns and maintenance, then we may be subject to a reduced power price, depending on the prevailing power market conditions. The agreement moves the power price to the market price instead of contracted price. We currently expect to forecast 9 megawatts of delivery on a 10-megawatt plant and the damages would then result if the actual delivery was only 8.1 megawatts or less. All 8.1 megawatts would be subject to a reduced price that is not possible to predict at this time. The total average revenue per megawatt hour is approximately $62.40 and the reduction in revenue could be perhaps 30 percent of that amount. As a risk mitigation element, we are not subject to this adjustment until year three of the contract and then we are able to submit a new forecast every three months thereby limiting this exposure.

There are some risks for which we do not or cannot carry insurance. Because our current operations are limited in scope, the Company carries property, public liability insurance and directors’ and officers’ liability coverage, but does not currently insure against any other risks.

As its operations progress, the Company will acquire additional coverage consistent with its operational needs, but the Company may become subject to liability for pollution or other hazards against which it cannot insure or cannot insure at sufficient levels or against which it may elect not to insure because of high premium costs or other reasons. In particular, coverage is not available for environmental liability or earthquake damage.

Our officers and directors may have conflicts of interests arising out of their relationships with other companies. Several of our directors and officers serve (or may agree to serve) as directors or officers of other companies or have significant shareholdings in other companies. To the extent that such other companies may participate in ventures in which the Company may participate, the directors may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. From time to time several companies may participate in the acquisition, exploration and development of natural resource properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment.

Failure to comply with regulatory requirements may adversely affect our stock price and business. As a public company, we are subject to numerous governmental and stock exchange requirements, with which we believe we are in compliance. The Sarbanes-Oxley Act of 2002 and the Securities and Exchange Commission (SEC) have requirements that we may fail to meet by the required deadlines or we may fall out of compliance with, such as the internal controls assessment, reporting and auditor attestation required under Section 404 of the Sarbanes-Oxley Act of 2002. The Company has documented and tested its internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”). SOX requires an annual assessment by management of the effectiveness of the Company’s internal control over financial reporting and an attestation report by the Company’s independent auditors on internal controls over financial reporting. We may incur additional costs in order to comply with Section 404. In addition, if we fail to achieve and maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act of 2002. Moreover, effective internal controls are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could drop significantly. Our failure to meet regulatory requirements and exchange listing standards may result in actions such as the delisting of our stock impacting our stock’s liquidity; SEC enforcement actions; and securities claims and litigation.

A significant number of shares of our common stock are eligible for public resale. If a significant number of shares are resold on the public market, the share price could be reduced and could adversely affect our ability to raise needed capital. The market price for our common stock could decrease significantly and our ability to raise capital through the issuance of additional equity could be adversely affected by the availability and resale of such a large number of shares in a short period of time. If we cannot raise additional capital on terms favorable to us, or at all, it may delay our exploration or development of existing properties or limit our ability to acquire new properties, which would be detrimental to our business.

Because the public market for shares of our common stock is limited, investors may be unable to resell their shares of common stock. There is currently only a limited public market for our common stock on the Toronto Stock Exchange in Canada and on the NYSE Amex in the United States, and investors may be unable to resell their shares of common stock. The development of an active public trading market depends upon the existence of willing buyers and sellers that are able to sell their shares and market makers that are willing to make a market in the shares. Under these circumstances, the market bid and ask prices for the shares may be significantly influenced by the decisions of the market makers to buy or sell the shares for their own account, which may be critical for the establishment and maintenance of a liquid public market in our common stock. We cannot give you any assurance that an active public trading market for the shares will develop or be sustained.

The price of our common stock is volatile, which may cause investment losses for our shareholders. The market for our common stock is highly volatile, having ranged in the last fiscal year ended March 31, 2009, from a low of $0.46 CDN to a high of $3.02 CDN on the TSX Exchanges and from a low of $0.39 to a high of $2.95 on the NYSE Amex. The trading price of our common stock on the TSX Exchange and on the NYSE Amex is subject to wide fluctuations in response to, among other things, quarterly variations in operating and financial results, and general economic and market conditions. In addition, statements or changes in opinions, ratings, or earnings estimates made by brokerage firms or industry analysts relating to our market or relating to our company could result in an immediate and adverse effect on the market price of our common stock. The highly volatile nature of our stock price may cause investment losses for our shareholders.

We do not intend to pay any cash dividends in the foreseeable future. We intend to reinvest any earnings in the development of our projects. Payments of future dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including our business, operating results and financial condition, current and anticipated cash needs, plans for expansion and any legal or contractual limitations on our ability to pay dividends.

Provisions in our bylaws and under Delaware law could discourage a takeover that stockholders may consider favorable. Our bylaws contain provisions that could depress the trading price of our common stock by acting to discourage, delay or prevent a change of control of our company or changes in our management that the stockholders of our company may deem advantageous. These provisions prohibit stockholders from calling special meetings, which may deter a takeover attempt. Additionally, we are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any holder of 15% or more of our capital stock for a period of three years following the date on which the stockholder acquired such ownership percentage, unless, among other things, our Board of Directors has approved the transaction. This statute likewise may discourage, delay or prevent a change of control.

The Company has interests in three areas in the Western United States. These interests include the Raft River area located in southeastern Idaho, the Neal Hot Springs area located in eastern Oregon (near the Idaho/Oregon boarder), and our interests located in northwestern Nevada. The properties in northwestern Nevada include San Emidio, Gerlach and Granite Creek. The Company currently has two commercially operational power plants. Unit I at Raft River became commercially operational on January 3, 2008. The San Emidio plant was acquired in the Empire Acquisition.

The Raft River project, where the company’s geothermal operations are located, is in southeastern 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.

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 approximately 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 ten parcels (generally referred to as the U.S. Geothermal Property, the Crank Lease, the Newbold Lease, the Jensen Investments Leases, the Stewart Lease, the Bighorn Mortgage Lease, the Doman Lease, the Griffin Lease, and the Glover Lease) comprising 783.93 acres of fee land and 4,736.79 acres of contiguous leased geothermal rights located on private property in Cassia County, Idaho. All parcels are defined by legal subdivision or by metes and bounds survey description. The ten parcels are as follows:

The U.S. Geothermal Property - Idaho. The U.S. Geothermal Property is comprised of three separate properties that total 783.93 acres: the Vulcan Property, the Elena Corporation Property and the Dewsnup property. The Vulcan Property includes both surface and geothermal rights and consists of two parcels. The first parcel has a total area of approximately 240 acres and three geothermal wells (RRGE-1, RRGP-4 and RRGP-5) are located on this parcel. The second parcel has a total area of approximately 320 acres, and 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 Elena Property is comprised of surface and geothermal rights to approximately 100 acres of property, excluding the oil and gas rights to the property. The property is contiguous to other properties owned or leased by the company.

The Dewsnup Property is comprised of the surface and geothermal rights to approximately 123.93 acres of property, excluding the oil and gas rights to the property, but including all surface water rights. The property is contiguous to other properties owned or leased by the company.

The Crank Lease. The Crank lease covers approximately 160 acres of mineral and geothermal rights, with right of ingress and egress.

The Newbold Lease. The Newbold lease covers approximately 20 acres of both surface and geothermal rights.

The Jensen Investments Leases. The first Jensen Investments lease covers approximately 2,954.75 acres of geothermal rights only. It is contiguous with the Vulcan Property and property covered by the Crank and Stewart leases. The second Jensen Investments lease covers approximately 44.5 acres of surface and geothermal rights, and is contiguous with property covered by the first Jensen lease.

The Stewart Lease. The Stewart Lease covers approximately 317.54 acres on two adjoining parcels. Parcel 1 contains approximately 159.04 acres and includes surface and geothermal rights. Parcel 2 contains approximately 158.50 acres and only covers surface rights. The underlying geothermal rights for Parcel 2 are subject to the first Jensen Investments Lease.

The Bighorn Mortgage Lease. The Bighorn Mortgage lease covers approximately 280 acres of surface and geothermal rights.

The Doman Lease. The Doman lease covers approximately 640 acres of surface and geothermal rights, excluding oil and gas rights.

The Griffin Lease. The Griffin lease contains approximately 160 acres of geothermal rights.

The Glover Lease. The Glover lease contains approximately 160 acres of geothermal rights.

BLM Lease. The geothermal resources lease agreement with the United States Department of Interior Bureau of Land Management (BLM) was entered into on August 1, 2007. The lease is for approximately 1,685 acres of land located contiguous to the Raft River Property in southeastern Idaho.

Unit I at Raft River became commercially operational on January 3, 2008. As a result of the project financing for Unit I of the Raft River project, the Company has contributed over $17.9 million in cash and property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River Holdings, an affiliate of Goldman Sachs Group, has contributed approximately $34 million to the project. Property assigned to Raft River Energy by the Company includes seven production and injection wells, seven monitoring wells, the Stewart lease, the Crank lease, the Newbold lease, the Doman lease, and the Glover lease. All appropriate permits and contracts have also been assigned to Raft River Energy for Unit I.

Although significant detail has been provided about each specific lease area, the economics of the project is based on the total resource. The reservoir supporting the project encompasses the entire Known Geothermal Resource Area (KGRA), which includes all the property owned or leased by the company at Raft River. All discussions of the economics of the project, including future phases, will be based at the project level rather than at the lease level.

The Crank lease, the Newbold lease, the Jensen Investments leases, the Bighorn Mortgage lease, the Doman lease, the Griffin lease and the Glover lease have 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 (RRGE-2) located on lessor’s property was not owned by the lessor (but instead was included in the Vulcan Property), a new lease was entered into on June 28, 2003, which excluded the ownership of RRGE-2, 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 have been recorded as lease expense. When commercial production is attained, these lease payments can be deducted from future production royalties. For later years, during commercial production, there is a minimum annual production royalty of $18,000. If the initial commercial production from the well is delayed past the primary lease term, we will seek an amendment to extend the primary term to the initial commercial plant production date. 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 is extended indefinitely so long as production from the geothermal field is maintained. Minimum lease payments are as follows:

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

The Jensen Investments Leases. The first Jensen Investments lease was originally with Sergene Jensen, as lessor, is dated July 11, 2002, and has a primary term of 10 years. In September 2005, the property subject to the lease was conveyed and the lease was assumed by Jensen Investments, Inc. Minimum lease payments (on a July to July basis) are as follows:

The minimum amount that will be payable over the course of the lease is $81,256. Maximum amounts payable will depend on production from the property. The second Jensen Investments lease, with Jensen Investments, Inc., is dated July 12, 2002, and has a primary term of 10 years. Minimum lease payments (on a July to July basis) are as follows:

The minimum amount that will be payable over the course of the lease is $1,224. Maximum amounts payable will depend on royalties on production from the property.

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

The minimum amount that will be payable over the course of the lease is $319,614. Maximum amounts payable will depend upon royalties on production from the property.

The Bighorn Mortgage Lease. The Bighorn Mortgage lease, with Bighorn Mortgage Corporation, is dated July 5, 2005, and has a primary term of 10 years. Minimum lease payments are as follows:

The minimum amount that will be payable over the course of the lease is $17,500. Maximum amounts payable will depend upon royalties on production from the property.

The Doman Lease. The Doman lease, with Dale and Ronda Doman, is dated June 23, 2005, and has a primary term of 10 years. Minimum lease payments are as follows:

The minimum amount that will be payable over the course of the lease is $24,000. Maximum amounts payable will depend upon royalties on production from the property.

The Griffin Lease. The Griffin lease, with Michael and Cleo Griffin, Harlow and Pauline Griffin, Douglas and Margaret Griffin, Terry and Sue Griffin, Vincent and Phyllis Jorgensen, and Alice Mae Griffin Shorts, is dated June 23, 2005, and has a primary term of 10 years. Minimum lease payments are as follows:

The minimum amount that will be payable over the course of the lease is $10,800. Maximum amounts payable will depend upon royalties on production from the property.

The Glover Lease. The Glover lease, with Philip Glover, is dated January 25, 2006, and has a primary term of 10 years. Minimum lease payments are as follows:

The minimum amount that will be payable over the course of the lease is $20,500. Maximum amounts payable will depend upon royalties on production from the property.

The total minimum amount payable under all of the leases during their primary terms is $522,393. The above listed lease payments are payable annually in advance, and are current through lease years beginning in 2005. The leases can be renewed for extended periods as long as the power plant continues to produce power.

With the construction of the power plant included in Unit I of the Raft River project, management has increased the general liability and umbrella liability insurance coverage, as deemed necessary. Additional builders risk insurance will be obtained prior to construction of the power plant.

BLM Lease. The lease has a primary term of 10 years. After the primary term, the Company has the right to extend the contract in accordance with regulation 43 CFR subpart 3207. The lease calls for annual payments of $3,502 including processing fees. BLM has the right to terminate the contract upon written notice if the Company does not comply with the terms of the agreement. The royalty rate is based upon 10% of the value of the resource at the well head.

The amounts are calculated according to a formula established by Minerals Management Service (“MMS”).

Neal Hot Springs is a promising geothermal resource located in Eastern Oregon. We acquired certain of the Neal Hot Springs geothermal energy and surface rights in September 2006. It is currently under development and no construction decision has been made at this time.

The first production well was completed in June 2008. A step-rate flow test, with pressure buildup, was conducted for 12 hours on July 12, 2008 and resulted in a flowing production temperature of 286.5º F (141º C). The well flowed under artesian pressure at a peak rate of 2,055 gallons per minute (“gpm”) at artesian pressure and then was stepped down to a lower flow rate of 1,210 gpm before it was shut in and the pressure buildup monitored. Richard Holt of Geothermal Science, Inc., an independent geothermal reservoir engineer, calculated a well productivity index of 450 gpm/psi, which is considered to be very high in the geothermal industry. We are currently seeking permits for drilling two additional production wells and one injection well.

Cyprus Gold Exploration Corporation. The lease is for mineral rights for 4,960 acres located in Malheur County, Oregon is dated January 24, 2007, and has a primary term of 10 years, and expires January 24, 2017. Minimum lease payments are as follows:

The agreement defines a royalty rate is based upon 2% of the actual revenue for the first 10 years of commercial production and 3% thereafter.

JR Land and Livestock. The lease is for mineral rights for 4,960 acres located in Malheur County, Oregon is dated January 24, 2007, and has a primary term of 10 years, and expires January 24, 2017. Minimum lease payments are as follows:

The agreement defines a royalty rate is based upon 3% of the gross proceeds for the first 5 years of commercial production, 4% of gross proceeds for the next 10 years, and 5% of the gross proceeds thereafter.

Effective May 1, 2008, the Company acquired a 3.6 megawatt operating geothermal power plant and approximately 28,358 acres (44.3 square miles) of geothermal energy leases and certain ground water rights all located north of Reno, Nevada. The total purchase price was $16.6 million. The assets are comprised of two locations: the San Emidio assets and the Granite Creek assets. The San Emidio assets are located in the San Emidio Desert, Washoe County, Nevada and include the geothermal power project, approximately 22,944 acres (35.9 square miles) of geothermal leases, and ground water rights used for cooling water. The Granite Creek assets are comprised of approximately 5,414 acres (8.5 square miles) of BLM geothermal leases located about 6 miles north of Gerlach, Nevada along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser.

The 3.6 -megawatt geothermal power plant has been producing power since 1987 and sells electricity to Sierra Pacific Power Corporation under an existing power purchase agreement that extends through 2017. A March 2008 resource assessment of the San Emidio geothermal leases by independent experts Susan Petty and Dennis Trexler of Black Mountain Technology shows a total resource potential of 44 megawatts with a 90% probability factor.

The power plant was constructed in 1986 with commercial power generation beginning in 1987. Deeper wells with higher temperatures were drilled in 1994 to supply the plant after output declined due to cooling of the original, shallow production wells. The current configuration of the plant consists of four 1.2 megawatt Ormat Energy Converters, three injection wells and four production wells. A three cell cooling tower was added in 1998 to improve summer power generation. The plant is connected to the transmission grid via a 60 kilovolt intertie.

San Emidio is our second operating geothermal power plant and is owned by a wholly owned subsidiary of the Company (USG Nevada LLC). The project is a small-scale geothermal power plant selling approximately three megawatts. The plant is approximately 22 years old and employs four binary cycle units. We have conducted a review of the information regarding the project, and we believe that the existing production wells can provide 4,000 to 5,000 gallons per minute of 280 to 300 °F fluid to the current power plant.

BLM Leases. At the closing of the Empire Acquisition, the geothermal leases with the BLM were assigned to the Company. The lease contracts are for approximately 21,905 acres of land and geothermal rights located in the San Emidio Desert, Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases require the lessee to conduct operations in a manner that minimizes adverse impacts to the environment.

The BLM lease contracts require royalty payments for the use of geothermal resources. The rate is based upon 10% of the value of the resource at the well head. The amounts are calculated according to a formula established by MMS.

Kosmos Lease. This is a geothermal resource lease agreement for 1,040 acres with The Kosmos Company (“Kosmos”). The lease has been in effect since October l987 and continues so long as the lessee is drilling for, producing geothermal power, or conducting remedial operations. Under the terms of the first amendment to the lease which became effective upon our acquisition of the San Emidio Geothermal assets, Kosmos will be paid the greater of $8,000 per month or 3.5% of the gross sales price of electric power from fluids produced and injected until the proposed new power plant achieves commercial operation. When a new power plant is installed and producing commercial power, the royalty will change to 1.75% of the gross sales price of electric power sold by the lessee for 120 months and 3.5% thereafter.

In May 2008, the Company entered into a joint venture agreement with Gerlach Green Energy LLC of Nevada to form a limited liability company named Gerlach Geothermal LLC. The joint venture owns geothermal rights for 3,615 acres (5.6 square miles) located in northwestern Nevada near the town of Gerlach. The target of the joint venture is the exploration of the regional Gerlach geothermal system. The joint venture is located near the Company’s Granite Creek leases that were recently acquired as part of the San Emidio geothermal power plant acquisition.

BLM Leases. The Gerlach Geothermal LLC assets are comprised two BLM geothermal leases and one private lease totaling 3,615 acres. Both BLM leases have a royalty rate is based upon 10% of the value of the resource at the wellhead. The amounts are calculated according to a formula established by MMS. One of the two BLM leases has a second royalty commitment to a third party of 4% of gross revenue for power generation and 5% for direct use based on BTUs consumed at a set comparable price of $7.00 per million BTU of natural gas. The private lease has a 10 year primary term and would receive a royalty of 3% gross revenue for the first 10 years and 4% thereafter.

The Granite Creek assets are comprised of approximately 5,414 acres (8.5 square miles) of BLM geothermal leases located about 6 miles north of Gerlach, Nevada along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser.

BLM Leases. The Company has three geothermal lease contracts with the BLM. The lease contracts are for approximately 5,414 acres of land and geothermal water rights located in the northwestern Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases state annual lease payments of $5,414, not including processing fees, and expire October 31, 2012.

The Company entered into a 3 year lease contract effective January 1, 2008 through January 31, 2011, for general office space for an executive office located in Boise, Idaho. The lease payments are due in monthly installments that start at $5,637 per month and increase annually to $5,981 per month.

As of May 31, 2009, management is not aware of any material current or pending legal proceedings in which the Company is a party, as plaintiff or defendant, or which involve any of its properties.

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

From June 3, 2005 to April 15, 2008, the common stock of U.S. Geothermal Inc. was quoted on the Over-The-Counter Bulletin Board (the “Bulletin Board”) under the trading symbol “UGTH”. Effective April 14, 2008, the common stock of U.S. Geothermal Inc. began trading on the American Stock Exchange, now the NYSE Amex Equities, under the trade symbol “HTM.” Future trading prices of our common shares will depend on many factors, including, among others, our operating results and the market for similar securities.

The following sets forth information relating to the trading of our common stock from April 1, 2007.

Bid Prices on the Over-The-Counter Bulletin and NYSE Amex
Fiscal Year Ended March 31, 2008
First Quarter	2.70	1.37
Second Quarter	3.10	1.85
Third Quarter	4.78	2.56
Fourth Quarter	4.09	2.07

Fiscal Year Ended March 31, 2009
First Quarter *	2.95	2.18
Second Quarter	2.52	1.51
Third Quarter	1.73	0.39
Fourth Quarter	1.16	0.60

* - The Company’s common shares began trading on the NYSE Amex on April 14, 2008.

The Company’s common shares began trading on the Toronto Stock Exchange (“TSX”) on October 1, 2007, under the symbol “GTH.” Prior to trading on the TSX, the Company’s common shares were traded on the TSX Venture Exchange through September 28, 2007 under the same symbol. TSX is the senior equity market in Canada. TSX Venture Exchange is a segment of the Toronto Stock Exchange Group that provides the global financial community with access to Canada's equity capital and energy markets. The TSX Venture Exchange provides access to capital for companies at the early stages of their growth while offering investors a well-regulated market for making venture investments. The following sets forth information relating to the trading on the TSX and TSX Venture Exchange:


Sales Prices on the TSX and TSX Venture Exchanges (CDN$)
Fiscal Year Ended March 31, 2008
First Quarter	2.80	1.59
Second Quarter	3.19	1.99
Third Quarter *	4.75	2.56
Fourth Quarter	4.05	2.00

Fiscal Year Ended March 31, 2009
First Quarter	3.02	2.28
Second Quarter	2.47	1.57
Third Quarter	1.84	0.46
Fourth Quarter	1.40	0.76

* - The Company’s common shares began trading on the TSX on October 1, 2007, and the Company’s common shares ceased trading on the TSX Venture Exchange on September 28, 2007.

The Company has never paid and does not intend to pay dividends on our common stock in the foreseeable future. Although the Company’s articles of incorporation and by-laws do not preclude payment of dividends, we currently intend to retain any future earnings for reinvestment in our business. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements and other relevant factors. All of the common shares are entitled to an equal share in any dividend declared and paid.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

U.S. Geothermal Inc. is a Delaware corporation. The Company’s shares of common stock trade on the TSX under the symbol “GTH” and on the NYSE Amex under the trade symbol “HTM”. On December 19, 2003, the Company acquired all of the outstanding securities of U.S. Geothermal Inc., an Idaho corporation (“Geo-Idaho”) incorporated in February 2002, through a transaction merging Geo-Idaho into Evergreen Power Inc., a wholly-owned Idaho subsidiary formed for purposes of the merger transaction. Following the merger, the Company changed its name from U.S. Cobalt Inc. to U.S. Geothermal Inc. Pursuant to the merger, Geo-Idaho became the surviving subsidiary of the Company, and Evergreen Power, Inc. ceased to exist. GTH is still, primarily, a development stage company and has just started receiving revenues from operating activities.

Raft River Unit I achieved commercial operation on January 3, 2008. During 2008, Raft River operated at 95 percent availability and averaged 9.8 megawatts for the year. A reverse osmosis filter system was added to the cooling water system for the removal of higher than anticipated levels of chloride, which would damage plant equipment.

The Company has assembled a team of seven qualified technicians for the ongoing operation and maintenance of the Unit I power plant and planned future power plant units at Raft River. The team underwent operator training from Ormat and is currently operating the plant unassisted.

With carbon regulation widely anticipated to increase the cost of power sourced from coal, and limited opportunities to purchase baseload geothermal power, the Company has found that utilities across the Western United States have been eager to discuss power purchases from the Raft River geothermal resource. As a result of the increased interest, U.S. Geothermal elected to withdraw its Raft River Unit II and Unit III Idaho Power PPAs without submitting them to the Idaho Public Utility Commission (“IPUC”) for approval in order to pursue larger capacity PPAs with other utilities. With the concurrence of Idaho Power, the Unit II and Unit III 10 megawatt contracts were voided without further obligation on either party.

On September 26 2007, Idaho Power Company and the Company announced the signing of a new, 13-megawatt, full output power purchase agreement. Idaho Power submitted the new PPA to the IPUC for their final approval, which was granted on January 16, 2008. The new PPA replaces the existing 10 megawatt, 20 year PPA and is part of Idaho Power’s 2006 formal request for geothermal electricity under which the Company was named the sole successful bidder in March 2007.

The new PPA is for electricity sales of an annual average of 13-megawatts and has a 25-year term. It is the first contract signed as part of ongoing negotiations with Idaho Power for a total of 45.5 megawatts. Idaho Power and the Company expect to be able to use this first contract as a template for advancing negotiations for the output from the planned Unit Three at Raft River and 26 megawatts of planned production from the Company’s Neal Hot Springs project located in southeast Oregon.

Eugene Water and Electric Board (“EWEB”), from Eugene, Oregon and U.S. Geothermal have signed a PPA with EWEB to purchase the full 13 megawatt annual electrical output of Raft River Unit II. With the execution of the EWEB PPA, and the increase of Unit I under the new Idaho Power PPA, the total planned output from the Unit I and Unit II Raft River power plants is expected to be 26 megawatts from two plants, instead of the originally planned 30 megawatts from three plants, resulting in substantial capital and operating cost savings through improved economy of scale. The ongoing negotiations with Idaho Power relating to Raft River Unit III and Neal Hot Springs and the signed EWEB PPA recognize that the PPAs are contingent upon extension of the federal Production Tax Credit, successful resource drilling and an economically feasible resource discovery at Raft River and Neal Hot Springs.

In addition, the strong regional interest in geothermal power has resulted in several utilities from California to Washington entering into discussions with U.S. Geothermal Inc. to purchase the electrical power output of Unit III. Subject to drilling confirmation of sufficient geothermal resource, the power plant output from three units at Raft River would be 39 megawatts, instead of the maximum 30 megawatts under the previous Idaho Power PPA provisions.

In May 2008, we acquired the geothermal assets, including a 3.6 net megawatt nameplate generating capacity power plant, from Empire Geothermal Power LLC and Michael B. Stewart, located in Washoe County, Nevada for approximately $16.6 million. The plant currently generates an approximate average net output of 3.1 megawatts, which is sold to Sierra Pacific Power Corporation. Subject to the receipt of all required permits, we intend to repower the project using the existing flow rate and build a new plant with 8 to 10 megawatts of capacity. When construction is complete, the existing 3.6 megawatt plant may be decommissioned. We believe the construction cost of the repower project will be approximately $25 to $26 million. Management is currently reviewing alternatives and believes project finance will be available for the development and construction. A new PPA for the amount of power above that is covered by the existing NV Energy PPA ( approximately 3 megawatts) will be required before financing can be completed. The method of financing the construction of the new power plant has not yet been determined.

Although other factors may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be affected by the following factors.

We hold a 50% interest in Raft River LLC, which owns Raft River Energy Unit I. Construction of Raft River Energy Unit I required substantial capital, and partnering with a co-venturer allowed us to share the risks and rewards of ownership. The joint venture has also allowed us to take advantage of production tax credits which would not otherwise have been available to us. We estimate we will receive cash payments totaling approximately $1.6 million per year from the Raft River Unit I project for the first four years of its operations from a water lease ($90,000), management fees ($250,000), sales proceeds from renewable energy credits ($160,000) and projected cash distributions available from operations ($100,000).

We managed the construction of the Raft River Energy Unit I plant pursuant to our operating agreement with Raft River LLC. Raft Holdings has contributed to Raft River LLC a total of approximately $34.2 million in cash and we have contributed $16.4 million in cash and approximately $1.5 million in production and injection wells and geothermal leases through March 31, 2009.

Under the terms of the Operating Agreement, Raft River LLC is required to distribute the cash it holds that is not otherwise allocated to its liabilities or reserves to Raft Holding and us at the end of each fiscal quarter. Raft Holdings is entitled to specific quarterly cash distributions in amounts outlined in the Operating Agreement. For the first four years after Raft River Unit I was placed into service, and once Raft Holdings has received cash distributions specified in the Operating Agreement, we are entitled to receive available cash distributions up to a certain specified limit. Following this period and continuing until Raft Holdings has achieved a specified rate of return, we will receive a de minimis percentage of the available cash distributions. At such time, we will receive less than half of all available cash distributions until the later of 20 years or the date we have achieve more than 30 megawatts of total net electrical generation capacity from geothermal resources in the United States under our ownership or control or the economic equivalent thereof. However, at this time, we will be receiving a majority of the cash flow due to payments made to us as fees and royalties under separate energy and water rights agreements. Thereafter, we will receive a significant majority of the available cash distributions for the remaining life of the project.

Raft River Unit I is currently selling between 8.5 and 9.5 megawatts of power to Idaho Power Company. Raft River LLC has also entered into an agreement with Holy Cross Energy of Colorado for the sale of the RECs associated with the Raft River Unit I power plant. Holy Cross Energy has agreed to pay a price of $7.50 per megawatt hour for the first 10 megawatts of generation on an annual basis. The price for these RECs will decrease annually by $0.50 per megawatt until the contract terminates in 2017. We also receive revenue from Raft River LLC from water and energy leases.

We use the equity method of accounting to account for the operating results of Raft River LLC over which we have significant influence due to our management of the operations and our participation on the management committee. Under the equity method, we recognize our proportionate share of the net income (loss) of Raft River LLC in the line item “Loss from investment in subsidiary.” Once we begin to receive the significant majority of the available cash distributions from Raft River LLC, we expect that Raft River Unit I will be accounted for as a consolidated entity.

Pursuant to a Management Services Agreement which continues until 2028, we provide operating and management services to Raft River LLC. We will receive approximately $250,000 per year for the next four year pursuant to this agreement. Thereafter, modest adjustments to this amount will occur according to an escalator clause in the agreement.

Prior to the construction of a geothermal project, we typically enter into a power purchase agreement with a utility, which fixes the price of energy produced at a project for a 20 to 25 year period. Such PPAs are typically negotiated with the utility company and approved by a state utility commission or similar regulating body.

Power purchase agreements generally provide for the payment of energy payments, capacity payments, or both. Energy payments are calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed, subject to adjustments in certain cases, or are based on the relevant power purchaser’s short-run avoided costs calculated as the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. Capacity payments, on the other hand, are generally calculated based on the amount of time that our power plants are available to generate electricity. Some power purchase agreements provide for bonus payments in the event that the producer is able to exceed certain target levels and forfeiture of payments if minimum target levels are not met.

Raft River Energy I LLC currently earns revenue from a full-output PPA with Idaho Power, which is expected to be 13-megawatts annual average. The PPA expires in 2032. This PPA was signed as part of ongoing negotiations with Idaho Power for PPAs covering an expected total output of 45.5 megawatts and may be used as the template for additional PPAs. The price of energy sold under the Idaho Power PPA is split into three seasons: power produced during the peak periods of July, August, November and December will be purchased at 120% of the set price; power produced in the three month low demand season will be purchased at 73.50% of the set price; and power produced in the remaining five months of the year will be purchased at 100% of the set price. The PPA sets a first year average purchase price of $53.60 per megawatt hour. The $53.60 purchase price is escalated each year at a compound annual rate of 2.1% until year 15. From years 16 to 25 of the contract the escalation rate will drop to 0.6% per year.

Power generated by San Emidio is sold to Sierra Pacific Power Corp. (NV Energy) pursuant to a 30 year PURPA PPA that terminates in December 2017. The PPA includes energy and capacity payment components, as well as peak and off-peak rates. The average power price received in 2008 is approximately $77.00 per megawatt hour. Contract prices are adjusted annually on March 1 based upon the Handy-Whitman price index, total steam production plant category, as specified by Nevada Public Utility Commission standards for PURPA contracts.

For the years ended March 31, 2009 and 2008, we incurred net losses of $5,735,747 and $3,549,186 which represented ($0.06) and ($0.04) per share; respectively. The increase from 2008 to 2009 was $1,606,302 (61.6%) . These figures are indicative of several factors that are both financially favorable and unfavorable. As discussed in more detail in the following paragraphs, the figures are primarily attributable to management fee income, corporate administrative and development, professional and management fees, salaries and related costs, lease and repair costs, as well as the operations of the subsidiary and the newly acquired power plant.

For the year ended March 31, 2008, management fee income increased $187,500 compared to the same period in 2008. Management fees are earned by the Company from its subsidiary RREI at a rate of $20,833 per month ($250,000 annual). These fees began when the plant became operational in January 2008. In the fiscal year ended March 31, 2008, the Company earned 3 months of management fees. For the fiscal year ended March 31, 2009, the Company earned fees for an entire year.

Administrative and development costs increased by $173,010 (28.9%) from the prior year. The primary components of the increase were the increases in exchange filing fees ($25,400), insurance ($58,000) and administration office rent ($50,500). The Company moved into a new building in January 2008. Therefore, the prior fiscal year only included three months of the higher rental costs for the new building.

For the year ended March 31, 2009, professional and management costs increased $151,545 (17.9%) compared to the same period in 2008. The increase was primarily due to additional audit fees, compliance with Sarbanes-Oxley Act and contractors involved in plant support. The financial statement audit fees increased approximately $25,000 due to the larger scope of the audit engagement related to the Company’s new entities. To comply with the Sarbanes-Oxley Act, additional audit fees of approximately $35,000 were incurred and additional consulting fees of $61,300 were incurred for a total of $136,000 for the fiscal year. An incremental amount of approximately $83,000 was paid to outside contractors that supported the operations of our primary subsidiary. These contractors were performing water testing and general plant operational support.

For the year ended March 31, 2009, our salary costs increased $563,324 (91.2%) as compared to 2007. There have not been notable changes in the number of management and development employees, pay scales or other benefits. Prior to January 3, 2008, the Company’s primary subsidiary was in a development stage, and directly involved efforts from management and development employees. Accordingly, their salaries and related costs (approximately $455,000 and $437,000 for the fiscal years ended 2008 and 2007; respectively) were allocated to the subsidiary. After the subsidiary became operational in 2008, the amount of salary costs from management and development employees were significantly reduced at the subsidiary level and now are carried at the corporate level.

For the year ended March 31, 2009, the lease and equipment maintenance costs increased $146,986 (211.5%) as compared to 2008. During the year, the Company began lease payments for utility line reservation fees of $101,928. Additional lease payments for geothermal water rights were incurred that amounted to over $81,000. Of that amount, $41,000 was for geothermal lease rights for the exploration activities conducted by the new joint venture company Gerlach Geothermal, LLC.

For the fiscal year ended March 31, 2009, the Company’s portion of net loss reported by RREI was $8,178. This was a decrease of $220,056 in the loss reported in the same period ended in 2008. The plant became commercially operational on January 3, 2008. The quarterly financial information is presented in the table below. The operating loss experienced in the first 3 quarters of commercial operations reflects the effect of reduced power generation due to plant startup in winter conditions, completion of construction punch list activities and the resulting higher labor costs, and increased chemical treatment costs for the reduction of elevated chloride in the cooling water circuit that were higher than anticipated. In addition, the mechanical failure of the pump in production well RRG-2 caused several weeks of reduced power generation and the associated lost revenues. The quarter ended December 26, 2008, was the first quarter that RREI reported a profit. The drop in revenues and the related net loss reported in the quarter ended March 27, 2009 was related to the decline in temperature for one of the four production wells (RRG-7) and the lower contracted power rate for the month of March. The temperature reduction for well RRG-7 is an on-going condition that is still being addressed. Under the terms of the PPA, the Company was paid 100% of the contracted power rate for the months of January and February. In March, the Company is paid the lower seasonal rate of 73.5% of the contracted power rate.

During the fiscal year ended March 31, 2009, the Company reported operating revenues of $1,449,696 (energy sales $1,416,853 and production energy credit and other $32,843) and plant expenses of $2,265,277. Effective May 1, 2008, the Company purchased and began operating a geothermal power plant located in North Western Nevada. Therefore, this was the first year the Company reported revenues and expenses from this plant.

Energy sales revenues were higher in the quarter ended September 30, 2008 due to regular plant production and premium contracted rates. Based upon the terms of the PPA, premium rates are paid during the months June through September. The plant was not as productive in the quarters ended December 31, 2008 and March 31, 2009 due to the down time experienced while extensive repairs and maintenance was conducted.

Significant repair and maintenance costs were incurred during the quarters ended December 31, 2008 and March 31, 2009. Repairs and other improvements have been made that are expected to reduce operating costs, as well as increase power generation. During the last fiscal year, the Company has spent over $164,000 making various repairs to allow the facility to continue to generate power until the repower or replacement of the power plant facility is completed. Items included in the repairs and maintenance total includes repair of electrical breakers and system controls, repair pentane storage and transfer system, gear box and drive shaft alignments on all OECs and cooling tower fans, repair leaking condenser tubes, replace turbine inlet gaskets, modification of OEC oil cooler water supply pipelines, replacement of leaking brine valves on the OECs and replacement of check valve on production pump 76-16. With these repairs, the power plant facility should continue to provide operating revenues and generate positive cash flow to the Company.

For the years ended March 31, 2008 and 2007, we incurred net losses of $3,549,186 and $1,942,884 which represented ($0.06) and ($0.04) per share; respectively. The increase from 2007 to 2008 was $1,606,302 (82.7%) . These figures are indicative of high levels of activities related to our efforts to develop, study and establish financing for our geothermal interests, as detailed below.

On January 3, 2008, the Company’s first plant became commercially operational. As a result, the Company began receiving operating revenues for management fees and lease and royalty payments.

The Company’s share of the operating loss from the Company’s major subsidiary increased $125,898 (123.0% increase) from the prior year. The subsidiary began commercial operations in January 2008 and costs are being incurred to optimize production levels. The Raft River Unit I plant is currently operating at between 9.6 to 11.7 megawatts output which is still below the design capacity. The plant has not yet been able to drop the purchases of third party power to run the production pumps as originally planned. The pump power purchases have increased the plant operating costs. Management continues to study the production issues related to this plant and believes that the plant will be profitable after initial start up costs have been incurred.

Administrative and development costs increased by $364,121 (168.6%) from the prior year. The primary component of the increase was the filing fee and other related costs for listing on the Toronto Stock Exchange ($269,273). Also, there were modest increases in insurance and depreciation costs.

Professional costs remained at a high level to support the legal and other consulting efforts to needed to comply with the Sarbanes-Oxley Act ($74,200), issue private placement offerings ($49,900), filing of a resale registration statement ($48,900), negotiate the terms of the Raft River Energy operating agreement ($45,200) and amend prior year tax returns ($21,100). Professional and management costs of $845,908 represent 17.6% of total operating expenses for the fiscal year ended March 31, 2008. These costs increased $137,384 (19.4%) and $423,218 (100.1%) from 2007.

Stock-based compensation represents 39.7% of the Company’s operating expenses for the fiscal year ended March 31, 2008. These costs increased $774,563 (68.6%) from the prior year. The main reason for the increase is number of options granted to directors, officers and employees in fiscal years ending March 31, 2007 and 2008. The stock options are a part of our annual executive compensation plan, and are issued to obtain, retain and motivate our directors, executives and employees. During the fiscal year ended March 31, 2008, we attained several significant milestones (moving to Toronto Stock Exchange, moving to American Stock Exchange (now NYSE Amex), completion of Raft River Unit I, etc.) which necessitated recognition of the significant work effort of our directors, executives and employees for current and prior years.

We believe our cash and liquid investments at March 31, 2009 are adequate to fund our general operating activities through March 31, 2010. Additional funding will be needed to finance the expansion of production volumes at Raft River and the development of the San Emidio, Nevada and Neal Hot Springs, Oregon projects. We anticipate that the additional funding may be raised through the issuance of shares and/or through the sale of ownership interest in tax credits and benefits.

The Company intends to continue its growth through the acquisition of ownership or leasehold interests in properties and/or property rights 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 geothermal or other renewable energy properties.

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been made. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for the financial statements.

The Company considers cash deposits and highly liquid investments to be cash and cash equivalents for financial reporting presentation on the consolidated balance sheet and statement of cash flows. The Company subscribes to the accounting standards that define cash equivalents as highly liquid, short-term instruments that are readily convertible to known amounts of cash, which are generally defined investments that have original maturity dates of less than three months. With the large value of funds invested in short-term deposits, small variations in short term interest rates may materially affect the value of cash equivalents. Investments in government obligations accumulate higher interest, but the principal balance is not insured by the FDIC.

During the development stage of operations, the Company has purchased and otherwise acquired geothermal properties for the production of power. The geothermal properties include: drilled wells, power plant components, power plant support components, land, land rights, surface water rights, and geothermal water rights. The Company’s first power plant became operational in January 2008. When the plant became operational, plant property and equipment costs were charged to operations in a systematic manner based upon the estimated useful lives of the individual assets. The factors and assumptions that comprise this allocation process will be based upon the best information available to us, and will be evaluated, at least, annually for viability. If it is determined that our cost allocations have produced results that vary significantly from the conditions surrounding the value of the Company’s geothermal properties, a gain or loss adjustment will be made in the period in which this determination is made. The cost allocation or amortization process is not intended to present the fair market value of our geothermal properties; rather to allocate the actual historical costs of those properties over their service lives.

According to generally accepted accounting practices, entities must recognize assets and/or liabilities that originate with the differences in revenues and expenses presented for financial reporting purposes and those revenues and expenses that are utilized to comply with federal and state income tax law. Often deductions can be accelerated for income tax purposes, thus creating temporary timing differences. Other items (generally non-allowable expenses) do not reverse over time, and are considered to be permanent differences. These types of costs are, typically, not factored into the deferred income tax asset or liability calculation. The Company’s primary element that impacts the liability or asset calculation relates to the operating losses generated in its early stages of operation that will be allowed to offset future earnings. Stock-based compensation is another significant area that impacts that recognition of deferred income taxes. Compensation that has been provided to employees and contractors based upon the value of the issuance of stock options is reported as an operating cost. However, this compensation is not an allowable deduction for income tax purposes. At the end of the fiscal year, the Company’s significant tax differences would ultimately result in the recognition of an asset; however, due to the uncertainly surrounding future earnings, an allowance has been calculated that effectively removes the asset. The Company continues to track the financial elements that comprise the deferred income tax calculation and will remove or reduce the asset allowance if the Company is determined to be in position where it is likely to produce earnings.

Effective April 1, 2007, the Company adopted a standard that states that if certain conditions are present surrounding the issuance of equity instruments as share based compensation, then circumstances may warrant the recognition of a liability for financial reporting purposes. One such condition was present when the Company originally issued stock options in a foreign currency (Canadian dollars) to employees before the beginning of the fiscal year. Authors of the standard have reasoned that when a condition is present that creates a financial risk to the recipient in addition to normal market risks (i.e., foreign currency translation risk), then the instrument takes on the characteristics of a liability, rather than an equity item. As the underlying stock options are exercised or are forfeited, then the stock based compensation liability will be reduced. The Company’s financial statements reflect these changes in the consolidated balance sheet. As the value of the options change over the vesting periods, these changes will ultimately be reflected in the amount of expense charged to operations.

The Company awards stock options for compensation to non-employees for services performed and/or services performed above and beyond expectations. After the services have been completed, the awards are made at the discretion of the Board of Directors. The fair value of the options are determined on the date the options are awarded according to several factors that include the exercise price of the option, the current price of the underlying share, the expected life of the options and the expected volatility of the stock. Generally speaking, a longer life and higher expected volatility yields a higher value of the option. In accordance with appropriate accounting guidance, the Company amortizes the value of these options as operating expense during the period in which they vest. Stock options awarded to Company employees are also valued on the date they are awarded. However, the value of these options are capitalized and expensed over the vesting period. The current vesting period for all options is eighteen months. The nature of the services provided determines whether the value will be expensed or added to the value of a Company asset. To date, no services have been provided directly related to the construction of property and equipment, thus, all services have been charged to operations.

As of March 31, 2009, the following table denotes contractual obligation by payments due for each period:

For further information regarding lease terms and conditions, please note Item 2, Description of Property, Lease/Royalty Terms beginning on page 28 of this document.

The obligations reflected for Stock Compensation Payable are reflected as due on the option expiration date. The obligation will be relieved upon exercise of the options, which may be at any time between vesting and expiration.

As of March 31, 2009, the Company does not have any off balance sheet arrangements.

At March 31, 2009, the Company held investments of $3,464,906 in money market accounts. These are highly liquid investments that are subject to risks associated with changes in interest rates. The money market funds are invested in governmental obligations with minimal fluctuations in interest rates and fixed terms.

The Company is subject to limited amount of foreign currency risks associated with cash deposits maintained in Canadian currency. The Company has utilized and it is continuing to utilize the Canadian markets for raising capital. By proper timing of the transactions and then maintenance of adequate operating funds in other financial resources, the Company has been able to mitigate some of the risks surrounding foreign currency exchanges. At fiscal year end, the Company did not hold any deposits in Canadian currency. Also, the Canadian currency exchange rate has been reasonably consistent over the past fiscal year. As a matter of standard operating practice, the Company does not maintain large balances of Canadian currency; and, substantially, all operating transactions are conducted in U.S. dollars.

The strike price for the Company’s stock option plan has been stated in Canadian dollars as the plan has been administered through our Vancouver office and Pacific Corporate Trust Company. This subjects the Company to foreign currency risk in addition to the normal market risks associated with the stock price fluctuations. A long-term liability has been established to reflect the fair value of the stock options payable. The strike price on future option grants will be stated in US dollars.

The Company is exposed to risks surrounding the volatility of energy prices. These risks are impacted by various circumstances surrounding the energy production from natural gas, nuclear, hydro, solar, coal and oil. The Company has been able to mitigate, to a certain extent, this risk by entering into long-term power purchase contracts for both the Raft River and San Emidio power plants. These types of arrangement will be the model for power purchase contracts planned for future power plants.

The information required hereunder is set forth under “Report of Independent Registered Public Accounting Firm,” “Consolidated Balance Sheets,” “Consolidated Statements of Operations,” “Consolidated Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit),” “Consolidated Statements of Cash Flows,” and “Notes to Consolidated Financial Statements” included in the consolidated financial statements that are a part of this Report (See Part IV, Item 15, exhibit 10.37) . Other financial information and schedules are included in the consolidated financial statements that are a part of this Report.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

In connection with the preparation of this annual report on Form 10-K, an evaluation was carried out by the Company’s management, with the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (“Exchange Act”)) as of March 31, 2009. Disclosure controls and procedures are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosures.

Based on their evaluation, our Chief Executive Officer and Chief Financial Officer concluded disclosure controls and procedures were effective as of March 31, 2009.

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2009. In making this assessment, it used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management concluded that, as of March 31, 2009, the Company’s internal control over financial reporting is effective based on those criteria.

Williams & Webster, P.S., independent registered public accounting firm, who audited and reported on the consolidated financial statements of U.S. Geothermal, Inc. included in this report, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of March 31, 2009, which report appears as Exhibit 10.41.

As of the end of the period covered by this report, there have been no changes in internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) during the quarter ended March 31, 2009, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

On February 26, 2009, the Company submitted an application for the Neal Hot Springs project to the Department of Energy (“DOE”) Energy Efficiency, Renewable Energy and Advanced Transmission and Distribution Solicitation loan guarantee program under Title XVII of the Energy Policy Act of 2005. The Company was notified that its project application is complete, the power plant technology choice qualifies as new or improved under the program, and the project has been selected to proceed in the project loan process. The Company announced on May 26, 2009, that it has been selected by the DOE to enter into due diligence review on an $85 million project loan for the Neal Hot Springs project located in eastern Oregon. If awarded, the loan is expected to provide 80% of the $106 million estimated total capital cost. The new plant, designed to deliver 22 megawatts of power net to the grid, is scheduled to begin commercial operations in late 2011.

On May 26, 2009, the Company announced the regular annual grant of employee stock options pursuant to its Stock Option Plan to directors, employees and consultants to acquire 1,795,000 shares exercisable at a price of $0.92 per share for a term of 5 years expiring May 26, 2014.

On June 1, 2009, the production pipe column on a well at Raft River Energy I, LLC failed. This is the pipe that carries the geothermal fluid to the surface and supports the pump weight. The repair process has started and the pipe column and pump have been removed from the well. While the final repair costs have not been determined, initial estimates indicate that repair costs could exceed $600,000. Plant energy production has been reduced due to the failure. If the repair process goes according to plan, the repairs will be completed by June 19, 2009.

The following sets forth certain information concerning the current directors, executive officers and significant employees of our company. Each director has been elected to serve until our next annual meeting of stockholders and until his successor has been elected and qualified. Each executive officer serves at the discretion of the board of directors of our company, and each has been elected for a 1 year term.

Daniel J. Kunz is the co-founder, President and Chief Executive Officer and a director of GTH and the President of Geo-Idaho. He has served as a director of the company since March 2000, and was Chairman of the Board of Directors from March 2000 until December 2003. Prior to the acquisition of Geo-Idaho, he served as a director and the President for that company from February 2002 until the acquisition. Mr. Kunz was an executive of Ivanhoe Mines Ltd. from 1997, and served as its President, Chief Executive Officer and Director from November 1, 2000 until March 1, 2003. From March 2, 2003 until March 8, 2004, Mr. Kunz served as President of Jinshan Gold Mines Inc. Mr. Kunz has more than 30 years of experience in international mining, engineering and construction, including, marketing, business development, management, accounting, finance and operations. Mr. Kunz was a founder of and directed the initial public offering of the NASDAQ listed MK Gold Company (President, Director & CEO) and held executive positions with Morrison Knudsen Corporation (Vice President & Controller, and as CFO to the Mining Group). Mr. Kunz holds a Masters of Business Administration and a Bachelor of Science in Engineering Science. He is currently a director of several companies publicly traded on the Toronto Stock Exchange and the TSX Venture Exchange, including Jinshan Gold Mines Inc., Kenai Resources Ltd., and Chesapeake Gold Corp.

Douglas J. Glaspey is the co-founder, Chief Operating Officer and a director of GTH. He has served as a director of the company since March 2000, and served as its President from March 2000 until the acquisition of Geo-Idaho. He also served as a director and the Chief Executive Officer of Geo-Idaho from February 2002 until the acquisition, and continues to serve as President. From December 1986 to the present, Mr. Glaspey has been a Metallurgical Engineer and Project Manager with Twin Gold Corporation. Mr. Glaspey has 29 years of operating and management experience. He holds a Bachelor of Science in Mineral Processing Engineering and an Associate of Science in Engineering Science. His experience includes production management, planning and directing resource exploration programs, preparing feasibility studies and environmental permitting. He has formed and served as an executive officer of several private resource development companies in the United States, including Drumlummon Gold Mines Corporation and Black Diamond Corporation.

John H. Walker is a director and the Chairman of the Board of directors of GTH. He has held that position since December 2003. He is Managing Partner of the IMG-Aurion Infrastructure Fund, a North American US$500 million dollar infrastructure fund based in Toronto and Washington D.C. with a focus on mid-market investment opportunities. He brings over 35 years experience in urban planning, energy security, investment banking and business diplomacy. Mr. Walker was a Founding Director of the Greater Toronto Airports Authority and was involved in the development of a $4.4 billion terminal complex at Toronto Pearson Airport, which was completed in 2005. He has held positions at Ontario Hydro, Loewen Ondaatje McCutcheon, Falconbridge, Mihaly International Canada, the Town of Oakville and the City of New Haven. Mr. Walker has a BS from Springfield College in urban studies and a Master of Environmental Studies degree from York University.

Paul Larkin serves as a director of GTH, a position he has held since March 2000. He served as Secretary of GTH until December, 2003, and served as a director and the Secretary-Treasurer of Geo-Idaho from February 2002 until the acquisition. Since 1983, Mr. Larkin has also been the President of the New Dawn Group, an investment and financial consulting firm located in Vancouver, British Columbia, and the President of Tyner Resources Ltd., a TSX Venture Exchange listed company. New Dawn is primarily involved in corporate finance, merchant banking and administrative management of public companies. Mr. Larkin held various accounting and banking positions for over a decade before founding New Dawn in 1983, and currently serves on the boards of the following companies which are listed on the TSX Venture Exchange: Tyner Resources Ltd., LNG Energy Limited, Kenai Resource Inc., and Condor Resources Inc.

Dr. Leland “Roy” Mink is the former Program Director for the Geothermal Technologies Program, U.S. Department of Energy (DOE). Prior to working for the DOE Dr. Mink was the Vice President of Exploration for U.S. Geothermal Inc. He has also worked for Morrison-Knudsen Corporation, Idaho Bureau of Mines and Geology and Idaho Water Resources Research Institute.

Kerry D. Hawkley serves as the company’s Chief Financial Officer and Corporate Secretary. He has served as the company’s controller since July 2003, and became CFO as of January 1, 2005. Since July 2003, he has also provided consulting services to Triumph Gold Corp. From 1998 to June 2003, Mr. Hawkley served as controller, director and treasurer of LB Industries. Mr. Hawkley has over 30 years experience in all areas of accounting, finance and administration. He holds Bachelor of Business Administration degrees in Accounting and Finance. He started his career as an internal auditor with Union Pacific Corporation and has held various accounting management positions in the oil and gas, truck leasing, mining and energy industries.

Kevin Kitz is the Vice President-Development of Geo-Idaho. He joined the company in April 2003. He is a mechanical engineer with 19 years of geothermal power plant design, construction and operating experience with UNOCAL, with whom he worked until November 2002. He holds a Bachelor of Science in Mechanical Engineering and Material Science, and is a Professional Engineer in California. During his career with Unocal, he was a Production and Operations Engineer at the 75 megawatt Salton Sea geothermal power plant in southern California, a Senior Production Engineer at the Geysers geothermal field in northern California, and a Power Plant Engineering Advisor in the Philippines for geothermal power plants ranging from 12 to 55 megawatts.

Robert Cline is the Vice President-Engineering of Geo-Idaho. He joined the company in February 2005. He is a civil engineer with 24 years experience developing energy and water resources projects in the western U.S. He holds Bachelor of Science degrees in Civil Engineering and Physics, and is a Professional Engineer in Arizona and Oregon. Prior to joining US Geothermal, he was the Manager of Engineering at Ida-West Energy Company, playing a key role in developing several hydroelectric and gas-fired generating facilities, and was instrumental in several highly successful hydroelectric acquisitions. Prior to 1991, he worked nine years for the US Bureau of Reclamation where he was involved in engineering, contracting and construction of various water resources related projects in Arizona.

Christopher S. Harriman is the President of US Geothermal Services LLC. He has over ten years of power management experience and has eighteen years of industry experience. He worked for Black Hills Generation as plant manager of two 10 megawatt cogeneration facilities in southern Idaho. He also spent eight years with Exxon Shipping, and served in the U.S. Coast Guard. He joined us in July 2006.

None of the directors or officers has entered into any arrangement or understanding with any other person pursuant to which he was selected as an officer or selected as a director or nominee of the Company.

The Board adopted the Company’s Code of Ethics in September 2005. The code of ethics applies to all directors, officers and employees of the company. Amendments or waivers to the Code of Ethics will be disclosed within four business days on a Form 8-K or on the Company’s web page at www.usgeothermal.com. The Code of Ethics is included in the Company’s web page.

The primary function of the Audit committee is to assist the Board in fulfilling its financial oversight responsibilities by reviewing the financial reports and other financial information provided by the Corporation to regulatory authorities and shareholders, the Corporation’s systems of internal controls regarding finance and accounting and the Corporation’s auditing, accounting and financial reporting processes. Consistent with this function, the Audit Committee will encourage continuous improvement of, and should foster adherence to, the Corporation’s policies, procedures and practices at all levels. The Audit Committee’s primary duties and responsibilities are:

The Audit Committee shall be comprised of three directors as determined by the Board, each of whom shall be free from any relationship that, in the opinion of the Board, would interfere with the exercise of his or her independent judgment as a member of the Audit Committee. At least one member of the Audit Committee shall have accounting and related financial management expertise. All members of the audit Committee that are not financially literate will work towards becoming financially literate to obtain a working familiarity with basic finance and accounting practices. For the purposes of the Audit Committee’s Charter, the definition of “financially literate” is the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity that can be resumed to be raised by the Corporation’s financial statement. The members of the Audit Committee shall be elected by the full Board at its first meeting after the annual shareholder’s meeting. Unless a Chair is elected by the full Board, the members of the Audit Committee may designate a Chair by a majority vote of the full Audit Committee membership.

The current members of the Audit Committee are Paul A. Larkin (Chair and Financial Expert), John H. Walker and Leland L. Mink.

To fulfill its responsibilities and duties, the Audit Committee shall review and update the Audit Committee’s charter annually, and review the Corporation’s financial statements, management’s discussion and analysis (MD&A) and any annual and interim earnings, press releases before the Corporation publicly discloses this information and any reports or other financial information (including quarterly financial statements), which are submitted to any governmental body, or to the public, including any certification, report, opinion, or review rendered by the external auditors.

The Audit Committee shall meet at least four times annually, or more frequently as circumstances dictate. As part of its job to foster open communication, the Committee will meet at least annually with the Chief Financial Officer and the external auditors in separate sessions.

Based solely on its review of the copies of such reports received by the Company, and on written representations by the Company's officers and directors regarding their compliance with the applicable reporting requirements under Section 16(a) of the Exchange Act, the Company believes that, with respect to its fiscal year ended March 31, 2009, all of the Company's officers and directors, and all of the persons known to the Company to own more than ten percent (10%) of the Common Stock, complied with all such reporting requirements except as follows: Mr. Kunz was late filing a Form 4 representing one transaction. Mr. Glaspey was late filing a Form 4 representing two transactions. Mr. Hawkley was late filing a Form 4 representing two transactions. And Mr. Larkin was late filing a Form 4 representing one transaction.

The Compensation and Benefits Committee is appointed annually by the Board of Directors to discharge the Board's responsibilities relating to compensation and benefits of the executive officers of the Company. The goals of the committee is to attract, retain and motivate our executive officers by providing appropriate levels of compensation and benefits while taking into consideration, among such other factors as it may deem relevant, the Company's performance, shareholder returns, the value of similar incentive awards to executive officers at comparable companies and the awards given to the executive officers in past years. The main categories of compensation available to the committee are base salary, discretionary annual performance bonuses, stock option grants, stock awards, and insurance reimbursements.

While U.S. Geothermal does not attach a weighting to the various components of executive compensation, the Compensation Committee attempts to pay a competitive salary (retention) to its executives while providing long-term incentive to the executives through equity awards (ownership/rewards) in order to align their interests with the long-term progression of the Company as a whole.

We compete with a variety of companies for our executive-level employees. The Compensation and Benefits Committee uses base salary to compensate the executive officers for services rendered as well as for motivation and retention purposes. Base salaries are intended to be competitive for companies of similar size and purpose, also taking into consideration individual factors such as experience, tenure, institutional knowledge and qualifications. Base salaries are reviewed annually to determine whether they are consistent with our overall compensation objectives. In considering increases in base salary, the Compensation and Benefits Committee reviews individual and corporate performance, market and industry conditions, and our overall financial health.

The CEO, and Compensation and Benefits Committee perform an informal annual review of compensation practices of similar size companies to educate themselves of the general parameters (levels and types of compensation) for executive compensation. They do not, however, benchmark the various components of executive pay. Their review highlights inconsistencies with compensation practices at similar sized companies and provides the committee with knowledge of the competitive landscape for its executives. None of the other executive officers participate in the determination of executive pay.

The Compensation and Benefits Committee may grant annual performance bonuses as a reward for achievement of individual and corporate short-term goals. Any grant of an annual performance bonus is discretionary and the amount is determined after recommendation from the chief executive officer. Bonus awards are dependent upon our financial and operational performance as well as the completion of specific milestone events by the individual executive officer. The Company has awarded bonus payments during two years when salaries were significantly below market, but does not consider this method of compensation as a material aspect of our continuing compensation package (approximately 5% of total executive compensation during 2007 and 2008; zero during 2009). The bonuses paid in January 2007 were based on the significant milestones and achievements of the company during the calendar year 2006 including the following:

The second bonus ever paid by the company amounted to one month’s salary for each employee and was paid in January of 2008 for the excellent work completed and significant milestone achievements in calendar year 2007. This bonus also recognized each employees dedication and long working hours to complete the construction of the Pacific Northwest’s first geothermal power plant with the salaried employee team working a significant number or hours over the expected 40 hours per week and working through holidays and vacation time to get the project complete. Other milestones include:

Generally, the Compensation and Benefits Committee grants stock options to all employees, including executive officers, annually after completion of our annual financial reports. Stock options are granted with an exercise price equal to the market value of our common stock on the date of the grant, and with a term of five years. The timing of the stock option grant is not coordinated with the release of material non-public information and is typically in the first or second fiscal quarter. The options vest 25% on date of grant, and another 25% each six months thereafter. In 2007, stock option grants to executive officers represented approximately 15% of the total stock option grants to all employees.

Our executive officers do not receive any material incremental benefits that are not otherwise available to all of our employees. Our health and dental insurance plans are the same for all employees.

Effective January 1, 2008, Daniel J. Kunz signed an employment agreement that sets the amount of time devoted to the business of the Company to 140 hours per month at a compensation of $170,400 annually. Mr. Kunz is entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as are or may become available to other employees, and vacation. The Company will also provide reasonable life insurance and accidental death coverage with the proceeds payable to Mr. Kunz’s estate or specified family member. The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance or other sums for causes which include failure to perform in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a conflict of interest, conviction which has become final for an indictable offense, fraud, dishonesty, refusal to follow reasonable and lawful direction of the company, breach of fiduciary duty, and a declaration of bankruptcy by or against Mr. Kunz. Otherwise, the Company may terminate the agreement upon one month written notice. The agreement includes covenants by Mr. Kunz of confidentiality and non-competition, and provides for equitable relief in the event of breach. In the case of a change of control, Mr. Kunz can elect to receive compensation equal to 24 monthly installments of his normal compensation no later than five working days after the effective date of the change of control (currently $340,800). Mr. Kunz’s 2008 employment agreement expired on December 31, 2008. Mr. Kunz's employment agreement for 2009 is currently under negotiation and has not been completed. Mr. Kunz and the Company have agreed to continue to pay Mr. Kunz under the 2008 salary guidelines until the new agreement can be completed.

Douglas J. Glaspey, Chief Operating Officer, signed an employment agreement on January 1, 2009, which provides for an annual salary of $144,000 which is unchanged from 2008. Mr. Glaspey is entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as are or may become available to other employees, and vacation. The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance or other sums for causes which include failure to perform in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a conflict of interest, conviction which has become final for an indictable offense, fraud, dishonesty, refusal to follow reasonable and lawful direction of the Company, breach of fiduciary duty, and a declaration of bankruptcy by or against Mr. Glaspey. In the event of early termination due to the Company’s failure to comply with the agreement, the employee would be entitled to compensation earned through the date of termination. In the case of termination of the employment agreement due to a change control, Mr. Glaspey will receive a lump sum payment in the amount equal to 18 monthly installments of the employee’s normal compensation (currently $216,000) and continuation of his medical and dental insurance (currently $9,100) for the subsequent 18 month period. A copy of the employment agreement is included as Exhibit 10.17 in Part IV of this report.

Kerry D. Hawkley, Chief Financial Officer, signed an employment agreement on January 1, 2009, which provides for an annual salary of $127,800 which is unchanged from 2008. Mr. Hawkley is entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as are or may become available to other employees, and vacation. The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance or other sums for causes which include failure to perform in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a conflict of interest, conviction which has become final for an indictable offense, fraud, dishonesty, refusal to follow reasonable and lawful direction of the Company, breach of fiduciary duty, and a declaration of bankruptcy by or against Mr. Hawkley. In the event of early termination due to failure comply with the agreement; the employee would be entitled to compensation earned through the date of termination. In the case of termination of the employment agreement due to a change control, Mr. Hawkley will receive a lump sum payment in the amount equal to 18 monthly installments of the employee’s normal compensation (currently $191,700) and continuation of his medical and dental insurance (currently $5,800) for the subsequent 18 month period. A copy of the employment agreement is included as Exhibit 10.16 in Part IV of this report.

GTH did not award any shares, units or rights to any executive officer under a Long-Term Incentive Plan during the fiscal years ended March 31, 2007, 2008, and 2009.

Effective January 1, 2008, Directors who are not otherwise remunerated per an employment agreement are paid $5,000 per quarter. Directors who are also officers do not receive any cash compensation for serving in the capacity of director. However, all directors are reimbursed for their out-of-pocket expenses in attending meetings.

During the year ended March 31, 2009, the Compensation and Benefits Committee was comprised of John H. Walker, Paul A. Larkin and Leland L. Mink.

No member of the Compensation Committee during the fiscal year ended March 31, 2009 is or has been a former or current executive officer or employee of the Company or has had any relationships requiring disclosure by the Company under the SEC’s rules requiring disclosure of certain relationships and related-party transactions. None of the Company’s executive officers served as a director or a member of a compensation committee (or other committee serving an equivalent function) of any other entity, the executive officers of which served as a director or member of the Compensation Committee during the fiscal year ended March 31, 2009.

The Compensation and Benefits Committee has reviewed and discussed with management the Compensation Discussion and Analysis contained in this Annual Report. Based on this review and discussion, the Compensation and Benefits Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in the Company’s Annual Report.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table details the number of securities authorized for issuance under the Company’s equity compensation plans for the fiscal year ended March 31, 2009:

The following table sets forth certain information known to the Company regarding the beneficial ownership of common stock as of March 31, 2009, or as of such later date as is listed below, of each person known to be the holder of more than 5% of our issued and outstanding stock. The stock information agrees to data provided by the Beneficial Owners on Schedule 13G as filed with the SEC during February 2009. The percentage is based on 62,033,882 shares of common stock issued and outstanding as of June 8, 2009.

The following table sets forth certain information known to the Company regarding the beneficial ownership of the common stock as of March 31, 2009, or as of such later date as indicated below, by (i) each of our directors, (ii) each of our named executive officers, and (iii) all of our executive officers and directors, serving at the time of the filing of this Report, as a group. The percentage is based on 62,033,882 shares of common stock issued and outstanding as of June 8, 2009, and adds the shares that the officer or director have the right to acquire within 60 days.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Our Board of Directors has determined that each of our directors other than Daniel J. Kunz and Douglas J. Glaspey has no material relationship with U.S. Geothermal Inc. and is independent. Mr. Kunz is not independent because he is the Chief Executive Officer and President of U.S. Geothermal Inc. Mr. Glaspey is not independent because he is Chief Operations Officer of U.S. Geothermal Inc. Each of our Audit, Governance and Compensation Committee is composed only of independent directors.

Our Board has adopted certain standards to assist it in assessing the independence of each of our directors. Absent other material relationships with U.S. Geothermal Inc., a director of U.S. Geothermal Inc. who otherwise meets the independence qualifications of the NYSE/AMEX listing standards may be deemed “independent” by the Board of Directors after consideration of all of the relationships between U.S. Geothermal Inc., or any of our subsidiaries, and the director, or any of his or her immediate family members (as defined in the NYSE/AMEX listing standards), or any entity with which the director or any of his or her immediate family members is affiliated by reason of being a partner, officer or a significant shareholder thereof.

In assessing the independence of our directors, our full Board carefully considered all of the business relationships between U.S. Geothermal Inc. and our directors or their affiliated companies. This review was based primarily on responses of the directors to questions in a questionnaire regarding employment, business, familial, compensation and other relationships with U.S. Geothermal Inc. and our management.

The Company’s on Stock is listed on the NYSE Amex and the TSX. Under NYSE Amex rules, the Board of Directors is required to affirmatively determine that each “independent” director has no material relationship with our company that would interfere with the exercise of independent judgment. Our Board has determined that the following directors are “independent” as required by NYSE Amex listing standards: John H. Walker, Paul A. Larkin, and Leland R. Mink. Additionally, all members of our Audit Committee are “independent” as defined in Rule 10A-3(b)(1) under the Exchange Act and for the purposes of Canadian National Instrument 58-101.

Transactions or Certain Business Relationships with Directors, Management and Others

The NYSE/AMEX has long recommended that independent Directors review related party transactions. At US Geothermal, the Audit Committee oversees our written procedure for identifying, analyzing and approving related party transactions. The Audit Committee also reviews information about Director independence and recommends independence standards and determinations to the Board.

The procedure for related party transactions applies to any transaction between US Geothermal or its affiliated companies on the one hand, and a Director, executive officer or his/her family members on the other hand. The procedure requires prior review by counsel of any related party transaction regardless of size. The prior review allows the Board and management to ensure that any related party transaction is consistent with the best interest of US Geothermal and its shareholders and, where a Director is involved, to assess the impact on Director independence.

The prior review of a proposed related party transaction includes a determination as to whether the transaction has been made on an arm’s length basis (that is, on terms comparable to those provided to unrelated third parties). The review also includes information about other, unrelated alternatives to a proposed related party transaction. For example, if a purchase of supplies were proposed, then the review would identify competing vendors/terms, or if a relative were considered for a job opening then the review would include a description of other applicants and their qualifications.

If a related party transaction is proposed, the results of the prior review are presented to the Audit Committee. If the Committee is comfortable with the proposed related party transaction, the transaction is tracked to assure that as the transaction occurs, it remains within the approved scope and amount. If a related party transaction or series of transactions spans multiple years, it is reconsidered once a year by the Committee.

US Geothermal maintains a list of related parties for each Director and executive officer which is updated as the Company learns of changes (for example, upon marriage or change of employment) and is confirmed in writing once a year by the Director or executive officer. To help assure no related party transaction has been inadvertently overlooked, US Geothermal checks accounts receivable and sales and accounts payable and disbursements against the list of related parties quarterly. Also, annually US Geothermal asks for written confirmation from each Director and executive officer as to all related party transactions that exceed the thresholds in the NYSE AMEX listing standards, the more restrictive US Geothermal Director Independence Standard, and for Audit Committee members, the additional independence standards specified in Rule 10A-3(b)(1) under the Exchange Act, and various disclosure thresholds and materiality standards as determined by US Geothermal’s counsel and accountants to be prudent for ensuring compliance with applicable laws and regulations.

The Company has not entered into any material business transactions, nor does a business relationship exist, with directors, executive officers, or family of directors or executive officers as at March 31, 2009.

The Goldman Sachs Group, an owner of more than 5% of the Company’s common stock, is also the owner of Raft River I Holdings LLC. Our relationship with Raft River I Holdings LLC is more fully described on page 6, 21, 32 and 44 of this document.

The aggregate fees billed by the Company’s principal accountant for the fiscal years ended March 31, 2009 and 2008 are as follows:

The Audit Committee reviews the Company’s financial statements, MD&A and any annual and interim earnings press releases before the Company publicly discloses this information and any reports or other financial information (including quarterly financial statements) which are submitted to any governmental body, or to the public, including any certification, report, opinion, or review rendered by the principal accountant performing the external audit of the Company’s records. The Audit Committee also confirms that adequate procedures are in place for the review of the Company’s public disclosure of financial information extracted or derived from the Company’s financial statements.

The Audit Committee engaged Williams & Webster to perform the annual audit of the financial statements of the company. Audit fees and scope of work are monitored and approved by the Audit Committee as part of the engagement process. Items not included in the engagement process are reviewed and authorized by senior management following pre-approval of the services by the Audit Committee.

* - Agreements are the subject of a confidential treatment request filed with the Commission on August 23, 2006.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Pursuant to the requirements of the Securities Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities and on the date indicated:

Delaware	84-1472231
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

1505 Tyrell Lane
Boise, Idaho	83706
(Address of Principal Executive Offices)	(Zip Code)

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $0.001 par value	NYSE Amex

Large accelerated filer [ ]	Accelerated filer [X]
Non-accelerated filer [ ] (Do not check if a smaller reporting company)	Smaller reporting company [ ]

Class of Equity	Shares Outstanding as of June 8, 2009
Common stock, par value	62,033,882
$ 0.001 per share

Additional Properties
Project	Location	Ownership	Target Development (MW)
Gerlach	Nevada	60%	To be determined
Granite Creek	Nevada	100%	To be determined

U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended March 31, 2009

		Page
PART I
Item 1	Description of Business	5
	General	5
	Development of Business	5
	History	5
	Plan of Operations	6
	Cash Requirements	8
	Material Acquisitions/Development	9
	Employees	12
	Principal Products	12
	Sources and Availability of Raw Materials	13
	Significant Patents, Licenses, Permits, Etc.	13
	Seasonality of Business	14
	Industry Practices/Needs for Working Capital	14
	Dependence on a Single Customer	14
	Competitive Conditions	15
	Environmental Compliance	15
	Financial Information about Geographic Areas	16
	Available Information	17
	Governmental Approvals and Regulations	17
	Environmental Credits	18
Item 1A	Risk Factors
	General Business Risks	20
	Risks Relating to the Market for Our Securities	27
Item 2	Description of Property	29
	Raft River – Idaho	29
	Raft River Unit I	32
	Neal Hot Springs – Oregon	36
	San Emidio – Nevada	37
	Gerlach – Nevada	39
	Granite Creek – Nevada	40
	Boise Administration Office - Idaho	40
Item 3	Legal Proceedings	40
Item 4	Submission of Matters to a Vote of Security Holders	40


PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6	Selected Financial Data	42


(1)	The resource assessment is based on 6.0 square miles. The remaining acreage was acquired subsequent to the GeothermEx report.
(2)	Actual production temperatures for existing wells.
(3)	Probable reservoir temperature as measured by Teplow and MWH Geo-Surveys Inc with a geothermometer.

1.	Heat source and temperature – The economic viability of a geothermal resource is related to the amount of heat generated. The higher the temperature, the more valuable the geothermal resource.

2.	Fluid – A geothermal resource is commercially viable only when the system contains water and/or steam as a medium to transfer the heat energy to the surface.

3.	Permeability – The fluid present underground must be able to move. In general, significant porosity and permeability within the rock formation are needed to create a viable reservoir.

4.	Depth – The cost of development increases with depth, as do resource temperatures. The proximity of the reservoir to the surface is therefore a key factor in the economic valuation of a geothermal resource.

1.	Geothermal well permits for production and injection wells issued by the Idaho Department of Water Resources.

2.	A Conditional Use Permit for the first two power plants was issued by the Cassia County Planning and Zoning Commission on April 21, 2005.

3.	The Idaho Department of Environmental Quality issued the Air Quality Permit to Construct on May 26, 2006.

4.	A Wastewater Reuse Permit issued by the Idaho Department of Environmental Quality on February 23, 2007.

1.	Geothermal well permits for production and injection wells issued by the Nevada Division of Minerals.

2.	A Special Use Permit issued by the Washoe County Board of Commissioners on July 1, 1987.

3.	An Air Quality Permit to Operate from Washoe County renewed on January 1, 2008.

4.	A Surface Discharge Permit from Nevada Division of Environmental Protection issued on June 11, 2001.

5.	An Underground Injection Permit from Nevada Division of Environmental Protection issued on August 18, 2000.

1)	Monthly production and injection reports which are filed with the IDWR;

2)	Quarterly ground water monitoring reports which are filed with IDWR;

3)	Annual land application and blowdown water quality reports filed with the Idaho Department of Environmental Quality.

4)	Annual Tier II reporting filed with the Idaho Bureau of Homeland Security, Local Emergency Planning Committee, and the local fire department.

(a)	Energy produced, saved and used for the generation of electric power, which is then sold by lessee, has a royalty of ten percent (10%) of the net proceeds.

(b)	Energy produced, saved and sold by lessee, then used by the purchaser for generation of electric power, has a royalty of ten percent (10%) of the market value.

(c)	Energy produced, which is used for any purpose other than the generation of electricity has a royalty of five percent (5%) of the gross proceeds.

(a)	Energy produced, saved and sold by the Lessee, then used by the purchaser for generation of electric power, has a royalty of ten percent (10%) of the market value of the electric power.

(b)	Energy produced, saved and used for the generation of electric power, which is then sold by Lessee, has a royalty of three percent (3%) of the market value of the electric power.

(c)	Energy produced, which is used for any purpose other than the generation of electricity has a royalty of five percent (5%) of the gross proceeds.

	Current Contract
Contract No.	Expiration Date	Acres	Annual Rate
N63004	9/30/2013	1,280	$ 1,280
N63005	9/30/2013	1,279	1,279
N63006	9/30/2013	1,920	1,920
N63007	9/30/2013	1,920	1,920
N75233	11/1/2011	1,868	3,738
N75552	11/1/2012	2,560	2,560
N75553	11/1/2012	1,480	1,480
N75554	11/1/2012	2,118	2,119
N75555	11/1/2012	960	960
N75556	11/1/2012	1,480	1,480
N75557	11/1/2012	1,280	1,280
N75558	11/1/2012	680	680
N42707	Indefinite	1,797	0
N47169	12/1/2017	3	0
N74196	4/30/2012	640	640
N57437	9/30/2013	640	2,560

					For the Fiscal Years Ended March 31,
		2009			2008			2007			2006			2005
Operating Revenues	$	1,796,387		$	184,242		$	90,206		$	0		$	0
Operating Expenses		7,669,046			4,797,105			3,138,169			1,663,069			1,751,530
Loss from Continuing Operations		(5,872,659	)		(3,549,186	)		(1,942,884	)		(1,490,593	)		(1,830,421	)
Loss per share from Continuing Operations		(0.09	)		(0.06	)		(0.04	)		(0.08	)		(0.12	)
Cash dividends declared and paid per common share		0			0			0			0			0
	As of March 31,
		2009			2008			2007			2006			2005

Total Assets	$	51,631,870		$	40,366,933		$	22,673,340		$	21,895,933		$	2,584,970
Total Long-term Obligations (1)		1,972,200			1,975,672			2,533,858			1,707,548			0

	Loss per share from Continuing Operations			Operating Revenues		Gross Profit		Loss from Operations			Net Loss from Continued Operations
Fiscal Year Ended March 31, 2007
1^stQuarter	$	(0.01	)	$	0	$	0	$	(961,777	)	$	(372,486	)
2^ndQuarter		(0.02	)		206		206		(746,292	)		(680,021	)
3^rdQuarter		(0.01	)		90,000		90,000		(610,310	)		(338,278	)
4^thQuarter		(0.01	)		0		0		(729,584	)		(552,099	)
Fiscal Year Ended March 31, 2008
1^stQuarter		(0.01	)		0		0		(694,622	)		(410,536	)
2^ndQuarter		(0.02	)		0		0		(1,374,285	)		(1,042,678	)
3^rdQuarter		(0.01	)		0		0		(1,103,192	)		(806,494	)
4^thQuarter		(0.02	)		184,242		184,242		(1,440,764	)		(1,289,478	)
Fiscal Year Ended March 31, 2009
1^stQuarter		(0.03	)		358,635		358,635		(1,936,923	)		(1,879,466	)
2^ndQuarter		(0.03	)		614,383		614,383		(1,645,823	)		(1,595,476	)
3^rdQuarter		(0.01	)		424,799		424,799		(903,830	)		(878,373	)
4^thQuarter		(0.02	)		398,570		398,570		(1,386,083	)		(1,382,432	)

				Net Income (Loss)
		Total Operating					U.S. Geothermal
Quarter Ended:		Revenues		Total			Inc.’s Portion

March 28, 2008	$	1,025,459	$	(406,606	)	$	(136,440	)
June 27, 2008		1,126,051		(119,141	)		(40,125	)
September 26, 2008		1,408,357		(319,558	)		(110,070	)
December 26, 2008		1,625,010		426,339			146,900
March 27, 2009		1,355,582		(14,170	)		(4,883	)

			Total
	MWH		Operating
Quarter Ended:	Produced		Revenues		Net Loss			Cash Flow

June 30, 2008 *	3,211	$	273,635	$	(215,769	)	$	(85,970	)
September 30, 2008 **	5,649		529,383		(63,779	)		131,267
December 31, 2008 **	4,097		337,272		(268,918	)		(71,977	)
March 31, 2009	3,808		309,406		(267,114	)		(65,402	)
	16,765	$	1,449,696	$	(815,580	)	$	(92,082	)

1)	optimizing the operation of the Unit I power plant at the Raft River, Idaho geothermal project (“Raft River Unit I”);

2)	evaluating flow test results from exploration well NHS-1, planning and permitting drilling and field development activities at Neal Hot Springs in Oregon;

3)	identifying potential buyers and negotiating a PPA for the Neal Hot Springs Project;

4)	optimizing the operation of the San Emidio (formerly Empire) power plant in Nevada, and planning for repowering the existing plant;

5)	drilling one exploration drill hole and permitting for additional exploration drill holes at the San Emidio Project; and

6)	the evaluation of potential new geothermal project acquisitions.

*	- two months of operations.
**	- Net Loss reflects a reclassification adjustment of $122,059 in expenses.

	Total	< 1 year	1-3 years	3-5 years	> 5 years
Operating Leases	$ 538,841	$ 143,377	$ 208,971	$ 87,702	$ 98,791
Capital Leases	49,943	10,998	24,573	14,372	0
Stock Compensation Payable	1,933,255	109,504	1,545,038	278,713	0

NAME	AGE	POSITION

Daniel J. Kunz	57	Chief Executive Officer, President and Director
Douglas J. Glaspey	56	Chief Operating Officer and Director
John H. Walker ^{(1) (2) (3)}	60	Chairman of the Board and Director
Paul A. Larkin ^{(1) (2) (3)}	58	Director
Leland R. Mink ^{(1) (3)}	69	Director
Kerry D. Hawkley	55	Chief Financial Officer and Corporate Secretary
Kevin Kitz	48	Vice President, Development, Geo-Idaho
Robert Cline	52	Vice President, Engineering, Geo-Idaho
Christopher S. Harriman	51	President, U.S. Geothermal Services LLC

⁽¹⁾	Member of the Audit, Compensation and Governance Committees.
⁽²⁾	Audit Committee Financial Expert.
⁽³⁾	Independent Director.

Summary Compensation Table
Name and Principal Position(s)	Years Ended March 31,	Salary ($)	Bonus ($)	Option Awards ($)	All Other Comp ($)	Totals ($)
(a)	(b)	(c)	(d)	(f)	(i)	(j)
Daniel J. Kunz, Chief Executive Officer and President	2007	132,000	30,000	532,257	37,960	732,217
	2008	141,600	11,000	61,756	0	214,356
	2009	170,400	0	304,849	8,170	483,419
Douglas J. Glaspey, Chief Operating Officer	2007	108,000	22,500	381,619	0	512,119
	2008	117,000	9,000	61,756	0	187,756
	2009	144,000	0	304,849	1,035	449,884
Kerry D. Hawkley, Chief Financial Officer	2007	96,000	25,000	135,575	0	256,575
	2008	103,950	8,000	61,756	0	173,706
	2009	127,800	0	121,940	0	249,740
Total Executive Officers	2007	336,000	77,500	1,049,451	37,960	1,500,911
	2008	362,550	28,000	185,268	0	575,818
	2009	442,200	0	731,638	9,205	1,183,043


(c)	– Annual compensation that includes the dollar value of base salary (cash and non-cash).
(d)	- Dollar value of bonuses (cash and non-cash) are eligible to all employees. Bonus plans are submitted and approved by the Board annually.
(f)	– Stock options are valued at the grant date using the SFAS 123R value.
(i)	– Other compensation consists of all other compensation not disclosed in another category.

			Termination
	Termination	Change	after change
	not for cause	of control	of control
Executive Officer	($)	($)	($)

Daniel J. Kunz*
Salary	-	-	-
Target bonus payout	-	-	-
Medical benefit continuation	-	-	-
Equity acceleration	-	-	-

Total	-	-	-
Douglas J. Glaspey
Salary	12,000	-	-
Target bonus payout	-	-	216,000
Medical benefit continuation	504	-	-
Equity acceleration	-	-	9,100

Total	12,504	-	225,100
Kerry D. Hawkley
Salary	10,650	-	-
Target bonus payout	-	-	191,700
Medical benefit continuation	320	-	5,800
Equity acceleration	-	-	-

Total	10,970	-	197,500

		Estimated Future Payouts Under			Estimated Future Payouts				All Other
		Non-Equity Incentive Plan			Under Equity Incentive Plan			All Other	Option
			Awards			Awards		Stock	Awards:
								Awards:	Number of
								Number of	Securities	Exercise or	Grant Date
								Shares of	Under-	Base Price	Fair Value
								Stock or	lying	of Option	of Stock
	Grant	Threshold	Target	Maximum	Threshold	Target	Maximu	Units	Options	Awards	and Option
Name	Date	($)	($)	($)	(#)	(#)	m (#)	(#)	(#)	($/Sh)	Awards¹⁸
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)
Daniel J. Kunz,
Chief Executive Officer	5/19/08								250,000	2.22	304,849

Douglas J Glaspey,
Chief Operating	5/19/08								250,000	2.22	304,849
Officer
Kerry D Hawkley,
Chief Financial	5/19/08								100,000	2.22	121,940
Officer

Outstanding Equity Awards at Fiscal Year End
	Option Awards					Stock Awards
Executive Name	Number of securities underlying unexercised options (#) exercisable	Number of securities underlying unexercised options (#) unexercisable	Equity incentive plan awards; number of securities underlying unexcersised unearned options (#)	Option exercise price ($)	Option expiration date	Number of shares not vested (#)	Market value of shares not vested (#)	Equity incentive plan awards: number of unearned shares or other rights that have not vested (#)	Equity incentive plan awards: market or payout value of unearned shares or other rights that have not vested ($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Daniel J. Kunz	530,000			1.00	4/12/11
Douglas J. Glaspey	380,000			1.00	4/12/11
Daniel J. Kunz	40,000			2.41	7/23/12
Douglas J. Glaspey	40,000			2.41	7/23/12
Kerry D. Hawkley	40,000			2.41	7/23/12
Daniel J. Kunz	125,000	125,000		2.22	5/19/13
Douglas J. Glaspey	125,000	125,000		2.22	5/19/13
Kerry D. Hawkley	50,000	50,000		2.22	5/19/13

Option Exercises and Stock Vested
	Option Awards		Stock Awards
	Number of shares	Value realized on	Number of shares	Value realized
Name	acquired on exercise	exercise	acquired on vesting	on vesting
	(#)	($)	(#)	($)
(a)	(b)	(c)	(d)	(e)
Douglas J. Glaspey	22,134	16,822	0/0	0/$0

Director Compensation
Name	Fees earned or paid in cash ($)	Stock awards ($)	* Option awards ($)	Non-equity incentive plan compensation ($)	Change in pension value and nonqualified deferred compensation earnings ($)	All other compensation ($)	Totals ($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
John H. Walker	20,000		73,164				93,164
Daniel J. Kunz	0		0				0
Paul A. Larkin	20,000		73,164				93,164
Douglas J. Glaspey	0		0				0
Leland L. Mink	20,000		73,164				93,164
Total	60,000		219,492				279,492

Equity Compensation Plan Information
	Number of securities to	Weighted average	Number of
Plan Category	be issued upon exercise	exercise price of	securities
	of outstanding options,	outstanding options,	remaining available
	warrants and rights	warrants and rights	for future issuance
Equity compensation plans approved by security holders	4,239,250	$1.62	1,964,138
Equity compensation plans not approved by security holders	Nil	Nil	Nil
Total	4,239,250	$1.62	1,964,138

Significant Owners
Title of Class	Name and Address of Beneficial Owner	Amount and Nature of Beneficial Owner	Percent of Class
(1)	(2)	(3)	(4)
Common Stock	Goldman, Sachs & Co, 30 Hudson Street, Jersey City, NJ 07302	4,610,874	7.43
Common Stock	Invesco Power Shares Capital Management LLC, 1555 Peachtree St. NE, Atlanta, GA 30309	5,521,026	8.90
Common Stock	Winslow Management Company LLC, 99 High Street, Boston, MA 02110	4,553,739	7.34

Name	Common Shares Beneficially Owned	Shares Individuals have the right to acquire within 60 days	Total Number of Shares Beneficially Owned	Percent of Class
(1)	(2)	(3)	(4)	(5)
Daniel J. Kunz	2,346,026	757,500	3,103,526	4.94
Douglas J. Glaspey	519,557	607,500	1,127,057	1.80
Kerry D. Hawkley	150,000	115,000	265,000	0.43
John H. Walker	78,234	150,000	228,234	0.37
Paul A. Larkin	368,068	255,000	623,068	1.00
Leland R. Mink	20,000	165,000	185,000	0.30

Years Ended
March 31,		Audit Fees (1)		Audit Related (2)		Tax Preparation (3)		Other Fees (4)
2009	$	55,007	$	34,264	$	-	$	77,992
2008		32,018		-		-		74,400

(1)	Includes services for the annual audit of the Company’s financial statements and services associated with SB-2 registration statements filed with the SEC.

(2)	Fees charged for assurance and related services reasonably related to the performance of an audit, and not included under “Audit Fees”.

(3)	Fees charged for tax compliance, tax advice and tax planning services.

(4)	Fees for services other than disclosed in any other column.

EXHIBIT NUMBER	DESCRIPTION

3.1	Certificate of Incorporation of U.S. Cobalt Inc. (now known as U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

3.2	Certificate of Domestication of Non-U.S. Corporation (Incorporated by reference to exhibit 3.2 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

3.3	Certificate of Amendment of Certificate of Incorporation (changing name of U.S. Cobalt Inc. to U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.3 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

3.4	Bylaws of U.S. Geothermal Inc. (formerly U.S. Cobalt Inc.) (Incorporated by reference to exhibit 3.4 to the registrant’s Form 10-Q quarterly report as filed on February 14, 2008)

3.5	Plan of Merger of U.S. Geothermal, Inc. and EverGreen Power Inc. (Incorporated by reference to exhibit 3.5 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

3.6	Amendment to Plan of Merger (Incorporated by reference to exhibit 3.6 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

4.1	Form of Stock Certificate (Incorporated by reference to exhibit 4.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

4.2	Form of Warrant Certificate (Incorporated by reference to exhibit 4.2 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

4.3	Provisions Regarding Rights of Stockholders (Incorporated by reference to exhibit 4.3 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

4.4	Form of Subscription Agreement (Incorporated by reference as exhibit 10.2 to the registrant’s Form 8-K current report as filed on May 2, 2008)

4.5	Form of Warrant (Incorporated by reference as exhibit 10.3 to the registrant’s Form 8-K current report as filed on May 2, 2008)

4.6	Form of Broker Warrant (Incorporated by reference as exhibit 10.4 to the registrant’s Form 8-K current report as filed on May 2, 2008)

10.1	Agreement between U.S. Geothermal Inc. and Vulcan Power Company dated December 3, 2002 regarding the acquisition of the Vulcan interest (Incorporated by reference to exhibit 10.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

10.2	Amendment No. 1 dated November 15, 2003 to Agreement between U.S. Geothermal Inc. and Vulcan Power Company (Incorporated by reference to exhibit 10.2 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

10.3	Amendment No. 2 to “Agreement by and between U.S. Geothermal Inc. and Vulcan Power Company” dated December 30, 2003 (Incorporated by reference to exhibit 10.3 to the registrant's Form SB-2 registration statement as filed on July 8, 2004)

EXHIBIT NUMBER	DESCRIPTION

10.4	Geothermal Lease and Agreement dated July 11, 2002, between Sergene Jensen, Personal Representative of the Estate of Harlan B. Jensen, and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.5 to the registrant's Form SB-2 registration statement as filed on July 8, 2004)

10.5	Geothermal Lease and Agreement dated June 14, 2002, between Jensen Investments Inc. and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.6 to the registrant's Form SB-2 registration statement as filed on July 8, 2004) Geothermal Lease and Agreement dated March 1, 2004, between Jay Newbold and U.S.

10.6	Geothermal Inc. (Incorporated by reference to exhibit 10.7 to the registrant's Form SB-2 registration statement as filed on July 8, 2004)

10.7	Geothermal Lease and Agreement dated June 28, 2003, between Janice Crank and thechildren of Paul Crank and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.8 to the registrant's Form SB-2 registration statement as filed on July 8, 2004)

10.8	Geothermal Lease and Agreement dated December 1, 2004, between Reid S. Stewartand Ruth O. Stewart and US Geothermal Inc. (Incorporated by reference to exhibit 10.9 to the registrant's Amendment No. 2 to Form SB-2 registration statement as filed on January 10, 2005)

10.9	Geothermal Lease and Agreement, dated July 5, 2005, between Bighorn Mortgage Corporation and US Geothermal Inc. (Incorporated by reference to exhibit 10.11 to the registrant's Form 10-QSB quarterly report as filed on February 17, 2006)

10.10	Geothermal Lease and Agreement, dated June 23, 2005, among Dale and Ronda Doman, and US Geothermal Inc. (Incorporated by reference to exhibit 10.13 to the registrant's Form 10-QSB quarterly report as filed on February 17, 2006)

10.11	Geothermal Lease and Agreement, dated June 23, 2005, among Michael and Cleo Griffin, Harlow and Pauline Griffin, Douglas and Margaret Griffin, Terry and Sue Griffin, Vincent and Phyllis Jorgensen, and Alice Mae Griffin Shorts, and USGeothermal Inc. (Incorporated by reference to exhibit 10.14 to the registrant's Form 10-QSB quarterly report as filed on February 17, 2006)

10.12	Geothermal Lease and Agreement dated January 25, 2006, between Philip Glover andUS Geothermal Inc. (Incorporated by reference to exhibit 10.9 to the registrant's Form 10-QSB quarterly report as filed on February 17, 2006)

10.13	Geothermal Lease and Agreement, dated May 24, 2006, between JR Land and Livestock Inc. and US Geothermal Inc. (Incorporated by reference to exhibit 10.30 to the registrant's Form 10-KSB annual report as filed on June 29, 2006)

10.16	Employment Agreement dated January 1, 2009 with Kerry D. Hawkley

10.17	Employment Agreement dated January 1, 2009 with Douglas J. Glaspey

10.18	Escrow Agreement made December 19, 2003, among U.S. Geothermal Inc., Pacific Corporate Trust Company, as escrow agent, and certain security holders (Incorporated by reference to exhibit 10.15 to the registrant's Form SB-2 registration statement as filed on July 8, 2004)

10.19	Escrow Agreement made December 19, 2003, among U. S. Geothermal Inc., Pacific Corporate Trust Company, as escrow agent, and certain security holders (Incorporated by reference to exhibit 10.16 to the registrant's Form SB-2 registration statement as filed on July 8, 2004)

10.21	First Amended and Restated Merger Agreement dated November 30, 2003 among U.S. Cobalt Inc., EverGreen Power Inc., U.S. Geothermal Inc., and the stockholders of U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.17 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)


10.22	Agreement with Dundee Securities Corporation dated June 28, 2004 (Incorporated by reference to exhibit 10.18 to the registrant's Form SB-2 registration statement as filed on July 8, 2004)

10.23	Amended and Restated Stock Option Plan of U.S. Geothermal Inc. dated September 29, 2006. (Incorporated by reference to exhibit 10.23 to the registrant's Form SB-2 registration statement as filed on October 2, 2006.)

10.24	Power Purchase Agreement dated December 29, 2004 between U.S. Geothermal Inc. and Idaho Power Company (Incorporated by reference to exhibit 10.19 to the registrant's Amendment No. 2 to Form SB-2 registration statement as filed on January 10, 2005)

10.25	Engineering, Procurement and Construction Agreement dated December 5, 2005 between U.S. Geothermal Inc. and Ormat Nevada Inc. (Incorporated by reference to exhibit 10.28 to the registrant's Form 10-QSB quarterly report as filed on February 17, 2006) *

10.26	Amendment to the Engineering, Procurement and Construction Agreement dated April 26, 2006 between U.S. Geothermal Inc. and Ormat Nevada Inc. (Incorporated by reference to exhibit 99.1 to the registrant's Form 8-K as filed on May 2, 2006)

10.27	Letter of Intent from Eugene Water and Electric Board to U.S. Geothermal Inc. dated February 22, 2006 (Incorporated by reference to exhibit 10.27 to the registrant’s Form SB-2 as filed on September 29, 2006).

10.28	Renewable Energy Credits Purchase and Sales Agreement dated July 29, 2006 between Holy Cross Energy and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.28 to the registrant’s Form SB-2 as filed on September 29, 2006).

10.29	Transmission Agreement dated June 24, 2005 between Department of Energy’s Bonneville Power Administration - Transmission Business Line and U.S. GeothermalInc. (Incorporated by reference to exhibit 10.27 to the registrant's Form 10-QSB quarterly report as filed on August 12, 2005)

10.30	Interconnection and Wheeling Agreement dated March 9, 2006 between Raft River Rural Electric Co-op and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.28 to the registrant's Form 10-KSB annual report as filed on June 29, 2006)

10.31	Construction Contract dated May 16, 2006 between Raft River Rural Electric Co-op and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.31 to the registrant’s Form SB-2 as filed on September 29, 2006).

10.32	Membership Admission Agreement, dated August 9, 2006, among Raft River Energy I LLC, U.S. Geothermal Inc., and Raft River I Holdings, LLC (Incorporated by reference to exhibit 10.1 to the registrant's Form 8-K as filed on August 23, 2006) *

10.33	Amended and Restated Operating Agreement of Raft River Energy I LLC, dated as of August 9, 2006, among Raft River Energy I LLC, Raft River I Holdings, LLC and U.S.Geothermal Inc (Incorporated by reference to exhibit 10.2 to the registrant's Form 8-K as filed on August 23, 2006).*

10.34	Management Services Agreement, dated as of August 9, 2006, between Raft River Energy I LLC and U.S. Geothermal Services, LLC (Incorporated by reference to exhibit 10.3 to the registrant’s Form 8-K as filed on August 23, 2006) *