US GEOTHERMAL INC - FORM 10-K

Attached files

file	filename
EX-13.1 - EXHIBIT 13.1 - US GEOTHERMAL INC	exhibit13-1.htm
EX-23.2 - EXHIBIT 23.2 - US GEOTHERMAL INC	exhibit23-2.htm
EX-31.1 - EXHIBIT 31.1 - US GEOTHERMAL INC	exhibit31-1.htm
EX-32.1 - EXHIBIT 32.1 - US GEOTHERMAL INC	exhibit32-1.htm
EX-23.3 - EXHIBIT 23.3 - US GEOTHERMAL INC	exhibit23-3.htm
EX-23.4 - EXHIBIT 23.4 - US GEOTHERMAL INC	exhibit23-4.htm
EX-32.2 - EXHIBIT 32.2 - US GEOTHERMAL INC	exhibit32-2.htm
EX-21.1 - EXHIBIT 21.1 - US GEOTHERMAL INC	exhibit21-1.htm
EX-31.2 - EXHIBIT 31.2 - US GEOTHERMAL INC	exhibit31-2.htm
EX-23.5 - EXHIBIT 23.5 - US GEOTHERMAL INC	exhibit23-5.htm
EX-23.1 - EXHIBIT 23.1 - US GEOTHERMAL INC	exhibit23-1.htm
EX-13.2 - EXHIBIT 13.2 - US GEOTHERMAL INC	exhibit13-2.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934
For the fiscal year ended March 31, 2010

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

Commission File Number 001-34023

U.S. GEOTHERMAL INC.

(Exact name of Registrant as specified in its charter)

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)

Registrant’s Telephone Number, Including Area Code 208-424-1027

Securities registered under Section 12(b) of the Exchange Act:

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

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is well-known seasoned issuer, as defined in Rule 405 of the Securities Act

[ ] Yes [X] 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 [X] 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.

[X] 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 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 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. [ ]

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.

Large accelerated filer [ ]	Accelerated filer [X]

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

[ ] Yes [X] 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, 2010: $57,412,876

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

Class of Equity	Shares Outstanding as of June 8, 2010
Common stock, par value	78,647,776
$ 0.001 per share

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant’s 2010 Annual Meeting of Shareholders to be held on August 23, 2010 are incorporated by reference into Part III of this Form 10-K.

U.S. Geothermal Inc. and Subsidiaries

Form 10-K

INDEX

For the Year Ended March 31, 2010

		Page
PART I

Item 1	Description of Business	5
	General	5
	Development of Business	6
	History	6
	Plan of Operations	8
	Cash Requirements	9
	Material Acquisitions/Development	11
	Employees	16
	Principal Products	16
	Sources and Availability of Raw Materials	16
	Significant Patents, Licenses, Permits, Etc.	17
	Seasonality of Business	18
	Industry Practices/Needs for Working Capital	18
	Dependence on a Few Customers	19
	Competitive Conditions	19
	Environmental Compliance	20
	Financial Information about Geographic Areas	20
	Available Information	20
	Governmental Approvals and Regulations	21
	Environmental Credits	22
	Regulatory Update	23
Item 1A	Risk Factors
	General Business Risks	24
	Risks Relating to the Market for Our Securities	31
Item 1B	Unresolved Staff Comments	32
Item 2	Description of Property	33
	Raft River, Idaho	34
	Raft River Energy Unit I	36
	Neal Hot Springs, Oregon	39
	San Emidio, Nevada	41
	Gerlach, Nevada	43
	Granite Creek, Nevada	44
	Republic of Guatemala	45
	Boise Administration Office, Idaho	45
Item 3	Legal Proceedings	46
Item 4	Removed and Reserved	46

U.S. Geothermal Inc. and Subsidiaries

Form 10-K

INDEX

For the Year Ended March 31, 2010

		Page
PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	47
Item 6	Selected Financial Data	49
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
	Factors Affecting Our Results of Operations	53
	Results of Operations	56
	Liquidity and Capital Resources	62
	Potential Acquisitions	63
	Critical Accounting Policies	63
	Contractual Obligations	65
	Off Balance Sheet Arrangements	66
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	66
Item 8	Financial Statements and Supplementary Data	67
Item 9	Changes in and Disagreements with Accountants on Accounting And Financial Disclosure	67
Item 9A	Controls & Procedures	67
Item 9B	Other Information	68

PART III
Item 10	Other Information	69
Item 11	Executive Compensation	69
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	70
Item 13	Certain Relationships and Related Transactions, and Director Independence	70
Item 14	Principal Accounting Fees and Services	70

PART IV
Item 15	Exhibits, Financial Statement Schedules	71

PART I

ITEM 1. DESCRIPTION OF BUSINESS

Information Regarding Forward Looking Statements

This document contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve a number of risks and uncertainties. We caution readers that any forward-looking statement is not a guarantee of future performance and that actual results could differ materially from those contained in the forward-looking statement. These statements are based on current expectations of future events. You can find many of these statements by looking for words like “believes,” “expects,” “anticipates,” “intend,” “estimates,” “may,” “should,” “will,” “could,” “plan,” “predict,” “potential,” or similar expressions in this document or in documents incorporated by reference in this document. Examples of these forward-looking statements include, but are not limited to:

our business and growth strategies;
our future results of operations;
anticipated trends in our business;
the capacity and utilization of our geothermal resources;
our ability to successfully and economically explore for and develop geothermal resources;
our exploration and development prospects, projects and programs, including construction of new projects and expansion of existing projects;
availability and costs of drilling rigs and field services;
our liquidity and ability to finance our exploration and development activities;
our working capital requirements and availability;
our illustrative plant economics;
market conditions in the geothermal energy industry; and
the impact of environmental and other governmental regulation.

These forward-looking statements are based on the current beliefs and expectations of our management and are subject to significant risks and uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ materially from current expectations and projections. The following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements:

the failure to obtain sufficient capital resources to fund our operations;
unsuccessful construction and expansion activities, including delays or cancellations;
incorrect estimates of required capital expenditures;

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increases in the cost of drilling and completion, or other costs of production and operations;
the enforceability of the power purchase agreements for our projects;
impact of environmental and other governmental regulation, including delays in obtaining permits;
hazardous and risky operations relating to the development of geothermal energy;
our ability to successfully identify and integrate acquisitions;
our dependence on key personnel;
the potential for claims arising from geothermal plant operations;
general competitive conditions within the geothermal energy industry; and
financial market conditions.

All subsequent written or oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. We do not undertake any obligation to release publicly any revisions to these forward-looking statements to reflect events or circumstances after the date of this document or to reflect the occurrence of unanticipated events, except as may be required under applicable U.S. securities law. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.

The U.S. dollar is the Company’s functional currency; however some transactions involved the Canadian dollar. 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,” “HTM” 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.

Development of Business

History

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.

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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, HTM 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 HTM 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 HTM, 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 (“RREI”) commenced commercial operations on January 3, 2008. Raft River Unit I is currently selling an annual average of 8.8 megawatts (“MWs”) of power to Idaho Power Company under a net 13 MW power purchase agreement (“PPA”) which expires in 2032. Management is currently evaluating alternatives to bring the RREI plant operations to its nameplate capacity of 13 MW.

In May 2008, we acquired the geothermal assets, including a 3.6 net MW nameplate generating capacity power plant, from Empire Geothermal Power LLC and Michael B. Stewart, located in Washoe County, Nevada for approximately $16.6 million which includes the Granite Creek geothermal and water rights. The plant currently generates an approximate average net output of 2.5 MWs, 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 35 MW development in two phases with the first phase 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 8.2 net MWs and currently is expected to be on line in late 2011. The second phase is anticipated to add 26 MW of power supplied from new production wells to be drilled but requires a significant transmission line upgrade. The second phase is expected to be on line late 2012.

On September 5, 2006, the Company announced the acquisition of property for a geothermal project at Neal Hot Springs, Oregon located in eastern Oregon near the Idaho boarder. The property is 8.5 square miles of geothermal energy and surface water rights. On May 5, 2008, the Company announced that drilling had begun on the first full size production well (“NHS-1”) which was completed on May 23^rd. In February 2009, the Company submitted an application for the project to the U.S. Department of Energy’s (“DOE”) Energy Efficiency, Renewable Energy and Advanced Transmission and Distribution Solicitation loan guarantee program under Title XVII of the Energy Policy Act of 2005. On May 26, 2009, the Company announced that it had been selected by DOE to enter into due diligence review on a project loan. Upon meeting requirements, the loan is expected to provide up to 75% of the total estimated construction costs. Construction on the first drill pad was completed in August 2009. In September 2009, the Company began drilling production well number 5 (“NHS-5”), which was substantially completed on October 15, 2009. Also, in September 2009, the Company began a temperature gradient well program to expand the knowledge of the entire geothermal resource. On December 14, the Company announced that it’s wholly owned subsidiary USG Oregon LLC has signed a 25-year power purchase agreement with Idaho Power Company that provides for the sale of up to 25 MWs. The PPA was approved by the Idaho PUC in May of 2010.

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Plan of Operations

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 exploration and development properties located in:

	-	Raft River, Idaho;
	-	Neal Hot Springs, Oregon;
	-	San Emidio, Nevada;
	-	Gerlach, Nevada;
	-	Granite Creak, Nevada; and,
	-	Republic of Guatemala.

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:

Leverage Management Team Capabilities and Experience – Our strategy is focused on the identification and acquisition of resources that can be developed in a cost-effective manner to produce attractive returns. In particular, we seek to acquire projects that have already undergone geothermal resource discovery. In addition, we intend to operate and manage construction of the projects, while using internal personnel and third-party contractors to efficiently and cost-effectively develop those resources. We believe that we have the strategic personnel in place to determine which resources provide the greatest opportunity for efficient development and operation. We have developed relationships and employed personnel that will allow us to develop and utilize geothermal resources as efficiently as possible.
Develop Our Pipeline of Quality Projects – Our project pipeline currently consists of several projects that we believe are aligned with our growth strategy. These projects have consulting reports from various industry experts supporting our belief in those projects’ potential, and we have started PPA negotiations for power off-take with counterparties for some of these growth opportunities. If realized, our identified project pipeline will greatly expand our renewable power generation capacity.
Utilize Production Tax Credits, Investment Tax Credits and Other Incentives – Although geothermal power production can be cost competitive with fossil fuel power generating facilities without government subsidies in some cases, production tax credits (“PTC”) and Investment Tax Credits (“ITC”) available to geothermal power producers enhance the project economics and attract capital investment. For the Raft River Unit I project, we partnered with Goldman Sachs in order to fully utilize production tax credits available to the joint venture. Our strategy going forward is to structure project ownership to be the primary beneficiary of project economics. Recent legislation enacted as part of the stimulus funding has provided an election to take 30% ITC 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 2013. This ITC election may be available to us at our San Emidio and Neal Hot Springs projects.

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Pursue Acquisition Strategy – The geothermal market, particularly in the United States, is fragmented and characterized by a few large players and a number of smaller ones. Geothermal exploration and development is costly, technically challenging and requires long lead times before a project will produce revenue. We believe that geothermal technical and managerial talent is limited in the industry and that access to capital to develop projects will not be equally available to all participants. As a result, we believe that there will be opportunities in the future to pursue acquisitions of geothermal projects and/or geothermal development companies with attractive project pipelines.
Evaluate Other Potential Revenue Streams from Geothermal Resources – In addition to electricity generation, we will evaluate additional applications for our geothermal resources including industrial, agriculture, and aquaculture purposes. These uses generally constitute lower temperature applications where, after driving a turbine generator, residual hot water can be cycled for secondary processes before being returned to the geothermal reservoir by injection wells, which can provide incremental revenue streams. We will evaluate the optimal use for each geothermal resource and determine whether selling heat for industrial purposes or generating and subsequently selling power to a grid will generate the highest return on the asset.

Cash Requirements

We believe our cash and liquid investments at March 31, 2010 are adequate to fund our general operating activities through March 31, 2011 including limited drilling at Neal Hot Springs and general development support activities at San Emidio. 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. In addition to government loans and grants discussed below, we anticipate that the additional funding may be raised through the issuance of equity and/or through the sale of ownership interest in tax credits and 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 2010 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 loans and 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 the near future. In these difficult financial times, the Company has also implemented procedures to conserve cash, reduce costs and maximize revenue. At the corporate level, we have 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 look for additional cost savings.

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On March 16, 2010, the Company closed a private placement of securities issued pursuant to a securities purchase agreement (the "Purchase Agreement") entered into with several institutional investors, pursuant to which the Company issued 8,209,519 shares of common stock at a price of $1.05 per share for gross proceeds of approximately $8.6 million (the "Private Placement"). Pursuant to the terms of the Private Placement, each investor was also issued a common share purchase warrant (a "Warrant") exercisable for 50% of the number of shares of common stock purchased by the investor. The Company paid commissions to agents in connection with the Private Placement in the amount of approximately $516,000 and issued warrants to purchase up to 246,285 shares of common stock. The net proceeds of the offering (approximately $8.0 million) will be used by the Company to further develop its Neal Hot Springs geothermal project and for general working capital purposes.

On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio will apply innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture fractures that represent high-productivity geothermal drilling targets.

On August 17, 2009, the Company completed a private placement of 8,100,000 Subscription Receipts (“Receipt”) at $1.35 CDN per Receipt for aggregate gross proceeds of CDN $10,935,000. Each Receipt was exchanged on December 17, 2009 for one share of common stock of the Company and one half of one common stock purchase warrant (a "Warrant"). Each Warrant entitles the holder thereof to acquire one additional share of common stock of the Company for $1.75 for 24 months from closing. The placement agents have been paid an aggregate cash fee of CDN $656,100, representing 6% of the aggregate gross proceeds of the offering, and have been issued compensation options, exercisable for 24 months, entitling the placement agents to purchase up to 243,000 shares of common stock of the Company at US$1.22. The proceeds were used to drill up to three production size wells at Neal Hot Springs to increase production capacity to 22 MW and allow a 30-day flow test to verify the well reservoir capacity. Completion of drilling is a condition precedent to the funding from the DOE loan program, if our application is approved.

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On February 26, 2009 U.S. Geothermal submitted an application for the Neal Hot Springs project to the DOE’s 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. Although we have not yet received approval, the DOE guaranteed loan is expected to provide up to 75% of the $119 million estimated capital cost of Stage I up to a maximum loan amount of $102.2 million. The capital cost has increased to $119 million from prior estimates of $106 million due to costs of labor, updated vendor pricing and construction materials, project loan costs and contingencies. Detailed design of a binary cycle power plant utilizing significantly improved technology is currently in progress with construction expected to begin in mid 2010. The new plant, designed to deliver approximately 22 MW of power net to the grid is scheduled to begin commercial operations in early 2012. The DOE guaranteed loan is anticipated to be a combined construction and term loan and provide the project with a low cost annual interest rate. We expect that we will be required to drill up to 8 additional wells as a condition precedent to drawing on the DOE guaranteed loan, if it is approved.

Material Acquisitions/Development

Raft River, Idaho

Raft River Energy Unit I is located in Idaho and has a 13 net MW capacity geothermal power plant in operation.

In early January 2009, production well RRG-7 underwent a temperature decline that has reduced the inlet fluid temperature to the power plant over the past year by approximately 10 degrees Fahrenheit. At the same time of the temperature change, fluid flow increased. Power generation has been reduced by an estimated 1 MW due to the lower temperature fluid. It was determined that the cement in a lap joint had failed so a mechanical packer was installed to reduce the cold water inflow, but was unsuccessful. A remediation program is planned that will “squeeze” cement into the lap joint and plug off the cold water flow to return the well temperature and increase power plant generation.

Raft River Unit I operated through the year at 95.2 percent availability which includes a scheduled maintenance outage of 12 days in April that was extended to replace a turbine damaged during construction. Raft River generated in a range of 7.7 to 10.1 net MWs during the twelve month period ended March 31, 2010 averaging 8.8 MWs. The reduction in output for the period compared to the planned generation was due to the loss of temperature from production well RRG-7.

The joint venture partners are evaluating a recovery plan that includes repairing the lap joint RRG-7, drilling a new production leg on one or two existing production wells and drilling a new injection well. We anticipate completing the repair of well RRG-7 in the first half of the year before a decision is made on the remainder of the recovery plan.

As shown in the table below, Raft River Unit II is estimated to cost approximately $134 million and Raft River Unit III is anticipated to cost approximately $166 million, 75% of which we believe may be funded by loans, with the remainder funded through equity financing. Provided equity funding is available to the project, Raft River Unit II is anticipated to begin construction in the fourth calendar quarter of 2010 with commercial operations commencing in the fourth calendar quarter of 2013. Raft River Unit III is anticipated to begin construction in the first calendar quarter of 2014 with commercial operations commencing in the second calendar quarter of 2015.

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San Emidio, Nevada

The San Emidio 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. 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 gross MW Ormat Energy Converters (“OEC”), five production wells (two wells in use and three on stand by), and four injection wells (three wells in use and one on standby). A cooling tower was added in 1998 to improve summer peak power generation. Power sales from the San Emidio plant for the last fiscal year averaged 2.2 MWs.

Two System Feasibility Studies were initiated in July 2008 with Sierra Pacific Power Corporation to begin the FERC mandated transmission study process for the development of the San Emidio resource. The studies are examining two levels of power generation, 15 MWs and 45 MWs, several transmission routes and the costs associated with each level of generation. The System Impact Study for the 15 MW Phase I repower, the second phase of interconnection study process, was completed in July and confirmed that the existing transmission system was able to handle up to 15 MWs. The third phase study, the Interconnection Facilities Study for the 15 MW option, was completed in October. A draft interconnection agreement is expected from Sierra Pacific Power before the end of the second calendar quarter of 2010.

Subsequent to the end of the fiscal year, the System Impact Study for the 45 MW option was received in April. The third phase study for the 45 MW option, the Interconnection Facilities Study, will be contracted during the second calendar quarter and is expected to be completed before year end.

On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio will apply innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture factures that represent high-productivity geothermal drilling targets. Initial geologic mapping under the program has been initiated and the seismic team has been contracted.

The San Emidio expansion will take place in two phases. Phase I will be a repower and Phase II will be the expansion. Phase I will utilize the existing production and injection wells with a new, more efficient power plant. As shown in the table below, the repower is anticipated to cost approximately $30 million and the expansion is anticipated to cost $127 million, 75% of which we believe may be funded by a Department of Energy loan guarantee, with the remainder funded through equity financing. The Phase I repower is anticipated to begin construction in the third calendar quarter of 2010 with commercial operations commencing in the fourth calendar quarter of 2011 or first calendar quarter of 2012. The Phase II expansion is anticipated to begin construction in the second calendar quarter of 2010 with commercial operations commencing in the third calendar quarter of 2012. The Company hopes to utilize Investment Tax Credits in connection with both the repower and the expansion. Both phases will require an amendment to the Sierra Pacific Power Purchase Agreement.

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Neal Hot Springs, Oregon

Neal Hot Springs is a promising geothermal resource located in Eastern Oregon.

Although we have not yet received approval, the DOE guaranteed loan is expected to provide up to 75% of the $119 million estimated capital cost of Stage I up to a maximum loan amount of $102.2 million. The capital cost has increased to $119 million from prior estimates of $106 million due to costs of labor, updated vendor pricing and construction materials, loan costs and contingencies. Detailed design of a binary cycle power plant utilizing significantly improved technology is currently in progress with construction expected to begin in mid 2010. The new plant, designed to deliver approximately 22 MWs of power net to the grid is scheduled to begin commercial operations in early 2012. The DOE guaranteed loan is anticipated to be a combined construction and term loan and provide the project with a low cost annual interest rate. We expect that we will be required to drill up to 8 additional wells as a condition precedent to drawing on the DOE guaranteed loan.

At our Neal Hot Springs project, an infill geophysical program was carried out to increase the density of data to highlight suspected geologic targets and structures. Applications for four additional exploration wells to further delineate the geothermal resource with production and injection targets were approved by the state of Oregon on September 11, 2009 and drilling of the second production well, NHS-5, began on September 18, 2009. October 15, 2009, the Company successfully completed well NHS-5, the second full size production well at the Neal Hot Springs project located in eastern Oregon. NHS-5 encountered several lost circulation zones within the targeted horizon and intercepted a large aperture fracture at 2,796 feet resulting in a total loss of circulation. The well was completed to a depth of 2,896 feet. An initial 16 hour flow test completed using air lift produced fluid at a rate of 1,500 gallons per minute and resulted in a down hole flowing temperature of 286º F (141º C).

The reservoir-hosting fracture zone intersected in NHS-5 is 509 feet deeper in the geologic system than the large producing fracture intersected by NHS-1 which is located approximately 600 feet to the southeast. Both wells were instrumented with pressure and temperature equipment during the flow test. Geologic information and flow data from the drilling and flow test has been incorporated into the ongoing development of a reservoir model of the Neal Hot Springs geothermal system.

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In addition to the drilling program for production-sized wells, the company has continued a temperature gradient (“TG”) drilling program utilizing a small diameter drill hole. Eleven TG holes ranging in depth from 500 to 1,060 feet have been completed, and are providing valuable temperature gradient data for the overall area that hosts the Neal Hot Springs reservoir. Currently, several TG holes are being deepened and another three to five new TG holes will be drilled with a number of the holes planned to reach a depth of 2,000 feet as the size of the geothermal anomaly is defined.

The Company received the Conditional Use Permit from the Malheur County Planning Commission for construction of its proposed 22 net MW power plant at Neal Hot Springs in eastern Oregon. The Conditional Use Permit received unanimous approval at a September 24, 2009 Planning Commission meeting and was issued on October 28, 2009. All of the Federal Energy Regulatory Commission (“FERC”) mandated transmission studies have been completed by Idaho Power Company. An interconnection agreement was signed with the Idaho Power Company in February 2009. Private right-of-ways for the transmission line have been acquired, the line route is surveyed and the final engineering design has reached approximately 99% completion.

The power purchase agreement (“PPA”) for the project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting price of $96 per MW-hour and escalates at a set percentage annually. Idaho Power Company submitted the PPA to the Idaho Public Utilities Commission on December 28, 2009. IPUC authorized a Modified Procedure for review of the PPA on March 17, 2010 which calls for a 45 day public comment period and 10 day reply period. Subsequent to the end of the year, approval of the PPA by the IPUC was received on May 20, 2010.

The total development cost of Neal Hot Springs Stage II is anticipated to be $154 million. Construction is anticipated to begin in the third quarter of 2011 with commercial operations commencing in the third quarter of 2013.

Gerlach, Nevada

An EA has been completed and a drill site has been permitted on one of the BLM leases. Planning is underway to drill a 2,000 foot temperature gradient well and a shallow, 300-700 foot deep exploration/production well in 2010. Past drilling has indicated the presence of a shallow 260 to 265° F resource on the property in addition to a possible higher temperature, deep resource.

Granite Creek, Nevada

The Granite Creek assets are comprised of three BLM geothermal leases totaling approximately 5,414 acres (8.5 square miles) 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. A first stage gravity geophysical program was completed in the third quarter of 2008 and will be used to evaluate the resource potential, and help determine where to drill temperature-gradient exploration wells.

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Republic of Guatemala

Subsequent to the end of the year, the Company announced on April 15 that it was successful in acquiring a geothermal concession in the Republic of Guatemala. The concession consists of 24,710 acres (100 square kilometers) and is located 14 miles southwest of Guatemala City, the capital. Nine wells with depths ranging from 560 to 2,000 feet (170 to 610 meters) were drilled in the El Ceibillo resource area within the concession area during the l990s. Six of the wells have measured reservoir temperatures in the range of 365 to 400°F (185 to 204°C). Fluid sample analysis and the mineralogy associated with drill cuttings suggest the existence of a deeper, higher permeability reservoir with temperature potential of 410 to 446°F (210 to 230°C).

Preliminary reservoir, transmission and environmental studies have been completed for the project. Four additional prospects containing fumaroles and hot springs are located within the concession area. Planning is underway for deepening and detailed testing of the El Ceibillo wells to quantify their electrical generating capacity and to explore the other prospective areas.

Projects in Operation
			Generating		Contract
Project	Location	Ownership	Capacity (MW)⁽¹⁾	Power Purchaser	Expiration
Raft River (Unit I)	Idaho	JV⁽²⁾	13.0	Idaho Power Company	2032
San Emidio (Existing)	Nevada	100%	3.6	Sierra Pacific Power Corp.	2017

(1)

Based on the designed annual average net output. The actual output of the Raft River Unit I plant currently varies between 7.1 and 10.0 megawatts and output of the Empire plant is approximately 2.6 megawatts.

(2)

As part of the financing package for Unit I of the Raft River project, we have contributed $16.5 million in cash and approximately $1.5 million in property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group, contributed $34 million to finance the construction of the project. Additional investment may be required for Unit I to operate at design capacity.

Projects Under Development
			Target	Projected	Capital
			Development	Commercial	Required	Anticipated
Project	Location	Ownership	(MW)	Operation Date	($million)	Power Purchaser
San Emidio Phase I (Repower)	Nevada	100	5.4	1^stQuarter 2012	$30	NV Energy
San Emidio Phase II (Expansion)	Nevada	100	26	3rd Quarter 2012	$127	TBD
Neal Hot Springs 1	Oregon	100	22	2ndQuarter 2012	$119	Idaho Power
Neal Hot Springs II	Oregon	100	28	3^rdQuarter 2013	$154	TBD
Raft River I (Repower)	Idaho	JV	3	3^rdQuarter 2010	$7	Idaho Power
Raft River (Unit II)	Idaho	100	26	4^thQuarter 2013	$134	Eugene Water and Electric Board
Raft River (Unit III)	Idaho	100	32	2^ndQuarter 2015	$166	TBD

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Additional Properties

Project	Location	Ownership	Target Development (MW)
Gerlach	Nevada	60%	To be determined
Granite Creek	Nevada	100%	To be determined
El Ceibillo	Guatemala, S.A.	100%	To be determined

Resource Details
			Resource
	Property Size	Temperature	Potential
Property	(square miles)	(°F)	(MW)	Depth (Ft)	Technology
Raft River	10.8⁽¹⁾	275-302⁽²⁾	127.0⁽¹⁾	4,500-6,000	Binary
San Emidio	35.8	289-305⁽²⁾	68.0⁽⁴⁾	1,500-2,000	Binary
Neal Hot Springs	9.6	311-347⁽³⁾	50.0⁽⁵⁾	2,500-3,000	Binary
Gerlach	5.6	338-352⁽³⁾	18.0	TBD	Binary
Granite Creek	8.5	TBD	25.0⁽⁶⁾	TBD	Binary
El Ciebillo	38.6	410-446⁽³⁾	TBD	TBD	Steam

(1)	Geothermex Inc.’s assessment of 94 MW was based on 6.0 square miles. The Company acquired additional acreage. The resource estimate of 127.0 MW is an internal estimate.
(2)	Actual production temperatures for existing wells.
(3)	Probable reservoir temperature as measured with a geothermometer.
(4)	Black Mountain Technology Resource estimate with respect to 49.0 MW, remainder is an internal estimate.
(5)	Geothermal Science, Inc. resource estimate with respect to 22.0 MW, remainder is an internal estimate.
(6)	Internal estimate.

Employees

At March 31, 2010, the Company had 33 full-time and one part time employee (12 administrative and project development, and 22 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.

Principal Products

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 under exploration or development are sites located in the Western Region of the United States of America. The Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America in April of 2010. Development options are currently being explored to determine how to maximize this opportunity.

Sources and Availability of Raw Materials

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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.

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

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.

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 Raft River, Idaho is a proven geothermal resource, and has a 13 net MW capacity geothermal power plant in operation. San Emidio, Nevada is a proven geothermal resource, and has a 3.6 net MW capacity 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.

Significant Patents, Licenses, Permits, Etc.

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

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.

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

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

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.

Seasonality of Business

The Company and its major subsidiary (RREI) have been producing energy revenues under the terms of two PPAs. These contracts specify favorable rate periods and levels of production. The San Emidio Nevada plant’s contractual terms provide for premium rates in the months from September to April. The RREI contract pays favorable rates in the months of July/August and November/December. Energy production can be influenced by the seasonal temperatures. Generally, 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. Drilling and other construction activities could be negatively impacted by inclement weather that can occur, primarily, during the winter months.

Industry Practices/Needs for Working Capital

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 Energy I, LLC that became operational January 3, 2008. The Company is expecting to be significantly involved in development activities for the next 5 to 10 years.

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Dependence on Few a Customers

Ultimately, the market for electrical power is vast; however, the numbers 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.

Competitive Conditions

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. According 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 an important sub-market in the broader electric 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:

number of market participants buying and selling electricity;
availability and cost of transmission;
amount of electricity normally available in the market;
fluctuations in electricity supply due to planned and unplanned outages of competitors’ generators;
fluctuations in electricity demand due to weather and other factors;
cost of fuel used by generators, which could be impacted by efficiency of generation technology and fluctuations in fuel supply;
environmental regulations that impact us and our competitors;
availability of production tax credits and other benefits allowed by tax law;
relative ease or difficulty of developing and constructing new facilities; and

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credit worthiness and risk associated with buyers.

Environmental Compliance

The Raft River project is 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. IDWR has concurred that there is no impact from the Company’s operations on adjacent aquifers.

Since operations have been initiated, key environmental reports include:

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.

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.

Financial Information about Geographic Areas

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 MW 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. Substantial drilling and testing activities have occurred during the last fiscal year. In April of 2010, the Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America. Significant project strategies have just begun.

The Company’s revenues for the three most recent fiscal years ended March 31, 2010, 2009 and 2008 were $2,579,152, $2,336,202, and $190,721; respectively. All of these revenues were attributable to customers in the Northwest of the United States.

Available Information

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.

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Governmental Approvals and Regulation

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. HTM is defined as an independent power producer under the rules and regulations of the Federal Energy Regulatory Commission (“FERC”). As an independent power producer, HTM’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 HTM. 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, HTM submitted proposals to Idaho Power in response to their “Request for Proposal for Geothermal Power.” HTM 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 MWs per month. Through subsequent contract negotiations, HTM 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 MWs. The annual average output capacity is on the order of 13 MWs.

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, HTM has found that utilities across the Western United States are eager to discuss PPAs with HTM.

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 MW 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 the Bonneville Power Agency (“BPA”) 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 MW from two plants. Before the burgeoning interest in geothermal power, the Company had originally planned 30 MWs from three plants. The construction of only two larger plants will result in substantial capital and operating cost savings through improved economy of scale.

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In addition to the EWEB agreement, the strong regional interest in geothermal power has resulted in numerous utilities inquiring with HTM 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. We anticipate that future plants will be developed under PPAs that do not restrict the output of the project.

The most recent such contract was a 25 MW (maximum) contract signed with Idaho Power on December 11, 2009 for the full output of the Neal Hot Springs development in Oregon. The contract has received approval from the Idaho PUC. The levelized cost of power for the project is $117.55/MWh for 25 years after the plant startup.

HTM 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 has provided 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 HTM 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.

Environmental Credits

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, are also available for sale to power companies (to allow them to meet their “green” power requirements) or to businesses which produce carbon based pollution. In all of U.S. Geothermal Inc.’s project, these credits have been sold separately, or bundled with the electricity to provide an additional source of revenue.

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

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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, 2014 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 2013, 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 60 days of operation of the plant.

Renewable Energy Credits. Renewable Energy Certificates, or RECs, are tradable environmental commodities that represent proof that 1 MW-hour of electricity was generated from an eligible renewable energy resource. A renewable energy provider is credited with one REC for every 1,000 kilowatt-hours or 1 MW-hour of electricity it produces. The electrical energy is fed into the electrical grid and the accompanying REC can either be delivered to the purchaser of the power (“bundled”) or can 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 87,600 RECs (10 MWs average over the year). 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. Under the revised RRU1 agreement with Idaho Power, keeps all RECs above 87,600 RECs per year. In addition, we retain 49% of the renewable energy credits associated with power production from Raft River Unit I after 2017 and Idaho Power retains the other 51%. We expect to receive a majority of the annual revenue from the ten-year renewable energy credits sales arrangement with Holy Cross Energy.

The power purchase agreements for the existing San Emidio power plant, the planned Raft River Unit II facility, and the planned Neal Hot Springs facility are all for bundled power and RECs. Therefore, under these contracts all RECs are delivered with the net power delivered to the utility.

Regulatory Update

In January 2009, Congress extended the federal PTC for renewable energy power plants for all projects initiating commercial production prior to December 31, 2013. The PTC enhances the annual revenues of the projects by about 25 percent per year for the first 10 years. Additionally, Congress provided that for power plants that begin construction before the end of 2010, the Company may elect to use the 30% ITC in lieu of the PTC. Application for the cash ITC payment may be made 60 days after the start of commercial generation and would be paid directly from the Department of Treasury.

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ITEM 1A. Risk Factors

General Business Risks

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, Guatemala 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.

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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. It’s possible 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. Additional capital is needed to repair the existing wells to deliver the full capacity of the resource available to the project. There is a risk that the partner may not agree to the capital needs which could reduce the plant’s performance and profitability.

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.

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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:

a portion of our cash flow from operations would be used for the payment of principal and interest on such indebtedness and would not be available for financing capital expenditures or other purposes;
a significant level of indebtedness and the covenants governing such indebtedness could limit our flexibility in planning for, or reacting to, changes in our business because certain activities or financing options may be limited or prohibited under the terms of agreements relating to such indebtedness;
a significant level of indebtedness may make us more vulnerable to defaults by the purchasers of electricity or in the event of a downturn in our business because of fixed debt service obligations; and
the terms of agreements may require us to make interest and principal payments and to remain in compliance with stated financial covenants and ratios. If the requirements of such agreements were not satisfied, the lenders could be entitled to accelerate the payment of all outstanding indebtedness and foreclose on the collateral securing payment of that indebtedness, which would likely include our interest in the project.

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:

failure of the acquired companies to achieve the results we expect;
inability to retain key personnel of the acquired companies;
risks associated with unanticipated events or liabilities; and

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the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.

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 Vice President of Finance, Jonathan Zurkoff, 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, 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.

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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 PTC, which was extended to December 31, 2014. Recent legislation enacted as part of the stimulus funding has also provided an election to take 30% ITC in lieu of the PTC and convertible into a cash grant for certain qualified investments being initiated before the end of 2010 and being placed in service before the end of 2013. 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 MWs 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:

from a well or drilling equipment at a drill site;

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leakage of fluids or airborne pollutants from gathering systems, pipelines, power plant and storage tanks;
damage to geothermal wells resulting from accidents during normal operations; and
blowouts, cratering and explosions.

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 steam 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 binary cycle power plant projects 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.

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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 Raft River Unit I power purchase agreement may be reduced if we are unable to forecast our production adequately. Under the terms of our power purchase agreement for Raft River Unit I, and starting with the third year of operation (2010), 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 MWs of delivery on a 10-MW plant and the damages would then result if the actual delivery was only 8.1 MWs or less. All 8.1 MWs would be subject to a reduced price that is not possible to predict at this time. The total average revenue per MW 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.

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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.

Risks Relating To the Market for Our Securities

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.

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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, 2010, 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.

Item 1B. Unresolved Staff Comments

None.

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Item 2. Description of Property

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 in May 2008.

REGIONAL LOCATION MAP

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Raft River, Idaho

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 four separate properties that total 1,723.93 acres: the Vulcan, Elena Corporation, Dewsnup and the Wilcox Ranch Properties. 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 from a local rancher. The Wilcox Ranch includes 940 acres of agricultural and range lands adjacent to Raft River that provides cooling water.

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.

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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.

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Raft River Energy Unit I

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.

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Lease/Royalty Terms

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:

(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 to RREI.

(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.

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

(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.

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 U.S. Geothermal Inc. 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.

Payments for years 2002 through 2006 have been recorded as lease expense. After commercial production was attained, these lease payments have been deducted from future production royalties. For later years, during commercial production, there is a minimum annual production royalty of $18,000. The minimum amount that will be payable over the course of the leases is $45,000. Maximum amounts payable will depend on production from the property.

The Newbold Lease. The company leases this property pursuant to a lease agreement with Jay Newbold dated March 1, 2004. The Newbold lease has a primary term of 10 years (through February 28, 2014) and is extended indefinitely so long as production from the geothermal field is maintained. Minimum lease payments are as follows:

Years 1-5: $10.00 per acre or $200 per year
Years 6-10: $15.00 per acre or $300 per year

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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:

Years 1-5: $2.50 per acre or $7,386.88 per year
Years 6-10: $3.00 per acre or $8,864.25 per year

The minimum amount that will be payable over the course of the lease is $81,256. 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:

Years 1-5: $2.50 per acre or $111.25 per year
Years 6-10: $3.00 per acre or $133.50 per year

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:

Year 1: $8,000
Year 2: $5,000
Year 3-30: $5,000 plus an annual increase of 5% per year.

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

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

Year 1-5: $1,400
Year 6-10: $2,100

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:

Year 1-5: $1,600
Year 6-10: $3,200

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.

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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:

Year 1: $1,600
Year 2-5: $800
Year 6-10: $1,200

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:

Year 1: $2,100
Year 2-5: $1,600
Year 6-10: $2,400

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 that began in 2009. The leases can be renewed for extended periods as long as the power plant continues to produce power.

BLM Lease. The lease entered into in August of 2007 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, Oregon

Neal Hot Springs is a geothermal resource located in Eastern Oregon. The Company acquired the Neal Hot Springs geothermal energy and surface rights in September 2006. It is currently under development.

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 engineering firm, calculated a well productivity index of 450 gpm/psi, which is considered to be very high in the geothermal industry. The Company proceeded with permitting up to a 22 MW power plant. USG has acquired all state and federal permits necessary for project construction. A Conditional Use Permit has been issued by Malheur County. The only remaining permits required prior to construction are the septic approval for the office facility and the local building permit. The transmission line right-of-ways have been acquired, and a power purchase agreement (with Idaho Power) has been approved by the IPUC.

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The Company has been issued permits for drilling up to 15 temperature gradient drill holes and 9 geothermal wells. Successful geothermal resource delineation has continued with the development of a second geothermal production well (NHS-5) located north of NHS-1 and temperature gradient well 21 which intersected additional geothermal resource south of NHS-1.

Lease/Royalty Terms

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:

	Year 2008-2011	$4,000
	Year 2012-2016	$8,000

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.

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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:

	Year 1	$15,000
	Year 2	$25,000
	Year 3	$30,000

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.

San Emidio, Nevada

Effective May 1, 2008, the Company acquired a 3.6 MW operating geothermal power plant and approximately 30,734.21 acres (48.0 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 Gerlach/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 Gerlach assets are comprised of approximately 3,415 acres (5.3 square miles) of BLM geothermal leases located about 1 mile north of Gerlach, Nevada. The Granite Creek assets are comprised of approximately 5,414 acres (8.5 square miles) of BLM geothermal leases located about 7 miles north of Gerlach, Nevada. The Gerlach and Granite Creek assets are along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser.

The 3.6 -MW 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 of Black Mountain Technology and Geologist, Dennis Trexler, estimated a total resource potential of 44 MWs 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 MW Ormat Energy Converters, three injection wells and two 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 2.5 MWs. 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.

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Lease/Royalty Terms

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 10 years, under two extension periods, at 5 years each, 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 terms of the BLM contracts are detailed as follows:

	Current Contract
Contract No.	Expiration Date	Acres	Annual Rate

*San Emidio*
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

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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

*Gerlach*
N55718	6/30/2012	1,252	10,016
N75228	10/31/2011	2,164	4,328

*Granite Creek*
N65655	10/31/2012	1,955	1,955
N66403	10/31/2012	1,202	1,202
N66404	10/31/2012	2,259	2,259

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.

Gerlach, Nevada

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.

Lease/Royalty Terms

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.

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Granite Creek, Nevada

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.

Lease/Royalty Terms

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.

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Republic of Guatemala

Boise Administration Office, Idaho

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.

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Item 3. Legal Proceedings

As of May 31, 2010, 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 4. [Removed and Reserved]

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PART II

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

NYSE Amex/Over-The-Counter Bulletin Board

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, 2008.

Bid Prices on the Over-The-Counter Bulletin and NYSE Amex

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

Fiscal Year Ended March 31, 2010
First Quarter	1.93	0.74
Second Quarter	1.75	1.14
Third Quarter	1.70	1.44
Fourth Quarter	1.61	0.91

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

TSX and TSX Venture Exchange

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:

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Sales Prices on the TSX and TSX Venture Exchanges (CDN$)

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

Fiscal Year Ended March 31, 2010
First Quarter	2.16	0.93
Second Quarter	1.87	1.34
Third Quarter	1.81	1.52
Fourth Quarter	1.69	0.93

As of May 31, 2010, we had approximately 20,100 stockholders of record.

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.

Recent Sales of Unregistered Securities

On March 16, 2010, we closed a private placement of securities issued pursuant to a securities purchase agreement entered into with several institutional investors, pursuant to which the Company issued 8,209,519 shares of common stock at a price of $1.05 per share for gross proceeds of approximately $8.6 million. Pursuant to the terms of the private placement, each investor was also issued a common share purchase warrant exercisable for 50% of the number of shares of common stock purchased by the investor. Each warrant is exercisable at $1.25 per share for a period of five years beginning six months after the closing of the Private Placement. However, under certain specified circumstances, the warrants may be exercised by means of a “cashless exercise.” The warrants have customary provisions for the adjustment to exercise price based on certain stock dividends, stock splits and certain types of fundamental transactions such as mergers and asset sales. After deducting for fees and expenses, the net proceeds were approximately $8.0 million. The securities were issued in reliance on exemptions from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended, and Rule 506 of Regulation D thereunder. Each of the investors has represented to the Company that it is an “accredited investor” as defined in Rule 501(a) of Regulation D promulgated under the Securities Act. The Company paid commissions to agents in connection with the private placement in the amount of approximately $516,000 and issued warrants to purchase up to 246,285 shares of common stock. The net proceeds of he offering will be used by the Company to further develop its Neal Hot Springs geothermal project and for general working capital purposes.

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Item 6. Selected Financial Data

	For the Fiscal Years Ended March 31,
	2010	2009	2008	2007	2006
Operating Revenues	$ 2,579,152	$ 2,336,202	$190,721	$90,206	$ 0
Operating Expenses	8,562,345	7,660,868	4,568,871	3,138,169	1,663,069
Loss from Continuing Operations	(5,983,193)	(5,324,666)	(4,378,150)	(1,942,884)	(1,490,593)
Loss per share from Continuing Operations	(0.09)	(0.08)	(0.06)	(0.04)	(0.08)
Cash dividends declared and paid per common share	0	0	0	0	0

	As of March 31,
	2010	2009	2008	2007	2006
Total Assets	$ 65,727,861	$ 52,451,343	$ 40,366,933	$ 22,673,340	$ 21,895,933
Total Long-term Obligations (1)	2,080,859	1,972,200	1,975,672	2,533,858	1,707,548

(1)

Long-term obligations represent the stock compensation payable, a promissory note, and a capital lease obligation. The stock compensation liability is the fair value of stock options to be exercised by officers, directors, employees and consultants of the Company. These obligations were recorded as a liability since the option exercise price was stated in Canadian dollars, subjecting the Company and the employee to foreign currency exchange risk in addition to the normal market price fluctuation risk.

	Loss per share				Net Loss from
	from	Operating	Gross Profit	Loss from	Continued
	Continuing	Revenues		Operations	Operations
	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)	190,721	190,721	(1,206,051)	(1,054,765)
Fiscal Year Ended March 31, 2009
1^stQuarter	(0.02)	480,915	480,915	(1,774,518)	(1,717,061)
2^ndQuarter	(0.03)	743,706	743,706	(1,406,431)	(1,356,084)
3^rdQuarter	(0.01)	575,886	575,886	(899,643)	(874,186)
4^thQuarter	(0.02)	535,695	535,695	(1,244,074)	(1,240,423)
Fiscal Year Ended March 31, 2010
1^stQuarter	(0.04)	335,736	335,736	(2,441,672)	(2,411,566)
2^ndQuarter	(0.02)	734,622	734,622	(1,156,554)	(1,122,525)
3^rdQuarter	(0.02)	731,315	731,315	(1,449,421)	(1,394,009)
4^thQuarter	(0.01)	777,479	777,479	(935,546)	(910,750)

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

The following is a list of projects that are in operation, under development or under exploration. Projects in operation have producing geothermal power plants. Projects under development have at least a geothermal resource discovery or may have wells in place, but require the drilling of new or additional production and injection wells in order to supply enough geothermal fluid sufficient to operate a commercial power plant. Projects under exploration do not have a geothermal resource discovery occurrence yet, but have significant thermal and other physical evidence that warrants the expenditure of capital in search of the discovery of a geothermal resource. Due to inflation and marketplace increases in the costs of labor and construction materials, previous estimates of property development costs may be low.

For the fiscal year ended March 31, 2010, the Company was focused on:

1)	optimizing the operation of the well field at the Raft River, Idaho geothermal project (“Raft River Unit I”);
2)	continuing due diligence for the Department of Energy Section 1703 loan guarantee program for the Neal Hot Springs Project;
3)	planning and permitting drilling and field development activities at Neal Hot Springs in Oregon and continuing the temperature gradient drilling program;
4)	negotiating a PPA for the San Emidio Phase I repower and Phase II expansion project;
5)	optimizing the operation of the San Emidio power plant in Nevada, and planning for the Phase I repower of the existing well field;
6)	planning and permitting for drilling at the Gerlach Joint Venture, and
7)	the evaluation of potential new geothermal project acquisitions.

Raft River, Idaho

Raft River Energy Unit I is located in Idaho and has a 13 MW capacity geothermal power plant in operation.

In early January 2009, production well RRG-7 underwent a temperature decline that has reduced the inlet fluid temperature to the power plant over the year by approximately 10 degrees Fahrenheit. At the same time of the temperature change, fluid flow increased. Power generation has been reduced by an estimated 1MW due to the lower temperature fluid. It was determined that the cement in a lap joint had failed and a mechanical packer was installed to reduce the cold water inflow, but was unsuccessful. A remediation program is planned that will “squeeze” cement into the lap joint and plug off the cold water flow to return the well temperature and increase power plant generation.

The joint venture partners are evaluating a recovery plan that includes repairing the lap joint RRG-7, drilling a new production leg on one or two existing production wells and drilling a new injection well. We anticipate completing the repair of well RRG-7, with a repair cost estimated at $813,300, in the first half of the fiscal year before a decision is made on the remainder of the recovery plan.

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Raft River Unit II is anticipated to cost approximately $134 million and Raft River Unit III is anticipated to cost approximately $166 million, up to 75% of which we believe may be funded by loans, with the remainder funded through equity financing. Provided funding is available, Raft River Unit II is anticipated to begin construction in the fourth calendar quarter of 2010 with commercial operations commencing in the fourth calendar quarter of 2013 or the first calendar quarter of 2014. Raft River Unit III is anticipated to begin construction in the first calendar quarter of 2014 with commercial operations commencing in the second calendar quarter of 2015.

Neal Hot Springs, Oregon

Neal Hot Springs is a promising geothermal resource located in Eastern Oregon.

Conditional approval of the DOE loan was received in May 2010, and it is expected to provide up to 75% of the $136 million estimated capital cost of Stage I up to a maximum loan amount of $102.2 million. The capital cost has increased to $136 million from prior estimates of $106 million due to costs of labor, updated vendor pricing and construction materials, loan costs and contingencies. Detailed design of a binary cycle power plant utilizing significantly improved technology is currently in progress with construction expected to begin in mid to late 2010. The new plant, designed to deliver approximately 22 MWs of power net to the grid is scheduled to begin commercial operations in early 2012. The DOE loan is anticipated to be a combined construction and term loan and provide the project with a low cost annual interest rate. We expect that we will be required to drill up to 8 wells as a condition precedent to drawing on the DOE loan, if it is approved.

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The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting price of $96 per MW-hour and escalates at a variable percentage annually. Idaho Power Company submitted the PPA to the Idaho Public Utilities Commission on December 28, 2009. IPUC authorized a Modified Procedure for review of the PPA on March 17, 2010 which calls for a 45 day public comment period and 10 day reply period. Subsequent to the end of the year, approval of the PPA by the IPUC was received on May 20, 2010.

The total development cost of Neal Hot Springs Stage II is estimated to be $154 million. Construction is anticipated to begin in the third quarter of 2011 with commercial operations commencing in the third quarter of 2013.

San Emidio, Nevada

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Subsequent to the end of the year, the System Impact Study for the 45 MW option was received in April. The third phase study for the 45 MW option, the Interconnection Facilities Study, will be contracted during the second calendar quarter and is expected to be completed before year end.

On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio will apply innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture factures that represent high-productivity geothermal drilling targets. Initial geologic mapping under the program has been initiated and the seismic team has been contracted.

The San Emidio 35 MW development in planned for execution in two phases. Phase I will be a repower and Phase II will be an expansion. Phase I will utilize the existing production and injection wells with a new, more efficient power plant. As shown in the table above, the repower is anticipated to cost approximately $30 million and the expansion is anticipated to cost $127 million, 75% of which we believe may be funded by a Department of Energy loan, with the remainder funded through equity financing. The Phase I repower is anticipated to begin construction in the third calendar quarter of 2010 with commercial operations commencing in the fourth calendar quarter of 2011 or first calendar quarter of 2012. The Phase II expansion is anticipated to begin construction in the second calendar quarter of 2010 with commercial operations commencing in the third calendar quarter of 2012. The Company expects to be granted about $40 million in ITC cash grant in connection with the $157 million 35 MW development. The 35 MW development will require an amendment to the existing Sierra Pacific Power Purchase Agreement.

Factors Affecting Our Results of Operations

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.

Raft River Energy I LLC

In early January 2009, production well RRG-7 underwent a temperature decline that has reduced the inlet fluid temperature to the power plant over the year by approximately 10 degrees Fahrenheit. At the same time of the temperature change, fluid flow increased. Power generation has been reduced by an estimated 1MW due to the lower temperature fluid. It was determined that the cement in a lap joint had failed so a mechanical packer was installed to reduce the cold water inflow, but was unsuccessful. A remediation program is planned that will “squeeze” cement into the lap joint and plug off the cold water flow to return the well temperature and increase power plant generation.

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Raft River Unit I operated through the year at 95.2 percent availability which includes a scheduled maintenance outage of 12 days in April 2009 that was extended to replace a turbine damaged during construction. Raft River generated in a range of 7.7 to 10.1 net MWs during the twelve month period averaging 8.8 MWs. The reduction in output for the period compared to the planned generation was primarily due to the loss of temperature from production well RRG-7.

Raft River Operating Agreement

We hold a 50% interest in Raft River Energy I LLC, which owns Raft River Unit I (“Unit I”). Construction of Unit I required substantial capital, and partnering with a co-venturer allowed us to share the risks of ownership. The joint venture has also allowed the project to take advantage of production tax credits which would not otherwise have been available to us. When Unit I operates at full capacity of 13 MWs, we estimate we will receive cash payments totaling approximately $1.6 million for the first four years of its operations. While Unit I generates at less than full capacity, our annual cash payments from the Raft River I project will be lower. See Note 5 “Investment in Subsidiary” in the financial statements for detail of cash payments from RREI.

The Company’s interests in the RREI as defined in the partnership agreements are summarized as follows:

		Years 1 - 4	Years 5 - 10	Years 11 - 20	Years 20 - 25
Cash Flow	RECs	70% ⁽¹⁾
	GAAP Income	1% ⁽²⁾		49%	80%
	Lease Payments, O&M Services & Royalties	100%
	Distributions	Guaranteed min. payment	1% ⁽³⁾	49%	80%
Tax Benefits		1% ⁽²⁾		49%	80%

(1)	U.S. Geothermal allocates 70% of income and receives 70% of available cash from RECs sold to third- parties. After year 10, REC income is shared with Idaho Power Co. For additional details, see U.S. Geothermal’s Form 10-Q filed on August 10, 2009 (Exhibit 10.36).
(2)	Flip to next tier occurs after the later of 10 years or Raft River I Holdings’ target IRR is achieved.
(3)	Flip to next tier occurs after Raft River I Holdings’ target IRR is achieved.

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San Emidio, Nevada

Power Purchase Agreements

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-MWs 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 MWs 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 MW 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. 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.

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The power purchase agreement (“PPA”) for the project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting price of $96 per MW-hour and escalates at a variable percentage annually. Idaho Power Company submitted the PPA to the Idaho Public Utilities Commission (“IPUC”) on December 28, 2009. Subsequent to the end of the year, the PPA was approved by the IPUC on May 20, 2010.

Results of Operations

San Emidio, Nevada Plant Operations

Summarized statements of operations for the San Emidio power plant are as follows:

	Years Ended March 31,
	2010				2009*				2008
	$		%		$		%		$	%
Operating revenues:									-	-
Energy sales	1,743,984		97.1		1,416,852		97.8		-	-
Energy credit sales	51,695		2.9		32,437		2.2		-	-
	1,795,679		100.0		1,449,289		100.00		-	-
Operating expenses:									-	-
General and administrative	349,422		19.5		282,176		19.5
Salaries and related costs	819,182		45.6		579,009		40.0		-	-
Operations:									-	-
Repairs and maintenance	596,516		33.2		200,106		13.8
Other	210,838		11.7		308,867		21.3
Rent and lease	78,683		4.4		45,442		3.1		-	-
Purchased utilities	65,543		3.7		126,179		8.7
Depreciation and amortization	822,365		45.7		723,498		49.9		-	-
	2,942,549		163.8		2,265,277		156.3		-	-
Net Loss	(1,146,870	)	(63.8	)	(815,988	)	(56.3	)	-	-

* - represents eleven months of operations.
% - represents the percentage of total operating revenues.

Select financial information by quarter is as follows:

			Ave. Rate		Depreciation
	Kilowatt	Energy	per		&
	Hours x	Sales	Kilowatt-	Net Loss	Amortization
Quarter Ended:	1,000	($)	Hour ($)	($)	($)
September 30, 2008	5,650	529,383	0.0937	(185,838)	195,046
December 31, 2008	4,097	317,256	0.0774	(146,859)	196,941
March 31, 2009	3,808	296,577	0.0779	(267,114)	201,711
June 30, 2009	2,851	243,752	0.0855	(589,082)	200,972
September 30, 2009	5,224	540,841	0.1035	(46,118)	207,066
December 31, 2009	4,689	463,286	0.0988	(348,073)	207,136
March 31, 2010	5,018	496,104	0.0989	(163,597)	207,191

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Effective May 1, 2008, the Company purchased geothermal rights and a geothermal power plant located in the San Emidio Desert of North Western Nevada. The primary objective of the acquisition was to secure water rights for future development. While the plant was expected to produce positive cash flows, the plant was not expected to generate significant operating profits. The plant has produced positive cash flows for four out of the last seven quarters of full operations. Fluctuations in energy revenues are a product of plant efficiency and the terms of the PPA which is based on an energy plus capacity payment. Rates are adjusted annually (September 1 to September 1) with the energy price component based upon the producer price index for coal and the capacity price component based upon the Handy-Whitman Total Steam Production Plant Index. Premium rates are paid during the months June through September. For the 2008-09 rate period, the kilowatt rates for the premium months ranged between $0.0757 and $0.1182, and ranged between $0.0616 and $0.1037 for non-premium months. For the 2009-10 rate period, the kilowatt rates for the premium months range between $0.0963 and $0.1418, and range between $0.0789 and $0.1274 for non-premium months.

For the year ended March 31, 2010, energy sales totaled $1,743,984, an increase of $327,132 (23%) over the prior year. Energy credit sales increased $19,258 (59%) to $51,695 for the same period. Major increases in expenses for the year ended March 31, 2010 when compared to the prior year were Salaries and related costs at $240,173 (41%) and Repairs and maintenance at $396,410 (198%).

Energy sales revenues were higher in the quarter ended September 30, 2008 due to regular plant production and premium contracted rates. 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. As a product of the repair efforts and capital improvements, the plant has been more productive. For the quarters ended March 31, 2010 and December 31, 2009 the plant produced 31.8% and 14.5% more power; respectively, than in the same quarters in the prior fiscal year.

A loss of $589,082 was incurred for the quarter ended June 30, 2009. Repair costs of over $112,000 were incurred to rebuild and reinstall a pump. Costs that amounted to over $59,000 were incurred to retube an OEC condenser and to install a new gear box. Both repairs resulted in loss of productivity due to over two weeks of downtime.

For the quarter ended December 31, 2009, the San Emidio plant reported a loss of $348,073. Energy production and related revenues increased ($146,030, 46.0%) in the quarter ended December 31, 2009 from the same period in 2008. This is primarily due to efficiencies gained from repairs made to the plant since it was purchased in May 2008. In the quarter ended June 30, 2009, repair costs of over $112,000 were incurred to rebuild and reinstall a pump.

During the last fiscal year ended March 31, 2010, the Company spent over $596,000 making various repairs. Notable repairs were made to electrical breakers and system controls, the pentane storage and transfer system, gear box and drive shaft alignments on all OECs and cooling tower fans, fix leaking condenser tubes, replace turbine inlet gaskets, modify the OEC oil cooler water supply pipelines, replacement of leaking brine valves on the OECs, AHD rebuilt production pumps in 75B-16 and 76-16, and replacement of check valve on production pump 76-16.

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Land, Water and Mineral Rights Lease Revenues

	Years Ended March 31,
	2010		2009		2008
	$	%	$	%	$	%
Geothermal and surface water leases	90,000	3.5	90,000	3.9	105,000	55.1
Rental income	112,560	4.4	7,098	0.3	-	0.0
Other	6,984	0.0	-	0.0	16,742	8.8
Net Loss	209,544	8.1	97,098	4.2	121,742	63.9

% - represents percentage of total operating revenues. The Company receives revenues from geothermal and water rights leases and rental income from its major subsidiary RREI. For the year ended March 31, 2010, the Company’s revenues from geothermal and water rights and rental income totaled $209,544, as compared to $97,098 in 2009 and $121,742 in 2008. The primary cause of the increase in 2010 was the receipt of increased rental income for use of buildings and facilities at Raft River owned by US Geothermal. In the fiscal year ended March 31, 2010, the Company started collecting rental revenues from RREI for the use of 4 buildings located in Raft River, Idaho. The Company began earning $7,504 per month in January 2009. Geothermal and surface water rights lease revenues have been consistent for the three fiscal years. In 2007, an adjustment was made to record two months of revenues earned in the prior period.

Management Fee Income

For the year ended March 31, 2010 and 2009, management fee income increased by $187,500 to $250,000 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 and 2010, the Company earned fees for an entire year.

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Gain on Investment in Subsidiary (Raft River Energy I, LLC)

The Company uses the hypothetical liquidation at book value method (“HLBV”) for allocating of RREI’s profits and losses. This method utilizes the specific terms outlined in the RREI’s operating agreement or other authoritative documents. These terms include cash disbursement terms, associated financial instruments, debt arrangements, and rights to specific revenue streams. The primary element of the profit and loss allocation from inception has been the amount of renewable energy credits earned. Summarized unaudited (based on different fiscal year-end than RREI Financial Statements included in Exhibit 13.2) statements of operations for RREI are as follows:

	Years Ended March 31,
	2010				2009				2008*
	$		%		$		%		$		%
Operating revenues:
Energy sales	4,365,522		89.7		4,637,226		88.1		1,174,043		86.6
Energy credit sales	499,405		10.3		625,474		11.9		181,415		13.4
	4,864,927		100.0		5,262,700		100.0		1,355,458		100.0
Operating expenses:
Operations	4,801,968		98.7		3,501,708		66.5		1,986,571		146.6
Depreciation and amortization	2,049,822		42.1		1,951,536		37.1		454,848		33.5
	6,851,790		140.8		5,453,244		103.6		2,441,419		180.1
Operating Loss	(1,986,863	)	(40.8	)	(190,544	)	(3.6	)	(1,085,961	)	(80.1	)
Other income	5,807		0.1		76,738		1.5		67,666		5.0
Net Loss	(1,981,056	)	(40.7	)	(113,806	)	(2.1	)	(1,018,295	)	(75.1	)
U.S. Geothermal Inc.’s Allocation of Net Loss	323,929				539,815				6,479

* - began commercial operations January 3, 2008. Includes nine months of test and development; and three months of normal operations.
% - represents the percentage of total operating revenues.

For the year ended March 31, 2010, RREI’s operating revenues decreased from $5,262,700 to $4,864,927 (7.6% decrease). This decrease was primarily due to loss of the geothermal water resource related to a collar failure that occurred at one of the production wells. The Company’s allocation of RREI’s profits and losses is based upon receiving 70% of revenue from renewable energy credits and 1% of all other profits and losses. The Company’s allocation of profits and losses decreased from $539,815 to $323,929 (40.0% decrease) from the fiscal year 2009 to 2010 primarily due to a decrease in energy production which reduced the energy credit sales earned during the fiscal year ended 2010.

RREI’s net operating loss was $1,505,100 for the quarter ended June 30, 2009. This was primarily due to both planned and unplanned maintenance and repairs that led to lower revenues and increased costs. The entire plant was shut down for planned maintenance from April 1, 2009 to April 13, 2009 to replace a turbine damaged during startup. The shut down reduced energy production for that time period. Overall, energy revenue was down approximately $279,000 for the quarter ended June 30, 2009 from the same quarter in 2008. In addition to the shut down, production was down due to loss in temperature as a result of a lap joint leaking at one production well and two pump failures. The pump repairs were substantially complete at September 30, 2009. The repairs on the lap joint were not completely successful and that well continues to suffer lower temperatures. The lower temperatures have reduced the productivity of the plant. Prior to the leak, the plant had averaged 7,588,151 kilowatt hours per month. After the leak, the plant has averaged 6,494,834 kilowatt hours per month (14.4% decrease). The severity of the leak continues to increase with time. A plan to repair this condition has been formulated by the Company and will be implemented upon acceptance of RREI’s other partner.

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In December 2008, the reverse osmosis system was placed into operations. Prior to its implementation, the average chemical treatment costs per month were approximately $73,000. After the system was operational, the average monthly treatment costs have been approximately $19,000 (monthly savings of $53,000, 72.6%) .

Corporate Administration

Corporate Administrative costs of $803,417 were incurred for the fiscal year ended March 2010 which were largely consistent with the costs incurred in 2009. Corporate Administrative costs of $753,045 were incurred for the fiscal year ended March 31, 2009, which was an increase of $173,010 (28.9%) from the prior fiscal year. The primary components of the increases in 2009 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 2008 fiscal year only included three months of the higher rental costs for the new building.

Professional and Management Fees

		Percentage	Percentage of
		of Increase	Total
Fiscal Year Ended	Amount	from Prior	Operating
March 31,	($)	Year (%)	Expenses (%)
2008	845,908	-	18.5
2009	997,452	17.9	13.2
2010	1,669,227	67.4	19.5

For the year ended March 31, 2010, the Company incurred professional and management fees of $1,669,227, which is an increase of $671,775 from 2009. Legal fees that exceeded $316,000 were incurred related to equity offerings, contract reviews and responses to SEC comment letters. Legal fees over $233,000 (over $101,000 in 2009) were paid related the equity offerings as well as meeting other filing requirements. Consulting fees of approximately $147,000 were paid for SOX compliance, review of quarterly filings and tax preparation. Consulting fees from the auditing firm directly related to assistance with the SEC comment letters were approximately $31,000. Similar costs of services related to the equity offerings and the SEC comment letters were not incurred in the same period in 2009.

For the year ended March 31, 2009, professional and management costs increased $151,544 (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.

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Salary and Related Costs

For the year ended March 31, 2010, our salary and related costs decreased from $1,180,647 to $1,171,752. There was a slight increase in staff (2 management and development staff) added in the fiscal year ended March 31, 2010; however, salary expenses were slightly lower ($8,895, 0.75%) than fiscal year ended 2009. The primary reason was that approximately $376,000 in salary and related costs was capitalized related to management and development efforts for the Neal Hot Springs project. For the year ended March 31, 2009, our salary and related costs increased $563,324 (91.2%) as compared to 2008. During that time period, there were no significant 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, the salaries and related costs of approximately $455,000 were allocated to the subsidiary in the fiscal year ended March 31, 2008. 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 were carried at the corporate level.

Travel and Promotion

For the year ended March 31, 2010, travel and promotion costs decreased $203,066 (39.7%) from the same period in 2009. The Company discontinued certain trade show expenditures which amounted to $227,000 in 2009. Travel and promotion costs for the fiscal year ended March 31, 2009 were reasonably consistent with the same period in 2008.

Lease and Equipment Repairs

For the year ended March 31, 2010, lease and equipment costs decreased $77,538 (35.8%) from the prior year. The primary reason for the decrease in the 2010 fiscal year ended December 2010, was utility line reservation fees as noted above were not incurred. For the year ended March 31, 2009, the lease and equipment maintenance costs increased $146,986 (211.5%) as compared to 2008. During the 2009 fiscal 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.

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Liquidity and Capital Resources

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On August 17, 2009, the Company completed a private placement of 8,100,000 Subscription Receipts (“Receipt”) at $1.35 CDN per Receipt for aggregate gross proceeds of CDN $10,935,000. Each Receipt was exchanged on December 17, 2009 for one share of common stock of the Company and one half of one common stock purchase warrant (a "Warrant"). Each Warrant entitles the holder thereof to acquire one additional share of common stock of the Company for $1.75 for 24 months from closing. The placement agents have been paid an aggregate cash fee of CDN $656,100, representing 6% of the aggregate gross proceeds of the offering, and have been issued compensation options, exercisable for 24 months, entitling the placement agents to purchase up to 243,000 shares of common stock of the Company at $1.22. The proceeds provided funds to drill production size wells at Neal Hot Springs to increase production capacity to 22 MW and allow a 30-day flow test to verify the well reservoir capacity. Completion of drilling is a condition precedent to the funding from the DOE loan program, if our application is approved.

Potential Acquisitions

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.

Critical Accounting Policies

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.

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Cash and Cash Equivalents

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.

Property, Plant and Equipment

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.

Income Taxes

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.

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Stock-Based Compensation

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.

Contractual Obligations

As of March 31, 2010, the following table denotes contractual obligation by payments due for each period:

	Total	< 1 year	1-3 years	3-5 years	> 5 years
Operating Leases	$ 538,841	$ 154,124	$ 161,221	$ 121,237	$ 74,192
Capital Leases	38,944	11,836	27,108	0	0
Promissory Note	230,000	0	230,000	0	0
Stock Compensation Payable	1,823,751	0	1,823,751	0	0

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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.

Off Balance Sheet Arrangements

As of March 31, 2010, the Company does not have any off balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Risk on Investments

At March 31, 2010, the Company held investments of $13,025,588 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.

Foreign Currency Risk

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.

Commodity Price Risk

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.

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Item 8. Financial Statements and Supplementary Data

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 13.1) . 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

None.

Item 9A. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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, 2010. 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, 2010.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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:

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pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2010. 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, 2010, the Company’s internal control over financial reporting is effective based on those criteria.

BehlerMick, 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, 2010, which report appears as Exhibit 13.1.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

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, 2010, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10 — Directors, Executive Officers and Corporate Governance

The information required by this item is set forth below or incorporated by reference to information under the caption “Proposal 1 - Election of Directors” and to the information under the captions “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance-Board Qualifications and Selection Process” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on August 23, 2010. See also Part I - Item1 - Executive Officers of the Registrant.

Audit Committee and Audit Committee Financial Expert

Our Board has a separately-designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee are John H. Walker, Paul A. Larkin and Leland L. Mink. Our Board has determined that Paul A. Larkin, Chairman of the Audit Committee, is an audit committee financial expert as defined by Item 407(d)(5) of Regulation S-K under the Exchange Act and that each member of the Audit Committee is independent under the NYSE Amex independence standards applicable to audit committee members.

Code of Ethics and Governance Guidelines

Our Board of Directors has adopted the U.S. Geothermal, Inc. Code of Business Conduct and Ethics to provide a corporate governance framework for our directors and management to effectively pursue U.S. Geothermal Inc.’s objectives for the benefit of our shareholders. The Board annually reviews and updates these guidelines and the charters of the Board committees in response to evolving “best practices” and the results of annual Board and committee evaluations. Our Code of Business Conduct and Ethics can be found at www.usgeothermal.com. by clicking on About Us and then Code of Ethics. Shareholders may request a free printed copy of our Code of Business Conduct and Ethics from our investor relations department by contacting them at info@usgeothermal.com or by calling (208) 424-1027. We will post any amendments to the Code of Business Conduct and Ethics at that location. In the unlikely event that the Board of Directors approves any sort of waiver to the Code of Business Conduct and Ethics for our executive officers or directors, information concerning such waiver will also be posted at that location. No waivers were granted in the most recent fiscal year. In addition to posting information regarding amendments and waivers on our website, the same information will be included in a Current Report on Form 8-K within four business days following the date of the amendment or waiver, unless website posting of such amendments or waivers satisfies applicable NYSE Amex listing rules.

Item 11 — Executive Compensation

The information required by this item is incorporated by reference to information under the captions “Proposal 1 – Election of Directors” and “Executive Compensation” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on August 23, 2010.

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

The information required by this item is incorporated by reference to information under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Proposal 1 - Election of Directors” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on August 23, 2010.

Securities Authorized for Issuance under Equity Compensation Plans

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, 2010:

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	5,725,875	$ 1.49	6,071,291
Equity compensation plans not approved by security holders	Nil	Nil	Nil
Total	5,725,875	$ 1.49	6,071,291

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

The information required by this item is incorporated by reference to information under the captions “Corporate Governance” and “Certain Relationships and Related Transactions” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on August 23, 2010.

Item 14 — Principal Accounting Fees and Services

The information required by this item is incorporated by reference to information under the caption “Audit Committee Report and Payment of Fees to Auditors” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on August 23, 2010.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

The following documents are filed as a part of this report:

	1.	Consolidated Financial Statements.

		See Item 8 of Part II for a list of the Financial Statements filed as part of this report.

	2.	Financial Statement Schedules.

		See Exhibit 13.2 for the following Financial Statement Schedules filed as part of this report:

		Financial Statements for Raft River Energy I LLC
		Report of Independent Auditors
		Balance Sheets at December 31, 2009 and November 28, 2008
		Statements of Operations for the periods ended December 31, 2009, December 26, 2008, November 28, 2008 and November 30, 2007
		Statements of Cash Flows
		Statement of Members’ Equity
		Notes to the Financial Statement

	3.	Exhibits. See below.

EXHIBIT LIST

EXHIBIT		DESCRIPTION
NUMBER
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		First Amended and Restated Bylaws of U.S. Geothermal Inc. (Incorporated by reference to exhibit 3.4 to the registrant’s Form 8-K as filed on November 4, 2009)
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)
3.7		Certificate of Amendment to Certificate of Incorporation filed on August 26, 2008 (incorporated by reference to Exhibit 3.4 to the Company’s Form 8-K as filed on August 27, 2008)
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		Provisions Regarding Rights of Stockholders (Incorporated by reference to Exhibit 4.3 to the Company’s Form SB-2 registration statement as filed on July 8, 2004)
4.3		Form of Warrant used in private placement of April 2008 (Incorporated by reference to Exhibit 10.3 to the Company’s Form 8-K current report as filed on May 2, 2008)
4.4		Form of Broker Warrant (Incorporated by reference as exhibit 10.4 to the Company’s Form 8-K current report as filed on May 2, 2008)
4.5		Form of Subscription Agreement relating to private placement of April 2008 (Incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K current report as filed on May 2, 2008)
4.6		Form of Subscription Agreement for Subscription Receipts relating to private placement of August 2009 (Incorporated by reference to Exhibit 4.3 to the Company’s Form S-1 registration statement as filed on November 27, 2009)
4.7		Subscription Receipt Agreement dated August 17, 2009 among the Company, Dundee Securities Corporation, Clarus Securities Inc., Toll Cross Securities Inc. and Computershare Trust Company of Canada (Incorporated by reference to Exhibit 4.4 to the Company’s Form S-1 registration statement as filed on November 27, 2009)

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4.8		Form of Warrant used in private placement of August 2009 (Incorporated by reference to Exhibit 4.5 to the Company’s Form S-1 registration statement as filed on November 27, 2009)
4.9		Form Broker Warrant (Incorporated by reference to Exhibit 4.6 to the Company’s Form S-1 registration statement as filed on November 27, 2009)
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)
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)
10.6		Geothermal Lease and Agreement dated March 1, 2004, between Jay Newbold and U.S. 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 the children 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. Stewart and 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 US Geothermal 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 and US Geothermal Inc. (Incorporated by reference to exhibit 10.9 to the registrant’s Form 10-QSB quarterly report as filed on February 17, 2006)

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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)
10.15		Employment Agreement dated May 18, 2010 with Daniel J. Kunz (Incorporated by reference to exhibit 99.1 to the registrant’s Form 8-K as filed on May 24, 2010)
10.16		Employment Agreement dated April 1, 2010 with Kerry D. Hawkley (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on May 28, 2010)
10.17		Employment Agreement dated April 1, 2010 with Douglas J. Glaspey (Incorporated by reference to exhibit 99.1 to the registrant’s Form 8-K as filed on May 28, 2010)
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. Geothermal

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		Inc. (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)
10.35		Construction contract dated May 22, 2006 between Industrial Builders and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.31 to the registrant’s Form 10- KSB annual report as filed on June 29, 2006)
10.36		First Amendment to the Amended and Restated Operating Agreement of Raft River Energy I LLC, dated as of November 7, 2006, among Raft River Energy I LLC, Raft River I Holdings, LLC and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.36 to the registrant’s Form 10-QSB as filed on February 20, 2007).
10.38		Geothermal Lease and Agreement dated August 1, 2007, between Bureau of Land Management and U.S. Geothermal Inc. (Incorporated by reference as exhibit 10.34 to the registrant’s Form S-1 as filed on March 26, 2010)
10.39		Asset Purchase Agreement dated as of March 31, 2008, between U.S. Geothermal Inc., and Empire Geothermal Power LLC and Michael B. Stewart (Incorporated by reference as exhibit 99.1 to the registrant’s Form 8-K current report as filed on April 7, 2008)
10.42		Water Rights Purchase Agreement Michael B. Stewart and U.S. Geothermal Inc. dated March 31, 2008 (Incorporated by reference as exhibit 99.2 to the registrants Form 8-K current report as filed on April 7, 2008).
10.43		Power Purchase Agreement dated as of December 11, 2009, between Idaho Power Company and USG Oregon LLC (Incorporated by reference to Exhibit 10.43 to the Company’s Form 10-Q quarterly report as filed on February 9, 2010)
10.44		Power Purchase and Sale Agreement, dated as of February 2008, between Eugene Water & Electric Board and U.S. Geothermal Inc. (Incorporated by reference to Exhibit 10.42 to the registrant’s Form 10-Q/A quarterly report as filed on March 3, 2010)
10.45		Long Term Agreement For the Purchase and Sale of Electricity, dated December 31, 1986, between Sierra Pacific Power Company and Empire Farms, as amended (Incorporated by reference to Exhibit 10.43 to the registrant’s Form 10-Q/A quarterly report as filed on March 3, 2010)
13.1		Audited Consolidated Financial Statements of U.S. Geothermal Inc. as of March 31, 2010.

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13.2		Audited Financial Statements of significant subsidiary Raft River Energy I LLC as of December 31, 2009
21.1		Subsidiaries of the Registrant
23.1		Consent of BehlerMick PS
23.2		Consent of PricewaterhouseCoopers LLP
23.3		Consent of GeothermEx Inc.
23.4		Consent of Black Mountain Technology, Inc.
23.5		Consent of Geothermal Science, Inc.
31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES

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.

		U.S. Geothermal Inc.
		(Registrant)


June 9, 2010		/s/ Daniel J. Kunz
Date		Daniel J. Kunz
		Chief Executive Officer and President
		(Principal Executive Officer)

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:

Name	Title	Date
	Chief Executive Officer, President and Director
/s/ Daniel J. Kunz	(Principal Executive Officer)	June 9, 2010
Daniel J. Kunz
	Chief Financial Officer (Principal Financial and
/s/ Kerry Hawkley	Accounting Officer)	June 9, 2010
Kerry Hawkley

/s/ Douglas J. Glaspey	Chief Operating Officer and Director	June 9, 2010
Douglas J. Glaspey

/s/ John H. Walker	Chairman and Director	June 9, 2010
John H. Walker

/s/ Paul A. Larkin	Director	June 9, 2010
Paul A. Larkin

/s/ Leland L. Mink	Director	June 9, 2010
Leland R. Mink

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Attached files

US GEOTHERMAL INC Reports

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