10-K

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, 2011

or

[     ] 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 ; 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, 2011: $71,264,303

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, 2011
Common stock, par value $ 0.001 per share	84,838,456

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant’s 2011 Annual Meeting of Shareholders to be held on September 9, 2011 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, 2011

	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	12
Employees	19
Principal Products	19
Sources and Availability of Raw Materials	19
Significant Patents, Licenses, Permits, Etc.	20
Seasonality of Business	21
Industry Practices/Needs for Working Capital	22
Dependence on a Few Customers	22
Competitive Conditions	22
Environmental Compliance	23
Financial Information about Geographic Areas	24
Available Information	24
Governmental Approvals and Regulations	24
Environmental Credits	26
Item 1A Risk Factors
General Business Risks	28
Risks Relating to the Market for Our Securities	35
Item 1B Unresolved Staff Comments	36
Item 2 Description of Property	37
Raft River, Idaho	38
Raft River Energy Unit I	40
Neal Hot Springs, Oregon	43
San Emidio, Nevada	45
Gerlach, Nevada	48
Granite Creek, Nevada	49
Republic of Guatemala	49
Boise Administration Office, Idaho	51
Item 3 Legal Proceedings	51
Item 4 Removed and Reserved	51

U.S. Geothermal Inc. and Subsidiaries

Form 10-K
INDEX

For the Year Ended March 31, 2011

	Page
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities	52
Item 6 Selected Financial Data	53
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Factors Affecting Our Results of Operations	60
Results of Operations	64
Liquidity and Capital Resources	69
Potential Acquisitions	71
Critical Accounting Policies	71
Contractual Obligations	74
Off Balance Sheet Arrangements	74
Item 7A Quantitative and Qualitative Disclosures about Market Risk	75
Item 8 Financial Statements and Supplementary Data	75
Item 9 Changes in and Disagreements with Accountants on Accounting And Financial Disclosure	75
Item 9A Controls & Procedures	75
Item 9B Other Information	76
PART III
Item 10 Directors, Executive Officers and Corporate Governance	77
Item 11 Executive Compensation	77
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
Item 13 Certain Relationships and Related Transactions, and Director Independence	78
Item 14 Principal Accounting Fees and Services	78
PART IV
Item 15 Exhibits, Financial Statement Schedules	79

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, the Company 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 the Company 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 the Company, 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 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 certain ground 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 three 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 8.6 net MWs and currently is under construction and expected to be on line in late 2011. The second phase is a planned 8.6 net MW module similar to the first phase unit and is expected to be online in the second quarter of 2013. The second phase unit requires additional drilling for production and injection wells to support the plant and that work is underway and supported by a $3.77 million cost sharing exploration grant from the DOE. The third phase is anticipated to add 17.2 MW of power supplied from new production wells to be drilled but requires a significant transmission line upgrade. The third phase is planned to be on line late 2013.

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 border. The property is 8.5 square miles of geothermal energy and surface 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, 2009. 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. Construction on a 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, 2009, the Company announced that its 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. The financial closing for the DOE loan guarantee took place in February 2011 which secured a $96.8 million loan guarantee from the Department of Energy and a direct loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 million loan represents 75% of the total project cost which is now estimated to be $129 million for the project. The DOE loan is a combined construction and 22 year term loan. The interest rate on the loan is set at the 22 year treasury rate plus approximately 37 basis points when each advance is drawn. With a $13 million equity investment made by Enbridge Inc. to acquire a 20% interest, the project is 100 percent financed.

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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.

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• 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 as a tax equity partner to fully utilize production tax credits available to the project. 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.
• 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, 2011 are adequate to fund our general operating activities through March 31, 2012 including drilling at Neal Hot Springs, general development support activities at San Emidio and repair activities at Raft River. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, the issuance of equity and/or through the sale of ownership interest in tax credits and benefits.

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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 2011 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 additional available DOE loans and guarantees in order to reduce interest costs for any debt instruments the Company may require.

On March 7, 2011, the Company closed a direct registered placement of 5,000,000 shares of Common Stock at a price of $1.00 per share for gross proceeds of $5 million. Each investor also received a Common Stock Purchase Warrant exercisable for 50% of number of shares of Common Stock purchased. Each Warrant will entitle the holder to purchase one additional share of Common Stock for $1.075 per share. The Warrants expire March 3, 2012. The issue included a placement agent fee of 112,000 Common Shares and 56,000 Warrants plus expenses of approximately $15,000. The securities were offered by the Company pursuant to a registration statement filed with the Securities and Exchange Commission (“SEC”), which became effective on December 31, 2010. A prospectus supplement relating to the offering was filed with the SEC on February 28, 2010. After deducting for fees and expenses, the net proceeds were approximately $4.95 million. The net proceeds of the offering will be used for general working capital, including exploration, development and expansion of its geothermal properties

On February 24, 2011, the Company completed the financial closing with the U.S. Department of Energy (“DOE”) of a $96.8 -million loan guarantee to construct its planned 23-megawatt-net power plant at Neal Hot Springs in Eastern Oregon. Neal Hot Springs is the first geothermal project to complete a loan guarantee under DOE’s Title XVII loan guarantee program, which was created by the Energy Policy Act of 2005 to support the deployment of innovative clean energy technologies. The DOE loan guarantee will guarantee a loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 -million Federal Financing Bank loan represents 75% of total project cost. When combined with the previously announced equity investment by Enbridge Inc., the loan provides 100 percent of the anticipated capital remaining to fully construct the project.

In September 2010, USG Oregon LLC (a wholly owned subsidiary) entered into agreements with Enbridge (U.S.) Inc. that formed a strategic and financial partnership to finance the Neal Hot Springs project located in eastern Oregon. A component of these agreements included a $5 million convertible promissory note. Upon conversion, the note shall be considered to be an equity contribution to the Company’s subsidiary. The conversion occurs automatically upon the closing of the Department of Energy (“DOE”) guaranteed project loan. The agreements also provide for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note, will earn Enbridge a 20% direct ownership in the subsidiary. In the event of cost overruns for the project, and at the election of the Company, an additional payment obligation of up to $5 million would be contributed by Enbridge that would increase their direct ownership by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments could increase Enbridge’s ownership to a maximum of 27.5%.

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In August 2010, USG Nevada LLC (a wholly owned subsidiary) entered into agreements with Benham Companies, LLC (subsidiary of Science Applications International Corporation) for a project loan. The project loan is expected to provide substantially all of the funding needed to construct an 8.6 net megawatt power plant for Phase I of the San Emidio project in northwest Nevada. Construction costs are estimated to be approximately $32 million and expected to be completed in October 2011. The construction loan is planned to be repaid with long term financing from available sources such as the Section 1705 loan guarantee program from the U.S. Department of Energy.

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 $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.

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Material Acquisitions/Development

Raft River, Idaho

Raft River Energy Unit I, located in southern Idaho, is a binary cycle geothermal power plant with 13 net megawatts of installed capacity. The power plant achieved commercial operation in January 2008.

Raft River Unit I operated at 98.4% availability and generated an average of 7.95 net megawatts during the fourth fiscal quarter. For the 2010 calendar year, the plant averaged 8.39 net megawatts of generation with 97.7% availability. The plant is operating at reduced output due to the continued loss of temperature from production well RRG-7 and the shutdown of production well RRG-2.

In early January 2009, production well RRG-7 underwent a temperature decline that has now reduced the inlet fluid temperature to the power plant by approximately 11.8 degrees Fahrenheit. Power generation has been reduced by an estimated 1.5 megawatts due to the lower fluid temperature entering the plant. It was determined that the cement in a lap joint (an overlap of well casing) had failed and washed out, thereby allowing lower temperature fluid to enter the wellbore. Production well RRG-2 was shut down on June 10, 2010 due to a reduction in flow and increased motor load which indicates an impending pump failure.

The project does not generate sufficient revenue to complete the repairs out of cash flow so the repairs must be completed by additional capital investment by the partners or some other infusion of capital. Until the repairs are completed, the plant output will continue at an estimated annual average of about 7.8 megawatts.

Subsequent to the end of the quarter, Raft River I Holdings consented to a repair plan for both RRG-2 and RRG-7. A Repair Services Agreement was executed between US Geothermal Services and Raft River Energy I LLC, whereby US Geothermal Services will provide up to $1.65 million in funding and manage the well repairs. The cost of the repairs will be repaid from project cash flow, and will be paid preferentially at a rate of 90% of increased cash created by the repairs. A fee of 12.75 percent of the actual repair cost incurred will be paid to USG Services. The outstanding balance of the repair cost will also earn USG Services interest income at the rate of 12.0 percent per-annum.

A pump rig was mobilized to the Raft River site on May 16 and began working on well RRG-2. If the repair program is completed successfully, the Company expects the annual average output of the plant to increase approximately 25% from a current level of approximately 8 megawatts annual average to approximately 10 megawatts. In addition to the well repairs, a flow stimulation technique called deflagration will be applied to wells RRG-2 and RRG-7 which may increase fluid flow from the known production zones. Deflagration has been used successfully in geothermal wells that contain productive zones that have been damaged by drilling mud or drill cuttings during drilling operations, with demonstrated increases in well permeability of up to 50 percent. If successful, additional power generation may be realized from the well stimulation program.

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The $10.2 million DOE cost-shared thermal fracturing program continues on schedule. Eight solar powered seismic stations were installed in June and will be used to monitor potential impacts from the test. Construction is complete on the injection pipeline that extends from the Unit 1 power plant to well RRG-9. A detailed, 3-D magnetotelluric survey was completed during the 3^rd fiscal quarter of 2010. It is now expected that a drill rig will be mobilized to set casing down to the geologic formation targeted for the thermal fracture test, and the first phase of cold water injection will commence during the 2^nd calendar quarter of 2011.

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 megawatt Ormat Energy Converters (“OEC”), five production wells (two wells in use), 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. During the third fiscal quarter ended December 31, 2010, the San Emidio plant operated at 99.6% availability and generated an average of 2.63 net megawatts during the period.

The San Emidio expansion will take place in three phases. Phase I is a repower and Phases II and III will be the expansion. Phase I will utilize the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant now under construction and expected to be online in the fourth calendar quarter of 2011. The Phase I repower is anticipated to cost approximately $32 million. The Phase II expansion is anticipated to cost approximately $50 million. For Phases I and II, the Company has made an application for the DOE’s 1705 loan guarantee program anticipating that 75% of the total project capital may be funded by a Department of Energy loan guarantee, with the remainder funded through equity financing. Subsequent to the end of the period, the Company received a letter from the DOE stating that our application for a loan guarantee for Phases I and II has been put on hold. We are seeking clarification on this matter, however, we believe third-party financing will be available for Phases I and II even without the loan guarantee, although the interest rate on such financing may be higher without the loan guarantee.  Phase III is a further expansion planned a for 17.2 MW net utilizing two additional power modules similar to Phases I and II. The Phase I repower began construction in the third calendar quarter of 2010. The Phase II expansion is anticipated to begin construction in the second calendar quarter of 2010 with commercial operations commencing in the second calendar quarter of 2013. The Company expects to utilize Investment Tax Credits in connection with both the repower and the Phase II expansion. Both Phases I and II will require an amendment to the Sierra Pacific Power Purchase Agreement. Phase III is expected to follow construction of Phase II and be online by the fourth quarter of 2013. Both Phase II and Phase III are subject to successful development of additional production wells through exploration and drilling activities.

Phase I will utilize the existing production and injection wells with the installation a new, more efficient power plant. The existing, historic power plant will be placed on operational standby when the Phase I plant comes on line. As shown in the Project Development table below, the Phase I repower is anticipated to cost approximately $32 million, with Phase II at approximately $50 million and Phase III approximately $100 million. We believe 75% of the Phase I and Phase II development may be funded by project loans, with the remainder funded through equity financing.

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The Phase I power plant began construction in August of 2010, with final completion scheduled to occur at the end of October 2011. All major foundations have been placed, main brine line tie to the new plant site completed, transmission line from the new plant site to the existing line installed, and the fresh water line for the cooling tower installed. Subsequent to the end of the quarter, the chemical building has been constructed, the main transformer is installed, and the cooling tower is being erected. The bulk of the major components for the power plant are scheduled to start arriving in late June and early July.

Phase II began development in the second calendar quarter of 2010 with commercial operations anticipated to commence in the second calendar quarter of 2013. The Company expects that the project will be granted about $28 million in ITC cash grant in lieu of PTC in connection with approximately $82 million Phase I and Phase II megawatt development.

On June 1, 2011, a PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for 19.4 megawatts of electricity. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the PPA. The PPA is subject to signature by NV Energy and approval by the Public Utility Commission of Nevada.

The Company entered into agreements with Science Applications International Corporation (“SAIC”) for a project loan and an engineering procurement and construction contract for the San Emidio Phase I power plant. SAIC’s design-build subsidiary, the Benham Companies LLC, will execute the construction of an 8.6 net megawatt power plant at San Emidio, Nevada. TAS Energy of Houston, Texas will supply a modular power plant to the project. The financing agreement calls for the contractor to provide a non-recourse project loan for the estimated $32 million dollar project. The construction loan is expected to be repaid with long term project loan.

Two System Feasibility Studies were initiated in July 2008 with Sierra Pacific Power Company to begin the FERC mandated transmission study process for the development of the San Emidio resource. The studies examined two levels of power generation; 15 megawatts and 45 megawatts, several transmission routes and the costs associated with each level of generation. The 15 megawatt study, which is directed toward the Phase I repower and Phase II, has completed the study process and resulted in an increase of available transmission to 16 megawatts. A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010.

The 45 megawatt study, which is directed toward the full build out of San Emidio with the addition of the 17.2 megawatt Phase III project, completed the second phase System Impact Study in April. A draft Interconnection Facilities Study, the third and final study, was received on November 22, 2010. The remainder of the 45 megawatt study has been put on hold pending further exploration of the project.

On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of Phase II of its San Emidio geothermal power project using advanced geophysical exploration techniques and drilling. 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.

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Surface geologic mapping by the University of Nevada-Reno has been completed and structural analysis of the mapping is underway. State-of-the-art interpretation of satellite data that measures ground surface deformation has also been completed. Preliminary results show excellent correlation between surface deformation and known producing fractures, establishing this method as an effective tool for locating wells. Field work for a high-precision seismic refraction survey is complete. Data processing and interpretation is complete and has been integrated with the structural mapping.

The results of the DOE exploration program have been finalized and submitted to the DOE for review. Drill sites have been selected, and permitting is underway for a targeted 3^rd quarter start on the drilling program.

Neal Hot Springs, Oregon

Neal Hot Springs, located in Malheur County, Oregon, has been established as a commercial geothermal resource.

On February 26, 2009 U.S. Geothermal submitted a loan 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 financial closing for the DOE loan guarantee took place on February 23, 2011 which secured a $96.8 million loan guarantee from the Department of Energy and a direct loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 million loan represents 75% of the total project cost which is now estimated to be $129 million for the project. The DOE loan is a combined construction and 22 year term loan. The interest rate on the loan is set at 37.5 basis points over the current average yield on outstanding marketable obligations of the United States of comparable maturity. With the $18.8 million equity investment made by Enbridge Inc., the estimated project cost is 100 percent financed.

Notice to proceed was issued to both the EPC contractor (Industrial Builders Inc.) and equipment supplier (TAS Energy) on February 24, 2011. Detailed design and construction of the supercritical cycle power plant utilizing significantly improved technology is currently in progress. The new plant, which will consist of three separate power modules, is designed to deliver approximately 23 megawatt of power net to the grid. The first module is scheduled to begin commercial operations in December 2011 and the full plant is scheduled to be completed during the 4th quarter 2013.

A long term reservoir test was initiated on November 16, 2010 with two production wells flowing brine at an average of 1,800 to 2,000 gallons per minute. Two injection wells were operated in tandem with the production to dispose of the fluid and to provide additional reservoir data. The flowing portion of the test ran until December 20, 2010 when the production wells were shut in and injection was halted. For a following 30 days, temperature and pressure instruments were maintained in the wells until January 24, 2011 when they were pulled and data downloaded.

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Geologic information, flow, temperature and pressure data from the production and T/G drilling programs and the long term reservoir test is being incorporated into the ongoing development of a numerical reservoir model of the Neal Hot Springs geothermal system. The reservoir model was completed on March 24, 2011 and the DOE independent reservoir engineer issued a reservoir certificate on March 31, 2011. The final reservoir report and certificate confirmed that the reservoir was able to sustain the production necessary for the planned 23 megawatt project from the existing four production wells. An injection plan was developed as part of the plan, and drilling operations resumed in April, 2011 to complete the injection well field for the project. A large diameter injection well, NHS-12 is being drilled on the western boundary of the geothermal field to an anticipated depth of 5,000 feet.

As part of the injection well program, a temperature gradient (“TG”) well was started on the south end of the resource area to help determine the limit where heat flow from the active geothermal reservoir extended. This extension of heat flow would be used to site a deep injection well. Subsequent to the end of the quarter, the TG well was completed to 3,020 feet deep and indicated a positive temperature gradient.

On November 3, 2010, USG Oregon LLC, had successfully drilled and tested NHS-2, the fourth large diameter production well at the Neal Hot Springs geothermal project located in eastern Oregon. The production well encountered the reservoir at 2,983 feet (979 meters). The well flowed under artesian pressure at a rate of 3,027 gallons per minute (“gpm”). The production temperature of the well is 287º F (142º C). USG Oregon LLC is owned 80% by U.S. Geothermal and 20% by Enbridge Inc. Subject to establishing reservoir pressure support by drilling additional injection wells, the four wells complete the total production wells needed for the 23 net MW project. Three existing production wells have previously been drilled and tested. Well NHS-1 intersected the reservoir at 2,287 feet (750 meters) and flows under artesian pressure at a rate of 2,315 gpm with a production temperature of 286.5º F (141º C). Well NHS-5 encountered the reservoir at 2,796 feet (917 meters) and flows at a rate of 1,500 gpm and with a production temperature of 286º F (141º C). NHS-8 intersected the reservoir at 3,604 feet (1,182 meters) and flows at a rate of 2,770 gpm with a production temperature of 287.5º F (142º C). Wells with a flowing temperature of 286º F (141º C) and a pumped flow rate of 2,000 to 3,000 gpm are considered very viable to substantiate commercial power generation.

The Company received the Conditional Use Permit from the Malheur County Planning Commission for construction of its proposed 23 net megawatt 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 is complete. Idaho Power Company is responsible for the construction of the transmission line with the cost paid for by the project. A notice to proceed was issued to Idaho Power Company to commence procurement and construction of the transmission line on April 8, 2011.

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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 megawatt-hour and escalates at a variable percentage annually. On May 20, 2010, the Idaho Public Utilities Commission approved the PPA with no changes to the terms and conditions.

Gerlach Joint Venture

The Gerlach Joint Venture, located adjacent to the town of Gerlach in Washoe County, Nevada is made up of both private and BLM geothermal leases. The Peregrine well, a historic exploration slim hole that encountered a lost circulation zone at a depth of 975 feet, was re-drilled and the hole was opened from a 6.5 inch diameter well to a 12.5 inch diameter well. Lost circulation was confirmed with three zones through the 900 to 1,024 foot interval. The well was stopped at a total depth of 1,070 feet. Temperature surveys and a short clean out flow test were conducted on the well.

A 2,000 foot deep temperature gradient well is permitted for the BLM lease site and is designed to test the deep temperature potential of the central portion of the interpreted reservoir block. A production target has been identified from previous drilling data at a depth of 2,700 to 3,000 feet.

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.

Republic of Guatemala

A geothermal energy rights concession located 14 kilometers southwest of Guatemala City was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April. The concession contains 24,710 acres (100 square kilometers) in the center of the Aqua and Pacaya twin volcano complex.

The concession contains the El Ceibillo geothermal project which has nine existing geothermal wells that were drilled in the l990s and have depths ranging from 560 to 2,000 feet (170 to 610 meters). Six of the wells have measured reservoir temperatures in the range of 365°F to 400°F and have high conductive gradients that indicate rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicate the existence of a high permeability reservoir below the existing well field.

An office and staff are located in Guatemala City and planning is underway to advance the project with initial work focused on negotiating necessary surface and access rights, a power sales agreement with the local utility company, strategic investors, and potential project lenders. Follow on work will include a detailed geophysical program, geologic mapping, sampling of hot springs, and to redrill one or two of the existing wells to test for deep, high temperature permeability. Discussions and planning are underway for the development of a power purchase agreement. Discussions are also taking place with several interested parties for the potential sale of a minority equity interest in the El Ciebillo project to a qualified local partner.

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Projects in Operation
Project	Location	Ownership	Generating Capacity (megawatts)(1)	Power Purchaser	Contract 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 San Emidio 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.
(3)	The repower below includes repairs to operating power plants.

Projects Under Development
Project	Location	Ownership	Target Development (Megawatts)	Projected Commercial Operation Date	Estimated Capital Required ($million)	Anticipated Power Purchaser
San Emidio Phase I (8.6 MW Repower)	Nevada	100%	5.0	December 2011	$32	NV Energy
San Emidio Phase II (Expansion)	Nevada	100%	8.6	2nd Quarter 2013	$50	NV Energy
San Emidio Phase III	Nevada	100%	17.2	4th Quarter 2013	$100	TBD
Neal Hot Springs I	Oregon	JV(1)	23	3rd Quarter 2012	$129	Idaho Power
Neal Hot Springs II	Oregon	100%	28	TBD	TBD	TBD
Raft River I (Repower)	Idaho	JV(2)	3	TBD	$8	Idaho Power
Raft River (Unit II)	Idaho	100%	26	4th Quarter 2013	$134	Eugene Water and Electric Board
Raft River (Unit III)	Idaho	100%	32	2nd Quarter 2015	$166	TBD

(1)

In September 2010, the Company’s wholly owned subsidiary (Oregon USG Holdings LLC) entered into agreements that formulated a strategic partnership with Enbridge (U.S.) Inc. (“Enbridge”) may provide up to $23.8 million in funds for the Neal Hot Springs geothermal project. After the planned debt conversion and additional contribution in April of 2011, Enbridge has contributed $18.8 million which they have received a 20% ownership interest in the project.

(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.

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

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Resource Details
Property	Property Size (square miles)	Temperature (°F)	Resource Potential (Megawatts)	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)	64.0(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)	A third party’s assessment of 94 megawatts was based on 6.0 square miles. The Company acquired additional acreage. The resource estimate of 127.0 megawatts was provided by Geothermex.
(2)	Actual production temperatures for existing wells.
(3)	Probable reservoir temperature as measured with a geothermometer.
(4)	A estimate by Black Mountain of 44.0 megawatts.
(5)	A third party resource estimate with respect to 23.0 megawatts, remainder is an internal estimate.
(6)	An estimate provided by Geothermex.

Employees

At March 31, 2011, the Company had 34 full-time and one part time employee (13 administrative and project development, and 24 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, energy credit sales, 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

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.

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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.

The reservoir located in Raft River, Idaho is a proven geothermal resource, and has a 13 net MW capacity geothermal power plant in operation (Raft River Energy I LLC). San Emidio, Nevada is a proven geothermal resource, and has a 3.6 net MW capacity geothermal plant in operation. Based upon the tests of the completed wells and other studies, the reservoir in Neal Hot Springs Oregon has been established as a commercial geothermal resource. Unless major geological changes occur that impact the geothermal reservoirs, the condition of the existing resources is expected to remain consistent over time.

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.
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:

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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.

Neal Hot Springs. The Neal Hot Springs project has received all necessary permits for construction and operation of a 22 MW power plant.

Agency	Approval Status	Effective Date	Approval Number or Designation
ODEQ (Oregon Department of Environmental Quality) (Underground Injection Control Permit)	Approved	3/29/2010	13281-8
ODWR (Oregon Department of Water Resources) (Water Right)	Approved	3/13/2008	LL-1103
ODEQ (WPCF-1200 C; Storm Water Discharge Permit)	Approved	10/12/2010	ORR10-C818
US Fish and Wildlife Service (Endangered Species Act Consultation)	Completed	7/30/2009	13420-2009-TA- 0134
Bureau of Land Management (Drilling Permit)	Approved	12/07/2009	OR-66192
Bureau of Land Management (Right-of-Way)	Approved	1/12/2010	OR-65701
Bureau of Land Management (NEPA/Environmental Assessment)	Completed	9/14/2009	DOI-BLM-OR- V040-2009-030- EA
Oregon Department of Geology and Mineral Industries (Well Drilling Permits)	Approved	2/11/2008 through 10/7/2010	DOGAMI Well ID-184 through 193
Malheur County (Conditional Use Permit)	Approved	8/13/2009	10/21/2009
Malheur County (Road Crossing Permit)	Approved	3/5/2008	08-10
Idaho PUC Approval regarding the PPA	Approved	5/20/2010	Final Order #31087

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.

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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. The Company is expecting to be significantly involved in development activities for the next 5 to 10 years.

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’s primary revenues originate from energy sales and the sale of energy credits. Currently, the Company generates energy revenues from two sources and energy credits from two separate sources. Energy sales are collected from the Idaho Power Company (through the Company’s major subsidiary Raft River Energy Unit I) and Sierra Pacific Power Company. The Company expects to sell power to Idaho Power Company for energy produced at the Neal Hot Springs, Oregon plant. Energy credits are currently being sold to Holy Cross Energy and Barrick Goldstrike Mines Inc. 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 8 or 9 within the next 5 to 10 years.

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.

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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
• 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.

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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, 2011, 2010 and 2009 were $3,253,545, $2,579,152, and $2,336,202; 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.

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 into 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.

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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.

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.

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

On June 1, 2011, the Company announced the signing of a 25 year power purchase agreement between its wholly owned subsidiary (USG Nevada LLC) and NV Energy for the purchase of an annual average of up to 19.9 net megawatts of energy produced from the San Emidio Geothermal Project located in Washoe County, Nevada. This agreement is still subject to approval by the PUC.

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:

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. The PTC enhances the annual revenues of the projects by about 25 percent per year for the first 10 years. 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.

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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, 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.

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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 Raft River (Idaho), 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.

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.

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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.

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 continuation of operations of the Raft River and San Emidio power plants and construction activities in Neal Hot Springs and San Emidio 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
• the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.

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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.

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.

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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 resources in the United States are 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;
• 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.

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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 (2011), 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.

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.

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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.

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.

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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, 2011, from a low of $0.74 CDN to a high of $1.38 CDN on the TSX Exchanges and from a low of $0.70 to a high of $1.36 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.

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:

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• 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. A geothermal power plant is currently under development.

On November 3, 2010, USG Oregon LLC, had successfully drilled and tested NHS-2, the fourth large diameter production well at the Neal Hot Springs geothermal project located in eastern Oregon. The production well encountered the reservoir at 2,983 feet (979 meters). The well flowed under artesian pressure at a rate of 3,027 gallons per minute (“gpm”). The production temperature of the well is 287º F (142º C). USG Oregon LLC is owned 80% by U.S. Geothermal and 20% by Enbridge Inc. Subject to establishing reservoir pressure support by drilling additional injection wells, the four wells complete the total production wells needed for the 23 net MW project. Three existing production wells have previously been drilled and tested. Well NHS-1 intersected the reservoir at 2,287 feet (750 meters) and flows under artesian pressure at a rate of 2,315 gpm with a production temperature of 286.5º F (141º C). Well NHS-5 encountered the reservoir at 2,796 feet (917 meters) and flows at a rate of 1,500 gpm and with a production temperature of 286º F (141º C). NHS-8 intersected the reservoir at 3,604 feet (1,182 meters) and flows at a rate of 2,770 gpm with a production temperature of 287.5º F (142º C). Wells with a flowing temperature of 286º F (141º C) and a pumped flow rate of 2,000 to 3,000 gpm are considered very viable to substantiate commercial power generation.

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The Company has been issued permits for drilling up to 15 temperature gradient drill holes and all necessary geothermal wells. Successful geothermal resource delineation has continued with the development of a three additional geothermal production wells (NHS-2,5,&8) located north and south of NHS-1 and temperature gradient well 21 which intersected additional geothermal resource south of NHS-1.

A thirty (30) day flow test was conducted in December 2010 and January 2011 to measure reservoir characteristics and evaluate the productivity of the geothermal resource. The results of the flow test were evaluated by Richard Holt, Geothermex and engineers with the U.S. Department of Energy. As a result, the Company has been issued our reservoir certificates and the project is proceeding with support from the DOE’s loan guarantee.

The project is projected to deliver power in the 3^rd quarter of 2012.

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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.

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.

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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.

The Company’s wholly owned subsidiary, USG Nevada LLC, has entered into agreements with Science Applications International Corporation (“SAIC”), a FORTUNE 500® scientific, engineering, and technology applications company, for a project loan and an engineering, procurement and construction contract for a geothermal power plant for Phase I of the San Emidio project in northwest Nevada. The work will be executed by SAIC’s design-build subsidiary, The Benham Companies, LLC.

The San Emidio expansion will take place in three phases. Phase I is a repower and Phases II and III will be expansions. Phase I will utilize the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant now under construction and expected to be online in the fourth quarter of 2011. The Phase I repower is anticipated to cost approximately $32 million. The Phase II expansion is anticipated to cost approximately $50 million. For Phases I and II, the Company has made an application for the DOE’s 1705 loan guarantee program anticipating that 75% of the total project capital may be funded by a Department of Energy loan guarantee, with the remainder funded through equity financing. Phase III is a further expansion planned a for 17.2 MW net utilizing two additional power modules similar to Phases I and II. Phase II began development in the second calendar quarter of 2010 with commercial operations anticipated to commence in the first calendar quarter of 2013. The Company expects to be granted about $28 million in ITC cash grant in lieu of PTC in connection with approximately $82 million Phase I and Phase II megawatt development.

Subsequent to the end of the quarter, a PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for 19.4 megawatts of electricity. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the PPA. The Company also received a letter from the DOE stating that our application for a loan guarantee for Phases I and II has been put on hold. We are seeking clarification as to what this means and why our application was treated this way.

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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:

Contract No.	Current Contract 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

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

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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 the Minerals Management Service.

The Company received BLM approval and designation of a Geothermal Unit and a “Participating Area”. The geothermal unit allows USG to hold all geothermal resources within the valley without the risk of lease expiration and allows exploration and development costs to be apportioned between and for the benefit of maintaining all the geothermal leases within the Unit. The first designated participating area encompasses the currently operated southern production zone. Royalties will be portioned to the mineral owners on a percentage of ownership within the participating area. The Unit Area and the Participating Area are key components for long term lease retention and resource development.

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. The Company received BLM approval and designation of a Geothermal Unit. The geothermal unit allows the Company to hold all geothermal resources within the valley without the risk of lease expiration and allows exploration and development costs to be apportioned between and for the benefit of maintaining all the geothermal leases within the Unit. The first designated participating area will be established after the geothermal resource has been delineated and a production strategy is implemented. The Unit Area and the Participating Area are key components for long term lease retention and resource development.

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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.

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

In the prior fiscal year, the Company successfully acquired 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).

Boise Administration Office, Idaho

The Company entered into a 1 year lease contract effective January 31, 2011 through January 31, 2012, for general office space for an executive office located in Boise, Idaho. The contract allows the Company two annual renewal options. The lease payments are due in monthly installments of $6,160 per month.

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Item 3. Legal Proceedings

As of May 31, 2011, 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, 2009.

Bid Prices on the Over-The-Counter Bulletin and NYSE Amex
Fiscal Year Ended March 31, 2010	High	Low
First Quarter	1.93	0.74
Second Quarter	1.75	1.14
Third Quarter	1.70	1.44
Fourth Quarter	1.61	0.91
Fiscal Year Ended March 31, 2011
First Quarter	1.07	0.70
Second Quarter	0.90	0.71
Third Quarter	1.36	0.80
Fourth Quarter	1.35	0.95

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 following sets forth information relating to the trading on the TSX Exchange:

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Sales Prices on the TSX Exchange (CDN$)
Fiscal Year Ended March 31, 2010	High	Low
First Quarter	2.16	0.93
Second Quarter	1.87	1.34
Third Quarter	1.81	1.52
Fourth Quarter	1.69	0.93
Fiscal Year Ended March 31, 2011
First Quarter	1.07	0.75
Second Quarter	0.94	0.74
Third Quarter	1.38	0.82
Fourth Quarter	1.28	0.94

As of May 31, 2011, 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.

Item 6. Selected Financial Data

	For the Fiscal Years Ended March 31,
		2011			2010			2009		2008			2007
Operating Revenues	$	3,253,545		$	2,579,152		$	2,336,202 $		190,721		$	90,206
Operating Expenses		7,270,395			8,562,345			7,660,868		4,568,871			3,138,169
Loss from Continuing Operations		(4,039,350	)		(5,983,193	)		(5,324,666	)	(4,378,150	)		(1,942,884	)
Loss per share from Continuing Operations		(0.05	)		(0.09	)		(0.08	)	(0.06	)		(0.04	)
Cash dividends declared and paid per common share		0			0			0		0			0

	As of March 31,
		2011		2010		2009		2008		2007
Total Assets	$	85,322,968	$	65,727,861	$	52,451,343	$	40,366,933	$	22,673,340
Total Long-term Obligations (1)		18,326,802		2,080,859		1,972,200		1,975,672		2,533,858

(1) Long-term obligations represent the stock compensation payable, a convertible loan, construction loan 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.

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		Loss per share from Continuing Operations			Operating Revenues		Gross Profit		Loss from Operations			Net Loss from Continued Operations
Fiscal Year Ended March 31, 2008
1st Quarter	$	(0.01	)	$	0	$	0	$	(694,622	)	$	(410,536	)
2nd Quarter		(0.02	)		0		0		(1,374,285	)		(1,042,678	)
3rd Quarter		(0.01	)		0		0		(1,103,192	)		(806,494	)
4th Quarter		(0.02	)		190,721		190,721		(1,206,051	)		(1,054,765	)
Fiscal Year Ended March 31, 2009
1st Quarter		(0.02	)		480,915		480,915		(1,774,518	)		(1,717,061	)
2nd Quarter		(0.03	)		743,706		743,706		(1,406,431	)		(1,356,084	)
3rd Quarter		(0.01	)		575,886		575,886		(899,643	)		(874,186	)
4th Quarter		(0.02	)		535,695		535,695		(1,244,074	)		(1,240,423	)
Fiscal Year Ended March 31, 2010
1st Quarter		(0.04	)		335,736		335,736		(2,441,672	)		(2,411,566	)
2nd Quarter		(0.02	)		734,622		734,622		(1,156,554	)		(1,122,525	)
3rd Quarter		(0.02	)		731,315		731,315		(1,449,421	)		(1,394,009	)
4th Quarter		(0.01	)		777,479		777,479		(935,546	)		(910,750	)
Fiscal Year Ended March 31, 2011
1st Quarter		(0.02	)		752,247		752,247		(1,491,924	)		(1,474,560	)
2nd Quarter		(0.01	)		838,688		838,688		(1,003,950	)		(966,691	)
3rd Quarter		(0.01	)		852,515		852,515		(843,584	)		(825,194	)
4th Quarter		(0.01	)		810,095		810,095		(677,392	)		(665,471	)

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.

U.S. Geothermal Inc. (“the Company”) is a Delaware corporation. The Company’s common stock trades on the Toronto Stock Exchange under the symbol “GTH” and on the NYSE Amex LLC under the trade symbol “HTM.”

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For the quarter ended March 31, 2011, the Company was focused on:

1)	Finalizing the reservoir model for the Neal Hot Springs reservoir and planning the 2011 drilling program;
2)	Negotiating a new PPA for San Emidio;
3)	Constructing the new San Emidio Unit 1 power plant in Nevada;
4)	Closing the Department of Energy Loan Guarantee for the Neal Hot Springs project;
5)	Completing the first phase of the DOE Innovative Exploration program and planning a drill program for the expansion of the San Emidio project;
6)	Negotiating partnership terms for San Emidio Phases I and II and discussing development funding for Phase III;
7)	Optimizing the operations of the existing San Emidio power plant in Nevada;
8)	Optimizing the operation of the well field at the Raft River project in Idaho (“Raft River Unit I”;
9)	Conducting negotiations for PPA and equity partners at the El Ciebello project in Guatemala; and
10)	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.

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 2011 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 located in Malheur County, Oregon and has been established as a commercial geothermal resource.

On February 26, 2009 U.S. Geothermal submitted a loan 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 financial closing for the DOE loan guarantee took place on February 23, 2011 which secured a $96.8 million loan guarantee from the Department of Energy and a direct loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 million loan represents 75% of the total project cost which is now estimated to be $129 million for the project. The DOE loan is a combined construction and 22 year term loan. The interest rate on the loan is set at 37.5 basis points over the current average yield on outstanding marketable obligations of the United States of comparable maturity. With the $18.8 million equity investment made by Enbridge Inc., the project is 100 percent financed.

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Notice to proceed was issued to both the EPC contractor (Industrial Builders Inc.) and equipment supplier (TAS Energy) on February 24, 2011. Detailed design and construction of the supercritical cycle power plant utilizing significantly improved technology is currently in progress. The new plant, which will consist of three separate power modules, is designed to deliver approximately 23 megawatt of power net to the grid. The first module is scheduled to begin commercial operations during the second calendar quarter of 2012 and the full plant is scheduled to be complete during the 3^rd quarter 2012.

A long term reservoir test was initiated on November 16, 2010 with two production wells flowing brine at an average of 1,800-2,000 gallons per minute. Two injection wells were operated in tandem with the production to dispose of the fluid and to provide additional reservoir data. The flowing portion of the test ran until December 20, 2010 when the production wells were shut in and injection was halted. For a following 30 days, temperature and pressure instruments were maintained in the wells until January 24, 2011 when they were pulled and data downloaded.

Geologic information, flow, temperature and pressure data from the production and T/G drilling programs and the long term reservoir test is being incorporated into the ongoing development of a numerical reservoir model of the Neal Hot Springs geothermal system. The reservoir model was completed on March 24, 2011 and the DOE independent reservoir engineer issued a reservoir certificate on March 31, 2011. The final reservoir report and certificate confirmed that the reservoir was able to sustain the production necessary for the planned 23 megawatt project from the existing four production wells. An injection plan was developed as part of the plan, and drilling operations resumed on April xx, 2011 to complete the injection well field for the project. A large diameter injection well, NHS-12 is being drilled on the western boundary of the geothermal field to an anticipated depth of 5,000 feet.

As part of the injection well program, a temperature gradient (“TG”) well was started on the south end of the resource area to help determine the limit where heat flow from the active geothermal reservoir extended. This extension of heat flow would be used to site a deep injection well. Subsequent to the end of the quarter, the TG well was completed to 3,020 feet deep and indicated a positive temperature gradient.

On November 3, 2010, USG Oregon LLC, had successfully drilled and tested NHS-2, the fourth large diameter production well at the Neal Hot Springs geothermal project located in eastern Oregon. The production well encountered the reservoir at 2,983 feet (979 meters). The well flowed under artesian pressure at a rate of 3,027 gallons per minute (“gpm”). The production temperature of the well is 287º F (142º C). USG Oregon LLC is owned 80% by U.S. Geothermal and 20% by Enbridge Inc. Subject to establishing reservoir pressure support by drilling additional injection wells, the four wells complete the total production wells needed for the 23 net MW project. Three existing production wells have previously been drilled and tested. Well NHS-1 intersected the reservoir at 2,287 feet (750 meters) and flows under artesian pressure at a rate of 2,315 gpm with a production temperature of 286.5º F (141º C). Well NHS-5 encountered the reservoir at 2,796 feet (917 meters) and flows at a rate of 1,500 gpm and with a production temperature of 286º F (141º C). NHS-8 intersected the reservoir at 3,604 feet (1,182 meters) and flows at a rate of 2,770 gpm with a production temperature of 287.5º F (142º C).

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Wells with a flowing temperature of 286º F (141º C) and a pumped flow rate of 2,000 to 3,000 gpm are considered very viable to substantiate commercial power generation.

The Company received the Conditional Use Permit from the Malheur County Planning Commission for construction of its proposed 23 net megawatt 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 is complete. Idaho Power Company is responsible for the construction of the transmission line with the cost paid for by the project. A notice to proceed was issued to Idaho Power Company to commence procurement and construction of the transmission line on April 8, 2011.

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 megawatt-hour and escalates at a variable percentage annually. On May 20, 2010, the Idaho Public Utilities Commission approved the PPA with no changes to the terms and conditions.

San Emidio, Nevada

The San Emidio expansion will take place in three phases. Phase I is a repower and Phases II and III will be the expansion. Phase I will utilize the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant now under construction and expected to be online in the fourth quarter of 2011. The Phase I repower is anticipated to cost approximately $32 million. The Phase II expansion is anticipated to cost approximately $50 million. For Phases I and II, the Company has made an application for the DOE’s 1705 loan guarantee program anticipating that 75% of the total project capital may be funded by a Department of Energy loan guarantee, with the remainder funded through equity financing. Phase III is a further expansion planned a for 17.2 MW net utilizing two additional power modules similar to Phases I and II. The Phase I repower began construction in the third calendar quarter of 2010. The Phase II expansion is anticipated to begin construction in the second calendar quarter of 2010 with commercial operations commencing in the second calendar quarter of 2013. The Company expects to utilize Investment Tax Credits in connection with both the repower and the Phase II expansion. Both Phases I and II will require an amendment to the Sierra Pacific Power Purchase Agreement. Phase III is expected to follow construction of Phase II and be online by the fourth quarter of 2013. Both Phase II and Phase III are subject to successful development of additional production wells through exploration and drilling activities. Subsequent to the end of the quarter, the Company received a letter from the DOE stating that our application for a loan guarantee for Phases I and II has been put on hold. We are seeking clarification as to what this means and why our application was treated this way.

Phase I will utilize the existing production and injection wells with installation of a new, more efficient power plant. The existing, historic power plant will be placed on operational standby when the Phase I plant comes on line. As shown in the Project Development table above, the Phase I repower is anticipated to cost approximately $32 million, with Phase II at approximately $50 million and Phase III approximately $100 million. We expect 75% of the Phase I and Phase II development may be funded by project loans, with the remainder funded through equity financing.

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The Phase I power plant began construction in August of 2010, with final completion scheduled to occur at the end of October 2011. All major foundations have been placed, main brine line tie to the new plant site completed, transmission line from the new plant site to the existing line installed, and the fresh water line for the cooling tower installed. Subsequent to the end of the quarter, the chemical building has been constructed, the main transformer is installed, and the cooling tower is being erected. The bulk of the major components for the power plant are scheduled to start arriving in late June and early July.

Phase II began development in the second calendar quarter of 2010 with commercial operations anticipated to commence in the second calendar quarter of 2013. The Company expects that the project will be granted about $28 million in ITC cash grant in lieu of PTC in connection with approximately $82 million Phase I and Phase II megawatt development.

On June 1, 2011, a PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for 19.4 megawatts of electricity. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the PPA. The PPA is subject to signature by NV Energy and approval by the Public Utility Commission of Nevada.

The Company entered into agreements with Science Applications International Corporation (“SAIC”) for a project loan and an engineering procurement and construction contract for the San Emidio Phase I power plant. SAIC’s design-build subsidiary, the Benham Companies LLC, will execute the construction of an 8.6 net megawatt power plant at San Emidio, Nevada. TAS Energy of Houston, Texas will supply a modular power plant to the project. The financing agreement calls for the contractor to provide a non-recourse project loan for the estimated $32 million dollar project. The construction loan is expected to be repaid with long term project loan.

Two System Feasibility Studies were initiated in July 2008 with Sierra Pacific Power Company to begin the FERC mandated transmission study process for the development of the San Emidio resource. The studies examined two levels of power generation; 15 megawatts and 45 megawatts, several transmission routes and the costs associated with each level of generation. The 15 megawatt study, which is directed toward the Phase I repower and Phase II, has completed the study process and resulted in an increase of available transmission to 16 megawatts. A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010.

The 45 megawatt study, which is directed toward the full build out of San Emidio with the addition of the 17.2 megawatt Phase III project, completed the second phase System Impact Study in April. A draft Interconnection Facilities Study, the third and final study, was received on November 22, 2010. The remainder of the 45 megawatt study has been put on hold pending further exploration of the project.

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.

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Surface geologic mapping by the University of Nevada-Reno has been completed and structural analysis of the mapping is underway. State-of-the-art interpretation of satellite data that measures ground surface deformation has also been completed. Preliminary results show excellent correlation between surface deformation and known producing fractures, establishing this method as an effective tool for locating wells. Field work for a high-precision seismic refraction survey is complete. Data processing and interpretation is complete and has been integrated with the structural mapping.

The results of the DOE exploration program have been finalized and submitted to the DOE for review. Drill sites have been selected, and permitting is underway for a targeted 3^rd quarter start on the drilling program.

Guatemala

A geothermal energy rights concession located 14 kilometers southwest of Guatemala City was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April. The concession contains 24,710 acres (100 square kilometers) in the center of the Aqua and Pacaya twin volcano complex.

The concession contains the El Ceibillo geothermal project which has nine existing geothermal wells that were drilled in the l990s and have depths ranging from 560 to 2,000 feet (170 to 610 meters). Six of the wells have measured reservoir temperatures in the range of 365°F to 400°F and have high conductive gradients that indicate rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicate the existence of a high permeability reservoir below the existing well field.

An office and staff are located in Guatemala City and planning is underway to advance the project with initial work focused on negotiating necessary surface and access rights, a power sales agreement with the local utility company, strategic investors, and potential project lenders. Follow up work will include a detailed geophysical program, geologic mapping, sampling of hot springs, and to redrill one or two of the existing wells to test for deep, high temperature permeability. Discussions and planning are underway for the development of a power purchase agreement. Also, discussions are taking place with several interested parties for the potential sale of a minority equity interest in the El Ciebillo project to a qualified local partner.

Gerlach Joint Venture

The Gerlach Joint Venture, located adjacent to the town of Gerlach in Washoe County, Nevada is made up of both private and BLM geothermal leases. The Peregrine well, a historic exploration slim hole that encountered a lost circulation zone at a depth of 975 feet, was redrilled and the hole was opened from a 6.5 inch diameter well to a 12.5 inch diameter well. Lost circulation was confirmed with three zones through the 900 to 1,024 foot interval. The well was stopped at 1,070 total depth. Temperature surveys and a short clean out flow test were conducted on the well.

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A 2,000 foot deep temperature gradient well is permitted for the BLM lease site and is designed to test the deep temperature potential of the central portion of the interpreted reservoir block. A production target has been identified from previous drilling data at a depth of 2,700 to 3,000 feet.

Granite Creek

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.

A summary of projects under development is as follows:

Projects Under Development
					Estimated
			Target	Projected	Capital
			Development	Commercial	Required	Anticipated
Project	Location	Ownership	(Megawatts)	Operation Date	($million)	Power Purchaser
San Emidio Phase I (8.6 MW Repower)	Nevada	100%	5.0	December 2011	$32	NV Energy
San Emidio Phase II (Expansion)	Nevada	100%	8.6	2nd Quarter 2013	$50	NV Energy
San Emidio Phase III	Nevada	100%	17.2	4th Quarter 2013	$100	TBD
Neal Hot Springs I	Oregon	JV	23	3rd Quarter 2012	$129	Idaho Power
Neal Hot Springs II	Oregon	100%	28	TBD	TBD	TBD
Raft River I (Repower)	Idaho	JV	3	TBD	$8	Idaho Power
Raft River (Unit II)	Idaho	100%	26	4th Quarter 2013	$134	Eugene Water and Electric Board
Raft River (Unit III)	Idaho	100%	32	2nd Quarter 2015	$166	TBD

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

Raft River Unit I operated at 98.4% availability and generated an average of 7.95 net megawatts during the fourth fiscal quarter. For the 2010 calendar year, the plant averaged 8.39 net megawatts of generation with 97.7% availability. The plant is operating at reduced output due to the continued loss of temperature from production well RRG-7 and the shutdown of production well RRG-2.

In early January 2009, production well RRG-7 underwent a temperature decline that has now reduced the inlet fluid temperature to the power plant by approximately 11.8 degrees Fahrenheit. Power generation has been reduced by an estimated 1.5 megawatts due to the lower fluid temperature entering the plant. It was determined that the cement in a lap joint (an overlap of well casing) had failed and washed out, thereby allowing lower temperature fluid to enter the wellbore. Production well RRG-2 was shut down on June 10, 2010 due to a reduction in flow and increased motor load which indicates an impending pump failure.

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The project does not generate sufficient revenue to complete the repairs out of cash flow so the repairs must be completed by additional capital investment by the partners or some other infusion of capital. Until the repairs are completed, the plant output will continue at an estimated annual average of about 7.8 megawatts. Plans for repair of both RRG-7 and RRG-2 are under a continuing discussion with Raft River I Holdings, a wholly owned subsidiary of Goldman Sachs Group Inc and the majority joint venture partner for Raft River Unit I.

On May 17, 2011, Raft River I Holdings, LLC finally consented to a repair plan for both RRG-2 and RRG-7. A Repair Services Agreement was executed between US Geothermal Services and Raft River Energy I LLC, whereby US Geothermal Services will provide up to $1.65 million in funding and manage the well repairs. The cost of the repairs will be repaid from project cash flow, and will be paid preferentially at a rate of 90% of increased cash created by the repairs. A fee of 12.75 percent of the actual repair cost incurred will be paid to USG Services. The outstanding balance of the repair cost will also earn USG Services interest income at the rate of 12.0 percent per-annum.

The $10.2 million DOE cost-shared thermal fracturing program continues on schedule. The Company’s contributions are made in-kind by the use of the RRG-9 well, well field data, and monitoring support totaling $228,089. Eight solar powered seismic stations were installed in June and will be used to monitor potential impacts from the test. Construction is complete on the injection pipeline that extends from the Unit 1 power plant to well RRG-9. A detailed, 3-D magnetotelluric survey was completed during the 3^rd fiscal quarter of 2010. It is now expected that a drill rig will be mobilized to set casing down to the geologic formation targeted for the thermal fracture test, and the first phase of cold water injection will commence during the 2^nd quarter of 2011.

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 tax partner allowed us to share the risks of ownership and monetize valuable tax credits and benefits. The joint venture partner structure allowed the project to monetize production tax credits which would not otherwise have been available to us. When Unit I operates at full capacity of 13 megawatts, we estimate we will receive cash payments totaling approximately $1.6 million for each of 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. If insufficient cash is generated to satisfy all joint venture obligations, the management fees will be deferred. See Note 5 “Investment in Subsidiaries” in the financial statements for detail of cash payments from RREI.

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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.

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 megawatt Ormat Energy Converters (“OEC”), five production wells (two wells in use), and four injection wells (three wells in use). A cooling tower was added in 1998 to improve summer peak power generation. During the third fiscal quarter ended December 31, 2010, the San Emidio plant operated at 99.6% availability and generated an average of 2.63 net megawatts during the period.

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.

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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. On May 31, 2011, we entered into a new power purchase agreement (“PPA”) with NV Energy. The PPA contemplates the purchase by NV Energy of an annual average of up to 19.9 net megawatts from the San Emidio Geothermal Project located in Washoe County, Nevada. The 25-year PPA anticipates the development of two electric power generation units at San Emidio. The PPA is subject to the Public Utilities Commission of Nevada (“PUCN”) approval and is expected to be submitted to the PUCN by NV Energy within 100 days of the announcement. USG Nevada LLC is currently investigating remedies for certain existing constraints related to transmission that may limit the total output of the project to 16 net megawatts. The base contract price is subject to adjustment annually based upon a fixed annual escalator. Upon PUCN approval, the PPA will replace the current 30 year Power Purchase Agreement that was scheduled to terminate in December 2017 with Sierra Pacific Power Corp. (NV Energy).

The power purchase agreement (“PPA”) for the Neal Hot Springs 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.

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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,
	2011				2010				2009*
	$		%		$		%		$		%
Operating revenues:
Energy sales	2,438,471		96.8		1,743,984		97.1		1,416,852		97.8
Energy credit sales	79,569		3.2		51,695		2.9		32,437		2.2
	2,518,040		100.0		1,795,679		100.0		1,449,289		100.00
Operating expenses:
General and administrative	343,512		13.6		349,422		19.5		282,176		19.5
Salaries and related costs	722,901		28.7		819,182		45.6		579,009		40.0
Operations:
Repairs and maintenance	117,759		4.7		596,516		33.2		200,106		13.8
Other	359,598		14.3		210,838		11.7		308,867		21.3
Rent and lease	27,154		1.1		78,683		4.4		45,442		3.1
Purchased utilities	54,391		2.2		65,543		3.7		126,179		8.7
Depreciation and amortization	1,134,993		45.1		822,365		45.7		723,498		49.9
	2,760,308		109.7		2,942,549		163.8		2,265,277		156.3
Net Operating Loss	(242,268	)	(9.7	)	(1,146,870	)	(63.8	)	(815,988	)	(56.3	)
Interest income	1,561		0.1		-		-		-		-
Net Loss	(240,707	)	(9.6	)	(1,146,870	)	(63.8	)	(815,988	)	(56.3	)

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

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 nine out of the last eleven quarters of full operations.

For the year ended March 31, 2011, energy sales totaled $2,438,471, an increase of $694,487 (39.8%) over same period ended in 2010 and an increase $1,021,619 (72.1%) from the same period ended in 2009. The increase was due to higher production levels and contracted rate increases. Significant improvements and repairs were made to the plant primarily in 2008 and 2009, which resulted in less downtime and increased plant efficiency. For the year ended March 31, 2011, the plant sold 22,303,021 kilowatt hours of energy (monthly average 1,858,585 kilowatt hours) which was an increase of 4,521,997 kilowatt hours from the same period ended in 2009 (monthly average 1,481,754). See quarterly production levels in the table below that details select financial information. For the fiscal year ended March 31, 2011, the average rate per kilowatt hour was $0.1093, which was an increase of 11.4% and 26.2% from the same periods ended 2010 and 2009; respectively. The plant is paid for energy production according to the terms of the PPA which are 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. The contracted rates per kilowatt hour for the San Emidio power plant are summarized as follows:

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Rate Periods Ended	Premium Rates		Non-Premium Rates
September 1,	High	Low	High	Low
2008-09	0.1182	0.0757	0.1037	0.0616
2009-10	0.1418	0.0963	0.1274	0.0789
2010-11	0.1500	0.1035	0.1356	0.0849

During the fiscal year ended March 31, 2010, repair and maintenance costs totaled $596,516 which was $478,757 (406.6%) and $396,410 (198.1%) higher than the same periods ended 2011 and 2009; respectively. In 2010, the Company’s notable repairs were made to: electrical breakers and system controls, the pentane storage and transfer system, gear boxes and drive shafts on all cooling tower fans, condenser tubes, turbine gaskets, the OEC oil cooler water pipelines, and production pumps. Repair costs in 2011 are considered to be at normal levels. Also, repair costs are being kept to a minimum since the plant is scheduled to be replaced in October 2011.

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
June 30, 2010	5,449	571,646	0.1049	(75,065	)	238,087
September 30, 2010	5,260	636,256	0.1210	(405	)	298,948
December 31, 2010	5,938	629,868	0.1061	(104,155	)	298,948
March 31, 2011	6,168	600,702	0.0974	(61,083	)	299,010

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

The Company uses the hypothetical liquidation at book value method (“HLBV”) for allocating of Raft River Energy I LLC’s (“RREI”) 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.

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The Company’s gain from RREI of $288,612 for the fiscal year ended March 31, 2011, decreased $35,317 (10.9%) from same fiscal period ended in 2010, and decreased $251,203 (46.5%) from the same period ended 2009. This was primarily due to energy production levels decreases. Energy production for the fiscal years ended March 31, 2011, 2010, and 2009 totaled 68,490,568, 73,272,800 and 90,547,326 kilowatt hours; respectively. While the plant continues to function according to expectations, the volume and temperature of the geothermal water being delivered to the plant has been trending downward since 2009. This is due to the lap joint failure that began in January 2009 and the shut down of production well RRG-2 on June 10, 2010. An agreement between the partners has been reached, in principal, on the financing of the repairs. A repair program for the pump in RRG-2 (estimated $599,583) and lap joint in RRG-7 (estimated $994,017) began in May of 2011.

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,
	2011				2010				2009
	$		%		$		%		$		%
Operating revenues:
Energy sales	3,837,278		89.8		4,111,702		89.1		4,891,047		88.7
Energy credit sales	433,599		10.2		500,925		10.9		623,956		11.3
	4,270,877		100.0		4,612,627		100.0		5,515,003		100.0
Operating expenses:
Operations	3,278,306		76.8		4,837,123		104.9		3,666,551		66.5
Depreciation and amortization	2,049,787		48.0		2,049,822		44.4		1,951,533		35.4
	5,328,093		124.8		6,886,945		149.3		5,618,084		101.9
Operating Loss	(1,057,216	)	(24.8	)	(2,274,318	)	(49.3	)	(190,544	)	(1.9	)
Other income	97		0.0		5,988		0.1		76,558		1.4
Net Loss	(1,057,119	)	(24.8	)	(2,268,330	)	(49.2	)	(26,523	)	(0.5	)
U.S. Geothermal Inc.’s Allocation of Net Loss	288,612				323,929				539,815

% - represents the percentage of total operating revenues.

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Professional and Management Fees

		Percentage of
		Increase (Decrease)		Percentage of
Fiscal Year Ended	Amount	from Prior Year		Total Operating
March 31,	($)	(%)		Expenses (%)
2009	997,452	17.9		13.2
2010	1,669,227	67.4		19.5
2011	1,108,170	(33.6	)	15.2

For the fiscal year ended March 31, 2011, the Company incurred professional and management fees of $1,108,170, which is a decrease of $561,057 from the same period ended 2010, and a slight increase from the same period in 2009. For all three periods, significant legal costs were incurred for compliance with the SEC and the TSX exchange, as well as routine contract review. Legal fees exceeded $430,000, $529,000 and $395,000 in the fiscal years ended 2011, 2010 and 2009; respectively. In the fiscal year ended 2011, additional legal fees were incurred for the direct placement equity offering. In the 2010 fiscal year, additional legal fees were incurred for a private placement offering and responses to SEC comment letters. Costs paid to a consultant to document and test internal controls for compliance with the Sarbanes-Oxley Act totaled $95,192, $99,478, $135,499 for the fiscal years ended 2011, 2010 and 2009; respectively.

Salary and Related Costs

For the fiscal year ended March 31, 2011, the Company reported $1,084,385 in salaries and related costs, which was reasonably consistent with the same fiscal periods ended in 2010 and 2009. Overall, salary and related costs increased in 2011 due to the addition of two management and development employees, company-wide bonuses and a general wage increase. These increases were offset by a higher percentage of salaries and related costs that were allocated to capital projects. Allocations have been made for the Neal Hot Springs project for engineering, design, permitting and project management efforts needed for well drilling, reservoir evaluation and preliminary plant construction. At San Emidio, salary cost allocations have been made for efforts primarily related to the transmission line studies, the new power plant design, and on site construction for Phase I of the project.

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Management and development employee salaries and related costs allocated to major U.S. Geothermal projects are summarized as follows:

	For the Years Ended March 31,
		2011		2010		Variance
Financial Element		$		$		$		%
Total Company salary and related, excluding San Emidio plant operations		2,128,257		1,633,721		(494,536	)	(30.3	)
Salary and related costs capitalized for the following projects:
USG Nevada LLC (San Emidio Phase I Project)		(409,397	)	(78,684	)	330,713		420.3
USG Oregon LLC (Neal Hot Springs Project)		(591,804	)	(376,468	)	215,336		57.2
Small projects		(42,671	)	(6,817	)	35,854		525.9
		1,084,385		1,171,752		87,367		7.5

% - represents the percentage of change from 2010 to 2011.
Amounts capitalized in 2009 were not significant.

Stock Based Compensation

For the fiscal year ended March 31, 2011, the Company reported $1,066,565 in stock based compensation, which was a decrease of $401,604 (27.4%) from the same fiscal period ended in 2010, and a decrease of $548,224 (34.0%) from the same fiscal period ended in 2009. The decreases were primarily due to the two factors that included the delay in the issuance of the 2010 stock options and a lower average common share price. In prior years, the annual stock option grants were awarded in the first fiscal quarter of the year. In the current fiscal year, the option grant was made on September 10, 2010, which resulted in a decrease of approximately $202,000 in stock based compensation recognized in the year ended March 31, 2011 from the same period ended in 2010. For the fiscal year ended 2011, there was a decrease in average stock price by approximately 29.7% from the same period in 2010 (39.0% from 2009), which resulted in approximately $218,000 decrease reported stock compensation.

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Travel and Promotion

		Percentage of
		Increase (Decrease)		Percentage of
Fiscal Year Ended	Amount	from Prior Year		Total Operating
March 31,	($)	(%)		Expenses (%)
2009	511,568	16.2		6.7
2010	308,502	(39.7	)	3.6
2011	378,528	22.7		5.2

For the fiscal year ended March 31, 2011, costs were 22.7% higher than 2010 and 26.0% lower than 2009. Travel and promotions costs, generally, consist of business show sponsorships, investor relations services, and general employee and director travel reimbursement. Investor relations and general travel costs have been reasonably consistent over the past 3 fiscal years. Business and trade show sponsorships amounted to over $190,000, $89,000, and $297,000 for the fiscal years ended March 31, 2011, 2010, and 2009; respectively. In the fiscal year ended 2011, significant business show sponsorships were incurred for two European trades shows ($78,169) and the Clinton Global Initiative ($20,000). In the fiscal year ended 2009, significant sponsorships were paid to the Money Channel ($27,000), and MJD Media LLC ($200,000).

Liquidity and Capital Resources

We believe our cash and liquid investments at March 31, 2011 are adequate to fund our general operating activities through March 31, 2012 including drilling at Neal Hot Springs, general development support activities at San Emidio and repair activities at Raft River. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, 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 2011 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 additional available DOE loans and guarantees in order to reduce interest costs for any debt instruments the Company may require.

On March 7, 2011, the Company closed a direct registered placement of 5,000,000 shares of Common Stock at a price of $1.00 per share for gross proceeds of $5 million. Each investor also received a Common Stock Purchase Warrant exercisable for 50% of number of shares of Common Stock purchased. Each Warrant will entitle the holder to purchase one additional share of Common Stock for $1.075 per share. The Warrants expire March 3, 2012. The issue included a placement agent fee of 112,000 Common Shares and 56,000 Warrants plus expenses of approximately $15,000. The securities were offered by the Company pursuant to a registration statement filed with the Securities and Exchange Commission (“SEC”), which became effective on December 31, 2010. A prospectus supplement relating to the offering was filed with the SEC on February 28, 2010. After deducting for fees and expenses, the net proceeds were approximately $4.95 million. The net proceeds of the offering will be used for general working capital, including exploration, development and expansion of its geothermal properties

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On February 24, 2011, the Company completed the financial closing with the U.S. Department of Energy (“DOE”) of a $96.8 -million loan guarantee to construct its planned 23-megawatt-net power plant at Neal Hot Springs in Eastern Oregon. Neal Hot Springs is the first geothermal project to complete a loan guarantee under DOE’s Title XVII loan guarantee program, which was created by the Energy Policy Act of 2005 to support the deployment of innovative clean energy technologies. The DOE loan guarantee will guarantee a loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 -million Federal Financing Bank loan represents 75% of total project cost. When combined with the previously announced equity investment by Enbridge Inc., the loan provides 100 percent of the anticipated capital remaining to fully construct the project.

In September 2010, USG Oregon LLC (a wholly owned subsidiary) entered into agreements with Enbridge (U.S.) Inc. that formed a strategic and financial partnership to finance the Neal Hot Springs project located in eastern Oregon. A component of these agreements included a $5 million convertible promissory note. Upon conversion, the note shall be considered to be an equity contribution to the Company’s subsidiary. The conversion occurs automatically upon the closing of the Department of Energy (“DOE”) guaranteed project loan. The agreements also provide for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note, will earn Enbridge a 20% direct ownership in the subsidiary. In the event of cost overruns for the project, and at the election of the Company, an additional payment obligation of up to $5 million would be contributed by Enbridge that would increase their direct ownership by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments could increase Enbridge’s ownership to a maximum of 27.5% . Subsequent to the period end, Enbridge’s convertible promissory note converted into equity if the LLC and Enbridge contributed an additional $13,000,000.

In August 2010, USG Nevada LLC (a wholly owned subsidiary) entered into agreements with Benham Companies, LLC (subsidiary of Science Applications International Corporation) for a project loan. The project loan is expected to provide substantially all of the funding needed to construct an 8.6 net megawatt power plant for Phase I of the San Emidio project in northwest Nevada. Construction costs are estimated to be approximately $32 million and expected to be completed in October 2011. The construction loan is planned to be repaid with long term financing from available sources such as the Section 1705 loan guarantee program from the U.S. Department of Energy.

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.

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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 $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 uncertainty 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.

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Contractual Obligations

As of March 31, 2011, 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	$	448,355	$	167,167	$	145,238	$	114,004	$	21,946
Capital Leases		27,108		12,736		14,372		0		0
Promissory Note		230,000		230,000		0		0		0
Construction Loan (1)		11,651,861		11,651,861		0		0		0
Convertible Loan (2)		5,132,740		5,132,740		0		0		0
Stock Compensation Payable (3)		1,527,829		1,527,829		0		0		0

(1)	Construction loan with Benham will be replaced at completion of construction period with long-term financing anticipated through a loan backed by DOE 1705 loan guarantee program.
(2)	Loan convertible to project equity in Neal Hot Springs project upon closing of DOE loan and receipt of GeoThermex reservoir certificate. The certificate was received and the conversion occurred in April 2011.
(3)	Payable liquidated to additional paid-in capital as stock options are exercised or expire.

Off Balance Sheet Arrangements

As of March 31, 2011, 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, 2011, the Company held investments of $7,610,027 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 grants prior to April 2007 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.

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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 the Raft River, Neal Hot Springs and San Emidio power plants. These types of arrangement will be the model for power purchase contracts planned for future power plants.

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, 2011. 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, 2011.

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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:

• 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, 2011. 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, 2011, 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, 2011, 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, 2011, 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 September 9, 2011. 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 September 9, 2011.

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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 September 9, 2011.

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, 2011:

Equity Compensation Plan Information
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance
Equity compensation plans approved by security holders	6,703,195	$ 1.38	6,011,098
Equity compensation plans not approved by security holders	Nil	Nil	Nil
Total	6,703,195	$ 1.38	6,011,098

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 September 9, 2011.

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 September 9, 2011.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

The following documents are filed as a part of this report:
         2. Consolidated Financial Statements.
             See Item 8 of Part II for a list of the Financial Statements filed as part of this report. 
         3. 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, 2010 and December 31, 2009
                  Statements of Operations for the periods ended December 31, 2010, December 31, 2009, December 26, 2008 and November 28, 2008 
                  Statements of Cash Flows 
                  Statement of Members’ Equity 
                  Notes to the Financial Statement 
         3. Exhibits. See below.

EXHIBIT LIST

EXHIBIT NUMBER	DESCRIPTION
3.1	Certificate of Incorporation of U.S. Cobalt Inc. (now known as U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.2	Certificate of Domestication of Non-U.S. Corporation (Incorporated by reference to exhibit 3.2 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.3	Certificate of Amendment of Certificate of Incorporation (changing name of U.S. Cobalt Inc. to U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.3 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.4	Second 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 October 18, 2010)
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)

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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 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)
4.6	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)
4.7	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)
4.8	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)
4.9	Form of Warrant used in March 2011 registered offering (Incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on February 28, 2011)
4.10	Form of Subscription Agreement used in March 2011 registered offering (Incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on February 28, 2011)
10.1	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)
10.2	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)
10.3	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)
10.4	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)
10.5	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)
10.6	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)
10.7	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)
10.8	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)

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10.9	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)
10.10	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)
10.11	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)
10.12	Employment Agreement dated April 1, 2011 with Kerry D. Hawkley (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on April 7, 2011)
10.13	Employment Agreement dated April 1, 2011 with Douglas J. Glaspey (Incorporated by reference to exhibit 99.1 to the registrant’s Form 8-K as filed on April 7, 2011)
10.14	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.)
10.15	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)
10.16	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)
10.17	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)
10.18	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).
10.19	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).
10.20	Transmission Agreement dated June 24, 2005 between Department of Energy’s Bonneville Power Administration - Transmission Business Line and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.27 to the registrant’s Form 10-QSB quarterly report as filed on August 12, 2005)
10.21	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)
10.22	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).
10.23	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)

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10.24	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).
10.25	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)
10.26	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)
10.27	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).
10.28	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)
10.29	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)
10.30	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).
10.31	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)
10.32	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)
10.33	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)
10.34	Engineering, Procurement and Construction Contract, dated as of August 27, 2010, between USG Nevada LLC and Benham Constructors LLC August 27, 2010. (Incorporated by reference to exhibit 99.1 to the registrant’s Form 8-K as filed on November 8, 2010) *
10.35	Amended and Restated Change in Control Guaranty made and entered into as of October 13, 2010, by U.S. Geothermal Inc., in favor of Benham Constructors, LLC. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on November 8, 2010)
10.36	Credit Addendum to Engineering, Procurement and Construction Contract, dated as of August 27, 2010, between USG Nevada LLC and Benham Constructors LLC August 27, 2010. (Incorporated by reference to exhibit 99.3 to the registrant’s Form 8-K as filed on November 8, 2010)

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10.37	Amended and Restated Limited Liability Company Agreement made and entered into as of September 7, 2010, by and among Oregon USG Holdings LLC, U.S. Geothermal Inc., and Enbridge (U.S.) Inc. (Incorporated by reference to exhibit 99.4 to the registrant’s Form 8-K as filed on November 8, 2010) *
10.38	Conditional Guaranty Agreement, entered into as of September 7, 2010, by US Geothermal Inc. to Enbridge (U.S.) Inc. (Incorporated by reference to exhibit 99.5 to the registrant’s Form 8-K as filed on November 8, 2010)
10.39	2009 Stock Incentive Plan of the Registrant (Incorporated by reference to Appendix A to the Company’s definitive proxy statement on Schedule 14A as filed on November 6, 2009)**
13.1	Audited Consolidated Financial Statements of U.S. Geothermal Inc. as of March 31, 2011.
13.2	Audited Financial Statements of significant subsidiary Raft River Energy I LLC as of December 31, 2010
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

*Portions of these exhibits have been omitted based on a grant of, or an application for, confidential treatment from the SEC. The omitted portions of these exhibits have been filed separately with the SEC.
** Management contracts or compensation plans or arrangements in which directors or executive officers are eligible to participate.

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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, 2011	/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, 2011
Daniel J. Kunz
	Chief Financial Officer (Principal Financial and
/s/ Kerry Hawkley	Accounting Officer)	June 9, 2011
Kerry Hawkley
/s/ Douglas J. Glaspey	Chief Operating Officer and Director	June 9, 2011
Douglas J. Glaspey
/s/ John H. Walker	Chairman and Director	June 9, 2011
John H. Walker
/s/ Paul A. Larkin	Director	June 9, 2011
Paul A. Larkin
/s/ Leland L. Mink	Director	June 9, 2011
Leland R. Mink

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EX-13.1

U.S. GEOTHERMAL INC.
________

Consolidated Financial Statements
March 31, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Stockholders of U.S. Geothermal Inc.

We have audited the accompanying consolidated balance sheets of U.S. Geothermal Inc. as of March 31, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three–year period ended March 31, 2011. We also have audited U.S. Geothermal Inc.’s internal control over financial reporting as of March 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). U.S. Geothermal Inc.’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.

U.S. Geothermal Inc.
Page 2 of 2

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of U.S. Geothermal Inc. as of March 31, 2011 and 2010, and the results of its consolidated operations and its cash flows for each of the years in the three- year period ended March 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, U.S. Geothermal Inc. maintained, in all material respects, effective internal control over financial reporting as of March 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ BehlerMick PS          
BehlerMick PS
Spokane, Washington

June 7, 2011

U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS
(Stated in U.S. Dollars)

		March 31, 2011			March 31, 2010
ASSETS
Current:
Cash and cash equivalents	$	8,098,905		$	12,970,612
Restricted cash (note 3)		645,000			585,000
Receivable from subsidiary		282,257			335,684
Trade accounts receivable		532,605			176,880
Other current assets		164,239			152,950
Total current assets		9,723,006			14,221,126
Deposit on mineral rights purchase		200,000			-
Investment in equity securities (note 4)		178,486			210,975
Investment in subsidiaries (note 5)		17,968,651			18,103,239
Property, plant and equipment, net of accumulated depreciation (note 6)		40,295,117			16,550,006
Intangible assets, net of accumulated amortization (note 7)		16,957,708			16,642,515
Total assets	$	85,322,968		$	65,727,861
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	940,563		$	446,790
Related party accounts payable		2,338			1,897
Current portion of capital lease obligation		12,736			11,837
Promissory note payable, current (note 10)		230,000			-
Total current liabilities		1,185,637			460,524
Long-term Liabilities:
Capital lease obligation, less current portion		14,372			27,108
Promissory note payable (note 10)		-			230,000
Stock compensation payable		1,527,829			1,823,751
Convertible loan payable (note 11)		5,132,740			-
Construction loans payable (note 12)		11,651,861			-
Total liabilities		19,512,439			2,541,383
Commitments and Contingencies (note 19)		-			-
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par value; issued and outstanding shares at March 31, 2011 and 2010 were: 84,761,956 and 78,647,776; respectively)		84,762			78,648
Additional paid-in capital		90,283,987			83,667,011
Accumulated other comprehensive income		108,990			136,693
Accumulated deficit		(25,308,177	)		(21,353,761	)
		65,169,562			62,528,591
Non-controlling interest (note 20)		640,967			657,887
Total stockholders’ equity		65,810,529			63,186,478
Total liabilities and stockholders’ equity	$	85,322,968		$	65,727,861

The accompanying notes are an integral part of these consolidated financial statements.

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Stated in U.S. Dollars)

		Years Ended March 31,
		2011			2010			2009
Operating Revenues:
Energy sales, San Emidio	$	2,438,471		$	1,743,984		$	1,416,852
Energy credit sales, San Emidio		79,569			51,695			32,437
Land, water, and mineral rights leases		196,893			209,544			97,098
Management fees		250,000			250,000			250,000
Gain from investment in subsidiary		288,612			323,929			539,815
Total operating revenues		3,253,545			2,579,152			2,336,202
Operating Expenses:
Consulting fees		20,823			59,777			121,599
Corporate administration		740,560			803,417			753,045
Professional and management fees		1,108,170			1,669,227			997,452
Salaries and wages		1,084,385			1,171,752			1,180,647
Stock based compensation		1,066,565			1,468,169			1,614,789
Travel and promotion		378,528			308,502			511,568
Plant operations, San Emidio		2,760,309			2,942,548			2,265,277
Lease and equipment repair		133,555			138,953			216,491
Total operating expenses		7,292,895			8,562,345			7,660,868
Loss from Operations		(4,039,350	)		(5,983,193	)		(5,324,666	)
Other Income (Loss):
Foreign exchange gain (loss)		(4,922	)		20,004			(41,507	)
Other income		29,844			-			880
Interest income		42,092			103,994			158,771
Total other income		67,014			123,998			118,144
Net Loss		(3,972,336	)		(5,859,195	)		(5,206,522	)
Net loss attributable to the non-controlling interest		17,920			20,345			18,768
Net Loss Attributable to U.S. Geothermal Inc.		(3,954,416	)		(5,838,850	)		(5,187,754	)
Other Comprehensive Income (Loss):
Unrealized gain (loss) on investment in equity securities		(27,703	)		40,802			95,891
Comprehensive Loss Attributable to U.S. Geothermal Inc.	$	(3,982,119	)	$	( 5,798,048	)	$	(5,091,863	)
Basic And Diluted Net Loss Per Share Attributable to U.S. Geothermal Inc.	$	(0.05	)	$	(0.09	)	$	(0.08	)
Weighted Average Number of Shares Outstanding for Basic and Diluted Calculations		79,831,008			64,814,882			62,020,474

The accompanying notes are an integral part of these consolidated financial statements.

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Stated in U.S. Dollars)

		For the Years Ended March 31,
		2011			2010			2009
Operating Activities:
Net loss	$	(3,972,336	)	$	(5,859,195	)	$	(5,206,522	)
Non-cash items:
Depreciation and amortization		1,304,939			990,061			865,057
Gain on operations of subsidiary		(288,612	)		(323,929	)		(539,815	)
Foreign exchange (gain) loss		4,922			(20,004	)		34,237
Loss on equity investment		4,964			-			-
Loss on disposal of equipment		-			900			-
Stock based compensation		1,066,565			1,468,169			1,614,789
Change in non-cash working capital items:
Accounts receivable		(302,298	)		(126,665	)		(180,866	)
Accounts payable and accrued liabilities		(15,436	)		(101,770	)		102,707
Prepaid expenses & other		(11,289	)		(17,145	)		(50,339	)
Total cash used by operating activities		(2,208,581	)		(3,989,578	)		(3,360,752	)
Investing Activities:
Purchases of property, plant and equipment		(13,070,992	)		(4,828,128	)		(21,960,096	)
Investment by non-controlling interest		1,000			-			-
Cash restricted by regulating entities		(60,000	)		(100,000	)		(200,000	)
Cash paid on deposit of mineral rights purchase		(200,000	)		-			-
Cash released from escrow for property acquisition		-			-			11,310,686
Investment in subsidiaries and equity securities		-			-			(940,100	)
Distributions from subsidiary		418,236			722,222			-
Proceeds from sale of equipment		-			500			-
Total cash used by investing activities		(12,911,756	)		(4,205,406	)		(11,789,510	)
Financing Activities:
Issuance of share capital, net of share issue costs		5,260,467			17,494,503			13,728,608
Proceeds from notes payable		5,000,000			230,000			-
Principal payments on capital lease		(11,837	)		(10,998	)		(3,507	)
Total cash provided by financing activities		10,248,630			17,713,505			13,725,101
Increase (Decrease) in Cash and Equivalents		(4,871,707	)		9,518,521			(1,425,161	)
Cash and Cash Equivalents, Beginning of Period		12,970,612			3,452,091			4,877,252
Cash and Cash Equivalents, End of Period	$	8,098,905		$	12,970,612		$	3,452,091
Supplemental Disclosures:
Non-cash investing and financing activities:
Amendment to geothermal lease with common stock	$	-		$	-		$	783,000
Purchase of equipment with capital lease		-			-			53,450
Contribution of geothermal rights by non-controlling interest		-			-			697,000
Purchase of property and equipment on account		509,650			12,733			145,658
Plant construction from construction loan		11,433,435			-			-
Capitalized accrued interest		351,166			-			-
Other Items:
Interest paid		9,955			8,676			1,752

The accompanying notes are an integral part of these consolidated financial statements.

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the Years Ended March 31, 2009, 2010 and 2011
(Stated in U.S. Dollars)

						Additional							Accumulated		Non-
	Number of			Common		Paid-In		Stock		Accumulated			Comprehensive		controlling
	Shares			Shares		Capital		Issuable		Deficit			Income		Interest			Totals
Balance at April 1, 2008	55,339,253		$	55,339	$	48,532,730	$	-	$	(10,327,157	)	$	-	$	-		$	38,260,912
Capital stock issued as result of a private placement closed April 28, 2008, net of issuance costs	6,382,500			6,383		13,711,784		-		-			-		-			13,718,167
Capital stock issued for amendment to royalty agreement with the Kosmos Company	290,000			290		782,710		-		-			-		-			783,000
Shares issued for stock options and warrants exercised	22,134			22		10,418		-		-			-		-			10,440
Adjustment to entitlement shares from consolidated Mango and US Cobalt stock consolidations	(5	)		-		-		-		-			-		-			-
Formation contribution by non-controlling interest (Gerlach Green Energy, LLC)	-			-		-		-		-			-		697,000			697,000
Stock based compensation	-			-		1,657,207		-		-			-		-			1,657,207
Unrealized gain on investment	-			-		-		-		-			95,891		-			95,891
Net loss	-			-		-		-		(5,187,754	)		-		(18,768	)		(5,206,522	)
Balance at March 31, 2009	62,033,882		$	62,034	$	64,694,849	$	-	$	(15,514,911	)	$	95,891	$	678,232		$	50,016,095

The accompanying notes are an integral part of these consolidated financial statements.

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY - Continued
For the Years Ended March 31, 2009, 2010 and 2011
(Stated in U.S. Dollars)

					Additional								Accumulated			Non-
	Number of		Common		Paid-In		Stock			Accumulated			Comprehensive			controlling
	Shares		Shares		Capital		Issuable			Deficit			Income			Interest			Totals
Balance at April 1, 2009	62,033,882	$	62,034	$	64,694,849	$	-		$	(15,514,911	)	$	95,891		$	678,232		$	50,016,095
Stock issued from the exercise of stock options	304,375		304		368,110		-			-			-			-			368,414
Subscription receipts issued August 17, 2009 (note 13)	-		-		-		9,120,294			-			-			-			9,120,294
Stock issued from subscription receipts on December 17, 2009 (note 13)	8,100,000		8,100		9,112,194		(9,120,294	)		-			-			-			-
Capital stock issued as result of a private placement closed March 16, 2010, net of issuance costs	8,209,519		8,210		7,914,186		-			-			-			-			7,922,396
Stock based compensation	-		-		1,577,672		-			-			-			-			1,577,672
Unrealized gain on investment	-		-		-		-			-			40,802			-			40,802
Net loss	-		-		-		-			(5,838,850	)		-			(20,345	)		(5,859,195	)
Balance at March 31, 2010	78,647,776		78,648		83,667,011		-			(21,353,761	)		136,693			657,887			63,186,478
Capital stock issued as result of a direct placement closed March 4, 2011, net of issuance costs	5,112,000		5,112		4,926,877		-			-			-			-			4,931,989
Stock issued from the exercise of stock options	297,180		297		328,318		-			-			-			-			328,615
Stock issued for the stock compensation plan (restricted shares)	235,000		235		232,415		-			-			-			-			232,650
Stock issued, restricted until vesting period complete (note 15)	470,000		470		28,252		-			-			-			-			28,722
Initial formation contribution by non-controlling interest in Oregon USG Holdings, LLC (note 20)	-		-		-		-			-			-			1,000			1,000
Stock compensation liability	-		-		1,101,114		-			-			-			-			1,101,114
Unrealized gain on investment	-		-		-		-			-			(27,703	)		-			(27,703	)
Net loss	-		-		-		-			(3,954,416	)		-			(17,920	)		(3,972,336	)
Balance at March 31, 2011	84,761,956	$	84,762	$	90,283,987	$	-		$	(25,308,177	)	$	108,990		$	640,967		$	65,810,529

The accompanying notes are an integral part of these consolidated financial statements.

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U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2011
(Stated in U.S. Dollars)

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

When U.S. Cobalt Inc. (“GTH” or the “Company”) completed a reverse take-over on December 19, 2003, the former stockholders of U.S. Geothermal Inc. (“GEO – Idaho”) a company incorporated on February 26, 2002 in the State of Idaho, U.S.A. acquired control of GTH. In connection with the transaction, U.S. Cobalt Inc. changed its name to U.S. Geothermal Inc. and consolidated its common stock on a one new to five old basis. All references to common shares in these financial statements have been restated to reflect the roll-back of common stock. The Company constructs and manages power plants that utilize geothermal resources to produce energy. The Company’s operations have been, primarily, focused in the Western United States of America.

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

Basis of Presentation

The Company consolidates subsidiaries that it controls (more-than-50% owned) and entities over which control is achieved through means other than voting rights. These consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, as well as one controlling interest. The accounts of the following companies are consolidated in these financial statements:

i)	U.S. Geothermal Inc. (incorporated in the State of Delaware);
ii)	U.S. Geothermal Inc. (incorporated in the State of Idaho);
iii)	Gerlach Geothermal LLC (organized in the State of Delaware);
iv)	U.S. Geothermal Services, LLC (organized in the State of Delaware);
v)	USG Nevada LLC (organized in the State of Delaware);
vi)	USG Gerlach LLC (organized in the State of Delaware);
vii)	USG Oregon LLC (organized in the State of Delaware)
viii)	Oregon USG Holdings, LLC (organized in the State of Delaware); and
ix)	U.S. Geothermal Guatemala, S.A.

All intercompany transactions are eliminated upon consolidation.

Raft River Energy I LLC, previously a 100% owned subsidiary, was consolidated through July 2006, after which the entity is recorded under the equity method.

In cases where the Company owns a majority interest in an entity but does not own 100% of the interest in the entity it recognizes a non-controlling interest. The Company will recognize 100% of the assets and liabilities of the entity, and disclose the non-controlling interest. The statements of operations will consolidate the subsidiary’s full operations, and will separately disclose the elimination of the non-controlling interest’s allocation of profits and losses.

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NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The following are summarized accounting policies considered to be significant by the Company’s management:

Accounting Method

The Company’s consolidated financial statements are prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and have been consistently applied in the preparation of the consolidated financial statements.

Use of Estimates

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities known to exist as of the date the consolidated financial statements are published, and the reported amounts of revenues and expenses during the reporting period. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of the Company’s consolidated financial statements; accordingly, it is possible that the actual results could differ from these estimates and assumptions and could have a material effect on the reported amounts of the Company’s consolidated financial position and consolidated results of operations.

Cash and Cash Equivalents

The Company considers all unrestricted cash, short-term deposits, and other investments with original maturities of no more than ninety days when acquired to be cash and cash equivalents for the purposes of the statement of cash flows. Discussion regarding restricted cash is included in Note 3.

Trade Accounts Receivable Allowance for Doubtful Accounts

Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts, accordingly. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of March 31, 2011 and 2010, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity through December 31, 2013. At March 31, 2011, the Company’s total cash balance, excluding money market funds, was $1,133,878, and bank deposits amounted to $1,255,208. The difference was due to outstanding checks and deposits. Of the bank deposits, $318,670 was not covered by or was in excess of FDIC insurance guaranteed limits. At fiscal year end, the Company’s money market funds invested in government backed securities totaled $7,610,027, and were not subject to deposit insurance.

Equity Securities

The Company determine the appropriate classification of marketable securities at the time of purchase and reevaluate this designation as of each balance sheet date. The Company classify these securities as either

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held-to-maturity, trading, or available-for-sale. All marketable securities and restricted investments were classified as available-for-sale securities. The Company classifies its investments as “available for sale” because it does not intend to actively buy and sell for short-term profits. The Company's investments are subject to market risk, primarily interest rate and credit risk. The fair value of investments is determined using observable or quoted market prices for those securities.

Available-for-sale securities are carried at fair value, with unrealized gains and losses included as a component of accumulated other comprehensive income (loss). Realized gains and losses, declines in value judged to be other than temporary and interest on available-for-sale securities are included in net income. The cost of securities sold is based on the specific identification method.

Allocation of Profits and Losses from Subsidiaries with Complex Ownership Structures

For subsidiaries that have contractually complex ownership rights, benefits and obligations, the Company utilizes the hypothetical liquidation at book value method (“HLBV”) for allocating profits and losses. This method utilizes the specific terms outlined in the subsidiary’s operating agreement or other authoritative documents. These terms may include cash disbursement terms, associated financial instruments, debt arrangements, and rights to specific revenue streams.

According to the operating agreement, upon liquidation and, after payment of all outstanding debts, any remaining funds would be distributed to the Members in accordance to their positive capital account balance ratio. Certain contract provisions contain allocation of profit and loss items to arrive at the capital account balances. Since the Company is currently the minority member recording their investment in RREI under the equity method, we utilize a hypothetical liquidation at book value at each balance sheet date to value our investment.

For our investment in RREI, the investment will change based upon actual capital contributions, actual cash distributions, 70% of revenue from renewable energy credits, and 1% of all other profit and loss items. See Note 5.

Property, Plant and Equipment

Property, plant and equipment, including assets under capital lease, are recorded at historical cost. Costs of acquisition of geothermal properties are capitalized on a geothermal reservoir basis. If a geothermal reservoir is abandoned, the associated costs that have been capitalized are charged to income in the year of abandonment. Major improvements that significantly increase the useful lives and/or capabilities of the assets are capitalized. Expenditures for repairs and maintenance are charged to expense as incurred. Interest costs incurred during the construction period of defined major projects from debt that is specifically incurred for those projects are capitalized.

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Depreciation is calculated on a straight-line basis over the estimated useful life of the asset. Where appropriate, terms of property rights and revenue contracts can influence the determination of estimated useful lives. Estimated useful lives by major asset categories are summarized as follows:

	Estimated Useful
Asset Categories	Lives in Years
Furniture, vehicle and other equipment	3 to 5
Power plant, buildings and improvements	3 to 30
Wells	30
Well pumps and components	5 to 15
Pipelines	30
Transmission lines	30

Intangible Assets

All costs directly associated with the acquisition of geothermal and water rights are capitalized as intangible assets. These costs are amortized over their estimated utilization period. There are several factors that influence the estimated utilization periods as well as underlying fair value that include, but are not limited to, the following:

• contractual expiration terms of the right,

• contractual terms of an associated revenue contract (i.e., PPAs),

• compliance with utilization and other requirements, and

• hierarchy of other right holders who share the same resource.

Currently, amortization expense is being calculated on a straight-line basis over an estimated utilization period of 30 years for assets placed in service. If an intangible water or geothermal right is forfeited or otherwise lost, the remaining unamortized costs are expensed in the period of forfeiture. An impaired right is reduced to its estimated fair market value in the year the impairment is realized. Costs incurred that extend the term of an intangible right are capitalized and amortized over the new estimated period of utilization.

Impairment of Long-Lived Assets

The Company evaluates its long-term assets annually for impairment or when circumstances or events occur that may impact the fair value of the assets. An impairment loss would be recognized if the carrying amount of a capitalized asset is not recoverable and exceeds its fair value. Management believes that there have not been any circumstances that have warranted the recognition of losses due to the impairment of long-lived assets as of March 31, 2011.

Stock Options Granted to Employees and Non-employees

The Company follows financial accounting standards that require the measurement of the value of employee services received in exchange for an award of equity instrument based on the grant-date fair value of the award. For employees, directors and officers, the fair value of the awards are expensed over the vesting period. The current vesting period for all options is eighteen months.

Non-employee stock-based compensation is granted at the Board of Director’s discretion to reward select consultants for exceptional performance. Prior to issuance of the awards, the Company was not under any obligation to issue the stock options. Subsequent to the award, the recipient was not obligated to perform any services. Therefore, the fair value of these options was expensed on the grant date, which was also the measurement date.

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Under the fair value recognition provisions, share-based compensation cost is measured at the grant date based on the value of the award and is recognized as expense over the vesting period. Determining the fair value of share-based awards at the grant date requires judgment. In addition, judgment is also required in estimating the amount of share-based awards that are expected to be forfeited. If actual results differ significantly from these estimates, stock-based compensation expense and our results of operations could be materially impacted.

The Company has 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 is present when the Company issued stock options denominated in a foreign currency (Canadian dollars) to employees. 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.

Stock Based Compensation Granted to Employees

The Company recognizes the value of common stock granted to employees and directors over the periods in which the services are received. The value of those services is based upon the estimated fair value of the common stock to be awarded. Estimated fair value is adjusted each reporting period. At the end of each vesting period, estimated fair value is adjusted to fair market value. The adjustment is reflected in the reporting period in which the vesting occurs.

Earnings Per Share

The Company follows financial accounting standards, which provides for calculation of "basic" and "diluted" earnings per share. Basic earnings per share includes no dilution and is computed by dividing net income available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of an entity similar to fully diluted earnings per share. Although there were common stock equivalents outstanding at March 31, 2011 and 2010, they were not included in the calculation of earnings per share because their inclusion would have been considered anti-dilutive. Total common stock equivalents at March 31, 2011 and 2010 were 102,665,193 and 96,404,418; respectively.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, trade account and other receivables, refundable tax credits, and accounts payable and accrued liabilities. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted.

Refundable tax credit is comprised of Goods and Services Tax (“GST”) which is refundable from the Government of Canada and is included in other current assets.

The Company’s functional currency is the U.S. dollar. Monetary items are converted into U.S. dollars at the rate prevailing at the balance sheet date. Resulting gains and losses are generally included in determining net income for the period in which exchange rates change.

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Revenue

Revenue Recognition
The energy sales revenue is recognized when the power is produced and delivered to the customer under the terms defined in the Power Purchase Agreements. Revenues from energy credits sales are recognized when the Company has met the terms of certain energy sales agreements with a financially capable buyer and has met the applicable governing regulations. Management fee income is recognized when the services have been provided. Royalties and Lease revenues are recognized as the resource has been utilized and other contractual obligations have been met.

Revenue Source
All of the Company’s direct and indirect operating revenues originate from energy production from its interests in geothermal power plants located in the states of Idaho and Nevada. All of the management fees and royalty revenues are earned from its subsidiary located in South Eastern Idaho. All of the power sales are earned from a power plant located in North Western Nevada.

Recent Accounting Pronouncements

Accounting for Various Topics
In January 2010, FASB issued Financial Accounting Standards Update 2010-22, Accounting for Various Topics (“Update 2010-22”). Update 2010-22 provides clarifications when to separate financial statement elements based upon materiality and volatility. The update was issued August 2010. Management believes that the Company is currently in compliance with the applicable contents of this update, and will continue to evaluate its impact on financial statements.

Accounting for Technical Amendments to Various SEC Rules and Schedules
In January 2010, FASB issued Financial Accounting Standards Update 2010-21, Accounting for Technical Amendments to Various SEC Rules and Schedules (“Update 2010-21”). Update 2010-21 provides clarifications on terminology on various elements that primarily pertain to the statement of equity. It also provided guidance on the proper reporting of changes in certain elements of equity. The update was issued August 2010. Management believes that the Company is currently in compliance with the applicable contents of this update, and will continue to evaluate its impact on financial statements.

Compensation-Stock Compensation
In January 2010, FASB issued Financial Accounting Standards Update 2010-13, Compensation-Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. (“Update 2010-13”). Update 2010-13 provides amendments to Topic 718 to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. Amendments of this Update are effective for fiscal years, and interim periods within those fiscal years beginning on or after December 15, 2010. The Company is still evaluating the impact of this Update. The adoption of this Update may have an impact in the statement of financial position.

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NOTE 3 – RESTRICTED CASH

The Company maintains cash balances that are restricted under Letter of Credit covenants for State and Federal well bonding requirements. These bonds renew on an annual basis. Restricted cash balances and explanations of the nature of the restrictions are summarized as follows:

		March 31,		March 31,
State Agency		2011		2010
Idaho Department of Water Resources, Geothermal Well Bond	$	260,000	$	260,000
Bureau of Land Management, Geothermal Lease Bond – Gerlach Geothermal		10,000		-
State of Nevada Division of Minerals, Statewide Drilling Bond		50,000		50,000
Bureau of Land Management, Geothermal Lease Bonds		150,000		150,000
Oregon Department of Geology and Mineral Industries, Mineral Land and Reclamation Program		175,000		125,000
	$	645,000	$	585,000

These bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. Other future costs of environmental remediation cannot be reasonably estimated and have not been recorded.

NOTE 4 – INVESTMENT IN EQUITY SECURITIES

Investments in equity securities (150,000 shares of a publicly traded geothermal corporation) activities consisted of the following:

		Amount
Available-for-sale equity securities:
Cost basis	$	88,515
Unrealized gains		95,891
Foreign exchange losses		(34,237	)
Fair value at March 31, 2009		150,169
Net unrealized gains/(losses)		40,802
Foreign exchange gains		20,004
Fair value at March 31, 2010		210,975
Net unrealized gains/(losses)		(27,703	)
Foreign exchange losses		(4,786	)
Fair value at March 31, 2011	$	178,486

NOTE 5 – INVESTMENT IN SUBSIDIARIES

Raft River Energy I is a joint venture between the Company and Raft River I Holdings, LLC a subsidiary of Goldman Sachs Group, Inc. An Operating Agreement governs the rights and responsibilities of both parties.

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RREI is a voting interest entity recorded on the financial records of the Company as an equity investment. For book and income tax purposes, Raft River I Holdings, LLC will receive a greater proportion of the share of losses and other income tax benefits. Additionally, during the initial years of operations Raft River I Holdings, LLC will receive a larger allocation of cash distributions.

RREI resulted from an August 9, 2006 agreement between the Company and Raft River Holdings, LLC, a subsidiary of the Goldman Sachs Group, for construction financing of Phase I of the Raft River project. To accommodate the construction financing, the Company sold 50% of its ownership in Raft River Energy to Raft River Holdings, LLC. As a result of the agreements, the Company was required to contribute cash and property sufficient to complete a power plant, and Raft River Holdings was required to contribute $34,170,100.

As of March 31, 2011, the Company has contributed $17,953,640 in cash and property to the project, while Raft River Holdings, LLC has contributed $34,170,100.

For periods prior to August 2006, the Company was the 100% owner of RREI and consolidated the loss. For the periods after August 2006, U.S. Geothermal Inc. recorded RREI under the equity method of accounting for investments in subsidiaries based on the HLBV method.

Effective December 26, 2008, the fiscal year for RREI was changed to a calendar year due to the conversion of Goldman Sachs to a bank holding company. RREI’s latest financial information is summarized as follows:

		December 31,		December 31,		November 28,
		2010		2009		2008
Total current assets	$	908,866	$	808,084	$	1,994,238
Property and equipment		45,939,087		47,993,261		50,016,779
	$	46,847,953	$	48,801,345	$	52,011,017
Total liabilities	$	434,925	$	791,116	$	1,434,413
Total members’ equity		46,413,028		48,010,229		50,576,604
	$	46,847,953	$	48,801,345	$	52,011,017

		Year			Year			Month		Fiscal Year
		Ended			Ended			Ended		Ended
		December 31,			December 31,			December 26,		November 28,
		2010			2009			2008		2008
Operating revenues	$	4,542,477		$	4,718,949		$	537,831	$	4,880,303
Operating earnings (loss)		(747,544	)		(2,278,806	)		352,483		(528,916	)
Net earnings (loss)		(747,396	)		(2,270,718	)		352,960		(448,593	)
U.S. Geothermal Inc., portion of net earnings (loss)	$	375,053		$	279,072		$	54,713	$	(156,060	)

For the Company’s investment in RREI, the investment will change based upon actual capital contributions, actual cash distributions, 70% of revenue from renewable energy credits and 1% of all other profits and losses.

-13-

The Company’s investment in the RREI has changed since March 31, 2007 as follows:

			Increase (Decrease) in
Year ended	Activity		Investment
March 31, 2007	Investment Account Balance	$	6,360,349
	Capital Contributions		10,641,871
	Allocation of profit/loss		6,479
	Prepaid amount		97,000
March 31, 2008	Investment Account Balance		17,105,699
	Capital Contributions		948,054
	Allocation of profit/loss		539,815
	Prepaid amount		(97,000	)
March 31, 2009	Investment Account Balance		18,496,568
	Cash distributions		(722,222	)
	Allocation of profit/loss		323,929
March 31, 2010	Investment Account Balance		18,098,275
	Cash distributions		(418,236	)
	Allocation of profit/loss		288,612
March 31, 2011	Investment Account Balance	$	17,968,651

An investment in a northwest British Columbia geothermal prospect totaling $0 and $4,964 as of March 31, 2011 and 2010 is also recorded on the balance sheet as an investment in subsidiary in addition to the investment in Raft River Energy I LLC.

NOTE 6 - PROPERTY, PLANT AND EQUIPMENT

During the fiscal year ended March 31, 2011, the Company was primarily focused on the development of the Neal Hot Springs, Oregon and San Emidio, Nevada projects. At Neal Hot Springs, drilling and testing costs for wells #2, 8, 10 and 13 amounted to approximately $7.6 million during the fiscal year. Over $3.5 million in legal, design, permitting and initial construction costs were incurred for the Neal Hot Springs plant site and pipelines. The total costs of the Neal Hot Springs project are estimated to be $106 million. Power plant construction costs, at San Emidio amounted to approximately $12.1 million during the fiscal year. The plant is expected to be completed in September 2011, and construction costs are expected to total $25 million. Also, at San Emidio, approximately $718,000 ($410,000 reimbursed by a federal grant) was incurred for surface geological mapping and a seismic survey.

During the fiscal year ended March 31, 2010, the Company continued well field evaluation and development activities at Neal Hot Springs, Oregon. Well No. 5 (“NHS-5”) costing approximately $1.9 million was substantially completed in October 2009. At fiscal year end, over $379,000 had been spent on temperature gradient wells. Transmission line surveying and engineering costs were incurred for approximately $191,000. Engineering, design and permitting costs of approximately $365,000 were incurred for the future power plant and plant site.

Land and a building were purchased in San Emidio, Nevada for approximately $262,000 for the site of new power plant. Improvements that amounted to over $336,000 were made to the old San Emidio power plant during the fiscal year.

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Property, plant and equipment, at cost, are summarized as follows:

		March 31, 2011			March 31, 2010
Land	$	652,507		$	652,507
Power production plant		2,275,474			1,665,882
Wells		3,617,312			3,617,312
Furniture and equipment		874,132			785,606
		7,419,425			6,721,307
Less: accumulated depreciation		(2,426,017	)		(1,396,605	)
		4,993,408			5,324,702
Construction in progress		35,301,709			11,225,304
	$	40,295,117		$	16,550,006

For the year ended March 31, 2011, the Company incurred interest costs of $361,121, of which $351,166 was capitalized as a component of the Neal Hot Springs and San Emidio projects. Interest costs incurred during the years ended March 31, 2010 and 2009 were not significant and no interest was capitalized for those years.

Depreciation expense charged to operations for the years ended March 31, 2011, 2010, and 2009 amounted to $1,029,412; $714,534 and $612,491; respectively.

Changes in Construction in Progress for the fiscal years ended March 31, 2011 and 2010, are summarized as follows:

		March 31, 2011			March 31, 2010
Beginning balances	$	11,225,304		$	7,807,445
Current development construction		25,300,205			3,417,859
Grant reimbursements		(1,223,800	)		-
Transfers into production		-			-
Write-off of unsuccessful projects		-			-
Ending balances	$	35,301,709		$	11,225,304

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Construction in Progress, at cost, consisted of the following projects/assets by location at fiscal year ends, are as follows:

		March 31,			March 31,
		2011			2010
Raft River, Idaho:
Unit II, power plant, substation and transmission lines	$	1,000,273		$	733,284
Unit II, well construction		2,888,972			2,085,250
Grant reimbursements		(791,687	)		-
		3,097,558			2,818,534
San Emidio, Nevada:
Power plant (Re-power project)		12,104,457			50,872
Interconnection studies for transmission line		197,679			76,032
Well construction		3,396,408			2,678,102
Grant reimbursements		(432,113	)		-
		15,266,431			2,805,006
Neal Hot Springs, Oregon:
Wells		12,546,127			4,916,905
Buildings and site preparation		4,064,074			493,852
Transmission lines and substation		327,519			191,007
		16,937,720			5,601,764
	$	35,301,709		$	11,225,304

NOTE 7 – INTANGIBLE ASSETS

In April 2010, the Company incurred consulting fees of $600,000 necessary to acquire the geothermal energy rights concession in Guatemala. The concession area is located 14 miles southwest of Guatemala City. The concession contains 24,710 acres (38.6 square miles) of energy rights located in the center of the Aqua and Pacaya twin volcano complex.

On February 19, 2010, the Company completed a water rights purchase agreement between Empire Farms, LLC for the purchase of approximately 724 acre feet of water rights located in the San Emidio Dessert in Nevada for a final purchase price of $700,000.

Intangible assets, at cost, are summarized as follows:

		March 31, 2011			March 31, 2010
In operation:
Geothermal and mineral rights	$	8,265,800		$	8,265,800
Less: accumulated amortization		(803,620	)		(528,093	)
		7,462,180			7,737,707
Inactive:
Surface water rights		5,469,861			5,484,059
Geothermal and mineral rights		4,025,667			3,420,749
	$	16,957,708		$	16,642,515

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Estimated aggregate amortization expense for the next five fiscal years is as follows:

		Projected
		Amounts
Years ending March 31,
2012	$	275,527
2013		275,527
2014		275,527
2015		275,527
2016		275,527
	$	1,377,635

Amortization expense charged to operations for the years ended March 31, 2011, 2010 and 2009 amounted to $275,527; $275,527 and $252,566; respectively.

NOTE 8 – PROVISION FOR INCOME TAXES

Income taxes are provided based upon the liability method. Under this approach, deferred income taxes are recorded to reflect the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end. A valuation allowance is recorded against deferred tax assets if management does not believe the Company has met the “more likely than not” standard imposed by accounting standards to allow recognition of such an asset.

At March 31, 2011, the Company had net deferred tax assets calculated at an expected rate, noted in the table below, of approximately $6,743,000 (March 31, 2010 - $4,942,000). As management of the Company cannot determine that it is more likely than not that the Company will realize the benefit of the net deferred tax asset, a valuation allowance equal to the net deferred tax asset was recorded at March 31, 2011 and 2010.

The significant components of the net deferred tax asset calculated with the estimated effective income tax rate at March 31, 2011 and 2010 were as follows:

		March 31,			March 31,
		2011			2010
Deferred tax assets*:
Net operating loss carry forward	$	6,379,000		$	4,924,000
Stock based compensation		806,000			515,000
Deferred tax liabilities*:
Depreciation and amortization		(442,000	)		(497,000	)
Net deferred income tax asset		6,743,000			4,942,000
Deferred tax asset valuation allowance		(6,743,000	)		(4,942,000	)
Net deferred tax asset	$	-		$	-

* - significant components of deferred assets and liabilities are considered to be long-term.

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The Company’s estimated effective income tax rate is summarized as follows:

	For the years ended March 31,
	2011		2010		2009
U.S. Federal statutory rate	34.0%		34.0%		34.0%
Average State income tax, net of federal tax effect	3.8		3.8		4.2
Production tax credits	(2.0	)	(2.0	)	(2.0	)
Net effective tax rate	35.8%		35.8%		36.2%

At March 31, 2011, the Company had net income tax operating loss carry forwards of approximately $17,622,000 ($13,678,000 in March 31, 2010), which expire in the years 2023 through 2031. The change in the allowance account from March 31, 2010 to March 31, 2011 was $1,801,000.

Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our tax provisions. Ultimately, the actual tax benefits to be realized will be based upon future taxable earnings levels, which are very difficult to predict.

Accounting for Income Tax Uncertainties and Related Matters

We may be assessed penalties and interest related to the underpayment of income taxes. Such assessments would be treated as a provision of income tax expense on our financial statements. For the years ended March 31, 2011, 2010 and 2009, no income tax expense has been realized as a result of our operations and no income tax penalties and interest have been accrued related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and in the States of Idaho and Oregon. These filings are subject to a three year statute of limitations. Our evaluation of income tax positions included the fiscal years ended March 31, 2011, 2010, and 2009, could be subject to agency examinations as of March 31, 2011. No filings are currently under examination. No adjustments have been made to reduce our estimated income tax benefit at fiscal year end. Any valuations relating to these income tax provisions will comply with U.S. generally accepted accounting principles.

NOTE 9 - CAPITAL LEASE OBLIGATION

Effective November 10, 2008, the Company entered into a capital lease obligation for the purchase of a forklift that is payable in monthly payments of $1,193 including interest to Wells Fargo Equipment, Inc. The contract includes a purchase option of $5,345 at the end of the lease term scheduled for November 2012. At March 31, 2011, equipment under capital lease amounted to $53,450 ($28,507 accumulated amortization). The schedule of minimum lease payments is as follows:

Years Ending March 31,		Principal		Interest		Totals
2012	$	12,736	$	1,580	$	14,316
2013		14,372		518		14,890
	$	27,108	$	2,098	$	29,206

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NOTE 10 – PROMISORY NOTE PAYABLE

On July 7, 2009, the Company financed the purchase of 40 acres of land and a building on property adjacent to our San Emidio power plant facility with a promissory note. The note for $230,000, is payable in 24 successive monthly installments commencing on the second month following the date of disbursement. The first 23 payments consist of interest only on the outstanding principal at 3.25% per annum. The entire principal and the accrued interest are due on the final payment. The note is unsecured. In the event of an assignment for the benefit of creditors, application for the appointment of a receiver or filing of a voluntary or involuntary petition in bankruptcy by or against the Company, the holder may declare this note immediately due and payable in full. Currently, the Company is in compliance with the note requirements.

NOTE 11 – CONVERTIBLE PROMISSORY NOTE

In September 2010, the Company’s wholly owned subsidiary (Oregon USG Holdings LLC) entered into agreements that formulated a strategic partnership with Enbridge (U.S.) Inc. (“Enbridge”) to provide up to $23.8 million in funds for the Neal Hot Springs geothermal project located in Eastern Oregon.

A component of this funding included a $5 million unsecured convertible promissory note that was signed on September 8, 2010. The note is payable on demand on September 30, 2011, including interest at 4.75% per annum. Upon conversion, the note shall be considered to be fully satisfied, including interest, and shall be treated for all purposes as a contribution to Oregon USG Holding LLC as of the conversion date. The conversion occurs automatically upon the closing of the Department of Energy (“DOE”) guaranteed project loan. The Company has the option to pay all accrued interest in cash prior to the conversion date. The loan shall become payable in full at the option of the Enbridge following any of the circumstances that create an “Event of Default.” Notable Events of Default include the DOE or relevant governmental authority communicates that it will not or does not intend to guarantee the Project Loan or the Project is unable to obtain a reservoir certificate by an independent reservoir engineer. Repayment of the note is guaranteed by U.S. Geothermal, Inc.

In April 2011, the conditions of the conversion were met. See Note 21 for details.

NOTE 12 – CONSTRUCTION NOTES PAYABLE

Effective August 27, 2010, the Company’s wholly owned subsidiary (USG Nevada LLC) signed a construction loan agreement with Benham Constructors LLC (“Benham”). Benham will be the primary contractor in the relocation and replacement of the existing power plant. The new 8.6 net megawatt power plant is expected to cost approximately $25 million, and is expected to be completed October 2011. Upon completion, the Company will pay the debt in full within 30 days of receipt of the final statement prepared by Benham. Interest will accrue on outstanding balance at 9.5% per annum. When due, the Company expects to obtain funds to repay the loan balance with a long-term project loan. The loan is non-recourse and is secured by the Project’s assets. Title of all work and materials shall pass to the Company the later of delivery to the Site or upon payment in full.

NOTE 13 – SUBSCRIPTION RECEIPTS/STOCK ISSUABLE

In the second quarter ended September 30, 2009, the Company entered into an agreement to privately place approximately 8,100,000 Subscription Receipts (“Receipt”) at $1.35 CDN ($1.22) per Receipt for gross proceeds of approximately $10,935,000 CDN ($9,882,000). Each Receipt was automatically exchanged, without additional consideration on the exchange date for one (“Unit”) of the Company. The exchange date was December 17, 2009. Each Unit consisted of one share of common stock of the Company and one half of

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one common stock purchase warrant (a "Warrant"). Each Warrant entitled the holder thereof to acquire one additional share of common stock of the Company for a period of 24 months following the closing of the offering for $1.75 per share of common stock.

NOTE 14 - CAPITAL STOCK

The Company is authorized to issue 250,000,000 shares of common stock. All shares have equal voting rights, are non-assessable and have one vote per share. Voting rights are not cumulative and, therefore, the holders of more than 50% of the common stock could, if they choose to do so, elect all of the directors of the Company.

On March 10, 2011, the Company issued 705,000 shares for the stock compensation plan (restricted shares) approved on September 10, 2010. The shares will be distributed to qualified recipients according to the approved vesting schedule. See note 15 for details.

On March 7, 2011, the Company issued 5,000,000 shares of Common Stock at a price of $1.00 per share. Each investor received a Common Stock Purchase Warrant exercisable for 50% of number of shares of Common Stock purchased. Each Warrant will entitle the holder to purchase one additional share of Common Stock for $1.075 per share. The Warrants expire March 3, 2012. The issue included a placement agent fee of 112,000 Common Shares and 56,000 Warrants with the same terms.

During the year ended March 31, 2011, the Company issued 297,180 common shares to employees of the Company upon exercise of stock options. Common shares of 272,180 were issued at a strike price of $1.00 CDN and 25,000 were issued at $0.92.

On March 16, 2010, the Company completed a private placement stock offering where the Company issued 8,209,519 shares of Common Stock at a price of $1.05 per share for gross proceeds of $8.6 million ($7,922,396 net proceeds). Each investor was, also, issued a common share purchase warrant (“Warrant”) exercisable for 50% of the number of shares of Common Stock purchased. Each Warrant is exercisable at $1.25 per share for a period of five years beginning September 16, 2010.

During the year ended March 31, 2010, the Company issued 304,375 common shares to employees and consultants of the Company upon exercise of stock options at strike prices between $0.72 and $.92.

As described in Note 9, the Company issued 8,100,000 shares for $1.35 CDN ($1.22) on December 17, 2009 for the exchange of subscription receipts.

During the quarter ended March 31, 2009, the Company verified an adjustment of 5 shares required for entitlement shares to be issued for the stock consolidations of Consolidated Mango (1999) and US Cobalt (2003) shares. These shares remain in escrow until the Consolidated Mango and US Cobalt shares are redeemed for U.S. Geothermal Inc. common shares.

During the year ended March 31, 2009, the Company issued 22,134 common shares to an officer of the Company upon exercise of stock options at a strike price of $0.60 CDN.

During the quarter ended June 30, 2008, the Company entered into an agreement with a Canadian investment dealer, in which an underwriter agreed to purchase 4,260,000 units of the Company’s equity interests. Each unit comprised one common share of the Company’s stock and one half of one common share purchase warrant. The initial offering, completed on April 28, 2008, generated gross proceeds $10,011,000 CDN (approximately $10,154,458) at a price of $2.35 CDN per share. Each warrant will entitle the holder the right to acquire one additional common share of the Company for a period of 24 months following the closing of the offering for $3.00 per share. In addition, the Underwriters exercised their option to purchase an

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additional 2,122,500 units at the issue price of the offering, resulting in the issuance of a total of 6,382,500 units for aggregate gross proceeds of approximately $15 million CDN.

During the quarter ended June 30, 2008, the Company issued 290,000 common shares at a price of $2.70 per share to the Kosmos Company in exchange for a favorable amendment to the existing royalty agreement. The royalty agreement is applicable to the operations of the newly acquired San Emidio plant.

NOTE 15 - STOCK BASED COMPENSATION

The Company has a stock incentive plan (the “Stock Incentive Plan”) for the purpose of attracting and motivating directors, officers, employees and consultants of the Corporation and advancing the interests of the Corporation. The Stock Incentive Plan is a 15% rolling plan approved by shareholders in December 2009, whereby the Company can grant options to the extent of 15% of the current outstanding common shares. Under the plan, all forfeited and exercised options can be replaced with new offerings. As of March 31, 2011, the Company can issue stock option grants totaling up to 12,714,296 shares. Options are granted for a term of up to five years from the date of grant. Stock options granted generally vest over a period of eighteen months, with 25% vesting on the date of grant and 25% vesting every six months thereafter. Effective April 1, 2007, all grants are stated in U.S. dollars. The Company recognizes compensation expense using the straight-line method of amortization. Historically, the Company has issued new shares to satisfy exercises of stock options and the Company expects to issue new shares to satisfy any future exercises of stock options. At March 31, 2011, the Company had 6,703,195 options granted and outstanding.

On September 10, 2010, the Company granted 1,300,000 stock options to employees exercisable at a price of $0.86 until September 10, 2015.

On September 23, 2009, the Company granted 80,000 stock options to employees exercisable at a price of $1.58 until September 23, 2014.

On May 26, 2009, the Company granted 1,795,000 stock options to employees and consultants exercisable at a price of $0.92 until May 26, 2014.

On August 9, 2008, the Company granted 95,000 stock options to employees exercisable at a price of $1.58 until August 9, 2013.

On May 19, 2008, the Company granted 1,505,000 stock options to employees and consultants exercisable at a price of $2.41 until May 19, 2013.

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The following table reflects the summary of stock options outstanding at March 31, 2008 and changes during the years ended March 31, 2009, 2010 and 2011:

				Weighted
				Average		Weighted
	Number of			Exercise		Average		Aggregate
	shares under			Price Per		Fair		Intrinsic
	options			Share		Value		Value
Balance outstanding, March 31, 2008	2,899,878		$	1.22	$	1.03	$	2,997,808
Forfeited	(238,494	)		0.98		0.63		(151,013	)
Exercised	(22,134	)		0.57		0.28		(6,093	)
Granted	1,600,000			2.19		0.87		1,394,017
Balance outstanding, March 31, 2009	4,239,250			1.62		1.00		4,234,719
Forfeited	(80,000	)		2.34		1.95		(156,000	)
Exercised	(304,375	)		0.90		0.82		(249,588	)
Granted	1,875,000			0.95		0.78		1,466,898
Balance outstanding, March 31, 2010	5,729,875			1.49		0.92		5,296,029
Forfeited	(29,500	)		2.00		0.66		(19,597	)
Exercised	(297,180	)		0.99		0.99		(294,066	)
Granted	1,300,000			0.86		0.58		752,206
Balance outstanding, March 31, 2011	6,703,195		$	1.38	$	0.86	$	5,734,572

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model using the assumptions noted in the following table. Expected volatilities are based on historical volatility of the Company’s stock. The Company uses historical data to estimate option volatility within the Black-Scholes model. The expected term of options granted represents the period of time that options granted are expected to be outstanding, based upon past experience and future estimates and includes data from the Plan. The risk-free rate for periods within the expected term of the option is based upon the U.S. Treasury yield curve in effect at the time of grant. The Company currently does not foresee the payment of dividends in the near term.

The fair value of the stock options granted was estimated using the Black-Scholes option-pricing model and is amortized over the vesting period of the underlying options. The assumptions used to calculate the fair value are as follows:

		Year Ended March 31,
	2011	2010	2009
Dividend yield	0	0	0
Expected volatility	89-92%	71-93%	71-82%
Risk free interest rate	0.26-0.78%	0.46-1.32%	1.74-2.23%
Expected life (years)	3.19	3.17	3.25

Changes in the subjective input assumptions can materially affect the fair value estimate and, therefore, the existing models do not necessarily provide a reliable measure of the fair value of the Company’s stock options.

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The following table summarizes information about the stock options outstanding at March 31, 2011:

	OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	1.00 CDN	1,170,820	0.03	1,170,820	$	1,188,983
	1.15 CDN	78,750	0.33	78,750		86,626
	1.40 CDN	157,500	0.81	157,500		139,271
	2.41	652,500	1.31	652,500		460,975
	2.22	1,465,000	2.13	1,465,000		1,786,417
	1.78	95,000	2.49	95,000		81,172
	0.92	1,715,625	3.15	1,715,625		1,212,487
	1.58	68,000	3.48	68,000		26,435
	0.86	1,300,000	4.45	650,000		376,103
$	1.38	6,703,195	2.36	6,053,195	$	5,358,469

The following table summarizes information about the stock options outstanding at March 31, 2010:

	OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	1.00 CDN	1,443,000	1.00	1,443,000	$	1,465,385
	1.15 CDN	78,750	1.33	78,750		86,626
	1.40 CDN	157,500	1.83	157,500		139,271
	2.41	660,000	2.33	660,000		466,274
	2.22	1,475,000	3.12	1,475,000		1,798,611
	1.78	95,000	3.48	95,000		81,172
	0.92	1,740,625	4.15	867,125		612,825
	1.58	80,000	4.17	40,000		15,550
$	1.49	5,729,875	2.77	4,816,375	$	4,665,714

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A summary of the status of the Company’s nonvested stock options outstanding at March 31, 2008 and changes during the fiscal years ended March 31, 2009, 2010 and 2011 are presented as follows:

				Weighted		Weighted
				Average Grant		Average
	Number of			Date Fair Value		Grant Date
	Options			Per Share		Fair Value
Nonvested, March 31, 2008	419,375		$	1.08	$	1.43
Granted	1,600,000			2.19		1.22
Vested	(980,881	)		2.25		1.26
Forfeited	(238,494	)		0.98		0.63
Nonvested, March 31, 2009	800,000			1.08		1.43
Granted	1,875,000			0.95		0.70
Vested	(1,681,500	)		1.52		0.97
Forfeited	(80,000	)		2.34		0.90
Nonvested, March 31, 2010	913,500			0.95		0.69
Granted	1,300,000			0.86		0.58
Vested	(1,557,500	)		0.90		0.66
Forfeited	(6,000	)		1.58		0.39
Nonvested, March 31, 2011	650,000		$	0.86	$	0.58

As of March 31, 2011, there was $341,567 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years. The total fair value of options vested at March 31, 2011 and 2010 was $805,193 and $1,468,169; respectively.

Stock Compensation Plan (Restricted Shares)

On September 10, 2010, the Company granted officers, directors and select employees 705,000 common shares that will be distributed in three six-month vesting periods. The recipients meet the vesting requirements by maintaining employment and good standing with the Company through the vesting periods. After vesting, there are no restrictions on shares. On March 10, 2011, the 705,000 common shares were issued to the recipients and held by the Company. All of these shares were considered to be issued and outstanding. On March 11, 2011, 235,000 common shares vested valued at $0.99 per share, and the shares were released to the qualified recipients. The remaining vesting schedule is as follows:

	Number of Shares
Remaining Vesting Dates	Vesting
September 10, 2011	235,000
March 11, 2012	235,000
	470,000

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Stock Purchase Warrants

At March 31, 2011, the outstanding broker warrants and share purchase warrants consisted of the following:

			Broker
			Warrant	Share		Warrant
	Broker		Exercise	Purchase		Exercise
Expiration Date	Warrants		Price	Warrants		Price
August 17, 2011	243,000	$	1.22	4,050,000	$	1.750
March 4, 2012	-		-	2,556,000		1.075
September 16, 2015	246,285		1.25	4,104,757		1.250

NOTE 16 – FAIR VALUE MEASUREMENT

On April 1, 2008, the Company adopted the provisions related to its financial assets and liabilities measured at fair value on a recurring basis. Current U.S. generally accepted accounting principles establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to the Company’s needs.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

-25-

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on its Consolidated Balance Sheet as of March 31, 2011 at fair value on a recurring basis:

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts	$	7,610,027	$	7,610,027	$	-	$	-
Investment in equity securities		178,486		-		178,486		-
	$	7,788,513	$	7,610,027	$	178,486	$	-

As allowed by current financial reporting standards, the Company has elected not to implement fair value recognition and reporting for all non-financial assets and non-financial liabilities, except for those that are recognized or disclosed at fair value in the financial statements on a recurring basis, that is, at least annually.

Changes in Level 3 assets measured at fair value on a recurring basis for the years ended March 31, 2010 and 2009:

Investment in equity securities:
Balance at March 31, 2009	$	150,169
Purchases		-
Realized gains/losses		-
Foreign exchange loss		11,156
Unrealized gain included in other comprehensive income		92,247
Transfer out of classification		(253,572	)
Balance at March 31, 2010	$	-

The equity securities purchased in June 2008 are actively traded on a stock exchange; however, the securities held by the Company are subject to trading restrictions. Therefore, the investment was moved from Level 3 to Level 2.

NOTE 17 - RELATED PARTY TRANSACTIONS

At March 31, 2011 and 2010 the amounts of $2,338 and $1,897, respectively, are payable to directors and officers of the Company for routine expense reimbursement. These amounts are unsecured and due on demand.

The Company’s subsidiary Raft River Energy I, LLC (“RREI”) owed the Company $282,257 and $335,684 at March 31, 2011 and 2010; respectively, for operating and maintenance expenses. The receivable balance is comprised of unsecured demand obligations due within twelve months. The Company received the following revenues from RREI:

				Years Ended March 31,
		2011		2010		2009
Management fees	$	250,000	$	250,000	$	250,000
Lease and royalties		196,893		209,544		97,098
	$	446,893	$	459,544	$	347,098

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The Company’s equity investment in RREI is adjusted monthly for its share of the profit and loss based on various revenue stream and cost allocations. Our share of the costs to RREI associated with the above noted management fees and lease and royalty revenues are deemed immaterial at this time, and related U.S. Geothermal, Inc.’s revenues and RREI costs have not been eliminated in the financial statements.

The Company paid directors fees in the amounts of $67,500, $60,000 and $60,000 for the years ended March 31, 2011, 2010 and 2009; respectively.

NOTE 18 - DIFFERENCES BETWEEN CANADIAN AND U.S. GAAP

The Company’s consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”). The material difference in respect to these financial statements between U.S. GAAP and Canadian GAAP is reflected in the recording of Property, Plant and Equipment. Under Canadian GAAP, development and exploration costs associated with the Raft River project (property lease payments, geological consulting fees, well monitoring and permitting, etc.) were recorded as a capital asset. Under U.S. GAAP, these amounts are expensed.

As a result of the above, under Canadian GAAP the following line items in the consolidated balance sheets and income statements would have been presented as follows:

Consolidated Balance Sheets		U.S. GAAP March 31, 2011		Canadian GAAP March 31, 2011		U.S. GAAP March 31, 2010		Canadian GAAP March 31, 2010
Plant, Property and Equipment	$	40,295,117	$	40,735,728	$	16,550,006	$	16,990,617
Intangible Assets		16,957,708		16,957,708		16,642,515		16,642,515
Total Assets		85,322,968		85,763,579		65,727,861		66,168,472
Stockholders’ Equity		65,169,562		65,610,173		62,528,591		62,969,202
Total Liabilities and Stockholders’ Equity	$	85,322,968	$	85,763,579	$	65,727,861	$	66,168,472

Consolidated Statements of Operations and Comprehensive Loss		U.S. GAAP Year Ended March 31, 2011			Canadian GAAP Year Ended March 31, 2011			U.S. GAAP Year ended March 31, 2010			Canadian GAAP Year ended March 31, 2010
Loss from Operations	$	(4,039,351	)	$	(4,039,351	)	$	(5,907,481	)	$	(5,907,481	)
Net Loss Attributable to U.S. Geothermal Inc.	$	(3,954,416	)	$	(3,954,416	)	$	(5,763,138	)	$	(5,763,138	)

The Company’s consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles. Effective our fiscal year beginning April 1, 2011, the Company will provide an explanation of differences between U.S. GAAP and International Financial Reporting Standards (“IFRS”) in a footnote to the financial statements.

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NOTE 19 - COMMITMENTS AND CONTINGENCIES

Operating Lease Agreements
The Company has entered into several lease agreements with terms expiring up to December 1, 2034 for geothermal properties in Washoe County Nevada; Neal Hot Springs, Oregon and adjoining the Raft River properties in Raft River, Idaho. The Company incurred total lease expenses for years ended March 31, 2011, 2010 and 2009, totaling $153,918, $177,109 and $81,392; respectively.

BLM Lease Agreements

Idaho
On August 1, 2007, the Company signed a geothermal resources lease agreement with the United States Department of the Interior Bureau of Land Management (“BLM”). The contract requires an annual payment of $3,502 including processing fees. The primary term of the agreement is 10 years. After the primary term, the Company has the right to extend the contract. BLM has the right to terminate the contract upon written notice if the Company does not comply with the terms of the agreement. The Company believes that it is in compliance with all of the lease terms.

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

Gerlach
The Gerlach Geothermal LLC assets are comprised of two BLM geothermal leases and one private lease totaling 3,615 acres. Both BLM leases have a royalty rate which is based upon 10% of the value of the resource at the wellhead. The amounts are calculated according to a formula established by Minerals Management Service (“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.

Granite Creek
The Company has three geothermal lease contracts with the BLM for the Granite Creek properties. The lease contracts are for approximately 5,414 acres of land and geothermal water rights located in North Western 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

Office Lease
The Company signed in a one year lease contract January 2011 for general office space for the executive office located in Boise, Idaho. The contract includes two one year renewal options for the Company. The lease payments are due in monthly installments of $6,160. The Company incurred total office lease expenses under the current contract and the prior contract for years ended March 31, 2011, 2010 and 2009, totaling $72,306, $70,200 and $67,987; respectively.

-28-

The following is the total contracted lease operating obligations (operating leases, BLM lease agreements and office lease) for the next five fiscal years:

Year Ending
March 31,		Amount
2012	$	167,167
2013		77,627
2014		67,611
2015		58,652
2016		55,352
Thereafter		21,946

Power Purchase Agreements
The Company has signed a power purchase agreement with Idaho Power Company for sale of power generated from its joint venture Raft River Energy I, LLC. The Company has also signed a transmission agreement with Bonneville Power Administration for transmission of the electricity from this plant to Idaho Power, and from the Phase Two plants to other purchasers. These agreements will govern the operational revenues for the initial phases of the Company’s operating activities.

The Company signed a power purchase agreement on March 12, 2008 with Eugene Water and Electric Board for the planned Phase Two power plant at Raft River, Idaho. The agreement allows for variable output up to a maximum of 16 megawatts with a term of 25 years. The agreement is subject to successful drilling and resource development.

As a part of the purchase of the assets from Empire Geothermal Power, LLC and Michael B. Stewart acquisition (“Empire Acquisition”), a power purchase agreement with Sierra Pacific Power Company was assigned to the Company. The contract has a stated expected output of 3,250 kilowatts maximum per hour and extends through 2017. All power produced will be purchased and there are no penalties for not meeting or exceeding expected output levels.

In December of 2009, the Company’s subsidiary (USG Oregon LLC), signed a power purchase agreement with Idaho Power Company for the sale of power generated by the Neal Hot Springs, Oregon project. The agreement has a term of 25 years and provides for the purchase of power up to 25 megawatts (22 megawatt planned output level). Beginning 2012, the flat energy price is $96 per megawatt hour. The price escalates annually by 6 percent in the initial years and by 1.33 percent during the latter years of the agreement. The approximate 25-year levelized price is $117.65 per megawatt hour.

401(k) Plan
The Company offers a defined contribution plan qualified under section 401(k) of the Internal Revenue Code to all its eligible employees. All employees are eligible at the beginning of the quarter after completing 3 months of service. The plan requires the Company to match 25% of the employee’s contribution up to 6%. Employees may contribute up to the maximum allowed by the Internal Revenue Code.

Mineral Rights Option Agreement
On May 24, 2010, USG Oregon LLC (a subsidiary of the Company) entered into an option agreement that allows for exclusive purchase of all mineral rights associated with 2,110 acres of land located in Malheur County, Oregon. Per the terms of the agreement, the Company transferred $200,000 to the seller. To exercise the option agreement, the Company must pay an additional $200,000 prior to November 25, 2012. If the second payment is not made, the Company loses all rights associated with the agreement.

-29-

NOTE 20 – JOINT VENTURES/NON-CONTROLLING INTEREST

Raft River Energy I LLC
Raft River Energy I is a joint venture between the Company and Raft River I Holdings, LLC a subsidiary of Goldman Sachs Group, Inc. An Operating Agreement governs the rights and responsibilities of both parties. At fiscal year end, the Company had contributed approximately $17.9 million in cash and property, and Raft River I Holdings, LLC has contributed approximately $34 million in cash. Profits and losses are allocated to the members based upon hypothetical liquidation at book value method. For income tax purposes, Raft River I Holdings, LLC will receive a greater proportion of the share of losses and other income tax benefits. This includes the allocation of production tax credits, which will be distributed 99% to Raft River I Holdings, LLC and 1% to the Company during the first 10 years of production. During the initial years of operations Raft River I Holdings, LLC will receive a larger allocation of cash distributions. During the initial term of the agreement, the Company accounts for its investment in this LLC under the equity method as a voting interest entity.

Gerlach Geothermal LLC
On April 28, 2008, the Company formed Gerlach Geothermal, LLC (“Gerlach”) with our partner, Gerlach Green Energy, LLC (“GGE”). The purpose of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. Based upon the terms of the members’ agreement, the Company owns a 60% interest and GGE owns a 40% interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to maintain its 40% ownership interest as additional capital contributions are required. If GGE dilutes to below a 10% interest, their ownership position in the joint venture would be converted to a 10% net profits interest. The Company has contributed $746,000 in cash and $300,000 for a geothermal lease and mineral rights; and the GGE has contributed $697,000 of geothermal lease, mineral rights and exploration data.

The consolidated financial statements reflect 100% of the assets and liabilities of Gerlach, and report the current non-controlling interest of GGE. The full results of Gerlach’s operations will be reflected in the statement of operations with the elimination of the non-controlling interest identified.

Oregon USG Holdings LLC
In September 2010, Oregon USG Holdings LLC (wholly owned by U.S. Geothermal Inc.) signed an LLC Operating Agreement with Enbridge Inc. for the right to participate in the Company’s project in the Neal Hot Springs project located in Malheur County, Oregon. The agreement provided for the issuance of a $5 million promissory note, with a conversion option, from Enbridge to Oregon USG Holdings LLC to provide funding for the completion of the drilling and testing activities (see Note 11 for details). Upon completion of the independent reservoir engineer’s report at Neal Hot Springs, Enbridge’s promissory note shall be converted into a direct equity ownership in Oregon USG Holdings LLC. Enbridge will earn a 20% direct ownership from conversion of $5 million convertible note and making an additional payment of $13.8 million to Oregon USG Holdings LLC. In the event of cost overruns for the project and at the Company’s election, an additional payment obligation of up to $5 million may be contributed by Enbridge that would increase their direct ownership by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments could increase Enbridge’s ownership to a maximum of 27.5% .

During the year ended March 31, 2011, Enbridge contributed $1,000 for the right to acquire a 20% ownership interest in Oregon USG Holdings LLC subject to completing the additional payment obligations and conversion of the promissory note.

See description of the conversion event that occurred subsequent to the fiscal year end in Note 21.

-30-

NOTE 21 – SUBSEQUENT EVENT

The Company has evaluated events and transactions that have occurred after the balance sheet date through June 9, 2011, which is considered to be the issuance date. The following event was identified for disclosure:

Conversion of Loan to Equity and Capital Contribution
In April 2011, the DOE guaranteed project loan was closed which triggered the terms of the conversion agreement. The unsecured convertible promissory note in the amount of $5,000,000 was converted to an equity interest in Oregon USG Holding LLC. With the note conversion and the additional capital contribution of $13.8 million, the partner (Enbridge) received a 20% ownership interest in Oregon USG Holdings LLC and has the right to acquire up to a maximum of 27.5% . Oregon USG Holdings LLC has full ownership of USG Oregon LLC.

San Emidio Nevada Project Purchase Agreement
On June 1, 2011, the Company announced the signing of a 25 year power purchase agreement between its wholly owned subsidiary (USG Nevada LLC) and NV Energy for the purchase of an annual average of up to 19.9 net megawatts of energy produced from the San Emidio Geothermal Project located in Washoe County, Nevada. This agreement is still subject to approval by the PUC.

Repairs Agreement for Raft River Energy I LLC
On May 17, 2011, Raft River I Holdings, LLC consented to a repair plan for both under performing wells utilized by Raft River Energy I, LLC (wells RRG-2 and RRG-7). A Repair Services Agreement was executed between U.S Geothermal Services, LLC (“USG Services”) and Raft River Energy I LLC, whereby USG Services will provide up to $1.65 million in funding and manage the well repairs. The cost of the repairs will be repaid preferentially from project cash flow at a rate of 90% of increased cash created by the repairs. A management fee of 12.75% of the actual repair cost incurred will be paid to USG Services. The outstanding balance of the repair cost will also earn USG Services interest income at the rate of 12.0 % per-annum.

-31-

EX-13.2

Exhibit 13.2

Raft River Energy I LLC
Financial Statements
December 31, 2010 and 2009

Raft River Energy I LLC

Index

December 31, 2010 and 2009

	Page(s)
Report of Independent Auditors	1
Financial Statements
Balance Sheets	2
Statements of Operations	3
Statements of Cash Flows	4
Statement of Members' Equity	5
Notes to the Financial Statements	6-14

Report of Independent Auditors

To the Members of Raft River Energy I LLC:

In our opinion, the accompanying balance sheets and the related statements of operations, of cash flows and of members' equity present fairly, in all material respects, the financial position of Raft River Energy I LLC at December 31, 2010 and December 31, 2009, and the results of its operations and its cash flows for the fiscal years ended December 31, 2010, December 31, 2009, November 28, 2008 and for the one-month period ended December 26, 2008 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 4 to the financial statements, the Company has entered into significant transactions with certain related parties.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Portland, Oregon
March 15, 2011

Raft River Energy I LLC

Balance Sheets

December 31, 2010 and 2009

		December 31,			December 31,
		2010			2009*
Assets
Current
Cash and cash equivalents	$	255,726		$	175,688
Accounts receivable, trade		469,415			463,791
Accounts receivable, related party		-			26,935
Inventory, parts and supplies		158,243			116,188
Other current assets		25,482			25,482
Total current assets		908,866			808,084
Property, plant and equipment (net)
Property and equipment, net accumulated depreciation		45,939,087			47,967,225
Construction in progress		-			26,036
Total property, plant and equipment (net)		45,939,087			47,993,261
Total assets	$	46,847,953		$	48,801,345
Liabilities and Members' Equity
Current
Accounts payable and accrued liabilities	$	210,395		$	218,284
Accounts payable, related party		224,530			572,832
Total current liabilities		434,925			791,116
Commitments and contingencies (Note 5)
Members' equity
Class A units - Raft River Holdings, LLC		33,705,975			33,943,416
Class B units - U.S. Geothermal Inc.		16,892,344			17,504,708
Accumulated deficit		(4,185,291	)		(3,437,895	)
Total members' equity		46,413,028			48,010,229
Total liabilities and members' equity	$	46,847,953		$	48,801,345

* - See change in fiscal year end, Note 9

The accompanying notes are an integral part of these financial statements.

2

Raft River Energy I LLC

Statements of Operations

Years Ended December 31, 2010 and 2009

		For the Year			For the Year			For the Month			For the Year
		Ended			Ended			Ended			Ended
		December 31,			December 31,			December 26,			November 28,
		2010			2009*			2008*			2008
Operating revenue
Energy sales	$	3,988,090		$	4,281,588		$	486,295		$	4,285,076
Renewable energy credit sales		554,387			437,361			51,536			595,228
Total operating revenues		4,542,477			4,718,949			537,831			4,880,304
Operating expenses
Insurance		227,273			225,619			16,934			191,116
Office and administration		71,047			51,216			1,227			37,859
Travel and promotion		9,367			9,486			396			22,879
Management and professional fees		400,985			518,582			(79,334	)		466,427
Plant and well field		1,019,929			2,523,365			53,753			1,392,098
Salaries and related costs		760,715			806,904			(47,743	)		616,205
Lease, rent and royalties		140,538			118,027			11,740			206,554
Utilities		612,929			695,874			58,929			608,197
Depreciation		2,047,238			2,048,682			169,446			1,719,927
Loss on equipment disposal		-			-			-			147,958
Total operating expenses		5,290,021			6,997,755			185,348			5,409,220
Income (loss) from operations		(747,544	)		(2,278,806	)		352,483			(528,916	)
Other income
Interest income		148			8,088			477			80,323
Total other income		148			8,088			477			80,323
Net income (loss)	$	(747,396	)	$	(2,270,718	)	$	352,960		$	(448,593	)

* - See change in fiscal year end, Note 9

The accompanying notes are an integral part of these financial statements.

3

Raft River Energy I LLC

Statement of Cash Flows

Years Ended December 31, 2010 and 2009

		For the Year			For the Year			For the Month			For the Year
		Ended			Ended			Ended			Ended
		December 31,			December 31,			December 26,			November 28,
		2010			2009*			2008*			2008
Cash flow from operating activities
Net loss	$	(747,396	)	$	(2,270,718	)	$	352,960		$	(448,593	)
Add (deduct) items not affecting cash
Depreciation		2,047,238			2,048,682			169,446			1,719,927
Loss on disposal of equipment		-			-			-			147,958
Other noncash items		(20,716	)		(25,000	)		-			(27,000	)
Net changes in
Accounts receivable		21,311			47,694			29,115			(481,469	)
Inventory		(42,055	)		(45,290	)		(3,176	)		(67,722	)
Accounts payable and accrued liabilities		(356,191	)		401,683			11,366			365,892
Other current assets		-			72,653			16,934			(107,403	)
Total cash provided by operating activities		902,191			229,704			576,645			1,101,590
Cash flow from investing activities
Purchases of property, plant and equipment		(19,100	)		(303,924	)		(973,966	)		(4,713,254	)
Sale of construction materials		20,252			-			-			-
Total cash used by investing activities		1,152			(303,924	)		(973,966	)		(4,713,254	)
Cash flow from financing activities
Capital distributions to member U.S. Geothermal Inc.		(612,363	)		(448,934	)		-			-
Capital distributions to member Raft River Holdings, LLC		(237,442	)		(199,684	)		-			(27,000	)
Noncash operating distributions to member Raft River Holdings, LLC		26,500			25,000			-			27,000
Capital contributions from member U.S. Geothermal Inc.		-			-			-			4,714,926
Total cash provided by financing activities		(823,305	)		(623,618	)		-			4,714,926
Increase (decrease) in cash and cash equivalents		80,038			(697,838	)		(397,321	)		1,103,262
Cash and cash equivalents at the Beginning of period		175,688			873,526			1,270,847			167,585
Cash and cash equivalents at the End of period	$	255,726		$	175,688		$	873,526		$	1,270,847
Schedule of noncash transactions
Equipment contributed by member U.S. Geothermal Inc.	$	-		$	-		$	-		$	300,000
Other Items
Accounts payable for capital expenditures		-			-			111,194			1,056,345
* - See change in fiscal year end, Note 9

The accompanying notes are an integral part of these financial statements.

4

Raft River Energy I LLC

Statement of Members' Equity

Years Ended December 31, 2010 and 2009

		Class A Units -			Class B Units -
		Raft River			U.S. Geothermal
		Holdings			Inc.			Totals
Balances at November 30, 2007	$	33,360,043		$	12,677,228		$	46,037,271
Capital contributions		-			5,014,926			5,014,926
Distributions		(27,000	)		-			(27,000	)
Net loss		(292,533	)		(156,060	)		(448,593	)
Balances at November 28, 2008		33,040,510			17,536,094			50,576,604
Net income		298,247			54,713			352,960
Balances at December 26, 2008*		33,338,757			17,590,807			50,929,564
Correction of error (Note 8)		(797,429	)		797,429			-
Distributions		(199,684	)		(448,933	)		(648,617	)
Net income (loss)		(2,549,790	)		279,072			(2,270,718	)
Balances at December 31, 2009*		29,791,854			18,218,375			48,010,229
Distributions		(237,442	)		(612,363	)		(849,805	)
Net income (loss)		(1,122,449	)		375,053			(747,396	)
Balances at December 31, 2010	$	28,431,963		$	17,981,065		$	46,413,028

* - See change in fiscal year end, Note 9

The accompanying notes are an integral part of these financial statements.

5

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

1.	Organization and Description of Business
	Raft River Energy I LLC (the "Company") is a limited liability company organized in the State of Delaware by U.S. Geothermal Inc. on August 18, 2005, for the purpose of constructing and operating a geothermal power plant located near Malta, Idaho. The Company's power plant is considered to be phase I of a Raft River, Idaho geothermal project expected to consist of three phases. As defined in the Membership Admission agreement, the Company is owned by U.S. Geothermal Inc. and Raft River I Holdings LLC, which is a Delaware limited liability company that is a subsidiary of The Goldman Sachs Group Inc. (collectively referred to as "the members"). As defined in the Management Services Agreements, U.S. Geothermal Services LLC, (a wholly owned subsidiary of U.S. Geothermal Inc.) is the Company's Operator.
2.	Summary of Significant Accounting Policies
	Accounting Method
	The Company's financial statements are prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America ("GAAP") which have been consistently applied.
	Accounts Receivable and Allowance for Doubtful Accounts
	Accounts receivable are stated at their estimated net realizable value. The Company has considered the economic conditions, historical trends, contractual terms and financial stability of its major customer when calculating an allowance for uncollectible accounts. At each fiscal year end, management determined that all accounts receivable were collectible and an accrual for an allowance for doubtful accounts was not necessary. Uncollectible accounts are removed when they are deemed uncollectible. Recovered bad debts are recorded as income in the period collected.
	Allocation of Profits and Losses
	The Company utilizes the hypothetical liquidation at book value method ("HLBV") for allocating profits and losses. This method utilizes the specific terms outlined in the entity's organizational contracts and other authoritative documents. These terms include cash disbursement terms, associated financial instruments, debt arrangements, and rights to specific revenue streams.
	According to the operating agreement, upon liquidation and after payment of all outstanding debts, remaining funds will be distributed to the Members based on to their respective positive capital account balance ratios. Certain contract provisions contain allocation of profit and loss items to arrive at the capital account balances. See Note 8.
	Cash and Cash Equivalents
	Cash and cash equivalents consist of cash deposits and short term instruments with original maturities of no more than ninety days.
	Concentration of Risk
	The Company's cash and cash equivalents consisted of commercial bank deposits and a money market account.All cash equivalents are held in a commercial bank located in Boise, Idaho. Deposits held in the checking account are subject to Federal Deposit Insurance Corporation (FDIC) up to $250,000 (level extended through December 31, 2013). The Company's cash deposits, at December 31, 2010, totaled $323,674 ($73,674 exceeded FDIC coverage limits).

6

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

Contributed Capital and Membership Structure

Agreements between U.S. Geothermal Inc. and Raft River Holdings LLC were completed for construction financing of Phase I of the Raft River project. To accommodate the construction financing, U.S. Geothermal, Inc. sold 50% of its ownership in the Company to Raft River Holdings in August 2006, with U.S. Geothermal Inc. owning 500 Class B member units and Raft River Holdings owning 500 Class A member units.

As of December 31, 2010, U.S. Geothermal Inc. has contributed $17,953,640 ($16,892,344, net of distributions of $1,061,296) in cash and property to the project, while Raft River I Holdings LLC has contributed $34,170,100 ($33,705,975, net of distributions of $464,125) in cash. Profits and losses have been allocated according to the HLBV method.

Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities known to exist as of the date the financial statements are published, and the reported amounts of revenues and expenses during the reporting period. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of the Company's financial statements; accordingly, it is possible that the actual results could differ from these estimates and assumptions and could have a material effect on the reported amounts of the Company's financial position and results of operations.

Financial Instruments

The Company's financial instruments consist of cash and cash equivalents, accounts receivable, accounts receivable-related party, accounts payable and accrued liabilities. Unless otherwise noted, it is management's opinion that the Company is not exposed to significant interest currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted.

Impairment of Long-Lived Assets

The Company evaluates long-lived assets for impairment in accordance with Accounting Standards Codification (ASC) No. 360, Property, Plant, & Equipment. Accordingly, the Company evaluates its long-term assets annually for impairment, or when circumstances or events occur that may impact the fair value of the assets. Management believes that there have not been any circumstances that have warranted the recognition of losses due to the impairment of long-lived assets as of December 31, 2010 and December 31, 2009.

Inventory

Inventory consists of supplies and replacement parts needed to maintain the power plant and are not intended for resale. Upon purchase, items are recorded at cost and maintained at the lesser of cost or fair market value. Inventory items are charged to operations in the period they are utilized.

Lease Arrangements

Arrangements which potentially convey the right to use property, plant, or equipment for a stated period of time are analyzed in accordance with financial reporting pronouncements that address determining whether an arrangement contains a lease to assess whether they should be accounted for as leases. For any arrangements that are found to meet the definition of a lease, an assessment is made as to whether they are capital leases or operating leases in accordance with accounting standards.

7

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

Property, Plant and Equipment

Costs of acquisition of geothermal properties are capitalized on a geothermal reservoir basis. If a geothermal reservoir is abandoned, the costs thereof are charged to income in the year of abandonment. Property, plant and equipment are recorded at historical cost. Depreciation is calculated on a straight-line basis over the estimated useful life of the asset. Major improvements that significantly increase the useful lives and/or the capabilities of the assets are capitalized. Expenditures for repairs and maintenance are charged to expense as incurred.

Estimated useful lives by asset categories are summarized as follows:

	Estimated Useful
Asset Categories	Lives in Years
Furniture, vehicle and other equipment	4 years
Power plant, buildings and improvements	15–30 years
Wells	30 years
Well pumps and components	5–15 years
Pipelines	30 years
Transmission lines	30 years

Revenue

Revenue Recognition

Energy Sales

The Company's primary operating revenue originates from electrical power generated by the Company's geothermal power plant. The revenue is recognized when the power is produced and delivered to the customer who is reasonably assured to be able to pay under the terms defined in the Power Purchase Agreement ("PPA").

Renewable Energy Credits

Revenues from Renewable Energy Credits ("RECs") are recognized when the Company has met the terms of certain energy sales agreements with a financially capable buyer and has met the applicable governing regulations. The Company earns one REC for each megawatt hour produced from the geothermal power plant. Each REC is certified by Western Electricity Coordinating Council Council ("WREGIS") and sold under a REC Purchase and Sales Agreement.

Revenue Source

All of the Company's energy sales are received from one major power company that, primarily, operates in the State of Idaho. All of the power generated originates from the one power plant that utilizes a geothermal reservoir located in southeastern Idaho. Approximately 92% of the accounts receivable balance at December 31, 2010, represented a balance due from one major customer.

8

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

3.	Property, Plant And Equipment
	Property, plant and equipment, at cost, are detailed as follows:

		December 31,			December 31,
		2010			2009
Furniture and equipment	$	73,431		$	73,431
Power plant, buildings and improvements		26,703,390			26,684,290
Wells		15,339,317			15,339,317
Well pumps		2,719,361			2,719,361
Pipelines		5,555,598			5,555,598
Transmission lines		1,538,107			1,538,107
		51,929,204			51,910,104
Less: Accumulated depreciation		(5,990,117	)		(3,942,879	)
		45,939,087			47,967,225
Construction in progress		-			26,036
	$	45,939,087		$	47,993,261

	At December 31, 2009, construction in progress consisted of materials used for drilling activities. All of these materials were either sold, at cost, or put into operations during the year ended December 31, 2010. See Note 4.
4.	Related Party Transactions
	The amounts payable to U.S. Geothermal Inc. and U.S. Geothermal Services, LLC as of December 31, 2010 and December 31, 2009, were $224,530 and $572,832; respectively. The amounts payable are unsecured and due on demand.
	At December 31, 2009, the Company had a balance of $26,935 receivable from USG Oregon, LLC. The receivable resulted from a sale of construction materials at the original purchase price. The balance was paid in full in January 2010.
	During the year ended December 31, 2010, materials classified as construction in progress at December 31, 2009 for $20,252 were sold, at cost, to USG Oregon, LLC and USG Nevada, LLC.
	U.S. Geothermal Inc. is the managing member of the Company. U.S. Geothermal Services, LLC, USG Nevada, LLC and USG Oregon, LLC are wholly owned subsidiaries of U.S. Geothermal Inc.

9

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

The Company's related party transactions are summarized as follows:

		For the Year		For the Year		For the Month		For the Year
		Ended		Ended		Ended		Ended
		December 31,		December 31,		December 26,		November 28,
		2010		2009		2008		2008
Capital expenditures	$	-	$	-	$	-	$	87,510
Insurance		227,273		152,966		-		-
Office and administration		68,128		50,040		1,084		31,298
Travel and promotion		9,367		9,385		385		22,879
Management and professional fees		304,084		279,173		20,585		291,925
Plant and well field		873,499		2,440,351		34,523		1,000,351
Salaries and related costs		760,715		706,904		48,809		616,205
Lease, rent and royalties		111,360		92,050		10,140		163,219
Utilities		3,354		11,653		1,517		7,383
	$	2,357,780	$	3,742,522	$	117,043	$	2,220,770

Management Services Agreement

The Company has entered into a management services agreement with U.S. Geothermal Services, LLC ³management company´ effective August 9, 2006, to provide certain management and operating services. The contract terminates upon the earlier of mutual agreement of the contracting parties or on August 9, 2028. The quarterly management fee starts at $62,500, and in addition there are incentive payments linked to certain performance targets. If the Company does not have sufficient funds to pay the facility's necessary operating expenses in a particular month, the management fee shall be deferred with no interest penalty.

The actual management fee is subject to contracted adjustments based upon financial performance of the Company calculated on a semi-annual basis. In the event that actual results exceed expected results a bonus shall be earned. For the first $10,000, whereby the actual results exceed the expected results, the bonus shall equal 10% of the difference. If the difference between the actual results and the expected result is more than $10,000, the second component shall equal 50% of the excess over $10,000. The second component bonus amount shall not exceed $20,000. In the event that expected results exceed actual results the management fee shall be reduced. If the difference between the expected results and actual results is less than or equal to $175,000, then the management company shall pay the absolute value of the difference multiplied by 10%. If the difference between the expected results and actual results is in excess of $175,000, then the management company shall pay the Company the amount equal to absolute value of the difference in excess of $175,000.

10

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

The Company paid U.S. Geothermal Services, LLC management services for the fiscal periods as follows:

		Management
Fiscal Period		Fees
For the Year Ended November 28, 2008	$	227,708
For the Month Ended December 26, 2008		18,958
For the Year Ended December 31, 2009		253,333
For the Year Ended December 31, 2010		250,000

Well Field Lease Contract

On November 2, 2006, the Company signed a lease contract with a primary term of 20 years for the groundwater rights needed for cooling purposes at the Facility payable to U.S. Geothermal Inc. ("lessor"). The annual rate of $90,000 is based upon the facility's expected needs of 900 acre feet per annum ("a.f.a.") ($10,000 per 100 a.f.a.). Based upon the needs of the facility and proper notice given by the lessor, the contract allows for an increase in the amount of water available for lease according to the noted rate. The payments are due annually within ten business days following the anniversary of the "placed in service" date which is the date of the facility became commercially operational. During the fiscal year ended November 28, 2008, the Company paid the lessor the "initial rent payment" of $90,000 due for the period of time from the contract date to the to the initial placed in service date, as well as an additional $74,475 for current year lease costs. Lease costs of $90,000 were paid in the year ended December 31, 2010.

The schedule of estimated lease payments for the primary contract term is as follows:

For the Year Ended December 31,		Amounts
2011	$	90,000
2012		90,000
2013		90,000
2014		90,000
2015		90,000
Thereafter		990,000
Total	$	1,440,000

Geothermal Water and Land Lease

On October 19, 2006, the Company signed a lease contract with U.S. Geothermal Inc. ("lessor") that is effective as long as the Company is utilizing the resource. The contract provides the lessee exclusive geothermal water rights and nonexclusive land rights to 903 acres located in Raft River, Idaho. For the first 5 years ("primary term") the lease rate will be $5.00 per acre with an initial setup fee of $3,300. After the primary term, the lease will be based on a royalty of 10% of net proceeds. Net proceeds is defined as generated electric power, less deductions of the sum of direct operating costs, property taxes, franchise taxes, marketing expenses and depreciation. Depreciation will be calculated on a 15 year straight-line basis. During the year ended December 31, 2010, the Company paid lease costs of $4,515. As of December 31, 2010, the Company owed the lessor $16,845 in unpaid lease costs that was paid in full in January 2011.

11

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

5.	Commitments And Contingencies
	Operating Lease Agreements
	The Company has entered into several lease agreements with terms expiring up to December 1, 2033, for geothermal properties adjoining the Raft River Geothermal Property. The schedule of estimated annual lease payments is as follows:

For the Year Ended December 31,		Amounts*
2011	$	125,115
2012		120,936
2013		121,287
2014		121,357
2015		118,544
Thereafter		1,410,535
Total	$	2,017,774

* The schedule includes the expected annual related party well field, water and land lease payments described in Note 4.

The terms of the management services agreement, the well field lease contract, and the water and land lease contract are described in Note 4.

Power Purchase Agreement

The Company signed a 20 year power purchase agreement dated December 29, 2004 with Idaho Power Company for sale of power generated from its planned phase one power plant. It has been determined this meets the definition of a lease arrangement under current accounting pronouncements and is accounted for as an operating lease. As there is no minimum payment, lease income will be recognized as revenue when sales of power occur.

Power Transmission

The Company has 27 year interconnection and wheeling agreement with Raft River Rural Electric Cooperative, Inc. with a date of execution of March 9, 2006. The contract specifies a 15 year extension subject to the renewal of the right of way agreement with the Bureau of Land Management. The interconnection and wheeling agreement provides for the transmission of electricity from the plant to the Bonneville Power Administration ("BPA") substation. On June 24, 2005, the Company signed a 30 year transmission agreement with a start date of June 1, 2006, with BPA for transmission of electricity from the BPA substation to Idaho Power.

Renewable Energy Credits

The Company signed a 10 year contract on July 29, 2006, to sell renewable energy credits to Holy Cross Energy. After the Holy Cross Energy contract has expired, the Company will sell renewable energy credits to the Public Utility District of Clallam County, Washington, in accordance with a 17 year contract signed December 2010.

12

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

6.	Members' Interests
	The Company has issued two classes of member units, the Class A units and the Class B units. Each class of ownership gives the owner participating rights in the business and results in equity ownership risks. The rights attached to the different classes will vary over time, in accordance with the terms of the Membership Admission Agreement. The agreement requires the Company to track separately the capital accounts of the members after November 24, 2006. The profits and losses of the Company are allocated based upon the HLBV method as discussed in Note 2. For income tax purposes, the Class A units will receive a greater proportion of the share of losses and other income tax benefits. This includes the allocation of production tax credits, which will be distributed 99% to the Class A units and 1% to the class B units during the first 10 years of production.
	Under the terms of the Membership Admission Agreement, as of November 28, 2008, Raft River I Holdings LLC, has contributed their full obligation of $34.2 million in cash, and U.S. Geothermal Inc. has contributed $17.9 million in assets to the Company. U.S. Geothermal Inc.'s contribution consisted of $16.5 in cash and approximately $1.4 million in property. Based upon the Operating Agreement, loans made by Members to the Company shall not be considered capital contributions. Based upon the advances made to the Company by a Member shall be payable only out of the Company's property in accordance with the terms and the conditions upon which such advances are made.
7.	Income Tax
	The Company is a Limited Liability Corporation that is treated as a partnership for tax purposes with each of the Members accounting for their share of the tax attributes and liabilities. Accordingly, there are no deferred income tax amounts recorded in these financial statements.
8.	Error Correction
	After re-examining the provisions of the Membership Admission Agreement prior to the issuance of the financial statements for the year ended December 31, 2009, Management determined that the profit and loss allocation method applied in the prior periods was not consistent with generally accepted accounting principles. This change is considered to be a correction of an error. To fairly allocate profits and losses between the members, the Company adopted the HLBV method. The adjustments reallocate the member equity balances as if the profits and losses had been allocated with the HLBV method from the Company's inception to December 31, 2009. Net earnings/losses or total member's equity balances are not affected by the reallocation.
	We assessed the materiality of this error on financial statements for prior periods and concluded that the error was not material to any periods presented. Accordingly, the Balance Sheet and Statement of Members' Equity herein have been revised to correct for the cumulative amount of this error in the year ended December 31, 2009.

13

Raft River Energy I LLC

Notes to the Financial Statements

December 31, 2010 and 2009

9. Fiscal Year-End Change

Due to the changes imposed on Member A's parent company, the Company was required to change its fiscal year-end from November to December, beginning with fiscal 2009. This change in the Company's fiscal year-end resulted in a one-month transition period that began on November 29, 2008 and ended on December 26, 2008. Fiscal year 2009 began on December 27, 2008 and ended on December 31, 2009. Financial information for this fiscal transition period is included in these financial statements.

The following summarized financial information was presented to compare operating results for the transition period:

				(Unaudited)
		Month Ended		Month Ended
		December 26,		December 28,
		2008		2007
Operating revenues	$	537,831	$	233,257
Operating expenses		185,348		111,692
Gain (loss) from operations		352,483		121,565
Other income		477		1,768
Net income (loss)	$	352,960	$	123,333

14

EX-21.1

Exhibit 21.1

LIST OF SUBSIDIARIES

U.S. Geothermal Inc. (incorporated in the State of Idaho)

Gerlach Geothermal LLC (organized in the State of Delaware)

U.S. Geothermal Services, LLC (organized in the State of Delaware)

USG Nevada LLC (organized in the State of Delaware)

USG Gerlach LLC (organized in the State of Delaware)

USG Oregon LLC (organized in the State of Delaware)

Oregon USG Holdings, LLC (organized in the State of Delaware)

U.S. Geothermal Guatemala, S.A. (organized in Guatemala)

Raft River Energy I LLC (organized in the State of Delaware)

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements on Form S-3/A (333-170202), S-1 (333-165728), S-1/A (333-163384), and S-8 (333-141262 and 333-164394) of our audit reports dated June 7, 2011, with respect to the consolidated financial statements of U.S. Geothermal Inc. and the effectiveness of internal control over financial reporting of U.S. Geothermal, Inc. included in the Annual Report (Form 10-K) for the year ended March 31, 2011.

/s/ BehlerMick PS           
BehlerMick PS
Spokane, Washington
June 7, 2011

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-164394), Form S-8 (No. 333-141262), Form S-3 (No. 333-163384), Form S-3 (No. 333-165728) and Form S-3 (No. 333-170202) of U.S. Geothermal Inc. of our report dated March 15, 2011 relating to the financial statements of Raft River Energy I LLC, which appears in this Form 10-K of U.S. Geothermal Inc.

/s/ PricewaterhouseCoopers LLP        
PricewaterhouseCoopers LLP
Portland, Oregon
June 9, 2011

EX-23.3

Exhibit 23.3

EX-23.4

Exhibit 23.4

EX-23.5

Exhibit 23.5

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Daniel J. Kunz certify that:

1.	I have reviewed this Form 10-K of U.S. Geothermal, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a- 15(f) and 15d-(f)) for the registrant and have:

a.	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c.	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: June 9, 2011

/s/ Daniel J. Kunz                                
Daniel J. Kunz
Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Kerry D. Hawkley certify that:

1.	I have reviewed this Form 10-K of U.S. Geothermal, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a- 15(f) and 15d-(f)) for the registrant and have:

a.	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c.	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: June 9, 2011

/s/ Kerry D. Hawkley                          
Kerry D. Hawkley
Chief Financial Officer

EX-32.1

Exhibit 32.1

U.S.GEOTHERMAL INC. AND SUBSIDIARIES

CERTIFICATIONS

In connection with the report of U.S. Geothermal Inc. on Form 10-K for the fiscal year ended March 31, 2011 as filed with the Securities and Exchange Commission (‘the Report”), I, Daniel J. Kunz, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the business issuer.

Date: June 9, 2011

/s/ Daniel J. Kunz                           
Daniel J. Kunz
Chief Executive Officer

EX-32.2

Exhibit 32.2

U.S. GEOTHERMAL INC. AND SUBSIDIARIES

CERTIFICATIONS

In connection with the report of U.S. Geothermal Inc. on Form 10-K for the fiscal year ended March 31, 2011 as filed with the Securities and Exchange Commission (‘the Report”), I, Kerry D. Hawkley, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the business issuer.

Date: June 9, 2011

/s/ Kerry D. Hawkley                         
Kerry D. Hawkley
Chief Financial Officer