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UNITED STATES 
SECURITIES AND EXCHANGE COMMISSIONWashington, 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

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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.

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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  

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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  

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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 8megawatts 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 the3rd 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 2nd 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.

-13-

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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.

-14-

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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 3rd 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.

-15-

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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.

-16-

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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.

-17-

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|                     
|---------------------
|Projects in Operation
|Project              
|Raft River (Unit I)  
|San Emidio (Existing)

| | (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                                  
|San Emidio Phase I
      (8.6 MW Repower)
|San Emidio Phase II (Expansion)          
|San Emidio Phase III                     
|Neal Hot Springs I                       
|Neal Hot Springs II                      
|Raft River I (Repower)                   
|Raft River
      (Unit II)               
|Raft River (Unit III)                    

| | (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              
|Gerlach              
|Granite Creek        
|El Ceibillo          

-18-

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|Resource
      Details
|----------------------
|Property              
|Raft River            
|San Emidio            
|Neal Hot Springs      
|Gerlach               
|Granite Creek         
|El Ciebillo           

| | (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.

-19-

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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:

-20-

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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.

-21-

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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.

-22-

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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.

-23-

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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 berestricted 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 3rd 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 RateSan EmidioN63004
    9/30/2013
    1,280
    $
      1,280N63005
    9/30/2013
    1,279
    1,279N63006
    9/30/2013
    1,920
    1,920N63007
    9/30/2013
    1,920
    1,920N75233
    11/1/2011
    1,868
    3,738N75552
    11/1/2012
    2,560
    2,560N75553
    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 IssuerPurchases 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. EffectiveApril 14, 2008, thecommon 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                         
|First Quarter                                                  
|Second Quarter                                                 
|Third Quarter                                                  
|Fourth Quarter                                                 
|                                                               
|Fiscal Year
      Ended March 31, 2011                         
|First Quarter                                                  
|Second Quarter                                                 
|Third Quarter                                                  
|Fourth Quarter                                                 

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:

-52-

---

|Sales Prices on the TSX Exchange (CDN$)
|---------------------------------------
|                                       
|Fiscal Year
      Ended March 31, 2010 
|First Quarter                          
|Second Quarter                         
|Third Quarter                          
|Fourth Quarter                         
|                                       
|Fiscal Year
      Ended March 31, 2011 
|First Quarter                          
|Second Quarter                         
|Third Quarter                          
|Fourth Quarter                         

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
    
    
    2007Operating Revenues
    $
    3,253,545
    
    $
    2,579,152
    
    $
    2,336,202 $
    
    
    190,721
    
    $
    90,206Operating Expenses
    
    7,270,395
    
    
    8,562,345
    
    
    7,660,868
    
    
    4,568,871
    
    
    3,138,169Loss 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
    
    
    2007Total Assets
    $
    85,322,968
    
    $
    65,727,861
    
    $
    52,451,343
    
    $
    40,366,933
    
    $
    22,673,340Total 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.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

-53-

---

Loss per share from Continuing
      Operations
    
    
    Operating Revenues
    
    
    Gross Profit
    
    
    Loss from Operations
    
    
    Net Loss from Continued
      OperationsFiscal Year Ended March 31,
      20081stQuarter
    $
    (0.01
    )
    $
    0
    
    $
    0
    
    $
    (694,622
    )
    $
    (410,536
    )2ndQuarter
    
    (0.02
    )
    
    0
    
    
    0
    
    
    (1,374,285
    )
    
    (1,042,678
    )3rdQuarter
    
    (0.01
    )
    
    0
    
    
    0
    
    
    (1,103,192
    )
    
    (806,494
    )4thQuarter
    
    (0.02
    )
    
    190,721
    
    
    190,721
    
    
    (1,206,051
    )
    
    (1,054,765
    )Fiscal Year Ended March 31, 20091stQuarter
    
    (0.02
    )
    
    480,915
    
    
    480,915
    
    
    (1,774,518
    )
    
    (1,717,061
    )2ndQuarter
    
    (0.03
    )
    
    743,706
    
    
    743,706
    
    
    (1,406,431
    )
    
    (1,356,084
    )3rdQuarter
    
    (0.01
    )
    
    575,886
    
    
    575,886
    
    
    (899,643
    )
    
    (874,186
    )4thQuarter
    
    (0.02
    )
    
    535,695
    
    
    535,695
    
    
    (1,244,074
    )
    
    (1,240,423
    )Fiscal Year Ended March 31,
      20101stQuarter
    
    (0.04
    )
    
    335,736
    
    
    335,736
    
    
    (2,441,672
    )
    
    (2,411,566
    )2ndQuarter
    
    (0.02
    )
    
    734,622
    
    
    734,622
    
    
    (1,156,554
    )
    
    (1,122,525
    )3rdQuarter
    
    (0.02
    )
    
    731,315
    
    
    731,315
    
    
    (1,449,421
    )
    
    (1,394,009
    )4thQuarter
    
    (0.01
    )
    
    777,479
    
    
    777,479
    
    
    (935,546
    )
    
    (910,750
    )Fiscal Year Ended March 31, 20111stQuarter
    
    (0.02
    )
    
    752,247
    
    
    752,247
    
    
    (1,491,924
    )
    
    (1,474,560
    )2ndQuarter
    
    (0.01
    )
    
    838,688
    
    
    838,688
    
    
    (1,003,950
    )
    
    (966,691
    )3rdQuarter
    
    (0.01
    )
    
    852,515
    
    
    852,515
    
    
    (843,584
    )
    
    (825,194
    )4thQuarter
    
    (0.01
    )
    
    810,095
    
    
    810,095
    
    
    (677,392
    )
    
    (665,471
    )


Item 7. Managements Discussion and Analysis of Financial
Condition and Results ofOperations

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.

-54-

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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.

-55-

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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 3rd
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).

-56-

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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.

-57-

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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.

-58-

---

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 3rd 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.

-59-

---

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 DevelopmentEstimatedTarget
    Projected
    CapitalDevelopment
    Commercial
    Required
    AnticipatedProject
    Location
    Ownership
    (Megawatts)
    Operation Date
    ($million)
    Power PurchaserSan Emidio Phase I (8.6 MW
      Repower)
    Nevada
    100%
    5.0
    December 2011
    $32
    NV EnergySan Emidio Phase II (Expansion)
    Nevada
    100%
    8.6
    2nd Quarter 2013
    $50
    NV EnergySan Emidio Phase III
    Nevada
    100%
    17.2
    4thQuarter 2013
    $100
    TBDNeal Hot Springs I
    Oregon
    JV
    23
    3rd Quarter 2012
    $129
    Idaho PowerNeal Hot Springs II
    Oregon
    100%
    28
    TBD
    TBD
    TBDRaft River I (Repower)
    Idaho
    JV
    3
    TBD
    $8
    Idaho PowerRaft River (Unit II)
    Idaho
    100%
    26
    4thQuarter 2013
    $134
    Eugene Water
      and Electric BoardRaft River (Unit III)
    Idaho
    100%
    32
    2ndQuarter 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.

-60-

---

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 the3rd 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 2nd 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 - 25Cash 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
    
    
    97.8Energy credit
      sales
    
    79,569
    
    
    3.2
    
    
    51,695
    
    
    2.9
    
    
    32,437
    
    
    2.22,518,040
    
    
    100.0
    
    
    1,795,679
    
    
    100.0
    
    
    1,449,289
    
    
    100.00Operating expenses:General and
      administrative
    
    343,512
    
    
    13.6
    
    
    349,422
    
    
    19.5
    
    
    282,176
    
    
    19.5Salaries and related costs
    
    722,901
    
    
    28.7
    
    
    819,182
    
    
    45.6
    
    
    579,009
    
    
    40.0Operations:Repairs and maintenance
    
    117,759
    
    
    4.7
    
    
    596,516
    
    
    33.2
    
    
    200,106
    
    
    13.8Other
    
    359,598
    
    
    14.3
    
    
    210,838
    
    
    11.7
    
    
    308,867
    
    
    21.3Rent and lease
    
    27,154
    
    
    1.1
    
    
    78,683
    
    
    4.4
    
    
    45,442
    
    
    3.1Purchased
      utilities
    
    54,391
    
    
    2.2
    
    
    65,543
    
    
    3.7
    
    
    126,179
    
    
    8.7Depreciation and amortization
    
    1,134,993
    
    
    45.1
    
    
    822,365
    
    
    45.7
    
    
    723,498
    
    
    49.92,760,308
    
    
    109.7
    
    
    2,942,549
    
    
    163.8
    
    
    2,265,277
    
    
    156.3Net 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 RatesSeptember 1,
    
    High
    
    
    Low
    
    
    High
    
    
    Low2008-09
    
    0.1182
    
    
    0.0757
    
    
    0.1037
    
    
    0.06162009-10
    
    0.1418
    
    
    0.0963
    
    
    0.1274
    
    
    0.07892010-11
    
    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
    
    
    
    
    
    DepreciationKilowatt
    
    
    Energy
    
    
    per
    
    
    
    
    
    &Hours x
    
    
    Sales
    
    
    Kilowatt-
    
    
    Net Loss
    
    
    AmortizationQuarter Ended:
    
    1,000
    
    
    ($)
    
    
    Hour
      ($)
    
    
    ($)
    
    
    ($)September 30, 2008
    
    5,650
    
    
    529,383
    
    
    0.0937
    
    
    (185,838
    )
    
    195,046December 31, 2008
    
    4,097
    
    
    317,256
    
    
    0.0774
    
    
    (146,859
    )
    
    196,941March 31, 2009
    
    3,808
    
    
    296,577
    
    
    0.0779
    
    
    (267,114
    )
    
    201,711June 30, 2009
    
    2,851
    
    
    243,752
    
    
    0.0855
    
    
    (589,082
    )
    
    200,972September 30, 2009
    
    5,224
    
    
    540,841
    
    
    0.1035
    
    
    (46,118
    )
    
    207,066December 31, 2009
    
    4,689
    
    
    463,286
    
    
    0.0988
    
    
    (348,073
    )
    
    207,136March 31, 2010
    
    5,018
    
    
    496,104
    
    
    0.0989
    
    
    (163,597
    )
    
    207,191June 30, 2010
    
    5,449
    
    
    571,646
    
    
    0.1049
    
    
    (75,065
    )
    
    238,087September 30, 2010
    
    5,260
    
    
    636,256
    
    
    0.1210
    
    
    (405
    )
    
    298,948December 31, 2010
    
    5,938
    
    
    629,868
    
    
    0.1061
    
    
    (104,155
    )
    
    298,948March 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.

-65-

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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
    
    
    88.7Energy credit
      sales
    
    433,599
    
    
    10.2
    
    
    500,925
    
    
    10.9
    
    
    623,956
    
    
    11.34,270,877
    
    
    100.0
    
    
    4,612,627
    
    
    100.0
    
    
    5,515,003
    
    
    100.0Operating expenses:Operations
    
    3,278,306
    
    
    76.8
    
    
    4,837,123
    
    
    104.9
    
    
    3,666,551
    
    
    66.5Depreciation and amortization
    
    2,049,787
    
    
    48.0
    
    
    2,049,822
    
    
    44.4
    
    
    1,951,533
    
    
    35.45,328,093
    
    
    124.8
    
    
    6,886,945
    
    
    149.3
    
    
    5,618,084
    
    
    101.9Operating 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
    
    
    1.4Net 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     
|Financial
      Element                                                       |                               | $        
|                                                                              |                               |          
|Total Company salary and related, excluding
      San Emidio plant operations |                               | 2,128,257
|Salary and related costs capitalized for the following
      projects:        |                               |          
|USG Nevada LLC (San Emidio Phase I Project)                                   |                               | (409,397 
|USG Oregon LLC (Neal Hot Springs Project)                                     |                               | (591,804 
|Small projects                                                                |                               | (42,671  
|                                                                              |                               | 1,084,385

% - 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

-69-

---

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 yearsOperating Leases
    $
    448,355
    
    $
    167,167
    
    $
    145,238
    
    $
    114,004
    
    $
    21,946Capital Leases
    
    27,108
    
    
    12,736
    
    
    14,372
    
    
    0
    
    
    0Promissory Note
    
    230,000
    
    
    230,000
    
    
    0
    
    
    0
    
    
    0Construction Loan (1)
    
    11,651,861
    
    
    11,651,861
    
    
    0
    
    
    0
    
    
    0Convertible Loan (2)
    
    5,132,740
    
    
    5,132,740
    
    
    0
    
    
    0
    
    
    0Stock 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 FinancialDisclosure

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 andRelated 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
      InformationPlan 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 issuanceEquity compensation plans approved by
      security holders
    6,703,195
    $ 1.38
    6,011,098Equity compensation plans not approved by security holders
    Nil
    Nil
    NilTotal
    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
    
    DESCRIPTION3.1
    
    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, 201021.1
    
    Subsidiaries of the Registrant23.1
    
    Consent of BehlerMick PS23.2
    
    Consent of PricewaterhouseCoopers LLP23.3
    
    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 200231.2
    
    Certification of Chief
      Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of
      200232.1
    
    Certification of Chief Executive Officer
      Pursuant to Section 906 of the Sarbanes-Oxley Act of 200232.2
    
    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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