U.S. Geothermal Inc.: Form 10-K - Filed by newsfilecorp.com

[ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

[X] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
[X] Yes [ ] No

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

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of the end of the registrant’s most recent second quarter (taking into account the change in fiscal year end), based upon the closing sale price of the registrant’s common stock as reported by the NYSE MKT LLC on March 25, 2012, was $32,913,701

The number of shares outstanding of the registrant’s common stock as of March 25, 2013 was 101,516,764.

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:

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:

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,” “we” or “us” or words of similar import) is in the renewable “green” energy business. Through our 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.

On July 5, 2012, the Company’s Board of Directors changed the Company’s fiscal year end from March 31 to December 31, beginning December 31, 2012.

Geo-Idaho was formed as an Idaho corporation in February 2002 to conduct geothermal resource development. On March 5, 2002, Geo-Idaho entered into a letter agreement with the previous owner, pursuant to which Geo-Idaho agreed to acquire all of the real property, personal property and permits that comprised the owner’s interest in the Raft River project located in southeastern Idaho.

The Company and Geo-Idaho entered into a merger agreement on February 28, 2002, which was amended and restated on November 30, 2003, and closed on December 19, 2003. In accordance with the merger agreement, 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. We currently operate geothermal projects in Raft River, Idaho; San Emidio, Nevada and Neal Hot Springs, Oregon. We, also have property interests in the Republic of Guatemala, and Gerlach and Granite Creek, Nevada that are either under development or exploration.

The Company signed a 20 year power purchase agreement with Idaho Power on December 29, 2004 to purchase power from the phase I power plant at Raft River located near Malta Idaho. Raft River Energy I LLC (“RREI”) was created on August 18, 2005 for the purpose of developing Raft River unit I. The limited liability company is a joint venture with Raft River I Holdings, LLC, which is a subsidiary of Goldman Sachs. RREI commenced commercial operations on January 3, 2008. The plant operated at normal levels through January 2009, when one of the wells experienced a lap joint failure. In June 2010, a production well was shut down due to a pump failure. On May 17, 2011, a repair services agreement was signed between the two partners to finance the repair of the two underperforming wells. The repairs were substantially completed in January 2012. The plant performed at normal levels through the first quarter 2012. In the second quarter 2012, the plant experienced a pump failure that was corrected in June 2012. The plant has operated at normal levels for the last two quarters of the calendar year 2012.

In May 2008, we acquired the geothermal assets, including an old 3.6 net megawatt nameplate generating capacity power plant, from Empire Geothermal Power LLC and Michael B. Stewart, located in Washoe County, Nevada for approximately $16.6 million which includes the Granite Creek geothermal and certain ground water rights. We secured financing from the general contractor for construction of a new power plant in August 2010. The plant was originally scheduled to be completed by November 2011; however, many issues delayed the plant from becoming operational as scheduled. The plant became commercially operational on May 25, 2012. The plant was originally estimated to operate at 8.6 net megawatts, and has been operating at an average of 9.42 and 9.65 megawatts for the months of November and December 2012; respectively. Work continues on finalizing a long term loan which is expected to close in the second quarter of 2013. The Company is evaluating the economic viability of second and third phases of development. The second phase is a planned 8.6 net megawatt module similar to the first phase unit. The third phase is planned as a further expansion for 17.2 megawatt net utilizing two additional power modules similar to the first and second phases.

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 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 the 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 its major production well, which was substantially completed on October 15, 2009. In December 2009, USG Oregon LLC signed a 25-year power purchase agreement with Idaho Power Company that provides for the sale of up to 25 megawatts. The PPA was approved by the Idaho PUC in May 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 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. Enbridge Inc. became an equity partner in April 2009. As of December 31, 2012, Enbridge has contributed approximately $13.5 million to the partnership. Enbridge’s equity interest has not been determined; however, the Company estimates it will be between 30% and 40%. The project is expected to be fully financed with the partners’ contributions and the DOE loan proceeds. In October 2011, USG Oregon LLC began drawing on the DOE loan. During the calendar year ended December 31, 2012, the Company completed drilling several wells for the project and substantial progress was made on construction of the power plant modules, cooling towers, support buildings and other critical components. The power plant became commercially operational on November 16, 2012.

In April 2010, the Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America. The Company signed a Memorandum of Understanding with a broker of electricity in Central America to negotiate a power purchase agreement for the El Ceibillo Project located near Guatemala City in October 2012. The framework of the agreement outlines a 15 year term to deliver up to 50 megawatts of power at competitive prevailing energy prices in the region. Geophysics and drilling activities are planned for 2013. A 25 megawatt flash steam plant is targeted to be in operation in the fourth quarter of 2015.

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.

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:

A summary of projects under development and additional properties is as follows:

Neal Hot Springs, Oregon
Neal Hot Springs is located in Eastern Oregon near the town of Vale, the county seat of Malheur County. A commercial geothermal resource has been defined at the site, and a 22 net megawatt power plant, consisting of three separate, 7.33 net megawatt modules, has been constructed and has undergone commissioning. The facility achieved commercial operation under the terms of the power purchase agreement on November 16, 2012. Generation from the facility during the fourth quarter of 2012 totaled 18,087 megawatt-hours. During commissioning, when all three modules were in operation under winter conditions, the facility achieved net output of 29.8 megawatts.

In order to finance the Neal Hot Springs project the Company applied 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 67% of the total project cost of $143.6 million. The DOE loan is a combined construction and 22 year term loan. The annual 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 as determined on each date that a draw is made on the loan and is estimated to be 2.616% (actual 2.396% to 2.997%) as an aggregate rate of the individual draws that occurred through December 31, 2012.

Over the course of the ongoing construction, the budget was increased by $14.6 million in equity contributions by the partners. The first increase of $7.0 million was to cover additional drilling costs and modifications in plant controls and the cooling mechanism. Enbridge Inc., our partner at Neal Hot Springs, provided the additional investment in exchange for increased ownership interest in the project from 20% to a percentage to be calculated based on an agreed upon financial model. A second budget increase of $6 million, also provided by Enbridge Inc., was to establish a contingency fund for potential additional drilling program to complete the well field. Each of the additional investments made by Enbridge Inc. will be subject to calculations that will result in increased ownership interest in the project. Current estimates show that Enbridge could own between 30% and 40% of the project depending on ITC and BETC cash grant sharing.

$281,000 of the $6.0 million contingency fund was used and the balance may be returned to Enbridge thereby adjusting the final Enbridge ownership. The project now has 100% of the required production and injection capacity drilled and proven. Enbridge and the Company expect to finalize the ownership percentages during the second calendar quarter 2013.

As of December 31, 2012, ten draws totaling $74.4 million have been made upon the DOE loan, which has annual interest rates between 2.396% and 2.997% . The project qualified for, and expects to receive an estimated $35.4 million cash grant under Section 1603 Specified Energy Property in Lieu of Tax Credits, subject to an 8.7% reduction due to federal sequestration. Subject to certain DOE loan covenants, the planned use of the grant proceeds is to: 1) fund certain cash reserves at the project level, 2) pay down approximately $13.5 million on the DOE loan and 3) use the balance to reimburse equity investors.

In July 2010, the Company applied to the Oregon Department of Energy (“ODOE”) for the Business Energy Tax Credit (“BETC”), which allows an income tax credit for up to $20 million in qualifying capital expenditures for a renewable energy project. On December 31, 2012, ODOE issued a Final Certificate Conditional for the Neal Hot Springs project BETC which can be sold to a pass-through tax partner and monetized at a cash value of $7.36 million. The final certificate was issued on March 1, 2013. It is anticipated that the BETC cash may be available within the first six months of 2013.

After a long term flow test of the reservoir was completed in January 2011, a computerized numerical reservoir model was constructed on March 24, 2011 by the Company’s consulting reservoir engineer, and after review, the DOE’s independent reservoir engineer issued a reservoir certificate on March 31, 2011. The final reservoir report and certificate confirmed that the reservoir is able to sustain the production necessary for the completed 22 megawatt project from the existing four production wells. Subsequent to the end of the fourth quarter of 2012, a colorimetric tracer test program was initiated with separate tracers introduced on January 10, 2013 into the three largest injection wells to help map the flow of geothermal fluid through the reservoir. Sampling of the four production wells for the tracers is planned to extend for 30-45 days, and then data from the test will be incorporated into the numerical reservoir model and an updated forecast will be completed.

Four production wells (NHS-1, NHS-2, NHS-5, and NHS-8) are providing up to 12,000 gpm of geothermal fluid to the power plant at an average inlet temperature of 287°F. Four large diameter injection wells (NHS-3, NHS-4, NHS-11, and NHS-13) and two slim-hole injection wells (NHS-10, and NHS-6,) are in use for injection of the cooled fluid exiting the power plant.

The new plant was designed and constructed by Industrial Builders Inc. pursuant to the Engineering-Procurement-Construction Agreement (“EPC”) and by TAS Energy pursuant to the Equipment Supply Agreement (“ESA”) contractor (TAS Energy). The new plant, which consists of three separate, air cooled power modules, is designed to deliver approximately 22 megawatts of power net to the grid on an annual average basis. As of December 31, 2012, construction of the total project under the EPC agreement was complete and commissioning under the terms of the ESA was underway.

On May 27, 2012, the Company was notified by the EPC contractor that mechanical completion was achieved on the first of the three units. On June 28, 2012, the construction contractor provided notice of mechanical completion for the second of the three modules and on July 31, 2012 notice of mechanical completion was received for the third 7.3 net megawatt, air cooled power plant module. All three units have undergone commissioning and tuning operations during the quarter and have operated continuously under commercial operation. Additionally, all three modules received upgraded bearings in the turbine gearbox, swirl brakes have been installed behind each of the three module’s turbine wheels, and each module’s silencers have been replaced. These modifications were first identified at the Company’s San Emidio project and implemented at Neal Hot Springs to address unwanted vibration.

The Company received a Conditional Use Permit from the Malheur County Planning Commission for construction of the 22 net megawatt power plant on October 28, 2009 after unanimous approval from the Planning Commission at a September 24, 2009 meeting. All of the Federal Energy Regulatory Commission (“FERC”) mandated transmission studies were completed by the Idaho Power Company. An interconnection agreement was signed with the Idaho Power Company in February 2009. Idaho Power completed the transmission line and substation during the second quarter of 2012.

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 average price for the year 2012 of $96.00 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. Test energy delivered prior to declaration of commercial operation is paid for at 90% of the monthly average, non-firm, Dow Jones Mid-Columbia Index. Since achieving commercial operation on November 16, 2012, the starting contract price of $96.00 per megawatt-hour was paid for power delivery during the remainder of 2012, and escalated to an average price of $99.00 for 2013 power generation.

San Emidio, Nevada
The new Phase I power plant at San Emidio achieved commercial operation on May 25, 2012. During the quarter ended December 31, 2012, the plant achieved 80.9% availability and generated an average of 9.0 net megawatts per hour. Power production totaled 16,191 megawatt-hours for the quarter. The Phase I plant completed its capacity testing during the quarter, and as a result of the capacity test exceeding the design output, the plant was up rated to 9.0 net annual average megawatts per hour from the design point basis of 8.6 megawatts.

Further expansion of the San Emidio resource is planned to take place in two additional phases. Phase II is a planned expansion within the bounds of the existing San Emidio geothermal reservoir and is subject to the successful development of additional production wells through exploration and drilling activities. Phase III is planned for 17.2 MW net utilizing two additional power modules similar to Phases I and II.

On November 9, 2011, the Company’s wholly owned subsidiary, USG Nevada LLC, entered into a bridge loan agreement with Ares Capital Corporation. The bridge loan monetized the Section 1603 ITC cash grant associated with the new Phase I power plant at San Emidio. The loan agreement provided for borrowing of up to 90% of the total expected cash grant and consisted of an initial funding of $7.5 million. The funds were drawn from a loan facility that included commercial terms for the payment of interest and associated fees. An application for an $11.65 million ITC cash grant was submitted to the United States Department of the Treasury on July 17, 2012, and on November 14, 2012 the Treasury issued $10.65 million of the requested ITC cash grant amount. $7.78 million was paid to Ares Capital to satisfy the bridge loan facility, with the remaining $2.87 million paid to USG Nevada LLC. In March 2013, the remaining cash grant balance of $1.05 million, for items included in the original submission, was received from the Treasury.

The Phase I repower began construction in the third calendar quarter of 2010 and was delayed in the startup due to EPC contractor’s delay in completing Unit I and certain technical issues related to the new plant. The Phase II expansion is delayed due to the extended time it has taken to get Phase I online, and we are not able to accurately determine when Phase II will be completed at this time. Due to the EPC contractor’s delay in completing the Unit I repower plant and the impact the delay has on future Phases, the Company expects to utilize the ITC cash grant in lieu of the Production Tax Credit only in connection with the Phase I repower. The Phase II expansion is still dependent on successful development of additional production well capacity.

The total capital cost of the Phase I repower was $29.5 million, with Phase II estimated at approximately $50 million and Phase III approximately $100 million. We expect that approximately 75% of the Phase II and Phase III development may be funded by project loans, with the remainder funded through equity financing.

Phase I achieved mechanical completion in December 2011, and following performance testing of the power plant, which began in early May 2012, achieved commercial operation on May 25, 2012. Commissioning was extended due to a series of mechanical issues related to the use of an innovative configuration of proven technology that include defective capacitors, the mechanical failure of the 2,500 horsepower process pump, excessive vibration in the turbine gear box, and failure of the silencer. The EPC contractor provided its services under a fixed price contract that included financial guarantees for the original completion date and power output of the plant. Discussions with the EPC contractor are complete and Substantial Completion under the EPC contract was achieved February 21, 2013. A final settlement agreement was executed as part of the Substantial Completion and included a fixed total construction loan payable to the EPC Contractor of $29.5 million.

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, SAIC Energy, Environment & Infrastructure LLC, constructed the 9.0 net megawatt power plant. TAS Energy of Houston, Texas supplied a modular power plant to the project. The contractor provided a non-recourse project loan for $29.5 million. A long term permanent loan is currently under negotiation with a lender, and is expected to close in the second quarter of 2013. The Company expects to use the long term loan to repay the SAIC construction loan.

On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1% annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the amended and restated PPA. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011.

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 routes for transmission lines and the cost associated with each level of generation. The 15 megawatt study, which was directed at providing transmission for the Phase I and Phase II plants, 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.

An additional System Impact Study was initiated on September 8, 2011 for an additional 3.9 megawatts of transmission to increase the transmission capacity to match the maximum limit of the new PPA. The 3.9 megawatt System Impact Study was completed in April 2012. Both the 3.9 megawatt study and the 45 megawatt study have been withdrawn until future transmission needs are identified.

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 has applied 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. Two zones along the 4.5 mile long San Emidio fault structure were identified as high quality targets for drilling during the first phase of the DOE program, a South Zone and a North Zone. The first phase was completed in 2011.

The second stage of the DOE program is a 50-50 cost shared drilling plan that followed up on the South Zone targets identified in the first stage. In order to meet construction targets for Phase II plant construction, the drilling stage of the program commenced prior to DOE approval, and two observation wells were completed by the Company. The proposed drilling program was approved by the DOE in early November 2011. One of the first two wells was deepened and three additional wells have been completed in the South Zone under the 50-50 cost share grant.

Three of the five wells drilled in the South Zone exhibit commercial permeability and temperature. Well OW-10 produced a flowing temperature of 302°F, well OW-9 produced a flowing temperature of 280°F and well OW-6 produced a flowing temperature of 279°F. Well OW-9 also has a zone of high permeability at 1,830’ deep, which was put behind casing during drilling operations that has a measured static temperature of 294°F. Additional drilling operations would be required to test this zone. Well OW-8 encountered 320°F fluid, but did not produce commercial quantities during flow testing. The last well drilled, 45A-21 did not encounter commercial permeability, but recorded a temperature of 316°F, which extends the high temperature reservoir approximately one-half of a mile south of OW-10. The North Resource Area has an additional five observation/temperature gradient wells and one production well planned and will be the focus of the next round of drilling. No start date has been set.

Raft River, Idaho
During the quarter ended December 31, 2012, Raft River Unit I operated at 99.5% availability and generated an average of 9.73 net megawatts per hour. Power production totaled 21,386 megawatt-hours during the quarter. For the 2012 calendar year, the plant averaged 8.6 net megawatts of generation with 98.7% availability.

The plant operated at reduced output during the first half of the year due to a mechanical problem with the production pump in well RRG-2. RRG-2 was shut down on April 15, 2012, the pump was replaced in early June 2012, and it came back on line June 14, 2012 and has run through the end of the year without any further mechanical issues.

The funding for the DOE cost-shared, thermal fracturing program was increased from $10.2 million to $11.4 million by an additional $1.2 million contribution from the DOE. NEPA approval for the injection program was received, allowing the injection phase of the program to inject fluid that may induce thermal fracturing, and it is anticipated that injection may start during the second quarter of 2013. Two monitoring wells are planned, and must be completed prior to injection testing. If the program is successful, and permeability is improved to a commercial level, well RRG-9 may be utilized as a production or injection well for the existing Raft River power plant.

The Company’s contributions are made in-kind by the use of the RRG-9 well, well field data and monitoring support totaling $816,877. Eight solar powered seismic stations were installed in June 2010 to provide a base line of seismic data and will be used to monitor potential impacts from the test. Construction is complete on the injection pipeline that extends from the Unit I power plant to well RRG-9. A detailed, 3-D magnetotelluric survey was completed during the fourth quarter of 2010.

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 2010. The concession contains 24,710 acres (100 square kilometers) in the center of the Aqua and Pacaya twin volcano complex. An office and staff are located in Guatemala City and a 17.2 acre plant site has been leased on land adjacent to the existing wells. Discussions are taking place with several interested parties for the potential sale of an equity interest in the El Ceibillo project. El Ceibillo, the first development target on the concession, is located near the town of Amatitlan, in a developed industrial zone immediately adjacent to the highway that connects Guatemala City to the Port of San Jose on the Pacific coast.

An initial development of a 25 megawatt, flash steam power plant is planned in the El Ceibillo area of the concession, but the final size of the facility will be determined after drilling and resource delineation has advanced. Initial transmission studies have been completed, and identified the grid interconnection point approximately 1.2 miles (2 kilometers) from the site.

A binding Memorandum of Understanding (“MOU”) was signed on October 18, 2012 with one of the largest power brokers in Central America. The MOU establishes the framework for a PPA that includes a 15-year term for an initially estimated 25 megawatts of power generation up to a maximum of 50 megawatts of power generation. The MOU includes a project power price that the Company believes is competitive with the prevailing energy prices in the region. Several conditions precedent must be met before the PPA is negotiated and becomes effective, including confirming the geothermal reservoir by an independent reservoir engineer, obtaining all required permits and authorizations, and securing a project finance commitment.

The MOU may be terminated (i) as a result of the bankruptcy of any of the parties, (ii) on January 1, 2015, unless such date is extended by mutual agreement, because the construction of the project has not been initiated and/or the commercial operation date has been moved beyond the date set out in the PPA framework, or (iii) if the geothermal resource found lacks the conditions to sustain a long-term commercial production that allows electric power to be produced under the necessary conditions of profitability.

On December 28, 2012 an environmental report titled “Construction and Operation of the Geothermal Electric Plant, El Ceibillo” was submitted to the Ministry of Environment and Natural Resources. This report is an EIS level review of the potential impacts from development of a 25 megawatt power plant and satisfied a requirement of the contract that granted the concession. A public review period concluded on January 29, 2013 without any comments received and it is now under formal review by the Ministry.

The El Ceibillo geothermal project area has nine existing geothermal wells that were drilled in the 1990s 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.

Subsequent to the end of the fourth quarter of 2012, preparations for the commencement of site work started with the construction of a temporary office and fencing on the plant site. Two geophysical surveys, a VES survey and a gravity survey, have been contracted and are expected to be complete by the end of March 2013. A plan and budget for an exploration slim hole of up to 1,000 meters deep has been developed. Results from the geophysical surveys will be used to select a location for the well to target the potential production zone.

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 feet total depth. Temperature surveys and a short clean out flow test were conducted on the well. The well flowed at an estimated 300-400 gallons per minute and the flowing temperature was 208°F. Geochemistry indicates an average potential source temperature of 374°F for the Gerlach site.

Drilling commenced on observation well 18-10a on October 30, 2011. The upper section of the well was drilled to 826 feet deep and an 8 inch liner was cemented in place. The well was secured and the drill rig was moved back to San Emidio. Temperature measurements in the well have provided the highest measured temperature in the field to date at 268°F within 160’ of surface and a temperature gradient of 6.4°F per 100’ in the bottom section of the hole. There are two previously identified lost circulation targets at 1,600’ and 2,800’ deep that will be targeted when drilling is resumed.

Drilling resumed on well 18-10a on April 14, 2012 and was stopped on April 18, 2012 at 1,943 feet deep. Circulation was lost in minor zones at 1,530 and 1,595 feet deep. Subsequent temperature surveys indicate an isothermal temperature profile at 241°F which may indicate that higher temperature fluid does not occur below the 18-10a well site.

A plan and budget for 2013 has been developed to deepen well 18-10a to intersect the lost circulation zone at 2,800 feet deep to provide temperature information on the deep structure. Further work is dependent upon additional funding from the partners.

Granite Creek, Nevada
The Granite Creek assets are 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.

After a detailed review of the geologic setting, the lease position at Granite Creek was reduced to 2,443.7 acres (3.8 square miles). One full lease and portions of the two remaining leases were relinquished to the Bureau of Land Management.

At December 31, 2012, the Company had 45 full-time and 2 part time employees (14 administrative and project development, and 33 field and plant operations). The Company continuously considers acquisition opportunities, and if the Company is successful in making acquisitions, additional management and administrative staff may be added.

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

The principal product is based upon activities related to the production of electrical power from the utilization of the Company’s geothermal resources. The primary product will be the direct sale of power generated by our interests in our geothermal power plants. Currently, our principal revenues consist of energy sales, 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.

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

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

The reservoir located in Raft River, Idaho is a proven geothermal resource, and has a 13 net megawatt annual average capacity geothermal power plant in operation (Raft River Energy I LLC). San Emidio, Nevada is a proven geothermal resource, and has a new 9.0 net megawatt geothermal plant in operation. Neal Hot Springs, Oregon has a new 22 net megawatt annual average geothermal power plant that became operational in November 2012. Based upon the tests of the completed wells and the initial operations, 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.

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

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

Neal Hot Springs. The Neal Hot Springs project has received all necessary permits for power plant operations. The four primary permits govern the operations at the Neal Hot Springs geothermal plant include:

The Company has been producing energy revenues under the terms of three PPAs. These contracts specify favorable rate periods and levels of production. The USG Nevada LLC (San Emidio, Nevada) plant’s contractual terms provide for premium rates in the months from September to April. The Raft River Energy I LLC (Raft River, Idaho) and USG Oregon LLC (Neal Hot Springs, Oregon) contracts pay higher 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.

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.

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 and energy credits from three sources. Idaho Power Company purchases energy generated by both Raft River Energy I LLC and USG Oregon LLC. NV Energy purchases energy from USG Nevada LLC. Energy credits earned by Raft River plant are sold to Holy Cross Energy. Under the current PPAs, energy credits that are earned by USG Oregon LLC and USG Nevada LLC plants are bundled with energy sales. Even at planned levels of operation, it is expected that the Company and its interests will have a small number of direct customers that may amount to less than 4 or 5 over the next 5 to 10 years.

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 require 33% renewable and Nevada require 20% renewable. According to the Department of Energy’s Energy Efficiency and Renewable Energy department, utilities in 34 states nationwide are providing their customers with the opportunity to purchase green, renewable power through premium pricing programs. As a result, we believe green power is an important sub-market in the broader electric market, in which many power purchasers are increasing or committing to increase their investments. Accordingly, the conventional energy producers do not provide direct competition.

In the Pacific Northwest there are currently only two geothermal facilities. 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:

Raft River Project
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.

The Company’s most significant environmental compliance investment is associated with water quality monitoring. The Company has added five years of monthly, quarterly and annual water monitoring data to an already substantial volume of historical data that was developed by the US Department of Energy. The IDWR and Idaho Department of Environmental Quality concur with the Company’s findings that there is no impact on water quality from the geothermal operation. The Company’s private lands must be managed on an ongoing basis to control weeds, manage riparian conditions of Raft River and maintain the irrigation and fencing infrastructure. In order to facilitate our land management obligations and minimize our labor and capital costs, the Company has leased the grazing rights and cropland rights to a local landowner.

In summary, the Raft River project is in compliance with all environmental permits and water quality monitoring requirements and remnant equipment from the original Department of Energy project continues to be cleaned up.

Neal Hot Springs
The Neal Hot Springs project is also well situated in an area with only two nearby residents. There are no unique plant or animal communities in the area and no unique cultural or environmental constraints.

Because Neal is an air-cooled plant, the Company’s only environmental reporting is a monthly production and injection report and an annual water quality summary. Both reports are sent to the Oregon Department of Environmental Quality and Oregon Department of Geology and Mineral Industries. Biannual water monitoring has been conducted since 2008 and will continue under our ODEQ permitted geothermal water injection program.

As a result of the Department of Energy’s Loan Guarantee an independent legal team has been reviewing all regulatory compliance requirements for the project.

Adjoining rangelands are privately and federally managed. As a result the Company has no rangeland or cropland management obligation. The Company is able to focus staff resources on the day to day power plant operations and management of the plant site.

The Neal project is in compliance with all environmental permits and water quality monitoring requirements and has received no formal or informal notices from any local, state, or federal agency. Post construction reclamation and site clean-up continues to improve the overall appearance of the project site.

San Emidio
The Company’s San Emidio project is located approximately 14 miles south of Gerlach Nevada and 63 air miles north northeast of the Reno airport. The project site includes the Company’s 9.0 megawatt water cooled power plant and 250,000 square feet of covered industrial warehouse and offices. The nearest residence is over four miles from the plant site.

The Company’s regulatory reporting requirements include quarterly and annual water and discharge reporting to the Department of Environmental Protection.

San Emidio is in compliance with all environmental and regulatory requirements and has received no formal or informal notices from any local, state, or federal agency.

Gerlach and Granite Ranch
No operations are being conducted on these two properties at this time. The Company is in compliance with all environmental and regulatory requirements and has received no formal or informal notices from any local, state, or federal agency. There are no monthly, quarterly, or annual reporting requirements associated with these projects.

The Company has interests in operational power plants in three locations in the Western region of the United States. The Raft River Energy I LLC power plant is located in the southeastern part of the State of Idaho. The Raft River unit became operational on January 3, 2008. The Company constructed a new power plant located in the northwestern part of the State of Nevada in the San Emidio Desert. The USG Nevada LLC (San Emidio) plant became commercially operational May 25, 2012. Three units owned by USG Oregon LLC were substantially completed in the fourth quarter of 2012. The units are located in the Eastern part of the State of Oregon near the Idaho border. The Oregon units became commercially operational November 16, 2012. A summary of total energy and energy credit sales by location is as follows:

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.

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

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

On December 11, 2009, the Company signed a 25 megawatt (maximum) contract with Idaho Power 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/megawatt hours for 25 years after the plant startup.

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.

The Company 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 (Nevada, Oregon, Idaho) 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 the Company with regard to siting, design and regulatory compliance.

For project development in Nevada, the Company is retaining similar consulting firms to supplement in-house staff.

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

As a “green” power producer, environmental-related credits, such as renewable energy credits or carbon credits, 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 the Company’s projects, these credits have been sold separately, or bundled with the electricity to provide an additional source of revenue.

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. Certain projects under construction before the end of 2013, 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 megawatt-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 megawatt-hour of electricity it produces. The electrical energy is fed into the electrical grid and the accompanying REC can either be delivered to the purchaser of the power (“bundled”) or can be sold on the open market providing the renewable energy producer with an additional source of income.

On July 29, 2006, the Company 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.

On December 10, 2010, a second REC contract was signed with Public Utility District No. 1 of Clallam County, Washington. The term of the agreement is from 2018 to 2034 and includes sales of an estimated 50,000 megawatt hours annually, representing the 49% ownership in RECs retained by RRU1 under the Idaho Power PPA.

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 sold to the utility.

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 (Nevada), Neal Hot Springs (Oregon), Gerlach (Nevada), 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.

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

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

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

We may not be able to manage our growth due to the continuation of operations of the Raft River, San Emidio and Neal Hot Springs power plants and construction and development activities in Guatemala and San Emidio II 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, Neal Hot Springs and San Emidio and other acquired properties into our operations, to hire additional personnel and to implement necessary enhancements to our management systems to respond to changes in our business. There can be no assurance that we will be successful in these efforts. Our inability to manage the increased scope of operations, to integrate acquired properties, to hire additional personnel or to enhance our management systems could have a material adverse effect on our results of operations.

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

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

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

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

The success of our business relies on retaining our key personnel. We are dependent upon the services of our Chief Executive Officer, Daniel J. Kunz, our Chief Financial Officer, Kerry D. Hawkley, our Treasurer and Executive Vice President, Jonathan Zurkoff, our President and Chief Operating Officer, Douglas J. Glaspey. 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. Legislation enacted as part of the stimulus funding has also provided an election to take a 30% ITC in lieu of the PTC and is 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. Recent legislation enacted as part of the “Fiscal Cliff” efforts resulted in the extension of the 30% ITC in lieu of the PTC with eligibility for projects that start construction in 2013. There is not a cash grant component to the ITC credit so there is a risk related to monetizing the credit. The loss of the PTC or ITC is a risk that could result in making future expansions at Raft River, San Emidio and at Neal Hot Springs uneconomic. New rules recently adopted by the Bureau of Land Management, as directed by the Energy Policy Act of 2005, require competitive auction of all geothermal leases on Federal lands. Competitive leasing is significantly increasing the cost of obtaining leases on Federal land, is adding to the capital costs needed to develop geothermal projects, is increasing the total electrical power prices needed to make a geothermal project viable and is making it more difficult to acquire additional adjacent lands for reservoir protection and exploration.

If Federal lands or any Federal involvement are included in any geothermal development, requirements of the National Environmental Policy Act ("NEPA") will be triggered. Most of the geothermal 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:

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, Neal Hot Springs 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 thermal fracturing and well drilling at 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.

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 at Raft River 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. Actual deliveries in the calendar years ended 2011 and 2012 fell within the 90-110% of forecasted deliveries, thus, a price adjustment was not incurred.

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.

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 (“SOX”) and the Securities and Exchange Commission (“the 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, as applicable, which are required under Section 404 of SOX. The Company has documented and tested its internal control procedures in order to satisfy the requirements of Section 404 of SOX. SOX requires an annual assessment by management of the effectiveness of the Company’s internal control over financial reporting, as well as an attestation report by the Company’s independent auditors on internal controls over financial reporting if the Company is no longer qualified as a “smaller reporting company” under applicable SEC rules. 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 SOX. Moreover, effective internal controls are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could drop significantly. Our failure to meet regulatory requirements and exchange listing standards may result in actions such as the delisting of our stock impacting our stock’s liquidity; SEC enforcement actions; and securities claims and litigation.

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

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

The price of our common stock is volatile, which may cause investment losses for our shareholders. The market for our common stock is highly volatile, having ranged in the last nine months ended December 31, 2012, from a low of CDN$0.29 to a high of CDN$0.50 on the TSX and from a low of $0.29 to a high of $0.51 on the NYSE MKT. The trading price of our common stock on the TSX and on the NYSE MKT 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 certificate of incorporation and under Delaware law could discourage a takeover that stockholders may consider favorable. Our certificate of incorporation contains 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 require advance notice of stockholder nominations and proposals at any annual or special meeting of stockholders and Board appointment of any director vacancies or newly created directorships, both of which may deter or delay a takeover attempt. Additionally, we are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any holder of 15% or more of our capital stock for a period of three years following the date on which the stockholder acquired such ownership percentage, unless, among other things, our Board of Directors has approved the transaction. This statute likewise may discourage, delay or prevent a change of control.

The Company has interests in three areas in the Western United States. The properties include the Raft River area located in southeastern Idaho, the Neal Hot Springs area located in eastern Oregon (near the Idaho/Oregon border), and three properties in northwestern Nevada. The properties in northwestern Nevada include San Emidio, Gerlach and Granite Creek. The Company has three commercial power plants. Raft River Unit I became commercially operational on January 3, 2008. The San Emidio plant was acquired in the Empire Acquisition in May 2008. The facility was replaced with a 9.0 megawatt power plant located on private land. San Emidio Phase 1 achieved commercial operation in early 2012. The Neal Hot Springs geothermal plant achieved commercial operation on November 16, 2012.

The Raft River project is in southeastern Idaho, approximately 55 miles southeast of Burley, the county seat of Cassia County. Burley has a population of about 11,000 and is the local agricultural and manufacturing center for the region, 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 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.

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

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

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

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

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

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

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

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

Although significant detail has been provided about each lease area, the economics of the project is based on the resource. All economic discussions, including future phases, are based at the project level rather than at the lease level.

The Crank lease, the Newbold lease, the Jensen Investments leases, the Bighorn Mortgage lease, the Doman lease, the Griffin lease and the Glover lease have royalties payable under the following terms:

All of the leases may be extended indefinitely as long as production is maintained from the lease either individually or as a geothermal unit. 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. 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.

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

The 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 are as follows:

The minimum amount that will be payable over the course of the lease is $81,256. The second Jensen Investments lease, with Jensen Investments, Inc., expires in 2013. Minimum lease payments are as follows:

The minimum amount that will be payable over the course of the lease is $1,224. The Jensen Investments leases are being renewed and consolidated to reflect the project needs and the term of the power purchase agreement.

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

The minimum amount that will be payable over the course of the lease is $319,614.

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:

The minimum amount that will be payable over the course of the lease is $17,500.

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

The minimum amount that will be payable over the course of the lease is $24,000.

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

The minimum amount that will be payable over the course of the lease is $10,800.

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

The minimum amount that will be payable over the course of the lease is $20,500.

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 the 2012 lease year. 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. The royalty rate is based upon 10% of the value of the resource at the well head. The amounts are calculated according to a formula established by Minerals Management Service (“MMS”).

Neal Hot Springs is a geothermal resource located in Eastern Oregon. The Company acquired the Neal Hot Springs geothermal energy and surface rights in September 2006. A new 22 net megawatt annual average geothermal power plant that became operational at Neal Hot Springs in November 2012.

USG Oregon LLC, has drilled four production wells (NHS-1, 2, 5, and 8) and nine injection wells (NHS-3, 4, 7, 9, 10, 11, 12, 13, 14) at the project.

Lease/Royalty Terms
Cyprus Gold Exploration Corporation. The lease for Cyprus’ 50% mineral ownership on 4,960 acres located in Malheur County, Oregon is dated January 24, 2007, has a primary term of 10 years, and expires January 24, 2017. Annual rental of $4,000 per year was paid through 2012 and is considered a pre-paid production royalty. The agreement defines a royalty rate based upon 2% of the actual revenue for the first 10 years of commercial production and 3% thereafter. As of January 2013 USG Oregon LLC began paying monthly royalties based on electricity delivery under our Idaho Power Purchase Agreement.

JR Land and Livestock. The lease for JR Land and Livestock’s 25% mineral ownership on 4,960 acres located in Malheur County, Oregon is dated January 24, 2007, has a primary term of 10 years and continues for as long as royalties are paid. Minimum rental was paid through 2012 and is considered a pre-paid production royalty. The lease agreement defines a royalty rate 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. As of January 2013 USG Oregon LLC began paying monthly royalties based on electricity delivery under our Idaho Power Purchase Agreement.

USG Oregon LLC. USG Oregon LLC owns the remaining mineral rights for the project. They include a 25% ownership and a 50% ownership depending on the parcel location.

In 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 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 old 3.6 megawatt geothermal power plant produced power from 1987 until December 2011. The power plant was constructed in 1986 with commercial power generation beginning in 1987. The original plant was replaced with the San Emidio Phase I repower project. The new 9.0 megawatt facility located on private land owned by USG Nevada was completed in 2012. Phase I repowering was completed utilizing the existing production and injection wells and achieved commercial operations in early 2012. USG Nevada is investigating the opportunity for expansion under Phase II in the northern area of the geothermal field.

All power production is committed under a power purchase agreement with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.4 megawatts of electricity on an annual average basis. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate.

Lease/Royalty Terms
BLM Leases. At the closing of the Empire acquisition approximately 21,905 acres of federal (BLM) geothermal leases and geothermal rights located in the San Emidio Desert were assigned to USG Nevada LLC. 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, as long as 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 Company received BLM approval and designation of a Geothermal Unit and a “Participating Area” in 2011. 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 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. The federal royalty is calculated based upon the percentage of acres of federal geothermal resources within the participating area and production royalty of 10.0% of the value of the resources prior to production cost deductions as required by a formula established by the Minerals Management Service.

Management evaluated our lease position and several years of new geologic data and determined that some leases should not be renewed. The 2013 geothermal leases are detailed as follows:

In May 2008, the Company entered into a joint venture agreement with Gerlach Green Energy LLC of Nevada and formed 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 development target is the Gerlach geothermal system. The BLM approved and designated 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 allocated 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.

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

The Granite Creek assets are comprised of approximately 2,443 acres (3.8 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 two geothermal leases with the BLM. The leases are for approximately 2,445 acres of land and geothermal water rights located in the northwestern Nevada. Federal lease N66404 is comprised of 1,563 acres and lease N66403 is 882 acres. The leases have primary terms of 10 years. Per federal regulations the lessee has the option to extend the primary lease terms another 40 years as long as the lessee maintains production in commercial quantities. The leases require an annual lease payment of $2,443, and have been extended as required by BLM regulations.

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).

The Company exercised its one year renewal option effective January 31, 2013 through January 31, 2014, for general office space for an executive office located in Boise, Idaho. The lease payments are due in monthly installments of $6,535 per month.

As of March 27, 2013, management is not aware of any material current or pending legal proceedings in which the Company is a party, as plaintiff or defendant, or which involve any of its properties.

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

NYSE MKT
On April 14, 2008, the Company’s common stock began trading on the NYSE MKT, under the trade symbol “HTM.” From June 3, 2005 to April 15, 2008, the Company’s stock was quoted on the Over-The-Counter Bulletin Board under the trading symbol “UGTH.”

The following table sets forth information relating to the trading of our common stock from April 1, 2011.

TSX and TSX Venture Exchange
The Company’s common stock 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 stock traded on the TSX Venture Exchange through September 28, 2007 under the same symbol. The TSX is the senior equity market in Canada. The 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 table sets forth information relating to the trading of the Company’s common stock on the TSX:

The Company has never paid and does not intend to pay dividends on its common stock in the foreseeable future. Although the Company’s certificate 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 shares of common stock are entitled to an equal share in any dividend declared and paid.

	Loss per share from Continuing Operations	Operating Revenues	Gross Profit (Loss)	Income (Loss) from Operations	Net Loss Attributable to U.S. Geothermal, Inc.
Fiscal Year Ended March 31, 2010
1^stQuarter	(0.04)	335,736	335,736	(2,441,672)	(2,411,566)
2^ndQuarter	(0.02)	734,622	734,622	(1,156,554)	(1,122,525)
3^rdQuarter	(0.02)	731,315	731,315	(1,449,421)	(1,394,009)
4^thQuarter	(0.01)	777,479	777,479	(935,546)	(910,750)
Fiscal Year Ended March 31, 2011
1^stQuarter	(0.02)	752,247	752,247	(1,491,924)	(1,474,560)
2^ndQuarter	(0.01)	838,688	838,688	(1,003,950)	(966,691)
3^rdQuarter	(0.01)	852,515	852,515	(843,584)	(825,194)
4^thQuarter	(0.01)	810,095	810,095	(699,892)	(687,971)
Fiscal Year Ended March 31, 2012
1^stQuarter	(0.03)	1,397,975	(1,110,296)	(4,639,138)	(2,341,024)
2^ndQuarter	(0.01)	1,689,609	421,852	(1,471,517)	(922,043)
3^rdQuarter	(0.02)	1,647,442	(100,363)	(2,596,788)	(1,315,339)
4^thQuarter	(0.01)	1,159,089	6,480	(1,921,134)	(1,643,723)
Nine Months Ended December 31, 2012
1^stQuarter	(0.01)	1,280,949	52,235	(1,828,947)	(930,870)
2^ndQuarter	0.00	2,019,749	270,012	(836,581)	(766,100)
3^rdQuarter	0.00	5,299,161	966,804	749,861	382,126

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

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

Neal Hot Springs, Oregon
Neal Hot Springs is located in Eastern Oregon near the town of Vale, the county seat of Malheur County. A commercial geothermal resource has been defined at the site, and a 22 net megawatt power plant, consisting of three separate, 7.33 net megawatt modules, has been constructed and is undergoing commissioning. The facility achieved commercial operation under the terms of the power purchase agreement on November 16, 2012. Generation from the facility during the fourth quarter of 2012 totaled 18,087 megawatt-hours. During commissioning, when all three modules were in operation under winter conditions, the facility achieved net output of 29.8 megawatts.

On February 26, 2009, the Company 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 67% of the total project cost which is now estimated to be $143.6 million for the project, a $14.6 million increase from the previous estimate. The DOE loan is a combined construction and 22 year term loan. The annual 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 as determined on each date that a draw is made on the loan and is estimated to be 2.616% as an aggregate rate of the individual draws that occurred through December 31, 2012.

Each of the additional investments made by Enbridge Inc. will be subject to calculations that will result in increased ownership interest in the project. Current estimates show that Enbridge could own between 30% and 40% of the project depending on ITC and BETC cash grant sharing.

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 average price for the year 2012 of $96.00 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. Test energy delivered prior to declaration of commercial operation is paid for at 90% of the monthly average, non-firm, Dow Jones Mid-Columbia Index. Since achieving commercial operation on November 16, 2012, the starting contract price of $96.00 per megawatt-hour was paid for power delivered the remainder of 2012, and escalated to an average price of $99.00 for 2013 power generation.

Further expansion of the San Emidio resource is planned to take place in two additional phases. Phase II is a planned expansion within the bounds of the existing San Emidio geothermal reservoir and is subject to the successful development of additional production wells through exploration and drilling activities. Phase III is planned for 17.2 megawatt net utilizing two additional power modules similar to Phases I and II.

Raft River, Idaho
During the quarter ended December 31, 2012, Raft River Unit I operated at 99.5% availability and generated an average of 9.73 net megawatts per hour. Power production totaled 21,386 megawatt-hours during the quarter ended December 31, 2012. For the 2012 calendar year, the plant averaged 8.6 net megawatts of generation with 98.7% availability.

Subsequent to the quarter ended December 31, 2012, preparations for the commencement of site work started with the construction of a temporary office and fencing on the plant site. Two geophysical surveys, a VES survey and a gravity survey, have been contracted and are expected to be complete by the end of March. A plan and budget for an exploration slim hole of up to 1,000 meters deep has been developed. Results from the geophysical surveys will be used to select a location for the well to target the potential production zone.

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 factors discussed below. A summary of the Company’s operations is as follows:

San Emidio, Nevada
The new Phase I achieved mechanical completion in December 2011. The power plant achieved commercial operation on May 25, 2012. During the quarter ended December 31, 2012, the plant achieved 80.9% availability and generated an average of 9.0 net megawatts per hour. Power production totaled 16,191 megawatt-hours for the quarter. The Phase I plant completed its capacity testing during the quarter, and as a result of the capacity test exceeding the design output, the plant was up rated to 9.0 net annual average megawatts per hour from the design point basis of 8.6 megawatts.

Neal Hot Springs, Oregon
The facility achieved commercial operation under the terms of the power purchase agreement on November 16, 2012. Generation from the facility during the quarter totaled 18,087 megawatt-hours. During commissioning, when all three modules were in operation under winter conditions, the facility achieved net output of 29.8 megawatts.

Raft River Energy I LLC
During the quarter ended December 31, 2012, Raft River Unit I operated at 99.5% availability and generated an average of 9.73 net megawatts per hour. Power production totaled 21,386 megawatt-hours during the quarter. For the 2012 calendar year, the plant averaged 8.6 net megawatts of generation with 98.7% availability.

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-venture 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 generates 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.

Initially, Raft River Energy I LLC (“RREI”) was a wholly owned subsidiary of the Company and was recorded as a fully consolidated subsidiary into the Company’s financial statements. In 2006, Raft River I Holdings (“Holdings”), a subsidiary of the Goldman Sachs Group, acquired an equity interest by providing a significant capital investment in RREI under a tax equity structure. Subsequent accounting activity of RREI was reflected under the equity method on the Company’s consolidated financial statements.

Based on management’s annual review of the conditions and circumstances, it was determined that the Company would no longer use the equity method to reflect the Company’s interest in RREI as of April 1, 2011. The Company is now fully consolidating RREI’s assets, liabilities and operations and is recognizing a non-controlling interest. When making this determination, Management analyzed whether control had shifted to the Company for accounting purposes, and notes that participation by Holdings is and has been passive. The Board of Managers does not hold regular meetings, does not formally approve the annual operating budgets, and Holdings declined to contribute additional funds even when benefits can be shown. The Company has possession of and operates the facility, makes all day-to-day operating decisions, and contributes additional required capital funding as needed. Active participation in the operations of RREI is a primary role of the Company’s operating staff. The most important element that has changed is the economics of the project due to the zero balance in the Raft River Holding’s tax capital account. Tax deductions associated with an additional $12.1 million equity contribution from the Company accelerated the exhaustion of the Holdings tax capital account to zero sooner than originally anticipated. The Company has allocated 100% of the tax deductions and operating losses for the tax year 2011 and subsequent years. Since the current structure of RREI was established to allocate significant tax benefits to Holdings, the exhaustion of the Holdings tax capital account to zero demonstrates that the majority of the tax benefits have been monetized. Holdings no longer has any tax capital at risk. The Company is the only partner with tax capital at risk, so future operating decisions will primarily impact the Company.

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

Power Purchase Agreements (“PPA”)
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.

San Emidio, Nevada
On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. 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 amended and restated PPA. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011.

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

Neal Hot Springs, Oregon
The power purchase agreement for the Neal Hot Springs project was signed on December 11, 2009 with the Idaho Power Company. Idaho Power Company submitted the PPA to the Idaho Public Utilities Commission (“IPUC”) on December 28, 2009 and it was approved by the IPUC on May 20, 2010. The PPA has a 25 year term with a starting price of $96 per megawatt hour. The price escalates annually by 3.9% in the initial years and by 1.0% during the latter years of the agreement. The approximate 25 year levelized price is $117.65 per megawatt hour.

For the nine months ended December 31, 2012, the Company reported a net loss attributable to the Company’s operations of $1.3 million ($0.01 loss per share) which represented a favorable decrease of $4.9 million (78.6%) from the fiscal year ended March 31, 2012. For the nine months ended December 31, 2012, the Company reported a net loss of attributable to the Company’s operations of $1.3 million ($0.02 loss per share) which represented a favorable decrease of $3.4 million (71.4%) from the nine months ended December 31, 2011 and a favorable decrease of $4.9 million (78.6%) from the fiscal year ended March 31, 2012. Notable favorable variances were reported in plant operations, professional and management fees, salaries and related costs and stock based compensation.

During the nine months ended December 31, 2012, the Company’s operating revenues from energy production and related operating costs originated from three power plants. The San Emidio plant (USG Nevada LLC) is located in the San Emidio Desert in the northwestern part of the State of Nevada. The original San Emidio plant and related water rights were purchased in 2008. The old plant ceased operations in December 2011 and was replaced with a new plant that began commercial operations in June of 2012. The Raft River plant (Raft River Energy I LLC) is located in South Eastern Idaho. The Raft River plant began operations in January of 2008.

The new plant at Neal Hot Springs, Oregon (USG Oregon LLC) began commercial operations on November 16, 2012.

Neal Hot Springs, Oregon Plant Operations
The Neal Hot Springs plant began producing power in the quarter ended December 31, 2012 and was considered to be commercially operational on November 16, 2012. For the nine months ended December 31, 2012, the plant reported an operating profit of $1,394,667. During the quarter ended December 31, 2012, the plant produced $2,063,311 (23,255,988 kwh) in energy sales, which was 27.1% of the Company’s total energy and energy credit sales. Depreciation and amortization on the plant and other assets amounted to $519,335.

San Emidio, Nevada Plant Operations
The energy sales generated from the San Emidio power plant represented 30.6% and 28.8% of total operating revenues for the Company for nine months ended December 31, 2012 and the year ended March 31, 2012; respectively. The energy sales generated from the San Emidio power plant represented 30.6% and 36.0% of total operating revenues for the Company for nine months ended December 31, 2012 and 2011, respectively.

For the nine months ended December 31, 2012, the San Emidio plant reported a net operating loss of $131,057 which was a favorable decrease of $762,284 (85.3%) from the operating loss reported for the year ended March 31, 2012. On December 12, 2011, the old power plant was shut down to facilitate the change to the new power plant. Due to the shutdown, no energy was produced in the quarter ended March 31, 2012 and less than average amounts of energy were produced during the quarter ended December 31, 2011. The new power plant did not become commercially operational until May 25, 2012, and experienced issues related to startup that caused the plant to be shut down 65 days during the quarter ended September 30, 2012. In the quarter ended December 31, 2012, the new plant produced record revenues of $1,472,688, which were 98.2% higher than the second highest quarter ended September 30, 2012. Despite the record revenues, the plant reported an operating loss due to higher operating costs. During nine months ended December 31, 2012, USG Nevada LLC was required to pay $709,587 in property taxes, which was an increase of 128.7% from the year ended March 31, 2012. Some of these taxes are a result of the actual higher value of the plant and some were due to errors in the tax calculation. The Company is currently working with the appropriate governmental entities to correct the calculation.

A new 25 year PPA was signed in December of 2011 that sets the new set rate at $0.0897 per kilowatt hour with a 1% annual escalation rate.

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

	For the Nine
	Months Ended				For the Year Ended
	December 31,2012				March 31, 2012				Variance
	$		%*		$		%*		$		%**
Operating revenues:
Energy sales	2,632,502		100.0		1,615,189		95.0		1,017,313		63.0
Energy credit sales	-		-		84,798		5.0		(84,798	)	(100.0	)
	2,632,502		100.0		1,699,987		100.0		932,515		54.9

Operating expenses:
General and administrative	178,438		6.8		218,136		12.8		39,698		18.2
Salaries and related costs	495,658		18.8		643,012		37.8		147,354		22.9
Operations:
Repairs and maintenance	93,482		3.6		81,090		4.8		(12,392	)	(15.3	)
Other	272,038		10.4		351,801		20.7		79,763		2.7
Rent and lease	18,908		0.7		26,634		1.6		7,726		36.6
Purchased utilities	119,384		4.5		70,115		4.1		(49,269	)	(70.3	)
Taxes and permits	734,798		27.9		350,487		20.6		(384,311	)	(109.7	)
Depreciation and amortization	850,853		32.3		852,053		50.1		1,200		0.1
	2,763,559		105.0		2,593,328		152.5		(170,231	)	(6.6	)

Operating Loss	(131,057	)	(5.0	)	(893,341	)	(52.5	)	762,284		(85.3	)
Interest income	130		-		2,183		0.1		(2,053	)	(94.0	)

Net Loss	(130,927	)	(5.0	)	(891,158	)	(52.4	)	760,231		(85.3	)

					(Unaudited)
	For the Nine				For the Nine
	Months Ended				Months Ended
	December 31, 2012				December 31, 2011				Variance
	$		%*		$		%*		$		%**
Operating revenues:
Energy sales	2,632,502		100.0		1,615,189		94.7		1,017,313		63.0
Energy credit sales	-		-		90,922		5.3		(90,922	)	(100.0	)
	2,632,502		100.0		1,706,111		100.0		926,391		54.3

Operating expenses:
General and administrative	178,438		6.8		115,662		6.8		(62,776	)	(54.3	)
Salaries and related costs	495,658		18.8		599,776		35.1		104,118		17.4
Operations:
Repairs and maintenance	93,482		3.6		62,317		3.7		(31,165	)	(50.0	)
Other	272,038		10.4		271,166		15.9		(872	)	(0.3	)
Rent and lease	18,908		0.7		25,993		1.5		7,085		27.3
Purchased utilities	119,384		4.5		43,996		2.6		(75,388	)	(171.4	)
Taxes and permits	734,798		27.9		340,943		20.0		(393,855	)	(115.5	)
Depreciation and amortization	850,853		32.3		662,927		38.8		(187,926	)	(28.3	)
	2,763,559		105.0		2,122,780		124.4		(640,779	)	(30.2	)

Operating Loss	(131,057	)	(5.0	)	(416,669	)	(24.4	)	285,612		68.5
Interest income	130		-		1,472		0.1		(1,342	)	(91.2	)

Net Loss	(130,927	)	(5.0	)	(415,197	)	(24.3	)	284,270		68.5

Key quarterly production data for the San Emidio, Nevada plant is summarized as follows:

Raft River Plant Operations (“RREI”)
The energy and energy credit sales generated from the Raft River power plant represented 42.3% and 71.2% of total operating revenues for the Company for nine months ended December 31, 2012 and the year ended March 31, 2012; respectively. The reduction in the total percentage relates primarily to the addition of the revenues produced by the new Neal Hot Springs plant.

The Company recognized a net loss from RREI operations of $648,376 for the nine months ended December 31, 2012, decreased favorably by $3,491,308 (84.3%) from year ended March 31, 2012. In January 2009, the lap joint for one of the production wells (RRG-7) began to fail. The failure resulted in a reduction in water temperature that had a negative impact on energy production for fiscal year ended March 31, 2012. In June of 2010, a production well RRG-2 was shut down. In May 2011, the repairs of wells RRG-2 and RRG-7 began under the terms of the Repair Service Agreement between the two partners. The repairs were completed in January 2012 and amounted to over $1.65 million. From January 2012 to March 2012, the plant operated at an average of 9.29 megawatts, which was a 27.8% increase from the average production levels from April 2011 to December 2011. The plant experienced an additional pump failure in April 2012, that was corrected in June 2012. The plant has performed within expectations after the last pump repair. Plant production increased 20.2% for the last six months of 2012 from the same period in 2011. Production levels for the quarter ended December 31, 2012 were the highest reported since the quarter ended March 31, 2009. Annual and quarterly summarized financial and production information is presented below.

For the nine months ended December 31, 2012, the Company incurred professional and management fees of $654,438, which was a decrease of $1,234,704 (65.4%) from the fiscal year ended March 31, 2012. For the nine months ended December 31, 2012, there was a decrease of $1,122,541 (63.2%) from the same period ended 2011. In the first fiscal quarter ended June 30, 2011, fees of $1,088,091 were paid to a placement agent for obtaining the equity partner in the Neal Hot Springs, Oregon project. This type of cost has not and is not expected to be incurred in subsequent periods. During the nine months ended December 31, 2012, the Company incurred additional audit related costs of approximately $60,000 required by financing entities and by governmental agencies for grant compliance.

For the nine months ended December 31, 2012, the Company reported $897,001 in salaries and related costs, which was a decrease of $340,460 (27.5%) from the fiscal year ended March 31, 2012. For the nine months ended December 31, 2012, there was a decrease of $134,710 (13.1%) from the same period ended 2011. Overall, salary and related costs based upon a quarterly average were reasonably consistent between the two periods. Salary and related costs were slightly higher in the prior period due to company-wide bonuses that totaled $450,000 issued in the quarter ended June 30, 2011. At San Emidio, salary cost allocations have been made for efforts primarily related to the new power plant construction management for Phase I of the project. Since the new San Emidio plant was substantially completed in the quarter ended June 30, 2012, fewer costs were capitalized for the nine months ended December 31, 2012. 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 plant construction. Since the plant became commercially operational in November 2012, fewer salary costs are expected to be capitalized in future periods.

For the nine months ended December 31, 2012, the Company recognized stock based compensation of $636,001, which was a decrease of $818,374 (56.3%) from the fiscal year ended March 31, 2012. For the nine months ended December 31, 2012, there was a decrease of $514,244 (44.7%) in stock based compensation from the same period ended 2011. Stock based compensation includes the calculated values of both Company stock and stock options. The variance was related to of the timing of the issuance of the stock option grants, the Company’s stock price and the stock compensation plan. Board of Directors approved grants of 2,917,000 stock options on August 24, 2012 and 2,590,000 stock options on June 3, 2011.

On September 10, 2010, the Company granted 705,000 common shares to officers, directors and select employees which vested over three six-month periods. In the fiscal year ended March 31, 2012, the Company recognized expenses of $248,579 related to the stock compensation plan. The stock compensation plan ended in March 2012; therefore, no stock compensation costs were incurred in the nine months ended December 31, 2012.

The net loss attributable to the non-controlling interest entities is the line item that removes the portion of the Company’s consolidated operations that are owned by the Company’s subsidiaries. For the nine months ended December 31, 2012, the Company reported $604,989 in net loss attributable to non-controlling interests, which was a favorable decrease of $3,962,166 (86.8%) from the net loss for the year ended March 31, 2012. For the nine months ended December 31, 2012, there was a favorable decrease of $3,190,031 (84.1%) from the same period ended 2011. The two primary reasons for the decrease were due to the favorable operating results of the power plants at Neal Hot Springs, Oregon (“NHS”) and the Raft River, Idaho (“RREI”). The NHS plant had a favorable impact of $275,624 due to the operating profit produced for the nine months ended December 31, 2012. Since the NHS plant was not operational until November 2012, the operating activities for the year ended March 31, 2012 were not significant. The favorable operating results of RREI decrease was due to the improvements in operations of Raft River Energy I LLC (“RREI”). The impact of the operations RREI in the Company’s financial statements on the loss attributable to non-controlling entities amounted to a $3,515,178 (80.6%) favorable decrease from the year ended March 31, 2012 as compared to the nine months ended December 31, 2012. As noted above, RREI’s has improved its operations as a result of the major repairs primarily incurred in the year ended March 31, 2012.

We believe our cash and liquid investments at December 31, 2012 are adequate to fund our general operating activities through December 31, 2013. Other project development, such as Guatemala, may require additional funding. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, market loans, 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. 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.

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 (“ITC”) in lieu of the production tax credit (“PTC”). The ITC may be converted into a cash grant within the first 90 days of operation of the plant. Phase I at San Emidio attained commercial operation on May 25, 2012. An application was submitted in July 2012 electing to take the ITC cash grant in lieu of the PTC. The United States Department of Treasury notified the Company that it would allow $10.65 million in cash grant. An additional $1.05 million of cash grant items are under review. The cash grant proceeds were received on November 10, 2012 and used to repay the Ares Capital bridge loan facility, with the remaining balance payable to USG Nevada LLC. For the Neal Hot Springs project, an application will be submitted in the first quarter 2013 electing to take the ITC cash grant, in lieu of the PTC, for approximately $35.5 million from U.S. Treasury and the funds will be used to fund reserves required under the DOE Loan Guarantee Agreement and return funds to our partner in the project, Enbridge.

In July 2010, the Company applied to the Oregon Department of Energy for the Business Energy Tax Credit (“BETC”), which allows an income tax credit for up to $20 million in qualifying expenditures for a renewable energy project. The Neal Hot Springs project has completed final certification for the credit which can be sold to a pass-through partner and monetized at a cash value of $7.36 million. It is anticipated that the BETC cash will be available within the first six months of 2013.

On May 21, 2012, the Company entered into a purchase agreement (the “Purchase Agreement”) with Lincoln Park Capital Fund, LLC (“LPC”), pursuant to which the Company has the right to sell to LPC up to $10,750,000 in shares of the Company’s common stock, (“Common Stock”), subject to certain limitations and conditions set forth in the Purchase Agreement and imposed by the Company’s board of directors and pricing committee thereof. Pursuant to the Purchase Agreement LPC initially purchased $750,000 in shares of Common Stock at $0.38 per share. Following this initial purchase, on any business day and as often as every other business day over the 36-month term of the Purchase Agreement, and up to an aggregate amount of an additional $10,000,000 (subject to certain limitations) in shares of Common Stock, the Company has the right, from time to time, at its sole discretion and subject to certain conditions to direct LPC to purchase up to 250,000 shares of Common Stock, which amount may be increased in accordance with the Purchase Agreement if the closing sale price of Common Stock on the NYSE MKT exceeds certain specified levels. The purchase price of shares of Common Stock pursuant to the Purchase Agreement will be based on prevailing market prices of Common Stock at the time of sales without any fixed discount, and the Company will control the timing and amount of any sales of Common Stock to LPC. No sales of Common Stock under the Purchase Agreement will be made through the TSX. The Purchase Agreement contains customary representations, warranties and agreements of the Company and LPC, limitations and conditions to completing future sale transactions, indemnification rights and other obligations of the parties. There is no upper limit on the price per share that LPC could be obligated to pay for Common Stock under the Purchase Agreement. LPC shall not have the right or the obligation to purchase any shares of Common Stock if the purchase price of those shares, determined as set forth in the Purchase Agreement, would be below $0.25 per share. The Company has the right to terminate the Purchase Agreement at any time, at no cost or penalty. Actual sales of shares of Common Stock to LPC under the Purchase Agreement will depend on a variety of factors to be determined by the Company from time to time, including (among others) market conditions, the trading price of the Common Stock and determinations by the Company as to available and appropriate sources of funding for the Company and its operations. As consideration for entering into the Purchase Agreement, the Company has issued to LPC 651,819 shares of Common Stock. The Company will not receive any cash proceeds from the issuance of these 651,819 shares. As of September 30, 2012, the Company has sold LPC an aggregate of 4,625,506 shares of common stock pursuant to the Purchase Agreement for net proceeds of approximately $1,343,639.

On December 21, 2012, the Company and LPC entered into an Amendment No. 1 to the Purchase Agreement (the “Amendment”) to reduce the total amount that can be purchased under the Purchase Agreement, including amounts already purchased, from $10,750,000 to $6,500,000.

The Company also entered into an agreement with Kuhns Brothers Securities Corporation (“KBSC”), pursuant to which KBSC agreed to act as the placement agent in connection with the sale of shares of Common Stock to LPC. The Company has agreed to pay KBSC the following compensation for its services in acting as placement agent in the sale of Common Stock to LPC: (A) the Company will pay a cash fee to KBSC in an amount equal to: (i) 6% of the aggregate gross proceeds received by the Company from the initial sale of $750,000 in shares of Common Stock to LPC pursuant to the Purchase Agreement, and (ii) 3% of the aggregate gross proceeds received by the Company from additional sales of Common Stock to LPC pursuant to the Purchase Agreement; and (B) the Company will issue to KBSC the number of warrants (the “Compensation Warrants”) equal to: (i) in the case of the initial sale of $750,000 in shares of Common Stock to LPC, 6% of the aggregate number of shares sold to LPC; and (ii) in the case of additional sales of Common Stock to LPC, 3% of the aggregate gross proceeds received by the Company from such sales divided by 115% of the closing sale price of one share of Common Stock on the day prior to the respective issuance of the Compensation Warrant. The Compensation Warrants issued pursuant to clause (ii) in the preceding sentence will be based on incremental sales to LPC of $2 million in aggregate gross proceeds. Each Compensation Warrant will have an exercise price equal to 115% of the closing sale price of one share of Common Stock on the day prior to its issuance, a term of five years from the date of its issuance and will otherwise comply with the rules of the Financial Industry Regulatory Authority, Inc. On December 26, 2012, the Company completed a registered direct offering with a number of investors, pursuant to which they acquired, in total, 11,810,816 units (each a “Unit”) of the Company at a price of $0.37 per Unit. Each Unit consists of one share of common stock of the Company and one half of one common stock purchase warrant (each whole warrant a “Warrant”). Each Warrant will entitle the holder thereof to acquire one additional share of common stock of the Company for a period of 60 months following the closing of the offering for $0.50 per share of common stock. The gross proceeds of the Unit offering were approximately $4.37 million. Kuhns Brothers Securities Corporation acted as placement agent for this offering and was paid a placement fee of $262,000, plus expenses of approximately $20,000.

On September 30, 2011, the Company entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with McNicoll, Lewis & Vlak LLC (“MLV”), pursuant to which the Company, from time to time, was entitled to issue and sell through MLV, acting as the Company’s sales agent, shares of the Company’s Common Stock. The Company’s board of directors authorized the issuance and sale of shares of the Company’s Common Stock under the Sales Agreement for aggregate gross sales proceeds of up to $10,000,000, subject to certain limitations based on the sales price per share, for a period of one year from the date of execution of the Sales Agreement. Pursuant to the Sales Agreement, MLV was entitled to compensation at a fixed commission rate of the greater of (i) 3% of the gross sales price per share sold or (ii)(1) $0.03 per share sold if the sale price per share was $0.80 or greater or (2) $0.0225 per share sold if the sale price per share was less than $0.80 (but in no event would compensation exceed 8% of gross proceeds). The Company has, also, agreed to reimburse a portion of MLV’s expenses in connection with the offering of the Company’s Common Stock under the Sales Agreement. The Company terminated the Sales Agreement effective May 19, 2012. Prior to such termination, the Company sold 241,989 shares of common stock pursuant to the Sales Agreement for net proceeds of approximately $126,133.

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 the Company’s planned 22-megawatt-net power plant at Neal Hot Springs in Eastern Oregon. Neal Hot Springs was the first geothermal project to complete a loan guarantee under the 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 67% of total project cost. When combined with the previously announced equity investments by the project’s partner, Enbridge Inc., the loan provides 100% of the anticipated capital remaining to fully construct the project.

In September 2010, Oregon USG Holdings, 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, which converted. DOE guaranteed project loan and was treated as an equity contribution by Enbridge to the project. The agreements also provided for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note earned Enbridge a 20% direct ownership in the project. As a result of cost overruns for the project, and at the election of the Company, an additional payment obligation of up to $8 million was contributed by Enbridge that increased their direct ownership in the project by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments increased Enbridge’s ownership to 27.5% . An additional $6 million cost overrun facility was established by Enbridge to cover costs that resulted from unexpected poor results from injection well drilling. The additional investment by Enbridge will increase their ownership in USG Oregon LLC based on running a project financial model and determining what percentage of the forecasted project income will be allocated to Enbridge to arrive at a predetermined rate of return for the additional investment. Current estimates of the ownership assuming that all of the investment is used for drilling shows that Enbridge could own up to 40% of the subsidiary. The model will be rerun after all of the variables have been fixed which is anticipated to be in the second quarter of 2013 to set the final ownership ratios between the two parties.

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.

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.

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.

As of December 31, 2012, the following table denotes contractual obligations by payments due for each period:

As of December 31, 2012, the Company does not have any off balance sheet arrangements.

At December 31, 2012, the Company held investments of $681,634 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 a 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 was stated in Canadian dollars as the plan had been administered through our Vancouver office and Pacific Corporate Trust Company at the time such stock options were granted. This subjected the Company to foreign currency risk in addition to the normal market risks associated with the common stock price fluctuations. A long-term liability has been established to reflect the fair value of the stock options payable. The strike price on the Company’s stock option grants since April 2007 has been stated U.S. dollars.

Commodity Price Risk
The Company is exposed to risks surrounding the volatility of energy prices. These risks are impacted by various circumstances surrounding the energy production from natural gas, nuclear, hydro, solar, coal and oil. The Company has been able to mitigate, to a certain extent, this risk by entering into long-term power purchase contracts for 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.

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 transition 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 transition report.

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

In connection with the preparation of this transition 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 December 31, 2012. 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 December 31, 2012.

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

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. 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 its assessment, management concluded that, as of December 31, 2012, the Company’s internal control over financial reporting is effective based on those criteria.

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 nine months ended December 31, 2012, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

The Board of Directors (the “Board”) of the Company is currently composed of six directors: Dennis J. Gilles, Douglas J. Glaspey, Daniel J. Kunz, Paul A. Larkin, Leland L. Mink and John H. Walker. The majority of the Board, made up of Mr. Gilles, Mr. Larkin, Dr. Mink and Mr. Walker, satisfy the applicable independence requirements of the NYSE MKT LLC (“NYSE MKT”), and National Instrument 58-101, Disclosure of Corporate Governance Practices and Multilateral Instrument 52-110, Audit Committees. Mr. Kunz and Mr. Glaspey do not satisfy such independence requirements based on their employment as executive officers of the Company. The Board has one class of members that is elected at each annual shareholders meeting to hold office until the next annual shareholders meeting or until their successors have been duly elected and qualified.

Dennis J. Gilles. Age 54, serves as a director of the Company, a position he has held since September 2011. Mr. Gilles also currently serves as a Director and Executive Board Officer of the Geothermal Resource Council. Mr. Gilles is a senior executive with 30 years of experience in the management, operations, maintenance, engineering, construction and administration of power and petrochemical plants and their related facilities. Mr. Gilles’ primary activities have included the identification, evaluation and acquisition of existing renewable projects or portfolios, as well as heading development of new green-field opportunities. As Senior Vice President of Calpine Corporation, Mr. Gilles managed the company’s geothermal portfolio of 750 megawatts at the Geysers geothermal field where he was instrumental in consolidating the majority of the ownership interests into a single entity. Mr. Gilles was part of the expansion and growth of Calpine Corporation from the very first megawatt to what is now the largest independent power producer in the United States. Mr. Gilles holds a Masters of Business Administration and a Bachelor of Science in Mechanical Engineering. Mr. Gilles’ qualifications to serve as a director of the Company include his over 20 years of experience in the natural resource industry and his many years of senior management and director experience.

Douglas J. Glaspey: Age 60, is the co-founder, President and Chief Operating Officer and a director of the Company. He has served as a director of the Company since March 2000, President of the Company since September 2011, and Chief Operating Officer of the Company since December 2003. Mr. Glaspey served from March 2000 until December 2004 as the President and Chief Executive Officer for the TSX Venture Exchange (“TSX-V”) listed U.S. Cobalt Inc. until the acquisition of Geo-Idaho in December 2003. He also served as a director and the Chief Executive Officer of Geo-Idaho from February 2002 until the acquisition of Geo-Idaho in December 2003. During his career in the mining industry, he has held operating positions with ASARCO, Earth Resources Company, Asamera Minerals, Atlanta Gold Corporation and Twin Gold Corporation. Mr. Glaspey has 34 years of operating and management experience. He holds a Bachelor of Science in Mineral Processing Engineering and an Associate of Science in Engineering Science. His experience includes public company financing and administration, production management, planning and directing resource exploration programs, preparing feasibility studies and environmental permitting. He has formed and served as an executive officer of several private resource development companies in the United States, including Drumlummon Gold Mines Corporation and Black Diamond Corporation. He is currently a director of TSX-V listed Thunder Mountain Gold, Inc., which is also quoted on the OTC Bulletin Board. Mr. Glaspey’s qualifications to serve as a director of the Company include his over 30 years of experience in the natural resource industry and his many years of senior management and director experience.

Daniel J. Kunz: Age 60, is the co-founder, Chief Executive Officer and a director of the Company. He has served as a director of the Company since March 2000, Chief Executive Officer since December 2003, and was Chairman of the Board of Directors from March 2000 until December 2003. He has also served as President of the Company from December 2003 to September 2011, and President of Geo-Idaho from February 2002 until September 2011. Mr. Kunz has more than 30 years of experience in international mining, engineering and construction, including, marketing, business development, management, accounting, finance and operations. Mr. Kunz served as Chairman of the Board of U.S. Cobalt Inc. until December 2004. He was senior vice president and Chief Operating Officer of Ivanhoe Mines Ltd. from 1997 until October 31, 2000, and served as its President, Chief Executive Officer and Director from November 1, 2000 until March 1, 2003. From March 2, 2003 until March 8, 2004, Mr. Kunz served as President and CEO of Ivanhoe’s subsidiary Jinshan Gold Mines Inc. Mr. Kunz was a founder of and directed the 1993 initial public offering of the NASDAQ listed MK Gold Company (President, Director & CEO) and for 17 years held executive positions with NYSE listed Morrison Knudsen Corporation (including Vice President & Controller). Mr. Kunz holds a Masters of Business Administration, a Bachelor of Science in Engineering and an associate accounting degree. He is currently a director of several companies publicly traded on the TSX-V, including Chesapeake Gold Corp. Mr. Kunz’s qualifications to serve as a director of the Company includes his over 30 years of experience in international mining, engineering and construction and his many years of senior management and NYSE, NASDAQ and TSX director experience.

Paul Larkin: Age 62, serves as a director of the Company, a position he has held since March 2000. He served as Secretary of the Company from March 2000 until December 2003, and served as a director and the Secretary-Treasurer of Geo-Idaho from February 2002 until its acquisition in December 2003. Since 1983, Mr. Larkin has also been the President of the New Dawn Group, an investment and financial consulting firm located in Vancouver, British Columbia, and a director and officer of various TSX-V listed companies. New Dawn is primarily involved in corporate finance, merchant banking and administrative management of public companies. Mr. Larkin held various accounting and banking positions for over a decade before founding New Dawn in 1983, and currently serves on the boards of the following companies which are listed on the TSX-V: LNG Energy Ltd., Condor Resources Ltd., Kenai Resources Ltd., Tyner Resources Ltd. Gstaad Capital Corp. and Westbridge Energy Corp. Mr. Larkin’s qualifications to serve as a director of the Company include his many years of senior leadership and management experience in corporate finance, merchant banking and administrative management of public companies.

Dr. Leland “Roy” Mink: Age 72, serves as a director of the Company, a position he has held since November 2006. Dr. Mink is currently self-employed as President of Mink GeoHydro Inc conducting consulting activities in hydrogeology and geothermal resource evaluations. He served as Program Director for the Geothermal Technologies Program at the U.S. Department of Energy (DOE) from February 2003 to October 2006. Prior to working for the DOE, Dr. Mink was the Vice President of Exploration for the Company from June 2002 to February 2003. He has also worked for Morrison-Knudsen Corporation, Idaho Bureau of Mines and Geology and Idaho Water Resources Research Institute. Dr. Mink’s qualifications to serve as a director of the Company include his many years of senior leadership and management experience in the geothermal energy industry.

John H. Walker: Age 64, is a director and the Chairman of the Board of Directors of the Company. He has held that position since December 2003. He is also a Managing Director of Kensington Capital Partners Ltd and a National Director of Trout Unlimited Canada. Mr. Walker has a 38 year history in urban planning, energy security and power plant development in Ontario and internationally as well as experience on both public and private sector boards. Mr. Walker was a founding director of the Greater Toronto Airports Authority in 1992 and chaired the first Planning and Development Committee of the Board which provided oversight in the construction of CDN$4.4 billion terminal complex at Toronto Pearson Airport completed in 2004. He was instrumental in the development of an 117MW cogeneration power plant at Toronto Pearson Airport which commenced operations in 2005. Additionally, he was a founding Director of the Borealis Infrastructure Fund which is now owned by Ontario Municipal Employee Retirement System (OMERS). Mr. Walker has worked in the financial services community as an investment banker with Loewen Ondaatje McCutcheon and has served on the Board of Directors of Sheridan College Institute of Technology and Advanced Learning. His background includes 10 years at Ontario Hydro where he was responsible for site selection, alternative energy and international market development. Mr. Walker has also acted as a senior advisor to Falconbridge on the Koniambo project, a CDN$3 billion nickel smelter, mine, power plant and port project in New Caledonia. Mr. Walker advises corporations on matters related to infrastructure and energy development and acts as a developer of power plants. Mr. Walker is a Registered Professional Planner in the Province of Ontario and a member of the Canadian Institute of Planners. Mr. Walker has a BSc. from Springfield College and a Masters of Environmental Studies (Urban and Regional Planning) from York University. Mr. Walker’s qualifications to serve as a director of the Company include his many years of senior leadership and management experience in international business development.

Kerry D. Hawkley. Age 59, serves as the Chief Financial Officer and Corporate Secretary of the Company. He has served as the Company’s controller since July 2003, and became CFO as of January 1, 2005. From July 2003 to December 2004, he also provided consulting services to Triumph Gold Corp. From 1998 to June 2003, Mr. Hawkley served as controller, director and treasurer of LB Industries. Mr. Hawkley has over 35 years of experience in all areas of accounting, finance and administration. He holds Bachelor of Business Administration degrees in Accounting and Finance. He started his career as an internal auditor with Union Pacific Corporation and has held various accounting management positions in the oil and gas, truck leasing, mining and energy industries.

Jonathan Zurkoff. Age 57, serves as the Treasurer and Executive Vice President of the Company, a position he has held since September 2011. From January 2009 to May 2009, Mr. Zurkoff served as a financial consultant to the Company. He then served as the Vice President Finance of the Company from June 2009 until September 2011. Mr. Zurkoff served as CFO of Tamarack Resorts from 2004 to 2008. Mr. Zurkoff has over 25 years of experience in engineering, construction, and all phases of project development with an emphasis on project and corporate finance. Mr. Zurkoff holds a Masters of Business Administration, a Masters of Science in Groundwater Hydrology, and a Bachelor of Science in Geology. Mr. Zurkoff has held positions in Tamarack Resort (CFO), Process Technologies (CFO & COO), and Morrison Knudsen Corporation (now URS).

Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) requires our executive officers and directors, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership of our securities with the SEC. Executive officers, directors and greater than 10% shareholders are required to furnish us with copies of these reports. Based solely on our review of the Section 16(a) reports furnished to us with respect to the transition period ended December 31, 2012 and written representations from our executive officers, directors and greater than 10% shareholders, we believe that all Section 16(a) filing requirements applicable to our executive officers, directors and greater than 10% shareholders were satisfied.

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 http://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 on our website. 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 on our website. No waivers were granted during the transition period ended December 31, 2012. 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 MKT listing rules.

Our Board of Directors 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 Dennis J. Gilles, Paul A. Larkin, Leland L. Mink and John H. Walker. 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 MKT independence standards applicable to audit committee members.

Our compensation philosophy is to structure compensation awards to members of our executive management that directly align their personal interests with those of our shareholders. Our executive compensation program is intended to attract, motivate, reward and retain the management talent required to achieve our corporate objectives and increase shareholder value, while at the same time making the most efficient use of shareholder resources. This compensation philosophy puts a strong emphasis on pay for performance, and uses equity awards as a significant component in order to correlate the long-term growth of shareholder value with management’s most significant compensation opportunities.

The three primary components of total direct compensation for our senior executives are:

The relative weighting of the three components of compensation is designed to strongly reward long-term performance, by heavily emphasizing the proportion of long-term equity compensation.

During the transition period ended December 31, 2012, the Company was focused on (1) operation and completion of construction for the San Emidio Phase I geothermal project in Nevada, (2) drilling, financing and completion of construction for the Neal Hot Springs project in Oregon, (3) conducting negotiations for PPA and equity partners at the El Ciebello project in Guatemala, (4) optimizing the operation of the well field at the Raft River project in Idaho, and (5) the evaluation of potential new geothermal project acquisitions.

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

We compete with a variety of companies for our executive-level employees. The Compensation and Benefits Committee uses base salary to compensate the executive officers for services rendered. Base salaries are intended to be competitive for companies of similar size and purpose, also taking into consideration individual factors such as experience, tenure, institutional knowledge and qualifications. An informal review of several public junior resource development companies was completed to provide the committee with comparative compensation information. The committee looked at Nevada Geothermal Power Inc., Ram Power Corp., China Gold International Resources Corp Ltd, and Chesapeake Gold Corp., who are involved in either geothermal development or in mineral exploration. Base salaries are reviewed annually to determine whether they are consistent with our overall compensation objectives. In considering increases in base salary, the Compensation and Benefits Committee reviews individual and corporate performance, market and industry conditions, and our overall financial health.

While the Company does not attach a weighting to the various components of executive compensation, the Compensation and Benefits Committee attempts to pay a competitive salary (retention) to its executives while providing long-term incentive to the executives through equity awards (ownership/reward) in order to align their interest with the long-term progression of the Company as a whole. Our Chief Executive Officer and Compensation and Benefits Committee perform an informal annual review of compensation practices of similar sized companies to educate themselves of the general parameters (levels and types of compensation) for executive compensation. They do not, however, benchmark the various components of pay. The review highlights areas of our executive pay package that may not be consistent with compensation practices at similar sized companies and provides the committee with knowledge of the compensation landscape for its executives.

The Compensation and Benefits Committee may grant annual performance bonuses as a reward for achievement of individual and corporate short-term goals. Any grant of an annual performance bonus is discretionary and the amount is determined after recommendation from the CEO. Involvement of other executive officers in the determination of bonus amounts to be paid is immaterial. Bonus amounts should be dependent upon our financial and operational performance as well as the completion of specific milestone events by the individual executive officer.

The bonuses paid in June 2011 were based on significant milestones and achievements of the Company during the calendar year 2010 including the following:

Generally, the Compensation and Benefits Committee grants stock options to all employees, including executive officers, for motivation and retention purposes annually after completion of our annual financial reports. Stock options are granted with an exercise price equal to the market value of our common stock on the date of the grant, and with a term of five years. The timing of the stock option grant is not coordinated with the release of material non-public information and is typically in the first or second fiscal quarter. The options vest 25% on date of grant, and another 25% each six months thereafter. During the transition period ended December 31, 2012, stock option grants to executive officers represented approximately 25% of the total stock option grants to all employees. During the fiscal year ended March 31, 2012, stock option grants to executive officers represented approximately 25% of the total stock option grants to all employees. We do not have a formal procedure for determining factors to consider when making grants. The committee uses an informal review of similar sized companies engaged in natural resource development to assist in determining the appropriate levels of stock option grants.

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

On September 29, 2011, Daniel J. Kunz, Chief Executive Officer, signed an employment agreement that sets the amount of time devoted to the business of the Company to 60 hours per month at a compensation of $120,000 annually. Mr. Kunz is entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as are or may become available to other employees, and vacation. The Company will also provide reasonable life insurance and accidental death coverage with the proceeds payable to Mr. Kunz’s estate or specified family member. The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance or other sums for causes which include failure to perform in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a conflict of interest, conviction which has become final for an indictable offense, fraud, dishonesty, refusal to follow reasonable and lawful direction of the Company, breach of fiduciary duty, and a declaration of bankruptcy by or against Mr. Kunz. Otherwise, the Company may terminate the agreement upon one month written notice. The agreement includes covenants by Mr. Kunz of confidentiality and non-competition, and provides for equitable relief in the event of breach. In the case of termination of employment due to a change of control, Mr. Kunz will receive a lump sum payment equal to 24 monthly installments of the employee’s normal compensation. Effective February 1, 2012, Mr. Kunz agreed to increase his hours to 120 hours per month at an annual rate of $240,000. Although the employment agreement expired on December 31, 2012, the terms of the last agreement will be effective until a subsequent agreement is finalized. Effective January 1, 2013, the annual salary for Mr. Kunz was increased to $252,000.

Douglas J. Glaspey, President and Chief Operating Officer, signed an employment agreement on April 1, 2011, which was effective as of April 1, 2011 and which provides for an annual salary of $175,000. Mr. Glaspey is entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as are or may become available to other employees, and vacation. The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance or other sums for causes which include failure to perform in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a conflict of interest, conviction which has become final for an indictable offense, fraud, dishonesty, refusal to follow reasonable and lawful direction of the Company, breach of fiduciary duty, and a declaration of bankruptcy by or against Mr. Glaspey. In the event of early termination due to failure to comply with the agreement, the employee would be entitled to compensation earned through the date of termination. In the case of termination of the employment agreement due to a change of control, Mr. Glaspey will receive a lump sum payment in the amount equal to 18 monthly installments of the employee’s normal compensation. Effective October 1, 2011, Mr. Glaspey’s annual salary was increased to $210,000.

Kerry D. Hawkley, Chief Financial Officer, signed an employment agreement on April 1, 2011, which was effective as of April 1, 2011 and which provides for an annual salary of $140,000. Mr. Hawkley is entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as are or may become available to other employees, and vacation. The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance or other sums for causes which include failure to perform in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a conflict of interest, conviction which has become final for an indictable offense, fraud, dishonesty, refusal to follow reasonable and lawful direction of the Company, breach of fiduciary duty, and a declaration of bankruptcy by or against Mr. Hawkley. In the event of early termination due to failure to comply with the agreement, the employee would be entitled to compensation earned through the date of termination. In the case of termination of the employment agreement due to a change of control, Mr. Hawkley will receive a lump sum payment in the amount equal to 18 monthly installments of the employee’s normal compensation. Effective January 1, 2013, Mr. Hawkley’s annual salary was increased to $151,000.

Jonathan Zurkoff, Treasurer and Executive Vice President, signed an employment agreement on December 31, 2010, which was effective as of December 31, 2010 and which provides for an annual salary of $160,000. Mr. Zurkoff is entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as are or may become available to other employees, and vacation. The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance or other sums for causes which include failure to perform in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a conflict of interest, conviction which has become final for an indictable offense, fraud, dishonesty, refusal to follow reasonable and lawful direction of the Company, breach of fiduciary duty, and a declaration of bankruptcy by or against Mr. Zurkoff. In the event of early termination due to failure to comply with the agreement, the employee would be entitled to compensation earned through the date of termination. In the case of termination of the employment agreement due to a change of control, Mr. Zurkoff will receive a lump sum payment in the amount equal to 18 monthly installments of the employee’s normal compensation. Effective October 1, 2011, Mr. Zurkoff’s annual salary was increased to $192,000.

The following table shows the compensation for the Transition Period and in each of the last two fiscal years awarded to or earned by our Chief Executive Officer and each of our three other most highly compensated executive officers (collectively, our “Named Executive Officers”).

Name and principal position(s)	Period	Salary ⁽¹⁾ ($)	Bonus ⁽²⁾ ($)	Option Awards ⁽³⁾ ($)	All other compensation ⁽⁴⁾ ($)	Total ($)

Daniel J. Kunz, Chief Executive Officer	12 Mths Ended 3/31/12	175,000	0	124,700	8,170	307,870
	*12 Mths Ended 12/31/12	230,000	0	41,348	8,170	279,518
	9 Mths Ended 12/31/12	180,000	0	41,348	8,170	229,518

Douglas J. Glaspey, President and Chief Operating Officer	12 Mths Ended 3/31/12	192,500	0	82,302	1,035	275,837
	*12 Mths Ended 12/31/12	210,000	0	31,806	1,035	242,841
	9 Mths Ended 12/31/12	157,500	0	31,806	1,035	190,341

Kerry D. Hawkley, Chief Financial Officer	12 Mths Ended 3/31/12	140,000	0	47,386	0	187,386
	*12 Mths Ended 12/31/12	140,000	0	25,110	0	165,110
	9 Mths Ended 12/31/12	105,000	0	25,110	0	130,110

Jonathan Zurkoff, Treasurer and Executive Vice President	12 Mths Ended 3/31/12	160,000	0	70,124	0	230,124
	*12 Mths Ended 12/31/12	192,000	0	22,200	0	214,200
	9 Mths Ended 12/31/12	144,000	0	22,200	0	166,200

The following table shows the unexercised stock options, unvested restricted stock, and other equity incentive plan awards held at the transition period ended December 31, 2012 by our Named Executive Officers.

Except as discussed below under “Potential Payments Upon Change-in-Control,” if the employment of any of our Named Executive Officers is voluntarily or involuntarily terminated, no additional payments or benefits will accrue or be paid to him, other than what the officer has accrued and is vested in under the benefit plans. A voluntary or involuntary termination will not trigger an acceleration of the vesting of any outstanding stock options or shares of restricted stock.

We have entered into employment agreements with Messrs. Kunz, Glaspey, Hawkley and Zurkoff which provide for change-in-control payments. For Messrs. Glaspey, Hawkley and Zurkoff, the employment agreements provide that if within twelve months of a change-in-control of U.S. Geothermal Inc. the officer is terminated either by U.S. Geothermal Inc. (other than for cause or disability), or by the officer for good reason, then the officer will be entitled to a lump-sum payment consisting of (a) the officer’s prorated base salary through the date of termination, (b) a severance payment equal to eighteen times the officer’s monthly base salary at termination, and (c) employee medical and dental coverage for eighteen months or until the officer commences alternate employment, whichever comes first. The terms “cause,” “good reason” and “change-in-control” are defined in the agreements.

For Mr. Kunz, the employment agreement provides that if within twelve months of a change-in-control of U.S. Geothermal Inc. the officer is terminated either by U.S. Geothermal Inc. (other than for cause or disability), or by the officer for good reason, then the officer will be entitled to a lump-sum payment consisting of (a) the officer’s prorated base salary through the date of termination, (b) a severance payment equal to twenty four times the officer’s monthly base salary at termination, and (c) employee medical and dental coverage for eighteen months or until the officer commences alternate employment, whichever comes first. The terms “cause,” “good reason” and “change-in-control” are defined in the agreement.

The following table summarizes the compensation paid to our directors during the transition period ended December 31, 2012.

Directors who are not otherwise remunerated per an employment agreement are paid $7,500 per quarter and eligible to receive awards under our equity compensation plans. Directors who are also officers do not receive any compensation for serving in the capacity of director. However, all directors are reimbursed for their out-of-pocket expenses in attending meetings.

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

The following table sets forth the number of securities authorized for issuance under the Company’s equity compensation plans as of the transition period ended December 31, 2012.

The following table sets forth certain information regarding beneficial ownership of the Company’s common stock, as of March 25, 2013, by each person known by us to be the beneficial owner of more than 5% of the Company’s outstanding common stock. The percentage of beneficial ownership is based on 101,516,764 shares of the Company’s common stock outstanding as of March 25, 2013.

Our executive officers and directors are encouraged to own our common stock to further align their interests with our shareholders’ interests. The following table sets forth certain information regarding beneficial ownership of the Company’s common stock, as of December 31, 2012, by each of our directors, Named Executive Officers and directors and executive officers as a group. The percentage of beneficial ownership is based on 101,516,764 shares of the Company’s common stock outstanding as of March 25, 2013.

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

Since April 1, 2011, there have been no financial transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which the Company or any of its subsidiaries, was or is to be a participant, and the amount involved exceeds the lesser of $120,000 or 1% of the average of the Company’s total assets at year end for the last two completed fiscal years, and in which a director, an executive officer, any immediate family member of a director or executive officer, a beneficial owner of more than 5% of the Company’s outstanding common stock or any immediate family member of the beneficial owner, had or will have a direct or indirect material interest.

The Board is currently composed of six directors: Dennis J. Gilles, Douglas J. Glaspey, Daniel J. Kunz, Paul A. Larkin, Leland L. Mink and John H. Walker. The majority of the Board, made up of Mr. Gilles, Mr. Larkin, Dr. Mink and Mr. Walker, satisfy the applicable independence requirements of the NYSE MKT. Mr. Kunz and Mr. Glaspey do not satisfy such independence requirements based on their employment as executive officers of the Company. The Board has three standing committees: the Audit Committee, the Nominating and Corporate Governance Committee and the Compensation and Benefits Committee. Each of the Board’s committees is composed only of directors that satisfy the applicable independence requirements of the NYSE MKT.

The Board has adopted certain standards to assist it in assessing the independence of each director. Absent other material relationships with the Company, a director of the Company who otherwise meets the applicable independence requirements of the NYSE MKT may be deemed “independent” by the Board after consideration of all relationships between the Company, or any of its subsidiaries, and the director, or any of his or her immediate family members (as defined in NYSE MKT listing standards), or any entity with which the director or any of his or her immediate family members is affiliated by reason of being a partner, officer or a significant shareholder thereof.

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

The aggregate fees billed to the Company by MartinelliMick PLLC for the nine months ended December 31, 2012, and the year ended March 31, 2012 for the audit of the Company’s annual financial statements and reviews of the financial statements included in the Company’s Quarterly Reports on Form 10-Q, were $52,482 and $22,460; respectively.

The aggregate fees billed to the Company by BehlerMick PS for the fiscal year ended March 31, 2012, for the reviews of the Company’s financial statements included in the Company’s Quarterly Reports on Form 10-Q was $66,064.

The aggregate fees billed to the Company by MartinelliMick PLLC for the nine months ended December 31, 2012, for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under “Audit Fees” above, was $25,617. The fees billed to the Company for the financial statement audits of the Company’s two subsidiaries USG Oregon LLC and USG Nevada LLC were $34,331. MartinelliMick PLLC billed the Company fees for audit and review services related to the submission of the application for the ITC cash grant that amounted to $4,809 for the nine months ended December 31, 2012.

The aggregate fees billed to the Company by MartinelliMick, PLLC for the fiscal year ended March 31, 2012, for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under “Audit Fees” above, was $8,214. The services comprising such fees related to compliance with the Sarbanes Oxley Act of 2002.

The aggregate fees billed to the Company by BehlerMick PS for the fiscal year ended March 31, 2012, for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under “Audit Fees” above, were $8,805. The services comprising such fees related to compliance with the Sarbanes Oxley Act of 2002.

The aggregate fees billed to the Company by Hein & Associates LLP for the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012, for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under “Audit Fees” above, were $78,141 and $71,205; respectively. The services comprising such fees related to compliance with the Sarbanes Oxley Act of 2002. Since the Company does not employ an internal audit staff, Hein & Associates LLP performed the internal audit function for verification of compliance with internal controls and procedures.

The aggregate fees billed to the Company by Hein & Associates LLP for the fiscal year ended March 31, 2012, for professional services rendered for tax compliance, tax advice, and tax planning were $32,490. The services comprising such fees related to tax compliance, including the preparation of and assistance with federal, state and local income tax returns, foreign and other tax compliance. Neither MartinelliMick PLLC nor BehlerMick PS rendered any professional services relating to tax compliance, tax advice, or tax planning during the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012.

The Company was not billed by MartinelliMick PLLC, BehlerMick PS or Hein & Associates LLP for any other services during the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012.

The Audit Committee is responsible for appointing, setting compensation for and overseeing the work of our independent auditor. The Audit Committee has established a policy for pre-approving the services provided by our independent auditor in accordance with the auditor independence rules of the Securities and Exchange Commission. This policy requires the review and pre-approval by the Audit Committee of all audit and permissible non-audit services provided by our independent auditor and an annual review of the financial plan for audit fees.

All of the services provided by our independent auditor for the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012, including services related to the Audit-Related Fees and Tax Fees described above, were approved by the Audit Committee under its pre-approval policies.

EXHIBIT NUMBER		EXHIBIT DESCRIPTION
3.1		Certificate of Incorporation of U.S. Cobalt Inc. (now known as U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.2		Certificate of Domestication of Non-U.S. Corporation (Incorporated by reference to exhibit 3.2 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.3		Certificate of Amendment of Certificate of Incorporation (changing name of U.S. Cobalt Inc. to U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.3 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.4		Second Amended and Restated Bylaws of U.S. Geothermal Inc. (Incorporated by reference to exhibit 3.4 to the registrant’s Form 8-K as filed on October 18, 2010)
3.5		Plan of Merger of U.S. Geothermal Inc. and EverGreen Power Inc. (Incorporated by reference to exhibit 3.5 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.6		Amendment to Plan of Merger (Incorporated by reference to exhibit 3.6 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.7		Certificate of Amendment to Certificate of Incorporation filed on August 26, 2008 (incorporated by reference to Exhibit 3.4 to the Company’s Form 8-K as filed on August 27, 2008)
4.1		Form of Stock Certificate (Incorporated by reference to exhibit 4.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
4.2		Provisions Regarding Rights of Stockholders (Incorporated by reference to Exhibit 4.3 to the Company’s Form SB-2 registration statement as filed on July 8, 2004)
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)
4.11		Form of Compensation Warrant (Incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 22, 2012)
4.12		Form of Warrant Certificate used in December 2012 registered offering (incorporated by reference to exhibit 4.1 to the Company’s Form 8-K filed on December 21, 2012)
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)
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 September 29, 2011 with Daniel J. Kunz (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on September 30, 2011)
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 6, 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 6, 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		At Market Issuance Sales Agreement dated September 30, 2011 between U.S. Geothermal Inc. and McNicoll, Lewis & Vlak LLC (Incorporated by reference to exhibit 1.1 to the registrant’s Form 8-K as filed on September 30, 2011).
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)
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		Amended and Restated Long-Term Portfolio Energy Credit and Renewable Power Purchase Agreement dated May 31, 2011 between Sierra Pacific Power Company d/b/a NV Energy, and USG Nevada LLC (Incorporated by reference to Exhibit 10.1 to the registrant’s Form 8-K filed on January 4, 2012)
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)
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 theregistrant’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)**
10.40		Loan Guarantee Agreement dated as of February 23, 2011, among USG Oregon LLC, U.S. Department of Energy, and PNC Bank N.A. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on August 31, 2011)
10.41		Equity Pledge Agreement dated as of February 23, 2011, among Oregon USG Holdings LLC, USG Oregon LLC, and PNC Bank, N.A. (Incorporated by reference to exhibit 99.3 to the registrant’s Form 8-K as filed on August 31, 2011)
10.42		Future Advance Promissory Note dated February 23, 2011, among USG Oregon LLC and Federal Financing Bank (Incorporated by reference to exhibit 99.4 to the registrant’s Form 8-K as filed on August 31, 2011)
10.43		Note Purchase Agreement dated as of February 23, 2011 among the Federal Financing Bank, USG Oregon LLC, and the Secretary of Energy, acting though the Department of Energy (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on September 15, 2011)
10.44		Financing Agreement dated November 9, 2011, between USG Nevada LLC and Ares Capital Corporation (incorporated by reference to Exhibit 10.1 to the registrant’s Form 8-K filed on November 16, 2011)
10.45		Purchase Agreement dated May 21, 2012, between U.S. Geothermal Inc. and Lincoln Park Capital Fund, LLC ( incorporated by reference to Exhibit 10.1 to the Registrant’s From 8-K as filed on May 22, 2012)
10.46		Amendment No. 1 to the Purchase Agreement with Lincoln Park Capital Fund, LLC, dated December 21, 2012 (incorporated by reference to exhibit 10.1 to the Company’s Form 8-K filed on December 21, 2012)
10.47		Form of Subscription Agreement used in December 2012 registered offering (incorporated by reference to exhibit 10.1 to the Company’s Form 8-K filed on December 21, 2012)
13.1		Audited Consolidated Financial Statements of U.S. Geothermal Inc. as of March 31, 2012.
21.1		Subsidiaries of the Registrant
23.1		Consent of MartinelliMick, PLLC
31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*Portions of these exhibits have been omitted based on a grant of, or an application for, confidential treatment from the SEC. The omitted portions of these exhibits have been filed separately with the SEC.

** Management contracts or compensation plans or arrangements in which directors or executive officers are eligible to participate.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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

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

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

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

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

		Page

PART IV

Item 15	Exhibits and Financial Statement Schedules	102

Projects Under Development
					Estimated
			Target	Projected	Capital
			Development	Commercial	Required
Project	Location	Ownership	(Megawatts)	Operation Date	($million)	Power Purchaser
El Ceibillo	Guatemala	100%	25	^4thQuarter 2015	$118	TBD
San Emidio Phase II	Nevada	100%	8.6	TBD ⁽¹⁾	$50	NV Energy
San Emidio Phase III	Nevada	100%	17.2	TBD ⁽¹⁾	$100	TBD
Neal Hot Springs II	Oregon	100%	28	TBD	TBD	TBD
Raft River (Unit II)	Idaho	100%	26	TBD	$134	TBD
Raft River (Unit III)	Idaho	100%	32	TBD	$166	TBD

				Page

PART I

Item 1	Business			6
		General		6
		Development of Business		8
			History	9
			Plan of Operations	9
			Material Acquisitions/Development	11
			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	21
			Dependence on a Few Customers	22
			Competitive Conditions	22
			Environmental Compliance	23
		Financial Information about Geographic Areas		24
		Available Information		25
		Governmental Approvals and Regulations		25
			Environmental Credits	26
Item 1A	Risk Factors			28
		General Business Risks		28
		Risks Relating to the Market for Our Securities		36
Item 1B	Unresolved Staff Comments			37
Item 2	Property			38
		Raft River, Idaho		39
		Raft River Energy Unit I		41
		Neal Hot Springs, Oregon		44
		San Emidio, Nevada		46
		Gerlach, Nevada		48
		Granite Creek, Nevada		49
		Republic of Guatemala		50
		Boise Administration Office, Idaho		50
Item 3	Legal Proceedings			51
Item 4	Mine Safety Disclosures			51

				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	64
			Results of Operations	67
			Liquidity and Capital Resources	77
			Potential Acquisitions	80
			Critical Accounting Policies	80
			Contractual Obligations	82
			Off Balance Sheet Arrangements	82
Item 7A	Quantitative and Qualitative Disclosures about Market Risk			82
Item 8	Financial Statements and Supplementary Data			83
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			83
Item 9A	Controls and Procedures			84
Item 9B	Other Information			85

PART III				86

Item 10	Directors, Executive Officers and Corporate Governance			86
Item 11	Executive Compensation			90
		Summary Compensation Table		94
		Outstanding Equity Awards at Fiscal Year-End		95
		Potential Payments Upon Termination or Change-in-Control		95
		Director Compensation		96
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			97
			Securities Authorized for Issuance under Equity Compensation Plans	97
			Security Ownership of Certain Beneficial Owners and Management	97
Item 13	Certain Relationships and Related Transactions, and Director Independence			99
Item 14	Principal Accountant Fees and Services			100

Additional Properties
Project	Location	Ownership	Target Development (Megawatts)
Gerlach	Nevada	60%	TBD
Granite Creek	Nevada	100%	TBD

Resource Details
			Resource
	Property Size	Temperature	Potential
Property	(square miles)	(^ºF)	(Megawatts)	Depth (Ft)	Technology
Raft River	10.8	275-302	127.0	4,500-6,000	Binary
San Emidio	35.8	289-305	64.0	1,500-3,000	Binary
Neal Hot Springs	9.6	311-347	50.0	2,500-3,000	Binary
Gerlach	5.6	338-352	18.0	TBD	Binary
Granite Creek	8.5	TBD	TBD	TBD	Binary
El Ceibillo	38.6	410-446	25.0	TBD	Steam

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

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

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

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

	1.	Geothermal well permits for production and injection wells issued by the Idaho Department of Water Resources.
	2.	A Conditional Use Permit for the first two power plants was issued by the Cassia County Planning and Zoning Commission on April 21, 2005.
	3.	The Idaho Department of Environmental Quality issued the Air Quality Permit to Construct on May 26, 2006.
	4.	A Wastewater Reuse Permit issued by the Idaho Department of Environmental Quality on February 23, 2007 is being renewed with the agency.

	1.	Geothermal well permits for production and injection wells issued by the Nevada Division of Minerals.
	2.	A Special Use Permit issued by the Washoe County Board of Commissioners on July 1, 1987.
	3.	An Air Quality Permit to Operate from Washoe County renewed on January 1, 2008.
	4.	A Surface Discharge Permit from Nevada Division of Environmental Protection issued on June 11, 2001.
	5.	An Underground Injection Permit from Nevada Division of Environmental Protection issued on August 18, 2000.

	1.	Geothermal Well Permits; Department of Geology; Multiple API #’s
	2.	Right-of-Way; Bureau of Land Management, OR-65701
	3.	Malheur County Conditional Use Permit; Malheur County, 10-21-2009
	4.	Underground Injection Control Permit; Oregon Department of Environmental Quality, 13281-8

	1)	Monthly production and injection reports which are filed with the Idaho Water Resources Department (IDWR);
	2)	Quarterly ground water monitoring reports which are filed with the Idaho Water Resources Department;
	3)	Annual land application and cooling 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.

		For the Nine
		Months Ended		For the Year
		December 31,		Ended March
		2012		31, 2012

Raft River Energy I LLC located in Southeastern Idaho	$	3,638,327	$	4,194,126
USG Nevada LLC located in Northwestern Nevada		2,632,502		1,699,987
USG Oregon LLC located in Eastern Oregon		2,329,030		-

Total energy and energy credits sales	$	8,599,859	$	5,894,113

Contract No.	Contract Expiration	Acres	Annual Rate
*San Emidio*
N63004	9/30/2013	1,280	$ 1,280
N63005	9/30/2013	1,279	1,279
N63006	9/30/2013	1,920	1,920
N63007	9/30/2013	1,920	1,920
N75233	11/1/2016	1,868	3,738
N75552	11/1/2012	2,560	2,560
N75555	11/1/2012	960	960
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	10/31/2016	1521	4,328

Sale Prices on the NYSE MKT
	High	Low
Fiscal Year Ended March 31, 2012	($)	($)
First Quarter	1.11	0.65
Second Quarter	0.74	0.45
Third Quarter	0.52	0.35
Fourth Quarter	0.65	0.34

Nine Months Ended December 31, 2012
First Quarter	0.51	0.35
Second Quarter	0.39	0.30
Third Quarter	0.44	0.27

Sale Prices on the TSX
	High	Low
Fiscal Year Ended March 31, 2012	(CDN$)	(CDN$)
First Quarter	1.07	0.67
Second Quarter	0.73	0.47
Third Quarter	0.52	0.36
Fourth Quarter	0.63	0.34

Nine Months Ended December 31, 2012
First Quarter	0.50	0.36
Second Quarter	0.40	0.30
Third Quarter	0.45	0.29

				Net
			Ave.	Operating		Depreciation
	Kilowatt	Energy	Rate per	Income		&
	Hours x	Sales	Kilowatt-	(Loss)		Amortization
Quarter Ended:	1,000	($)	Hour ($)	($)		($)
June 30, 2010	5,449	571,646	0.1049	(76,625	)	238,087
September 30, 2010	5,260	636,992	0.1210	(405	)	298,948
December 31, 2010	5,938	629,867	0.1061	(104,155	)	298,948
March 31, 2011	5,656	600,702	0.1062	(61,083	)	299,010
June 30, 2011	5,556	623,731	0.1123	(16,818	)	246,038
September 30, 2011	4,943	629,582	0.1274	45,876		210,366
December 31, 2011 ⁽¹⁾	3,291	361,876	0.1100	(433,861	)	206,522
March 31, 2012 ⁽¹⁾	-	-	-	(475,961	)	189,126
June 30, 2012 ⁽²⁾	5,465	427,931	0.0776	(8,748	)	181,333
September 30, 2012	8,280	745,494	0.0897	101,103		253,429
December 31, 2012	16,231	1,459,078	0.9000	(223,412	)	416,091

	(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.

	(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.

	For the Nine Months Ended December 31, 2012	For the Fiscal Years Ended March 31,
	For the Nine Months Ended December 31, 2012	2012	2011	2010	2009
Operating Revenues	$ 8,599,859	$ 5,894,113	$ 3,253,545	$ 2,579,152	$2,336,202
Operating Expenses	10,515,526	16,522,690	7,270,395	8,562,345	7,660,868
Loss from Continuing Operations	(1,915,667)	(10,789,284)	(4,039,350)	(5,983,193)	(5,324,666)
Loss per share from Continuing Operations	(0.01)	(0.07)	(0.05)	(0.09)	(0.08)
Cash dividends declared and paid per common share	-	-	-	-	-

	As of December 31, 2012	As of March 31,
	As of December 31, 2012	2012	2011	2010	2009
Total Assets	$240,496,096	$219,030,868	$ 85,322,968	$ 65,727,861	$ 52,451,343
Total Long-term Obligations (1)	104,318,236	69,495,470	18,326,802	2,080,859	1,972,200

	1)	Operating the new Phase I San Emidio power plant in Nevada;
	2)	Commissioning and operating the Neal Hot Springs power plant in Oregon;
	3)	Operating the Raft River Unit I power plant in Idaho;
	4)	Negotiating long term financing for the San Emidio Phase I power plant and for a potential future Phase II, and discussing development funding for Phase III;
	5)	Conducting negotiations on a power purchase agreement and discussions with potential equity partners for the El Ceibillo project in Guatemala;
	6)	Completing the environmental report, planning geophysical surveys and drilling program at El Ceibillo; and
	7)	The evaluation of potential new geothermal projects.

Projects in Operation
			Generating
			Capacity		Contract
Project	Location	Ownership	(megawatts)⁽¹⁾	Power Purchaser	Expiration
Raft River (Unit I)	Idaho	JV⁽²⁾	13.0	Idaho Power	2032

San Emidio (Unit I)	Nevada	100%	9.0	Sierra Pacific	2038

Neal Hot Springs	Oregon	JV(3)	22.0	Idaho Power	2036

(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.
(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)	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”). As of September 30, 2012, Enbridge has contributed approximately $32.8 million to the Neal Hot Springs geothermal project. The Company and Enbridge have not yet determined Enbridge’s current equity interest in the project, but current estimates show that Enbridge could own between 30% and 40% of the project depending on cash grant sharing and the return of unused contingency funds.

		Years 1 – 4 (2008-2011)	Years 5 – 10 (2012-2017)	Years 11 – 20 (2018-2027)	Years 20 – 25 (2028-2032)
Cash Flow	RECs	70% (1)
	GAAP Income	1% (2)		49%	80%
	Lease Payments, O&M Services & Royalties	100%
	Distributions	Guaranteed min. payment	1% (3)	49%	80%
Tax Benefits		1% (2)		49%	80%

	(1)	The Company 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 the Company’s Form quarterly report on 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.

	%* -	represents the percentage of total operating revenues.
	%** -	represents the percentage of change from the two periods presented. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

	⁽¹⁾	The old power plant ceased operations on December 12, 2011, to facilitate the transfer of operations to the new power plant.
	⁽²⁾	The new power plant became commercially operational on May 25, 2012. The plant produced power at a lower “test rate” in May and at the full contract rate of .08975 per kilowatt hour in June.

	Kilo-		Ave. Rate			Depreciation
	watt	Energy	per	Net Income		&
	Hours x	Sales	Kilowatt-	(Loss)*		Amortization
Quarter Ended:	1,000	($)	Hour ($)	($)		($)
September 30, 2010	16,116	1,019,499	0.0656	(123,032	)	511,771
December 31, 2010	17,878	1,173,232	0.0656	(13,931	)	511,505
March 31, 2011	16,898	914,457	0.0541	321,507		514,300
June 30, 2011	14,144	651,059	0.0487	(1,986,673	)	510,367
September 30, 2011	14,562	942,111	0.0673	(489,767	)	508,968
December 31, 2011	17,888	1,159,245	0.0670	(965,553	)	508,405
March 31, 2012	19,639	1,057,091	0.0557	(696,689	)	509,027
June 30, 2012	15,999	765,255	0.0503	(805,286	)	507,783
September 30, 2012	17,836	1,176,107	0.0681	2,348		505,560
December 31, 2012	21,170	1,398,218	0.0679	154,752		505,559

	For the Nine
	Months		For the Year
	Ended		Ended
	December		March 31,
	31, 2012		2012		Variance
Financial Element	$		$		$		%

Total all salary and related costs, excluding power plant operations	1,780,875		2,608,737		(827,862	)	(31.7	)

Salary and related costs capitalized for the following projects:
USG Nevada LLC (San Emidio Phase I Project)	(243,251	)	(670,990	)	364,739		54.4
USG Oregon LLC (Neal Hot Springs Project)	(623,555	)	(667,540	)	43,985		6.6
Small projects	(17,068	)	(32,746	)	15,678		47.9
Total salary and related expense	897,001		1,237,461		(340,460	)	(27.5	)

Quarterly Averages:
Total all salary and related costs, excluding power plant operations	593,625		652,184		(14,640	)	(2.2	)
Total salary and related expense	299,000		309,365		(10,365	)	(3.4	)

	Total	< 1 year	1-3 years	3-5 years	> 5 years
Operating Leases	$ 1,101,408	$ 200,308	$ 196,837	$ 157,167	$ 547,096
Capital Leases	114,317	45,278	138,078	-	-
Construction Loan ⁽¹⁾	28,694,812	1,710,000	2,150,000	3,200,000	21,634,812
Construction Loan ⁽²⁾	76,005,697	866,342	6,823,000	6,842,000	61,474,355
Retention payable ⁽³⁾	8,089,704	8,089,704	-	-	-
Convertible Loan ⁽⁴⁾	2,125,000	-	2,125,000	-	-

	(1)	Construction loan with SAIC that the Company anticipates will be replaced with long-term financing. Payout is estimated to occur over a 25 year period.
	(2)	Construction loan with the Department of Energy. Payout is estimated to occur over a 22 year period.
	(3)	Retention payable will be financed as part of the long-term financing described for the SAIC and DOE loans.
	(4)	Loan convertible to project equity in Oregon USG Holdings, LLC (Neal Hot Springs project).

*	Pro Forma/Unaudited. For informational purposes only.
(1)	Dollar value of base salary (cash and non-cash) earned by the Named Executive Officer during the fiscal year.
(2)	Dollar value of bonus (cash and non-cash) earned by the Named Executive Officer during the fiscal year. Bonuses are eligible to all employees and submitted and approved by the Board annually.
(3)	Stock options and restricted stock are valued at the grant date in accordance with FASB ASC Topic 718.
(4)	Other compensation consists of all other compensation not disclosed in another category.

	Option Awards				Stock Awards
	Number of	Number of
	Securities	Securities			Number of	Market Value of
	Underlying	Underlying			Shares or Units	Shares or Units of
	Unexercised	Unexercised	Option	Option	of Stock That	Stock That Have
	Options	Options ⁽¹⁾	Exercise Price	Expiration	Have Not Vested	Not Vested
Name	(#) Exercisable	(#) Unexercisable	($)	Date	(#)	($)
Daniel J. Kunz	250,000	0	2.22	5/19/13	0	0
Douglas J. Glaspey	250,000	0	2.22	5/19/13	0	0
Kerry D. Hawkley	100,000	0	2.22	5/19/13	0	0
Daniel J. Kunz	175,000	0	0.92	5/26/14	0	0
Douglas J. Glaspey	150,000	0	0.92	5/26/14	0	0
Kerry D. Hawkley	100,000	0	0.92	5/26/14	0	0
Jonathan Zurkoff	150,000	0	0.92	5/26/14	0	0
Daniel J. Kunz	200,000	0	0.86	9/10/15	0	0
Douglas J. Glaspey	100,000	0	0.86	9/10/15	0	0
Kerry D. Hawkley	50,000	0	0.86	9/10/15	0	0
Jonathan Zurkoff	145,000	0	0.86	9/10/15	0	0
Daniel J. Kunz	250,000	0	0.83	6/13/16	0	0
Douglas J. Glaspey	165,000	0	0.83	6/13/16	0	0
Kerry D. Hawkley	95,000	0	0.83	6/13/16	0	0
Jonathan Zurkoff	146,000	0	0.83	6/13/16	0	0
Daniel J. Kunz	61,750	185,250	0.31	8/24/17	0	0
Douglas J. Glaspey	47,500	142,500	0.31	8/24/17	0	0
Kerry D. Hawkley	37,500	112,500	0.31	8/24/17	0	0
Jonathan Zurkoff	37,500	112,500	0.31	8/24/17	0	0

Name	Fees earned or paid in cash ($)	Stock awards ($)	Option awards ⁽¹⁾ ($)	Non-equity incentive plan compens- ation ($)	Nonqualified deferred compensa- tion earnings ($)	All other compensa- tion ($)	Total ($)
John H. Walker	22,500	0	16,740	0	0	0	39,240

Paul A. Larkin	22,500	0	16,740	0	0	0	39,240

Leland L. Mink	22,500	0	16,740	0	0	0	39,240

Dennis J. Gilles	22,500	0	16,750	0	0	0	39,240

Equity Compensation Plan Information
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	10,239,625	$0.91	2,522,442
Equity compensation plans not approved by security holders	Nil	Nil	Nil
Total	10,239,625	$0.91	2,522,442

	Amount and Nature
Name and Address of Beneficial Owner	of Beneficial	Percent of
	Ownership	Class
Sprott Inc. 200 Bay Street, Suite 2700, PO Box 27 Toronto, ON, Canada M5J 2J1	9,980,873⁽¹⁾	9.83%

AGF Management Limited PO Box 50, Toronto Dominion Bank Tower, 31^stFloor, Toronto, ON, Canada M5K 1E9	5,203,762⁽²⁾	5.13%

The Goldman Sachs Group, Inc. 200 West Street, New York, NY 10282	5,036,378⁽³⁾	4.96%