10-K

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

FORM 10-K

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

For the year ended December 31, 2013

or

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

For transition period _______ to _______

Commission File Number 001-34023

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

Delaware	84-1472231
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)
390 Parkcenter Blvd, Suite 250
Boise, Idaho	83706
(Address of Principal Executive Offices)	(Zip Code)
Registrant’s Telephone Number, Including Area Code	208-424-1027

Securities registered pursuant to Section 12(b) of the Act:

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

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

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.

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

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 21, 2014, was $85,252,768

The number of shares outstanding of the registrant’s common stock as of March 21, 2014 was 102,714,178.

U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2013

		Page
PART I
Item 1	Business	6
	General	8
	Development of Business	8
	History	9
	Plan of Operations	10
	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	21
	Competitive Conditions	21
	Environmental Compliance	22
	Financial Information about Geographic Areas	24
	Available Information	24
	Governmental Approvals and Regulations	25
	Environmental Credits	26
Item 1A	Risk Factors	28
	Risks Related to Our Business	28
	Risks Related to Our Growth	34
	Risks Related to Our Power Purchase Agreements	39
	Risks Related to Our Liquidity and Capital Resources	40
	Risks Related to Government Regulation	43
	Risks Related to Ownership of Our Common Stock	45
Item 1B	Unresolved Staff Comments	48
Item 2	Property	49
	Neal Hot Springs, Oregon	50
	San Emidio, Nevada	51
	Raft River, Idaho	53
	Raft River Energy Unit I	55
	Gerlach, Nevada	58
	Granite Creek, Nevada	59
	Republic of Guatemala	60
	Boise Administration Office, Idaho	60
Item 3	Legal Proceedings	61
Item 4	Mine Safety Disclosures	61

U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2013

		Page
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	62
Item 6	Selected Financial Data	63
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	64
	Factors Affecting Our Results of Operations	72
	Operating Results	76
	Liquidity and Capital Resources	85
	Potential Acquisitions	88
	Critical Accounting Policies	89
	Contractual Obligations	90
	Off Balance Sheet Arrangements	91
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	91
Item 8	Financial Statements and Supplementary Data	91
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	92
Item 9A	Controls and Procedures	92
Item 9B	Other Information	93
PART III
Item 10	Directors, Executive Officers and Corporate Governance	94
Item 11	Executive Compensation	97
	Summary Compensation Table	106
	Outstanding Equity Awards at Fiscal Year-End	107
	Potential Payments Upon Termination or Change-in-Control	107
	Director Compensation	109
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	110
	Securities Authorized for Issuance under Equity Compensation Plans	110
	Security Ownership of Certain Beneficial Owners and Management	110
Item 13	Certain Relationships and Related Transactions, and Director Independence	112
Item 14	Principal Accountant Fees and Services	113

U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2013

		Page
PART IV
Item 15	Exhibits and Financial Statement Schedules	115

PART I

Item 1. Business

Information Regarding Forward Looking Statements

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

• our business and growth strategies;

• our future results of operations;

• anticipated trends in our business;

• the capacity and utilization of our geothermal resources;

• our ability to successfully and economically explore for and develop geothermal resources;

• our exploration and development prospects, projects and programs, including construction of new projects and expansion of existing projects;

• availability and costs of drilling rigs and field services;

• our liquidity and ability to finance our exploration and development activities;

• our working capital requirements and availability;

• our illustrative plant economics;

• market conditions in the geothermal energy industry; and

• the impact of environmental and other governmental regulation.

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

• the failure to obtain sufficient capital resources to fund our operations;

• unsuccessful construction and expansion activities, including delays or cancellations;

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• incorrect estimates of required capital expenditures;

• increases in the cost of drilling and completion, or other costs of production and operations;

• the enforceability of the power purchase agreements for our projects;

• impact of environmental and other governmental regulation, including delays in obtaining permits;

• hazardous and risky operations relating to the development of geothermal energy;

• our ability to successfully identify and integrate acquisitions;

• our dependence on key personnel;

• the potential for claims arising from geothermal plant operations;

• general competitive conditions within the geothermal energy industry; and

• financial market conditions.

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

The U.S. dollar is the Company’s functional currency; however some transactions involved the Canadian dollar. All references to “dollars” or “$” are to United States dollars and all references to CDN$ are to Canadian dollars.

U.S. Geothermal Inc. (the “Company,” “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.

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Development of Business

History

Geo-Idaho was formed as an Idaho corporation in February 2002 to conduct geothermal resource development.

U.S. Cobalt Inc. entered into a merger agreement with Geo-Idaho on February 28, 2002, which was amended and restated on November 30, 2003, and closed on the reverse take-over 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 was the surviving corporation and is the subsidiary through which the Company conducts operations. As part of this acquisition, the Company name was changed to U.S. Geothermal Inc. The Company currently owns and operates the following geothermal projects: Raft River, Idaho; San Emidio, Nevada; and Neal Hot Springs, Oregon. The Company also has property interests in the Republic of Guatemala, and Gerlach and Granite Creek, Nevada, some of which are under development or exploration.

On March 5, 2002, Geo-Idaho entered into a letter agreement with the owner of the Raft River project located in southeastern Idaho, pursuant to which Geo-Idaho agreed to acquire all of the real property, personal property and permits that comprised the owner’s interest in that project.

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 currently operates at a reduced output of 10 MW net, but has held steady at that level for over a year.

In May 2008, the Company acquired 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 included certain ground water rights, plus the Granite Creek geothermal prospect. Financing was secured 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, but has been rerated to 9.0 megawatts due to higher than expected efficiency. On February 15, 2013, USG Nevada LLC signed a second settlement agreement with SAIC. The settlement agreement reduced the construction cost and accrued interest liability incurred under the construction loan agreement by approximately $1.6 million. The agreement also defined the remaining liability as consisting of three components. The first component was a $1.0 million non-interest bearing note that was paid in full in June 2013. The second component was a $2,000,000 obligation that will be paid in quarterly installments that are scheduled through 2018. The third component was a balloon payment of $26,525,000 that was replaced with long-term financing. Effective May 1, 2013, USG Nevada LLC entered into a third credit addendum with SAIC. This addendum superseded the prior credit addendum and replaced the third component of obligation with a new aggregate indebtedness that totaled $26,350,000. The new obligation consisted of two components. The first component of $1,350,000 was paid in full as of the effective date of third credit addendum. The remaining portion of $25,000,000 was replaced by a long-term note held by Prudential Financial Group that was finalized on September 26, 2013. The Prudential loan will be repaid with quarterly payments that are scheduled through 2037. The Company has begun drilling in support of the development of a second phase of development. The current Power Purchase Agreement allows for 19.9 megawatts, but only 9 megawatts is currently committed, leaving a potential contacted expansion potential of 11 megawatts.

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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 the project in April 2009. In October 2011, USG Oregon LLC began drawing on the DOE loan. The Company received the Final Conditional Certificate on December 31, 2012 needed to receive the Oregon Business Energy Tax Credit (“BETC”). The Company was able to successfully monetize the BETC on November 14, 2013. Equity ownership interest in the project has now been determined with the Company owning 60%, and Enbridge owning 40%. The power plant became commercially operational on November 16, 2012. The final draw of the DOE loan occurred on July 31, 2013.

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 activities and the drilling of the first exploration well occurred during 2013. A 25 megawatt flash steam plant is targeted to be in operation in the fourth quarter of 2015.

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Plan of Operations

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

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

• Leverage Management Team Capabilities and Experience – Our strategy is focused on the identification and acquisition of resources that can be developed in a cost-effective manner to produce attractive returns. In particular, we seek to acquire projects that have already undergone geothermal resource discovery. In addition, we intend to operate and manage construction of the projects, while using internal personnel and third-party contractors to efficiently and cost-effectively develop those resources. We believe that we have the strategic personnel in place to determine which resources provide the greatest opportunity for efficient development and operation. We have developed relationships and employed personnel that will allow us to develop and utilize geothermal resources as efficiently as possible.

• Develop Our Pipeline of Quality Projects – Our project pipeline currently consists of several projects that we believe are aligned with our growth strategy. We are currently engaged in negotiation for the acquisition of additional Pipeline opportunities that are also aligned with our growth strategy. These projects typically have consulting reports from various industry experts supporting our belief in those projects’ potential. We are evaluating the potential of those projects and expect to negotiate Power Purchase Agreements for power deliveries with counterparties for some of these growth opportunities. If realized, our identified project pipeline will greatly expand our renewable power generation capacity as we move forward with the development of those opportunities.

• Utilize Production Tax Credits, Investment Tax Credits and Other Incentives – Although geothermal power production can be cost competitive with fossil fuel power generating facilities on a life cycle cost basis, government incentives such as production tax credits (“PTC”) and Investment Tax Credits (“ITC”) available to geothermal power producers enhance the project economics and attract capital investment. For the Raft River Unit I project, we partnered with Goldman Sachs as a tax equity partner to fully utilize production tax credits available to the project. Our strategy going forward is to structure project ownership to be the primary beneficiary of project economics. Under current legislation, a company may elect to take 30% ITC for certain qualified investments provided construction was started prior to the end of 2013. The second phase of our San Emidio project qualifies for this credit.

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• Pursue Acquisition Strategy – The geothermal market, particularly in the United States, is fragmented and characterized by a few large players and a number of smaller ones. Geothermal exploration and development is costly, technically challenging and requires long lead times before a project will produce revenue. We believe that geothermal technical and managerial talent is limited in the industry and that access to capital to develop projects will not be equally available to all participants. As a result, we believe that there will be opportunities in the future to pursue acquisitions of geothermal projects and/or geothermal development companies with attractive project pipelines.

• Evaluate Other Potential Revenue Streams from Geothermal Resources – In addition to electricity generation, we may evaluate additional applications for our geothermal resources including industrial, agriculture, and aquaculture purposes. These uses generally constitute lower temperature applications where, after driving a turbine generator, residual hot water can be cycled for secondary processes before being returned to the geothermal reservoir by injection wells, which can provide incremental revenue streams. We may evaluate the optimal use for each geothermal resource and determine whether selling heat for industrial purposes or generating and subsequently selling power to a grid will generate the highest return on the asset.

Material Acquisitions/Development

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

Projects Under Development
					Estimated
			Target	Projected	Capital
			Development	Commercial	Required
Project	Location	Ownership	(Megawatts)	Operation Date	($million)	Power Purchaser
El Ceibillo Phase I	Guatemala	100%	25	4th Quarter 2015	$135	MOU
San Emidio Phase II	Nevada	100%	11	4th Quarter 2015	$55	NV Energy

Additional Properties
Project	Location	Ownership	Target Development (Megawatts)
Gerlach	Nevada	60%	TBD
Granite Creek	Nevada	100%	TBD
El Ceibillo Phase II	Guatemala	100%	25
San Emidio Phase III	Nevada	100%	17.2
Neal Hot Springs II	Oregon	100%	28
Raft River Unit II	Idaho	100%	26
Raft River Unit III	Idaho	100%	32

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Resource Details
	Property Size	Temperature
Property	(square miles)	(º F)	Depth (Ft)	Technology
Raft River	10.8	275-302	4,500-6,000	Binary
San Emidio	35.8	289-316	1,500-3,000	Binary
Neal Hot Springs	9.6	311-347	2,500-3,000	Binary
Gerlach	5.6	338-352	2,000-3,000	Binary
Granite Creek	3.8	TBD	TBD	Binary
El Ceibillo	38.6	410-526	1,800-TBD	Steam

Neal Hot Springs, Oregon
Neal Hot Springs is located in Eastern Oregon near the town of Vale, the county seat of Malheur County. The Neal Hot Springs facility is designed as a 22 megawatt net annual average power plant, consisting of three separate, 7.33 net megawatt modules. 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 2013 totaled 53,445 megawatt-hours with an average of 25.62 net megawatts per hour of operation. Plant availability was 94.7% during the quarter as plant operations continue to improve. Generation for the year was 155,430 megawatt-hours with annual plant availability of 83.1% .

On June 27, 2013, the Company accepted substantial completion by the EPC contractor of all three of the Neal Hot Springs units. Final completion of the project was achieved on July 31, 2013.

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 DOE loan for the project was closed at final completion and has a balance of $70.4 million that bears an interest rate of 2.6% over a 22 year term. The construction cost of the project has been set at $128.1 million. Total project cost, including $11.2 million in reserves, was $139.3 million, which is $4.3 million less than previously reported due primarily to the inclusion of unused contingency funds which have since been released by the project lender.

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 to complete the well field. Each of the additional investments made by Enbridge Inc. was subject to calculations which would result in increased ownership interest in the project.

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Subsequent to the end of the quarter, in February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal received an approximate $6.2 million cash distribution from the partnership.

The project received a $32.75 million cash grant under Section 1603 Specified Energy Property in Lieu of Tax Credits from the Treasury Department. The cash grant, originally approved at $35.4 million, was subject to an 8.7% reduction due to Federal sequestration ordered by Congress under the Budget Control Act. The proceeds from the grant were used to: 1) fund $11.2 million in project level cash reserves as required by the terms of the DOE loan, 2) pay down $11.9 million on the DOE loan and 3) the balance of $9.7 million was distributed to 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. The Company received unconditional approval of the final certificate on March 1, 2013. The BETC was sold to a pass-through tax partner in November 2013 for approximately $7.36 million.

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. Power generated during 2013 was paid at an average price of $99.00 per megawatt-hour. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.3% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $102.78 per megawatt-hour.

San Emidio, Nevada
The Phase I power plant at San Emidio is located approximately 100 miles north of Reno, Nevada and achieved commercial operation on May 25, 2012. Generation from the facility during the fourth quarter 2013 totaled 21,103 megawatt-hours, with an average of 9.72 net megawatts per hour of operation. Plant availability was 98.3% during the quarter. Generation for the year was 76,696 megawatt-hours with annual plant availability of 94.5% .

The Company entered into agreements with Science Applications International Corporation (“SAIC”) for a project loan and an engineering procurement and construction (“EPC”) contract for the San Emidio Phase I power plant repower. SAIC’s design-build subsidiary, SAIC Energy, Environment & Infrastructure LLC, constructed a new 9.0 net megawatt power plant, replacing the old 3.6 net megawatt power plant. TAS Energy of Houston, Texas, supplied a modular power plant to the project. 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. SAIC provided its services under a fixed price contract that included financial guarantees for the original completion date and power output of the plant. The Phase I plant completed its capacity testing during the first quarter of 2013, and as a result of the capacity test exceeding the designed output; the plant was up-rated to 9.0 megawatt net annual average per hour from the design point basis of 8.6 megawatts.

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Substantial Completion under the contract was achieved February 21, 2013. Final Completion under the terms of the EPC was executed on June 24, 2013.

A final settlement agreement was executed as part of Substantial Completion and included a fixed total construction loan payable to the EPC contractor of $29.5 million. Prior to Substantial Completion, the Company had paid down the loan balance by $1.0 million in three monthly payments. Upon Substantial Completion, a payment of $1.35 million was made to SAIC, and the construction loan was extended until November 15, 2013 with a balance of $25.0 million carrying an interest rate of 10%. Additionally, a $2.0 million, 5 year term, unsecured loan was put in place for the balance of the construction loan. This loan bears interest at 7% and has a payment obligation of $119,382 per quarter.

The $25 million construction loan with SAIC was paid off in September of 2013, and was replaced with long term notes purchased by Prudential Capital Group’s related entities. The notes are for an aggregate of approximately $30.74 million, have a term of approximately 24 years, and bear a fixed interest rate of 6.75% per annum. Proceeds from the sale of the notes were used to repay the SAIC construction loan, fund project reserves, and pay certain closing expenses, and approximately $2.56 million of the proceeds was distributed to U.S. Geothermal Inc. to be used for general corporate working capital purposes, including the further development of Phase II at San Emidio.

The Phase II expansion was delayed due to the extended time required to get Phase I online, and is still dependent on successful development of additional production and injection well capacity. The cost of development for Phase II is estimated at approximately $55 million. We expect that approximately 75% of the Phase II development may be funded by project loans, with the remainder funded through equity financing.

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. Power generated during 2013 was paid at the price of $90.27 per megawatt-hour. The average price paid under the PPA for 2014 has increased to $91.17 per megawatt-hour.

The electrical output from both Phase I and Phase II may 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. If Phase II cannot achieve commercial operation under a proposed milestone schedule by December 2015, a new PPA would need to be negotiated and signed before financing and construction could begin. A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010. Subsequent to the end of the year, an application to increase the interconnection agreement to the full 19.9 megawatts allowed under the PPA was submitted to NV Energy on January 9, 2014.

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On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio 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.

The DOE cost shared drilling program continues with the further resource identification in the South Zone and the addition of the resource identification in the North Zone. The North Resource Area, has an additional five observation/temperature gradient wells and one production well planned as part of the cost share drilling program. Drilling began on well OW-12 on September 2, 2013. The well was completed on October 23, 2013 to a depth of 3,643 feet and is being evaluated in relation to the San Emidio reservoir model. Well 61-21 (formerly OW-10) in the South Zone, was reworked beginning on October 25, 2013 and was completed on November 2, 2013. Flow testing of 61-21 is planned for the spring or early summer. The results from both wells will be used to determine the continuing resource development plan in support of the Phase II plant construction.

In addition, permitting was initiated with the Bureau of Land Management for four new observation wells to be drilled in the South Zone to follow up on the high temperatures found in wells 61-21 (302°F) and 45-21 (316°F). Subsequent to the end of the quarter, a seismic program was carried out covering three lines in the South Zone to provide additional data for targeting the next drill holes.

Raft River, Idaho
The Raft River project is located in Southern Idaho, near the town of Malta, and achieved commercial operation in January 2008. Generation from the facility during the fourth quarter 2013 totaled 21,742 megawatt-hours, with an average of 9.85 net megawatts per hour of operation. Plant availability was 99.2% during the quarter. Generation for the year was 77,552 megawatt-hours with annual plant availability of 96.5% .

The PPA for the project was signed on September 24, 2007 with the Idaho Power Company. The PPA has a 25 year term with a starting average price for the year 2007 of $52.50 that escalates at 2.1% per year. Power generated during 2013 was paid at an average price of $59.47 per megawatt-hour. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.5% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $60.72 per megawatt-hour. In addition to the price paid for energy, Raft River currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits.

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The DOE $11.4 million cost-shared, thermal fracturing program began the first stage of injection in June 2013 and continued until September when the second stage was started. Four, 300 foot deep seismic monitoring wells were completed in the area around well RRG-9 and seismic geophones were installed. Seismic monitoring will be conducted for the duration of the thermal fracturing program. Injection continued through the fourth quarter from power plant injectate at an approximate temperature of 140°F. Flow in to the well has seen a moderate increase indicating that additional permeability is developing. The program has continued through the winter with low level injection going in to the well with a high pressure injection phase planned for spring 2014.

If the fracturing 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 for the thermal fracturing program are made in-kind by the use of the RRG-9 well, well field data, and monitoring support totaling $991,417.

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 has a 5 year term for the development and construction of a power plant. Discussions are being held with the Guatemalan Ministry of Energy and Mines to allow a new schedule based on the current status of the project. There are 24,710 acres (100 square kilometers) in the concession which is at 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.

During the first phase of drilling on well EC-1, the well was drilled to a depth of 4,829 feet (1,472 meters) and encountered a bottom hole temperature of 491°F (255°C), with the temperature gradient at the bottom of the hole rising at a rate of 7.1°F/100 Feet (129.1°C/km) . High temperatures in excess of 392°F (>200°C) were encountered in the well beginning at a depth of 2,625 feet (800 meters), which represents a potential high temperature reservoir interval in excess of 2,204 feet (672 meters). Due to the high temperature gradient found in the lower section of the well, the decision was made to deepen the well, and a second phase of drilling commenced on August 21, 2013. The final depth of the well, reached on September 15, 2013 is 5,650 feet (1,722 meters) with a measured bottom-hole temperature of 526°F (274°C). Clean out and short term flow tests were conducted along with temperature surveys, and the data was provided to a third party consulting group with specific expertise in volcanic geothermal resources for analysis and evaluation. Planning is underway for another round of drilling to further delineate the El Ceibillo resource. Subsequent to the end of the year, a temperature gradient (“TG”) drilling program was initiated with a series of 200 meter (656 foot) deep wells planned for the first quarter of 2014. Nine TG wells have been completed and the results are being evaluated.

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In early September 2013, the Guatemalan Ministry of the Environment and Natural Resources (“MARN”) issued the Environmental License for the construction and operation of the planned, first phase, 25 megawatt power plant at the El Ceibillo site. The license is based on the Environmental Impact Assessment Study that was submitted in December 2012, describing the initial design of the 25 megawatt facility, and requires the submittal of final design specifications for review by MARN prior to starting physical construction of the plant. Additionally, the license requires compliance with all legal and regulatory requirements under Guatemalan law, submittal of an air quality monitoring plan, and that final design comply with the strict guidelines for noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an environmental bond of $344,850 Quetzals (approximately US $45,000) was posted with the Ministry of Environment and Natural Resources.

An initial development of a 25 megawatt (Phase I) 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.

The El Ceibillo geothermal project area had nine previous wells drilled into the geothermal concession drilled in the 1990s and having depths ranging from 560 to 2,000 feet (170 to 610 meters). A few of those wells had adequate flow and temperature to support a direct use application. Six of the wells had measured reservoir temperatures in the range of 365°F to 400°F and had high conductive gradients that indicated rapidly increasing temperature with depth.

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Fluid samples and mineralization from the wells indicated the existence of a high permeability reservoir below or near the existing well field.

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 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.

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Employees

At December 31, 2013, the Company had 46 full-time and 1 part time employees (13 administrative and project development, and 34 field and plant operations). The Company continuously considers acquisition opportunities, and if the Company is successful in making acquisitions, additional management and administrative staff may be added.

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

Principal Products

The principal product is based upon activities related to the production of electrical power from the utilization of the Company’s geothermal resources. The primary product will be the direct sale of power generated by our interests in our geothermal power plants. Currently, our principal revenues consist of energy sales and energy credit sales. All power plants currently under exploration or development are sites located in the Western Region of the United States of America or in the Republic of Guatemala.

Sources and Availability of Raw Materials

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

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

1.	Heat source and temperature – The economic viability of a geothermal resource is related to the amount of heat generated. The higher the temperature, the more valuable the geothermal resource.
2.	Fluid – A geothermal resource is commercially viable only when the system contains water and/or steam as a medium to transfer the heat energy to the surface.
3.	Permeability – The fluid present underground must be able to move. In general, significant porosity and permeability within the rock formation are needed to create a viable reservoir.
4.	Depth – The cost of development increases with depth, as do resource temperatures. The proximity of the reservoir to the surface is therefore a key factor in the economic valuation of a geothermal resource.

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

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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 9.0 net megawatt geothermal plant in operation. Neal Hot Springs, Oregon is a proven geothermal resource and has a 22 net megawatt annual average geothermal power plant in operation. Unless major geological changes occur that impact the geothermal reservoirs, the condition of the existing resources is expected to remain relatively consistent over time.

Significant Patents, Licenses, Permits, Etc.

Neal Hot Springs. The Neal Hot Springs project has four primary permits that govern the continued operations at the Neal Hot Springs geothermal plant. The permits include:

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

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

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

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

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

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Seasonality of Business

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 can be negatively impacted by inclement weather that can occur, primarily, during the winter months.

Industry Practices/Needs for Working Capital

The Company is heavily involved in development operations; therefore high levels of working capital are committed, either directly or indirectly to the construction efforts. After a plant becomes commercially operational and the necessary operating reserves have been funded, the needs of working capital are typically low. The Company is expecting to be significantly involved in development activities for the next 5 to 10 years.

Dependence on a Few Customers

Ultimately, the market for electrical power is vast; however, the numbers of entities that can physically, logistically and economically purchase the commodity in large quantities in our area of operations are limited. The Company’s primary revenues originate from energy sales and the sale of energy credits. Currently, the Company generates energy revenues 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 5 or 6 over the next 5 to 10 years.

Competitive Conditions

Although the market for different forms of energy is large and dominated by very powerful players, we perceive our industrial competition to be independent power producers and in particular those producers who provide “green” renewable power. Our definition of green power is electricity derived from a source that does not pollute the air, water or earth. Sources of green power, in addition to geothermal, include wind, solar, biomass and run-of-the river hydroelectric. A number of states have instituted renewable portfolio standards (“RPS”) that require utilities to purchase a minimum percentage of their power from renewable sources. For example, RPS statutes in California 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.

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

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

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

Environmental Compliance

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.

Since operations have been initiated, key environmental reports include:

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.

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

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.

Neal Hot Springs
The Neal Hot Springs project is also well situated in an area with only two nearby residents. There are no unique plants 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 124,490 square feet of covered industrial warehouse and offices. The nearest residence is over four miles from the plant site.

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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.

Financial Information about Geographic Areas

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. USG Nevada LLC constructed a new power plant located in the northwestern part of the State of Nevada in the San Emidio Desert. This power plant owned by USG Nevada LLC became commercially operational May 25, 2012. The three units owned by USG Oregon LLC became commercially operational November 16, 2012. These units are located in the Eastern part of the State of Oregon near the Idaho border. A summary of total energy and energy credit sales by location is as follows:

		For the Year Ended December 31,
		2013		2012
USG Oregon LLC located in Eastern Oregon	$	15,566,409	$	2,329,030
USG Nevada LLC located in Northwestern Nevada		6,792,382		2,626,378
Raft River Energy I LLC located in Southeastern Idaho		5,012,143		4,803,537
Total energy and energy credits sales	$	27,370,934	$	9,758,945

Available Information

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

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Governmental Approvals and Regulation

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.

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Environmental Credits

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

As a “green” power producer, environmental-related credits, such as renewable energy credits or carbon credits, are also available for sale to power companies (to allow them to meet their “green” power requirements) or to businesses which produce carbon based pollution. In all of the Company’s projects, these credits have been sold separately, or bundled with the electricity to provide an additional source of revenue.

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

Production Tax Credits and Investment Tax Credits. A Production Tax Credit (PTC) provides 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 as much as 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 2013 was 2.3 cents per kilowatt-hour. Alternatively, certain projects under construction before the end of 2013, are eligible to elect to take a 30% Investment Tax Credit (ITC) in lieu of the PTC. The ITC may be taken after the plant has gone into operation and monetized. Both PTC and ITC credits require a tax equity partner to monetize.

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 Energy Unit I power production on October 2007, and is expected to continue purchasing through 2017. Under the revised RREI 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.

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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 of RECs annually, representing the 49% ownership in RECs retained by RREI under the Idaho Power PPA.

The power purchase agreements for the existing San Emidio and Neal Hot Springs power plants require the bundling of power sales and RECs. Therefore, under these contracts all RECs are delivered with the net power sold to the utility.

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Item 1A. Risk Factors

Investing in our common stock involves a high degree of risk. You should carefully consider the following risk factors, as well as the other information in this 10-K filing and related financial statements, before deciding whether to invest in shares of our common stock. The occurrence of any of the following risks, or other risks that are currently unknown or unforeseen by us, or that we currently believe are not material, could harm our business, financial condition, results of operation or growth prospects. In that case, you may lose all or a portion of your investment.

We have organized the following risk factors into categories to present related risks together. As a consequence of this, it is highly recommended that you read this entire risk factor section completely. The risks we have identified have been grouped into the following categories:

• Risks Related to Our Business;
• Risks Related to Our Growth;
• Risks Related to Our Power Purchase Agreements;
• Risks Related to Our Liquidity and Capital Resources;
• Risks Related to Government Regulation;
• Risks Related to Ownership of Our Common Stock.

Risks Related to Our Business

Our geothermal power plants have numerous pieces of equipment that are subject to breakdown or failure, many beyond our control. Failure of critical equipment could have a material impact on electrical generation and associated revenues. Our financial performance depends on the successful operation of our geothermal power plants, which are subject to numerous operational risks that are outside of our control. The continued operation of our geothermal power plants involves many risks, including breakdown or failure of power generation equipment, transmission lines, pipelines, geothermal pumps or other equipment or processes, and performance below expected levels of output or efficiency. If any of these risks were to materialize, they could have a material and adverse effect on our financial condition and results of operations.

A breakdown or failure in our geothermal power plants, our power generation equipment, the transmission lines, pipelines, geothermal pumps or other equipment or processes would also mean lost revenue because such a failure or breakdown could prevent us from selling electricity to our customers. For instance, because we rely on transmission lines owned by third parties to deliver all of the power that we generate to the purchasers of our electricity, any interruption in a transmission line’s service could result in lost revenue. Any such interruption in our ability to provide electricity to our customers on a timely basis could therefore materially and adversely affect our financial condition and results of operations.

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Our geothermal reserves could decline in the future. Declines greater than those that we expect would reduce our electricity production levels, which could have a material adverse effect on our ability to generate revenue. We currently derive all of our revenue from geothermal energy and anticipate that we will continue to generate substantially all of our revenue from our current geothermal power plants for the next several years. Electricity production from geothermal properties can decline as the water resources in the earth are used, with the rate of water or temperature decline depending on reservoir characteristics and our ability to re-inject water effectively back into the earth. Therefore, we try to minimize the decline in water and temperature of the water in the ground and maximize the resources that we use to generate electricity. For each of our geothermal power plants, we estimate the productivity of the geothermal resource and the expected decline in productivity. We base our operating plans and financial models on these estimates of resources. However, because the development and operation of geothermal energy resources are subject to substantial risks and uncertainties, the productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the electrical power capacity desired. Factors that could adversely affect our geothermal reserves and result in decline rates greater than we forecast include, among others:

• significant changes in the characteristic of the geothermal resource;
• drilling in areas in and around our facilities by third parties; and
• the total amount of recoverable reserves.

An unexpected decline in productivity of our geothermal resources would therefore reduce the amount of electricity that we can produce and, therefore, the revenue that we will be able to generate from our geothermal resources.

We cannot assure you that our estimates of future generation resources, production capacity and cash flows are accurate. Estimates of future generation resources and the future net cash flows attributable to those resources are prepared by independent engineers, geologists and geoscientists. There are numerous uncertainties inherent in estimating these resources and the potential future cash flows attributable to such resources. Reserve engineering is a subjective process of estimating underground accumulations that cannot be measured in an exact manner. The accuracy of an estimate of quantities of resources, or of cash flows attributable to such resources, is a function of the available data, assumptions regarding future electricity prices and expenditures for future development and exploitation activities, and of engineering and geological interpretation and judgment. In order to undertake these estimates and studies, independent third parties must often rely to some extent on our own estimates and data, which we believe are reasonable and accurate but which may ultimately be proved to be incorrect. Actual future production, revenue, taxes, development expenditures, operating and royalty expenses, quantities of recoverable resources and the value of cash flows from such resources may vary significantly from the assumptions and underlying information set forth herein. In addition, different reserve engineers may make different estimates of resources and cash flows based on the same available data. We cannot assure you that we will accurately estimate the quantity or productivity of our geothermal resources.

Our results are subject to quarterly and seasonal fluctuations. Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including:

• seasonal variations in ambient weather conditions;
• variations in levels of production; and
• the completion of exploration and production projects.

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Operating hazards, natural disasters or other interruptions of our geothermal power plant operations could result in potential liabilities, which may not be fully covered by our insurance. The geothermal business involves certain operating hazards such as:

• well blowouts;
• casing deformation;
• casing corrosion;
• uncontrollable flows of steam and hot water;
• pollution; and
• induced seismic activity.

The occurrence of any one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties.

In addition, all of our operations are susceptible to damage from natural disasters, such as earthquakes and fires, which involve increased risks of personal injury, property damage and service interruptions. Any of these events could cause serious injuries, fatalities or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development and acquisition, or could result in a loss of our properties. Our insurance policies are subject to deductibles, limits and exclusions that are customary or reasonable given the cost of procuring insurance, current operating conditions and insurance market conditions. There can be no assurance that such insurance coverage will continue to be available to us on an economically feasible basis, nor that all events that could give rise to a loss or liability are insurable, nor that the amounts of insurance will at all times be sufficient to cover each and every loss or claim that may occur involving the operations of our assets. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we do not have liability insurance, our business, results of operations and financial condition could be materially and adversely affected.

Our geothermal resource leases may terminate if not placed into production, which could require 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 originally for a fixed term but provide for continuation for so long as we extract geothermal resources in “commercial quantities” or pursuant to other terms of extension. Most of the leases have been producing in “commercial quantities” for many years. The land covered by a few of our periphery leases have yet to produce “commercial quantities” of geothermal resources. Leases covering land that remains undeveloped and does not produce geothermal resources in commercial quantities will terminate. In the event that we determine that a terminated lease is subsequently required for a project, we would need to enter into one or more new leases in order to develop and exploit these geothermal resources. It may not be possible to enter into new leases or these new leases could be on less favorable financial terms than the prior leases, which could materially and adversely affect our ability to achieve commercial success on the applicable project.

Pursuant to the terms of our leases with the United States Bureau of Land Management, which we refer to as BLM, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any applicable regulations governing our use of the land, the BLM may, thirty days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, operating results and cash flow.

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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 where our current projects are located 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.

As an SEC reporting company, failure to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could in turn have a material and adverse effect on our business and stock price. Under current rules of the SEC, we are required to document and test our internal control over financial reporting so that our management can certify as to the effectiveness of our internal control over financial reporting and our independent registered public accounting firm can render an opinion on management’s assessment. We cannot be certain as to the timing of completion of our evaluation, testing and remediation actions, if any, related to internal controls and other SEC rules or the impact of the same on our operations. The assessment of our internal control over financial reporting will require us to expend significant management and employee time and resources and incur significant additional expense.

During the course of our assessment of the effectiveness of our internal control over financial reporting, we may identify material weaknesses in our internal control over financial reporting, as well as any other significant deficiencies that may exist or hereafter arise or be identified, which could harm our business and operating results, and could result in adverse publicity, regulatory scrutiny and a loss of investor confidence in the accuracy and completeness of our financial reports. In turn, this could have a materially adverse effect on our stock price, and, if such weaknesses are not properly remediated, could adversely affect our ability to report our financial results on a timely and accurate basis. Although we believe we would be able to take steps to remediate any material weaknesses we may discover, we cannot assure you that this remediation would be successful or that additional deficiencies or weaknesses in our controls and procedures would not be identified. In addition, we cannot assure you that our independent registered public accounting firm will agree with our assessment that any identified material weaknesses have been remediated. Moreover, we expect to continue to operate at a relatively low staffing level. Our control procedures have been designed with this staffing level in mind; however, they are highly dependent on each individual’s performance of controls in the required manner. The loss of accounting personnel, particularly our chief financial officer, would adversely impact the effectiveness of our control environment and our internal controls, including our internal control over financial reporting.

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Our participation in joint ventures is subject to risks relating to working with a co-venturer. We are subject to risks in working with a co-venturer that could adversely impact our current projects as well as anticipated development of expansion projects. It’s possible that the proposed project expansions may utilize the geothermal resource within the current joint venture boundaries. Our required contribution to the joint venture could also exceed returns from the joint venture.

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.

Counterparty credit default could have an adverse effect on the Company. Our revenues are generated under contracts with various counterparties. Results of operations would be adversely affected as a result of non-performance by any of these counterparties of their contractual obligations under the various contracts. A counterparty’s default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to the counterparty, or due to circumstances caused by other market participants having a direct or indirect relationship with such counterparty. We seek to mitigate the risk of default by evaluating the financial strength of potential counterparties and utilizing industry standard credit provisions in our contracts, however, despite our mitigation efforts, defaults by counterparties may occur from time to time, and this could negatively impact our results of operations, financial position and cash flows.

Environmental liabilities and compliance costs could adversely affect our financial condition.

The geothermal business is subject to environmental hazards, such as leaks, ruptures and discharges of geothermal fluids and hazardous substances, emissions of toxic gases and disposal of hazardous substances. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. In addition, we also may be liable for environmental damages caused by the previous owners or operators of properties we have purchased or are currently operating.

A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:

• water extraction from surface streams and lakes;
• well drilling or workover, operation and abandonment;
• waste management;
• injection well classifications;

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• land reclamation;
• financial assurance, such as posting bonds; and
• controlling air, water and waste emissions.

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities and could lead to a curtailment or shut down of one or more of our plants. Additionally, our compliance with these laws may result in increased costs to our operations or our exploration, acquisition and development of new plants or may result in decreased production from our existing plants. We are unable to predict the ultimate cost of complying with these regulations. Pollution and similar environmental risks generally are not fully insurable.

We use industrial lubricants and other substances at our projects that are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the projects, we could become liable for the investigation and removal of those substances, regardless of their source or time of release. If we fail to comply with these laws, ordinances or regulations, we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the projects into compliance. Furthermore, we can be held liable for the cleanup of releases of hazardous substances at other locations where we arranged for disposal of those substances, even if we did not cause the release at that location. The cost of any remediation activities in connection with a spill or other release of such substances could be significant.

Our geothermal facilities have been in operation for a substantial length of time, and current or future local, state and federal environmental and other laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these laws and regulations.

We depend on our senior management, geothermal resource and other technical employees. The loss of these employees could harm our business. We are dependent upon the services of our Chief Executive Officer, Dennis J. Gilles, our President and Chief Operating Officer, Douglas J. Glaspey, our Chief Financial Officer, Kerry D. Hawkley, and our Treasurer and Executive Vice President, Jonathan Zurkoff. 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 success depends on the skills, experience and efforts of our people, particularly our senior management, geothermal resource and other technical employees. The geothermal industry is relatively small with a limited number of individuals with the management, technical and operational expertise necessary to run and operate facilities. In addition, many of our workers have significant and unique knowledge on how to manage and operate geothermal facilities. The loss of the services of one or more members of our senior management or of numerous employees with critical skills could have a negative effect on our business.

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 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.

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Our officers and directors may have conflicts of interests arising out of their relationships with other companies. Several of our directors and officers serve (or may agree to serve) as directors or officers of other companies or have significant shareholdings in other companies. To the extent that such other companies may participate in ventures in which the Company may participate, the directors may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation.

Risks Related to Our Growth

Our growth prospects depend in part on our ability to further develop or acquire geothermal or other renewable energy power generation facilities and resources, which are subject to substantial risks. Because production from geothermal properties generally declines as both water and temperature is depleted, with the rate of decline depending on reservoir characteristics, our geothermal resources will decline as we continue to produce electricity unless we conduct other successful exploration and development activities or supplement the current amounts of water that we inject into the reservoir with sufficient water from other sources, or both. The acquisition and development of geothermal power generation facilities and resources is complex, expensive, time consuming and subject to substantial risks, many of which are outside of our control. In connection with the development of geothermal power generation facilities and resources, we must:

• identify suitable locations and appropriate technology;
• secure rights to exploit the resources;
• obtain sufficient capital and revenue sources;
• obtain appropriate governmental permits;
• maintain cost controls during construction; and
• identify, hire and retain a qualified work force.

We may be unsuccessful in accomplishing any of these matters or in doing so on a timely basis. In our exploration efforts, we may not find commercially productive reservoirs or, if we do, the remote location of the resource may hinder our access to markets or delay our production. In addition, project development is subject to various environmental, engineering and construction risks. Although we may attempt to minimize the financial risks in the development of a power generation facility by obtaining all required governmental permits and approvals and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable.

In addition, community opposition could delay or prevent us from obtaining the necessary approvals The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. If we are unable to complete the development of a facility, we would most likely not recover any of our investment in the project. We cannot assure you that we will be successful in the acquisition of additional geothermal resources or development of power generation facilities in the future or that we will be able to successfully complete construction of our facilities currently in development, nor can we assure you that any of these facilities of resources will be profitable or generate consistent and reliable cash flow.

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Actual costs of construction or operation of a power plant may exceed estimates used in negotiation of power purchase and power financing agreements. If the actual costs of construction or operations exceed the costs used in our economic model, 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. As an example, 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 used 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, maintenance and management.

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

• failure of the acquired companies to achieve the results we expect;
• inability to retain key personnel of the acquired companies;
• risks associated with unanticipated events or liabilities; and
• the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.

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.

Our development activities are inherently very risky. The high risks involved in the development of a geothermal resource must be emphasized. The development of geothermal resources at our projects is 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 and testing, 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 resources can result in well depths that are relatively deep with well costs typically proportionate to the depth and geology encountered. Drilling may involve unprofitable efforts, not only from dry wells, but also from wells that do not produce sufficient volumes to generate net revenues that provide a profit after drilling, operating and other costs.

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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, chemical corrosion, 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.

Our exploration and development activities may not be commercially successful. Exploration activities involve numerous risks, including the risk that no commercially productive reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• unexpected drilling conditions; irregularities in formations; equipment failures or accidents;
• compliance with governmental regulations;
• unavailability or high cost of drilling rigs, equipment or labor;

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, results of operations and financial position.

Our acquisition strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions. Our growth strategy may include acquiring geothermal and other renewable energy businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully.

Furthermore, acquisitions involve a number of risks and challenges, including:

• diversion of management’s attention;
• the need to integrate acquired operations;
• potential loss of key employees of the acquired companies;
• greater geographic dispersion of employees;
• the potential that we may make bad acquisitions;

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• potential lack of operating experience in a geographic market of the acquired business; and
• an increase in our expenses and working capital requirements.

Any of these factors could materially and adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.

Development and expansion are dependent on the ability to successfully complete drilling activity. Drilling and exploration are the main methods of establishing new reserves. However, drilling and exploration may be curtailed, delayed or cancelled as a result of:

• availability of equipment, particularly drilling rigs and well casing;
• lack of acceptable prospective acreage;
• inadequate capital resources;
• weather;
• compliance with governmental regulations; and
• mechanical difficulties;
• opposition to development.

Natural gas prices are volatile, and a decline in gas prices would affect significantly the electricity prices we are able to obtain future PPA contracts. Development of our new plants depends on the prices we are able to negotiate in our long term Power Purchase Agreements (“PPAs”). The prices of those PPAs in today’s market are substantially associated with the prices and demand for natural gas. The markets for these commodities are volatile, and modest drops in prices can affect significantly our financial results and impede our growth. Prices for natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control, such as:

• domestic and foreign supply of oil and gas;
• price and quantity of foreign imports;
• actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;
• domestic and foreign governmental regulations;
• political conditions in or affecting other oil producing and gas producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
• weather conditions, as evidenced by recent hurricanes;
• technological advances affecting oil and gas consumption;
• overall U.S. and global economic conditions; and
• price and availability of alternative fuels.

Further, oil prices and gas prices do not necessarily fluctuate in direct relationship to each other. Because our geothermal reserves are valued similar to gas reserves, our financial results are more sensitive to movements in gas prices. Lower gas prices decrease our potential revenues available from future long term power purchase agreements, but have little impact on the actual proved reserves we can produce economically, unlike typical oil and gas fields that require extensive ongoing drilling to sustain production.

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Our foreign projects expose us to risks related to the application of foreign laws, taxes, economic conditions, labor supply and relations, political conditions and policies of foreign governments, any of which risks may delay or reduce our ability to profit from such projects.

We have development projects outside of the United States. Our foreign development is subject to regulation by various foreign governments and regulatory authorities and are subject to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our projects in the United States, which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such projects. Our foreign development are also subject to significant political, economic and financial risks, which vary by country, and include:

• Changes in government policies or personnel;
• Changes in general economic conditions;
• Restrictions on currency transfer or convertibility;
• Changes in labor relations;
• Political instability and civil unrest;
• Changes in the local electricity market;
• Breach or repudiation of important contractual undertakings by governmental entities; and
• Expropriation and confiscation of assets and facilities.

In particular, the Guatemalan electricity sector was partially privatized and it is currently unclear whether further privatization will occur in the future. Such developments may affect our projects and the El Ceibillo project currently under development if, for example, they result in changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers.

We plan to obtain political risk insurance in connection with our foreign project, when appropriate, but note that such political risk insurance does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to a political risk insurance policy, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the lenders to a project as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances.

Our foreign project may expose us to risks related to fluctuations in currency rates, which may reduce our profits from such projects and operations. Risks attributable to fluctuations in currency exchange rates can arise when any foreign subsidiary borrows funds or incurs operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary's ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary's overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad or restrictions on the conversion of local currency into foreign currency would have an adverse effect on the operations of our foreign project and may limit or diminish the amount of cash and income that we receive from such foreign projects.

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Changes in costs and technology may significantly impact our business by making our power plants less competitive. A basic premise of our business model is that generating baseload power at central geothermal power plants achieves economies of scale and produces electricity at a competitive price. However, gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity, most notably fossil fuel power systems, hydroelectric systems, wind-turbines and photovoltaic (solar) cells. Some of these alternative technologies currently produce electricity at a higher average price than our geothermal plants; however, research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity is gradually declining. It is possible that advances will further reduce the cost of alternate methods of power generation to a level that is equal to or below that of most geothermal power generation technologies. If this were to happen, the competitive advantage of our projects may be significantly impaired.

Risks Related to Our Power Purchase Agreements

A force majeure event, disruption of existing transmission or a forced outage affecting a project or unexpected operating expenses could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If a plant experiences a force majeure event, such as a fire, earthquake or flood, we would be excused from our obligations to deliver electricity under the PPAs to which we are parties. However, the power purchasers under those PPAs may/will not be required to make any and/or energy payments with respect to the affected project or plant so long as the force majeure event continues and, pursuant to certain of our power purchase agreements, will have the right to prematurely terminate the power purchase agreement altogether. Additionally, to the extent that a forced outage has occurred, a power purchaser may not be required to make any energy payments to the affected project, and if as a result the project fails to attain certain performance requirements under certain of our power purchase agreements, the purchaser may have the right to prematurely terminate the power purchase agreement altogether. As a consequence, we may not receive any net revenues from the affected project or plant other than the proceeds from any business interruption insurance that may apply to the force majeure event or forced outage after the relevant waiting period, and we may incur significant liabilities in respect of past amounts required to be refunded.

In addition, we rely on transmission lines owned by local utilities to deliver all of the electricity that we generate to the purchasers of our electricity. If the transmission system were to experience a force majeure event or a forced outage which prevented it from transmitting the electricity from our projects to a power purchaser, the power purchaser would not be required to make energy payments for that electricity with respect to the affected project so long as such force majeure event or forced outage continues.

Any of these events could significantly increase the expenses incurred by our projects or reduce the overall generating capacity of our projects and could significantly reduce or entirely eliminate the revenues generated by one or more of our projects, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.

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Payments under our power purchase agreements may be reduced if we are unable to forecast our production adequately. Under the terms of certain of our power purchase agreements, if we do not deliver electricity output within 90% to 110% of our forecasted amount, 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 receive reduced 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 replacement power costs, depending on the prevailing power market conditions. The agreement moves the power price to the market price instead of contracted price, 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.

Our failure to supply the contracted capacity under some of our PPAs with investor-owned electric utilities in states that have renewable portfolio standards may result in the imposition of penalties. The terms of certain of our PPAs require that we make payments to the relevant power purchaser in an amount equal to such purchaser's replacement costs for renewable energy that we are required to but do not provide as required under the PPA and which such power purchaser obtains from an alternate source. In addition, we may be required to make payments to the relevant power purchaser in an amount equal to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant PPA. All of which could materially and adversely affect our business, financial condition, future results and cash flow.

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.

Risks Related to Our Liquidity and Capital Resources

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Substantial leverage and debt service obligations may adversely affect our cash flows, liquidity and operations. We will have substantial indebtedness that we may be unable to service and that restricts our activities. Our ability to meet our debt service obligations and repay, extend, or refinance our outstanding indebtedness will depend primarily upon the operational performance of our geothermal power generation, the prices that we receive for the electricity that we generate, risk management activities, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. In addition, this indebtedness has important consequences, including:

• limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, entering into other renewable energy businesses, or other purposes;
• limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;
• increasing our vulnerability to general adverse economic and industry conditions;
• limiting our ability to or increasing the costs of refinance indebtedness; and
• limiting our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can transact and the volume of those transactions.

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 expansion of the Raft River (Idaho), San Emidio (Nevada), Neal Hot Springs (Oregon) projects, and the development of the Gerlach (Nevada), El Ceibillo (Guatemala) and Granite Creek Ranch (Nevada) projects. Also, the Company requires funds for other operating activities, and to finance the growth of our business, including the construction and commissioning of power generation facilities. We may not be able to obtain the needed funds on terms acceptable to us or at all. Further, if additional funds are raised by issuing equity securities, significant dilution to our current shareholders may occur and new investors may get rights that are preferential to current shareholders. Alternatively, we may have to bring in joint venture partners to fund further development work, which would result in reducing our interests in the projects.

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

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

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It is very costly to place geothermal resources into commercial production. Before the sale of any power can occur, it will be necessary to construct a gathering and disposal system, a power plant, and a transmission line, and considerable administrative costs would be incurred, together with the drilling of production and injection wells. Future expansion of power production at Raft River, Idaho, San Emidio, Nevada, and Neal Hot Springs, Oregon and development of El Ceibillo, Guatemala and other opportunities 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 or expand the current ownership of existing joint venture partners. 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 debt instruments impose significant operating and financial restrictions on us; any failure to comply with these restrictions could have a material adverse effect on our liquidity and our operations. The instruments governing our outstanding debt impose significant operating and financial restrictions on our geothermal operating subsidiaries. These restrictions could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs. These restrictions limit our ability to, among other things:

• make prepayments on or purchase indebtedness in whole or in part;
• pay dividends to us or make other distributions to us thereby limiting our ability to use available cash to pay dividends to stockholders, repurchase our capital stock or make other investments in geothermal projects or other renewable energy businesses;
• make certain investments, including capital expenditures;
• enter into transactions with affiliates;
• create or incur liens to secure debt;
• consolidate or merge with another entity, or allow one of our subsidiaries to do so;
• lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
• incur dividend or other payment restrictions affecting certain subsidiaries;
• engage in certain business activities; and
• acquire facilities or other businesses

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In addition, any debt facilities that we enter into in the future are likely to contain similar or additional covenants.

Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We cannot assure you that such waivers, amendments or alternative financing could be obtained, or if obtained, would be on terms acceptable to us.

If we are unable to comply with the terms of the documents governing our indebtedness, we may be required to refinance all or a portion of our indebtedness or to obtain additional financing or sell assets. However, we may be unable to refinance or obtain additional financing because of our existing levels of indebtedness and the debt incurrence restrictions under our existing indentures and other debt agreements. If our cash flow is insufficient and refinancing or additional financing is unavailable, we may be forced to default on our indebtedness. Such a default or other breach of the covenants or restrictions contained in any of our existing or future debt instruments could result in an event of default under those instruments and, due to cross-default and cross-acceleration provisions, under our other debt instruments. Upon an event of default under our debt instruments, the debt holders could elect to declare the entire debt outstanding thereunder to be due and payable and could terminate any commitments they had made to supply us with further funds. If any of these events occur, we cannot assure you that we will have sufficient funds available to repay in full the total amount of obligations that become due as a result of any such acceleration, or that we will be able to find additional or alternative financing to refinance any accelerated obligations.

Risks Related to Government Regulation

We are subject to complex government regulation which could adversely affect our operations. Our activities are subject to complex and stringent environmental and other governmental laws and regulations. The exploration and production of geothermal energy requires numerous permits, approvals and certificates from appropriate federal, state and local governmental agencies, including state and local agencies, whose regulations typically are more stringent than in other states or localities, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals and permits for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations could be changed or reinterpreted, or new laws and regulations may become applicable to us that could increase our costs associated with compliance or otherwise harm our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project.

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Under certain circumstances, the United States Office of Natural Resource Revenue (“ONR”) may require that our operations on federal leases be suspended or terminated. These circumstances include our failure to pay royalties or our failure to comply with safety and environmental regulations. The requirements imposed by these laws and regulations are frequently changed and subject to new interpretations, and if such were to occur, could negatively impact our results of operations and cash flows.

On a Federal level, the most important tax rule that affects our business is the PTC, which was extended to December 31, 2014. Recent legislation enacted as part of the “Fiscal Cliff” efforts resulted in the extension of the 30% ITC with eligibility for projects that started 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 our current project sites, or development at new sites, 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.

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

• from a well or drilling equipment at a drill site;
• leakage of fluids or airborne pollutants from gathering systems, pipelines, power plant and storage tanks;
• damage to geothermal wells resulting from accidents during normal operations; and
• blowouts, cratering and explosions.

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 our Raft River and San Emidio project properties were previously operated by others, we may be liable for environmental damage caused by such former operators.

Changes in the legal and regulatory environment affecting our projects could significantly harm our business financial position and results of operations. Our operations are subject to extensive regulation and, therefore, changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our projects. The structure of federal and state energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.

Risks Related to Ownership of Our Common Stock

The public market for our common stock is not that liquid which could result in purchasers being unable to liquidate their investment. The market price for shares of our common stock may be highly volatile and could be subject to wide fluctuations. Some of the factors that could negatively affect our share price include:

• actual or anticipated variations in our reserve estimates and quarterly operating results;
• changes in electricity prices;
• changes in our funds from operations or earnings estimates;
• publication of research reports about us or the exploration and production industry;
• increases in market interest rates which may increase our cost of capital;

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• changes in applicable laws or regulations, court rulings and enforcement and legal actions;
• changes in market valuations of similar companies;
• adverse market reaction to any increased indebtedness we incur in the future;
• additions or departures of key management personnel;
• actions by our stockholders;
• speculation in the press or investment community;
• large volume of sellers of our common stock pursuant to our resale registration statement with a relatively small volume of purchasers; and
• general market and economic conditions.

The market price of our common stock could be volatile, which could cause the value of your investment to decline. Securities markets worldwide experience significant price and volume fluctuations. This market volatility, as well as general economic, market or political conditions, could reduce the market price of our common stock in spite of our operating performance. In addition, our operating results could fall short of the expectations of market analysts and investors, and in response, the market price of our common stock could decrease significantly. You may be unable to resell your shares of our common stock at or above the initial offering price.

The market for our common stock is volatile, having ranged in the year ended December 31, 2013, from a low of $0.31 to a high of $0.59 on the NYSE MKT, and from a low of CDN$0.31 to a high of CDN$0.65 on the TSX. The trading price of our common stock on the NYSE MKT and on the TSX is subject to 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.

You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock. We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders. We are currently authorized to issue 250,000,000 shares of common stock. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes, or for other business purposes.

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.

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We do not anticipate paying any dividends on our common stock in the foreseeable future.

We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to use cash flow generated by operations to expand our business. We may enter into other borrowing arrangements in the future that restrict our ability to declare or pay cash dividends on our common stock.

Future sales of our common stock by our existing stockholders may depress our stock price.

Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline and impair our ability to raise capital through the sale of additional securities.

If securities or industry equity analysts do not publish research or reports about our business, our stock price and trading volume could be adversely affected. To the extent one develops, the trading market for our common stock will depend in part on the research and reports that securities or industry equity analysts publish about us or our business. Our common stock is not currently and may never be covered by securities and industry equity analysts. If no securities or industry equity analysts commence coverage of our company, the trading price of our stock would be negatively impacted. In the event we obtain securities or industry equity analyst coverage of our common stock, if one or more of the equity analysts who covers us downgrades our stock, our stock price would likely decline. If one or more of these equity analysts ceases coverage of our company or fails to regularly publish reports on us, interest in the purchase of our stock could decrease, which could cause our stock price or trading volume to decline.

Provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The existence of some provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Our certificate of incorporation and bylaws prohibit our stockholders from taking action by written consent absent approval by all of our Board of Directors. Further, our stockholders will not have the power to call a special meeting of stockholders.

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The sale of our common stock under our ATM to Lincoln Park Capital (“LPC”) may cause dilution and the sale of the shares of common stock acquired by LPC could cause the price of our common stock to decline. The ATM allows for the sale of up to $6,500,000 in shares of our common stock that we may issue and sell to LPC pursuant to the terms of the Purchase Agreement, less any shares already sold under the Purchase Agreement. The number of shares ultimately offered for sale by LPC is dependent upon the number of shares purchased by LPC under the Purchase Agreement. The purchase price for the common stock to be sold to LPC pursuant to the Purchase Agreement will fluctuate based on the price of our common stock. It is anticipated that shares will be sold over a period of up to 36 months from the date of the initial purchase under the Purchase Agreement. Depending upon market liquidity at the time, a sale of shares under the offering at any given time could cause the trading price of our common stock to decline. We can elect to direct purchases in our sole discretion. After LPC has acquired such shares, it may sell all, some or none of such shares. Therefore, sales to LPC by us under the Purchase Agreement may result in substantial dilution of the percentage ownership of other holders of our common stock. The sale of a substantial number of shares of our common stock under the offering, or anticipation of such sales, could make it more difficult for us to sell equity or equity-related securities in the future at a time and at a price that we might otherwise wish to effect sales. However, we have the right to control the timing and amount of any sales of our shares to LPC and the Purchase Agreement may be terminated by us at any time at our discretion without any cost to us.

Item 1B. Unresolved Staff Comments

None.

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Item 2. Property

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. The Neal Hot Springs geothermal plant achieved commercial operation on November 16, 2012. 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. Raft River Unit I became commercially operational on January 3, 2008.

REGIONAL LOCATION MAP

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Neal Hot Springs, Oregon

Neal Hot Springs is a geothermal resource located in Eastern Oregon. The Company acquired the Neal Hot Springs geothermal energy and surface rights in September 2006. A 22 megawatt geothermal power plant was developed by USG Oregon LLC, and is currently in operation at this site.

The project has 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.

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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.

All power production is committed under a 25 year term power purchase agreement with Idaho Power Company for purchase of up to 25 megawatts of electricity that was signed in December 2009. Beginning 2012, the flat energy price is $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.

San Emidio, Nevada

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 3.6 -MW 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 1 repower project. A new 8.6 MW facility located on private land owned by USG Nevada was completed in 2012. Phase 1 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 19.4 megawatts of electricity. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate.

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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. 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 USG to hold all geothermal resources within the valley without the risk of lease expiration and allows exploration and development costs to be apportioned between and for the benefit of maintaining all the geothermal leases within the Unit. The first designated participating area encompasses the currently operated southern production zone. Royalties are 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.

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USG 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:

Lease No.	Next Renewal Date	Acres	Annual Rate
San Emidio
N63004	9/30/2018	1,280	$ 5,120
N63005	9/30/2018	1,279	5,116
N63006	9/30/2018	1,920	7,680
N63007	9/30/2018	1,920	7,680
N75233	11/1/2016	1,868	3,738
N75552	11/1/2017	2,560	10,240
N75555	11/1/2017	960	3,840
N75557	11/1/2017	1,280	5,120
N75558	11/1/2017	680	2,720
N42707	Indefinite	1,797	*
N47169	12/1/2017	3	n/a
N74196	4/30/2017	640	2,560
N57437	9/30/2018	640	2,560
Gerlach
N55718	6/30/2017	1,252	10,016
N75228	10/31/2016	1521	4,328
* - royalty based.

Raft River, Idaho

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:

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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.

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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.

Raft River Energy Unit I

Unit I at Raft River became commercially operational on January 3, 2008. As a result of the project financing for Unit I of the Raft River project, the Company 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, 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.

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

(a)	Energy produced, saved and used for the generation of electric power, which is then sold by lessee, has a royalty of ten percent (10%) of the net proceeds to RREI.
(b)	Energy produced, saved and sold by lessee, then used by the purchaser for generation of electric power, has a royalty of ten percent (10%) of the market value.
(c)	Energy produced, which is used for any purpose other than the generation of electricity has a royalty of five percent (5%) of the gross proceeds.

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

(a)	Energy produced, saved and sold by the lessee, then used by the purchaser for generation of electric power, has a royalty of ten percent (10%) of the market value of the electric power.
(b)	Energy produced, saved and used for the generation of electric power, which is then sold by Lessee, has a royalty of three percent (3%) of the market value of the electric power.
(c)	Energy produced, which is used for any purpose other than the generation of electricity has a royalty of five percent (5%) of the gross proceeds.

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:

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

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:

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

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

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

The minimum amount that will be payable over the course of the lease is $1,224. 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:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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”).

Gerlach, Nevada

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.

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Granite Creek, Nevada

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.

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Republic of Guatemala

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, with a few of those wells having adequate temperature and flow to support a direct use application. 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 526°F (210 to 274°C).

Boise Administration Office, Idaho

On August 12, 2013, the Company signed a 5 year lease agreement for office space and janitorial services. The lease payments are due in monthly installments starting February 1, 2014. The monthly payments that begin February 1, 2014 have two components which include a base rate of $3,234 that is not subject to increase and a rate beginning at $6,418 that is adjusted annually according to the cost of living index. The contract includes a 5 year extension option.

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Item 3. Legal Proceedings

As of March 25, 2014, management is not aware of any material current or pending legal proceedings in which the Company is a party, as plaintiff or defendant, or which involve any of its properties.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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.”

The following table sets forth information relating to the trading of our common stock from January 1, 2012 through December 31, 2013.

Sale Prices on the NYSE MKT
	High	Low
Year Ended December 31, 2013	($)	($)
First Quarter	0.37	0.31
Second Quarter	0.43	0.32
Third Quarter	0.59	0.36
Fourth Quarter	0.50	0.37
Year Ended December 31, 2012
First Quarter	0.65	0.34
Second Quarter	0.51	0.35
Third Quarter	0.39	0.30
Fourth Quarter	0.44	0.27

TSX
The Company’s common stock began trading on the Toronto Stock Exchange (“TSX”) on October 1, 2007, under the symbol “GTH.” The following table sets forth information relating to the trading of the Company’s common stock on the TSX:

Sale Prices on the TSX
	High	Low
Year Ended December 31, 2013	(CDN$)	(CDN$)
First Quarter	0.39	0.31
Second Quarter	0.44	0.33
Third Quarter	0.65	0.36
Fourth Quarter	0.53	0.39
Year Ended December 31, 2012
First Quarter	0.63	0.34
Second Quarter	0.50	0.36
Third Quarter	0.40	0.30
Fourth Quarter	0.45	0.29

As of March 21, 2014, we had approximately 16,500 stockholders.

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

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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.

Item 6. Selected Financial Data

	For the Years Ended December 31,		For the Fiscal Years Ended March 31,
	2013	2012	2012	2011	2010
Operating Revenues	$ 27,370,934	$9,758,946	$ 5,894,113	$3,253,545	$ 2,579,152
Operating Expenses	23,240,285	14,090,471	16,522,690	7,292,895	8,562,345
Income (Loss) from Continuing       Operations	4,130,649	(4,331,525)	(6,222,129	(3,954,416)	(5,838,850)
Income (Loss) attributable to U.S.       Geothermal Inc.	1,946,579	(2,958,567)
Income (Loss) per share attributable       to U.S. Geothermal Inc.	0.02	(0.03)	(0.07)	(0.05)	(0.09)
Cash dividends declared and paid per       common share	-	-	-	-	-

	As of December 31,		As of March 31,
	2013	2012	2012	2011	2010
Total Assets	$    232,765,297	$    240,496,096	$    219,030,868	$      85,322,968	$      65,727,861
Total Long-term      Obligations (1)	99,247,344	104,318,206	69,495,470	18,326,802	2,080,859

(1) Long-term obligations represent the stock compensation payable, a convertible loan, construction loans and capital lease obligations. The stock compensation liability is the fair value of stock options to be exercised by officers, directors, employees and consultants of the Company. These obligations were recorded as a liability since the option exercise price was stated in Canadian dollars, subjecting the Company and the employee to foreign currency exchange risk in addition to the normal market price fluctuation risk. As of December 31, 2013 and 2012, long-term obligations did not include stock compensation payable.

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	Income (loss) per share attributable to U.S. Geothermal Inc.	Operating Revenues	Gross Profit (Loss)	Income (Loss) from Operations	Net Loss Attributable to U.S. Geothermal, Inc.
Fiscal Year Ended March 31, 2011
1st Quarter	(0.02)	752,247	752,247	(1,491,924)	(1,474,560)
2nd Quarter	(0.01)	838,688	838,688	(1,003,950)	(966,961)
3rd Quarter	(0.01)	852,515	852,515	(843,584)	(825,194)
4th Quarter	(0.01)	810,095	810,095	(699,892)	(687,701)
Fiscal Year Ended March 31, 2012
1st Quarter	(0.03)	1,397,975	(1,110,296)	(4,633,355)	(2,341,024)
2nd Quarter	(0.01)	1,689,609	(336,683)	(1,467,778)	(922,043)
3rd Quarter	(0.02)	1,647,442	(1,876,779)	(2,534,598)	(1,315,339)
4th Quarter	(0.01)	1,159,087	(1,061,775)	(2,415,858)	(1,643,723)
Year Ended December 31, 2012
1st Quarter	(0.01)	1,159,087	(1,061,775)	(2,415,858)	(1,643,723)
2nd Quarter	(0.01)	1,280,949	(52,235)	(1,827,157)	(930,870)
3rd Quarter	(0.00)	2,019,749	270,012	(836,581)	(766,100)
4th Quarter	(0.01)	5,299,161	966,804	748,072	382,126
Year Ended December 31, 2013
1st Quarter	0.01	7,086,990	4,102,509	2,235,079	1,388,523
2nd Quarter	(0.01)	4,973,076	1,012,227	(1,966,627)	(1,376,359)
3rd Quarter	0.00	5,760,495	2,461,352	186,198	(28,137)
4th Quarter	0.02	9,550,373	5,635,824	3,675,999	1,962,552

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.

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For the year ended December 31, 2013, the Company was focused on:

1)	Operating and optimizing Neal Hot Springs, San Emidio and Raft River power plants;
2)	Closing the sale of the Business Energy Tax Credit for Neal Hot Springs;
3)	Drilling of well OW-12 and reworking well 61-21 for San Emidio Phase II;
4)	Testing and evaluating well EC-1 at El Ceibillo;
5)	Permitting new wells at San Emidio; and
6)	The evaluation of potential new geothermal projects and acquisition opportunities.

Projects Under Development
					Estimated
			Target	Projected	Capital
			Development	Commercial	Required
Project	Location	Ownership	(Megawatts)	Operation Date	($million)	Power Purchaser
El Ceibillo Phase I	Guatemala	100%	25	4th Quarter 2015	$135	MOU
San Emidio Phase II	Nevada	100%	11	4th Quarter 2015	$55	NV Energy

Additional Properties
Project	Location	Ownership	Target Development (Megawatts)
Gerlach	Nevada	60%	TBD
Granite Creek	Nevada	100%	TBD
El Ceibillo Phase II	Guatemala	100%	25
San Emidio Phase III	Nevada	100%	17.2
Neal Hot Springs II	Oregon	100%	28
Raft River Unit II	Idaho	100%	26
Raft River Unit III	Idaho	100%	32

Resource Details
	Property Size
Property	(square miles)	Temperature (º F)	Depth (Ft)	Technology
Raft River	10.8	275-302	4,500-6,000	Binary
San Emidio	35.8	289-316	1,500-3,000	Binary
Neal Hot Springs	9.6	311-347	2,500-3,000	Binary
Gerlach	5.6	338-352	2,000-3,000	Binary
Granite Creek	3.8	TBD	TBD	Binary
El Ceibillo	38.6	410-526	1,800-TBD	Steam

Projects in Operation
			Generating		Contract
Project	Location	Ownership	Capacity (megawatts)	Power Purchaser	Expiration
Raft River (Unit I)	Idaho	JV(2)	13.0(1)	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 is approximately 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 $1.4 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.
(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”). Enbridge contributed approximately $32.8 million to the Neal Hot Springs geothermal project. Enbridge’s equity interest in the project is 40%.

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Neal Hot Springs, Oregon
Neal Hot Springs is located in Eastern Oregon near the town of Vale, the county seat of Malheur County. The Neal Hot Springs facility is designed as a 22 megawatt net annual average power plant, consisting of three separate, 7.33 net megawatt modules. 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 2013 totaled 53,445 megawatt-hours with an average of 25.62 net megawatts per hour of operation. Plant availability was 94.7% during the quarter as plant operations continue to improve. Generation for the year was 155,430 megawatt-hours with annual plant availability of 83.1% .

On June 27, 2013, the Company accepted substantial completion by the EPC contractor of all three of the Neal Hot Springs units. Final completion of the project was achieved on July 31, 2013.

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 DOE loan for the project was closed at final completion and has a balance of $70.4 million that bears an interest rate of 2.6% over a 22 year term. The construction cost of the project has been set at $128.1 million. Total project cost, including $11.2 million in reserves, was $139.3 million, which is $4.3 million less than previously reported due primarily to the inclusion of unused contingency funds which have since been released by the project lender.

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 to complete the well field. Each of the additional investments made by Enbridge Inc. was subject to calculations which would result in increased ownership interest in the project.

Subsequent to the end of the year, in February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal received an approximate $6.2 million cash distribution from the partnership.

The project received a $32.75 million cash grant under Section 1603 Specified Energy Property in Lieu of Tax Credits from the Treasury Department. The cash grant, originally approved at $35.4 million, was subject to an 8.7% reduction due to Federal sequestration ordered by Congress under the Budget Control Act. The proceeds from the grant were used to: 1) fund $11.2 million in project level cash reserves as required by the terms of the DOE loan, 2) pay down $11.9 million on the DOE loan and 3) the balance of $9.7 million was distributed to equity investors.

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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. The Company received unconditional approval of the final certificate on March 1, 2013. The BETC was sold to a pass-through tax partner in November 2013 for approximately $7.36 million.

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. Power generated during 2013 was paid at an average price of $99.00 per megawatt-hour. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.3% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $102.78 per megawatt-hour.

San Emidio, Nevada
The Phase I power plant at San Emidio is located approximately 100 miles north of Reno, Nevada and achieved commercial operation on May 25, 2012. Generation from the facility during the fourth quarter 2013 totaled 21,103 megawatt-hours, with an average of 9.72 net megawatts per hour of operation. Plant availability was 98.3% during the quarter. Generation for the year was 76,696 megawatt-hours with annual plant availability of 94.5% .

The Company entered into agreements with Science Applications International Corporation (“SAIC”) for a project loan and an engineering procurement and construction (“EPC”) contract for the San Emidio Phase I power plant repower. SAIC’s design-build subsidiary, SAIC Energy, Environment & Infrastructure LLC, constructed a new 9.0 net megawatt power plant, replacing the old 3.6 net megawatt power plant. TAS Energy of Houston, Texas, supplied a modular power plant to the project. 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. SAIC provided its services under a fixed price contract that included financial guarantees for the original completion date and power output of the plant.

Phase I plant completed its capacity testing during the first quarter of 2013, and as a result of the capacity test exceeding the design output: the plant was up-rated to 9.0 megawatt net annual average per hour from the design point basis of 8.6 megawatts.

Substantial Completion under the contract was achieved February 21, 2013. Final Completion under the terms of the EPC was executed on June 24, 2013.

A final settlement agreement was executed as part of Substantial Completion and included a fixed total construction loan payable to the EPC contractor of $29.5 million. Prior to Substantial Completion, the Company had paid down the loan balance by $1.0 million in three monthly payments. Upon Substantial Completion, a payment of $1.35 million was made to SAIC, and the construction loan was extended until November 15, 2013 with a balance of $25.0 million carrying an interest rate of 10%. Additionally, a $2.0 million, 5 year term, unsecured loan was put in place for the balance of the construction loan. This loan bears interest at 7% and has a payment obligation of $119,382 per quarter.

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The $25 million construction loan with SAIC was paid off in September of 2013, and was replaced with long term notes purchased by Prudential Capital Group’s related entities. The notes are for an aggregate of approximately $30.74 million, have a term of approximately 24 years, and bear a fixed interest rate of 6.75% per annum. Proceeds from the sale of the notes were used to repay the SAIC construction loan, fund project reserves, and pay certain closing expenses, and approximately $2.56 million of the proceeds was distributed to U.S. Geothermal Inc. to be used for general corporate working capital purposes, including the further development of Phase II at San Emidio.

The Phase II expansion was delayed due to the extended time required to get Phase I online, and is still dependent on successful development of additional production and injection well capacity. The cost of development for Phase II is estimated at approximately $55 million. We expect that approximately 75% of the Phase II development may be funded by project loans, with the remainder funded through equity financing.

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. Power generated during 2013 was paid at the price of $90.27 per megawatt-hour. The average price paid under the PPA for 2014 has increased to $91.17 per megawatt-hour.

The electrical output from both Phase I and Phase II may 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. If Phase II cannot achieve commercial operation under a proposed milestone schedule by December 2015, a new PPA would need to be negotiated and signed before financing and construction could begin. A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010. Subsequent to the end of the year, an application to increase the interconnection agreement to the full 19.9 megawatts allowed under the PPA was submitted to NV Energy on January 9^th 2014.

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.

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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.

The DOE cost shared drilling program continues with the further resource identification in the South Zone and the addition of the resource identification in the North Zone. The North Resource Area, has an additional five observation/temperature gradient wells and one production well planned as part of the cost share drilling program. Drilling began on well OW-12 on September 2, 2013. The well was completed on October 23, 2013 to a depth of 3,643 feet and is being evaluated in relation to the San Emidio reservoir model. Well 61-21 (formerly OW-10) in the South Zone, was reworked beginning on October 25, 2013 and was completed on November 2, 2013. Flow testing of 61-21 is planned for the spring or early summer. The results from both wells will be used to determine the continuing resource development plan in support of the Phase II plant construction. In addition, permitting was initiated with the Bureau of Land Management for four new observation wells to be drilled in the South Zone to follow up on the high temperatures found in wells 61-21 (302°F) and 45-21 (316°F).

Raft River, Idaho
The Raft River project is located in Southern Idaho, near the town of Malta, and achieved commercial operation in January 2008. Generation from the facility during the fourth quarter 2013 totaled 21,742 megawatt-hours, with an average of 9.85 net megawatts per hour of operation. Plant availability was 99.2% during the quarter. Generation for the year was 77,552 megawatt-hours with annual plant availability of 96.5% .

The PPA for the project was signed on September 24, 2007 with the Idaho Power Company. The PPA has a 25 year term with a starting average price for the year 2007 of $52.50 that escalates at 2.1% per year. Power generated during 2013 was paid at an average price of $59.47 per megawatt-hour. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.5% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $60.72 per megawatt-hour. In addition to the price paid for energy, Raft River currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits.

The DOE $11.4 million cost-shared, thermal fracturing program began the first stage of injection in June 2013 and continued until September 2013 when the second stage was started. Four, 300 foot deep seismic monitoring wells were completed in the area around well RRG-9 and seismic geophones were installed. Seismic monitoring will be conducted for the duration of the thermal fracturing program. Injection continued through the quarter from power plant injectate at an approximate temperature of 140°F. Flow in to the well has seen a moderate increase indicating that additional permeability is developing. The program has continued through the winter with low level injection going in to the well with a high pressure injection phase planned for spring 2014.

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If the fracturing 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 for the thermal fracturing program are made in-kind by the use of the RRG-9 well, well field data, and monitoring support totaling $991,417.

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 has a 5 year term for the development and construction of a power plant. Discussions are being held with the Guatemalan Ministry of Energy and Mines to allow a new schedule based on the current status of the project. There are 24,710 acres (100 square kilometers) in the concession which is at 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.

During the first phase of drilling on well EC-1, the well was drilled to a depth of 4,829 feet (1,472 meters) and encountered a bottom hole temperature of 491°F (255°C), with the temperature gradient at the bottom of the hole rising at a rate of 7.1°F/100 Feet (129.1°C/km) . High temperatures in excess of 392°F (>200°C) were encountered in the well beginning at a depth of 2,625 feet (800 meters), which represents a potential high temperature reservoir interval in excess of 2,204 feet (672 meters). Due to the high temperature gradient found in the lower section of the well, the decision was made to deepen the well, and a second phase of drilling commenced on August 21, 2013. The final depth of the well, reached on September 15, 2013 is 5,650 feet (1,722 meters) with a measured bottom-hole temperature of 526°F (274°C). Clean out and short term flow tests were conducted along with temperature surveys, and the data was provided to a third party consulting group with specific expertise in volcanic geothermal resources for analysis and evaluation. Planning is underway for another round of drilling to further delineate the El Ceibillo resource. Subsequent to the end of the year, a temperature gradient (“TG”) drilling program was initiated with a series of 200 meter (656 foot) deep wells planned for the first quarter of 2014. Nine TG wells have been completed and the results are being evaluated.

In early September 2013, the Guatemalan Ministry of the Environment and Natural Resources (“MARN”) issued the Environmental License for the construction and operation of the planned, first phase, 25 megawatt power plant at the El Ceibillo site. The license is based on the Environmental Impact Assessment Study that was submitted in December 2012, describing the initial design of the 25 megawatt facility, and requires the submittal of final design specifications for review by MARN prior to starting physical construction of the plant. Additionally, the license requires compliance with all legal and regulatory requirements under Guatemalan law, submittal of an air quality monitoring plan, and that final design comply with the strict guidelines for noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an environmental bond of $344,850 Quetzals (approximately US $45,000) was posted with the Ministry of Environment and Natural Resources.

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An initial development of a 25 megawatt (Phase I) 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.

The El Ceibillo geothermal project area had nine previous wells drilled into the geothermal concession, drilled in the 1990s and having depths ranging from 560 to 2,000 feet (170 to 610 meters). A few of those wells had adequate flow and temperature to support a direct use application. Six of the wells had measured reservoir temperatures in the range of 365°F to 400°F and had high conductive gradients that indicated rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicated the existence of a high permeability reservoir below or near the existing well field.

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.

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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 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.

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:

Neal Hot Springs, Oregon
The facility achieved commercial operation under the terms of the power purchase agreement on November 16, 2012. During the year ended December 31, 2013, the plant achieved 83.1% availability and generated an average of 21.4 net megawatts per hour. Generation from the facility during the year ended December 31, 2013 totaled 155,430 megawatt hours.

San Emidio, Nevada
The Phase I plant achieved commercial operation on May 25, 2012. During the year ended December 31, 2013, the plant achieved 94.5% availability and generated an average of 9.3 net megawatts per hour. Power production totaled 76,696 megawatt hours for the year ended 2013.

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The plant was up rated to 9.0 net annual average megawatts per hour from the design point basis of 8.6 megawatts.

Raft River Energy I LLC
During the year ended December 31, 2013, Raft River operated at 96.5% availability and generated an average of 9.2 net megawatts per hour. Power production totaled 77,552 megawatt hours for the year ended 2013. For the 2012 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 2014. 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 $991,417. 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.

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 which 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. 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.

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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 received 100% of the tax deductions and operating losses for the tax year 2011 and will receive them in 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:

		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 amended and restated operating agreements as amended.
(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.

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.

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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 was signed on September 24, 2007 and 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.

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Operating Results

For the year ended December 31 2013, the Company reported net income attributable to the Company of $1,946,579 ($0.02 income per share) which represented a $4,905,146 favorable increase from the net loss of $2,958,567 million reported in the year ended 2012 ($0.03 loss per share). Net income from plant operations for the year ended December 31, 2013 increased $12,984,636 from the income of $227,276 reported in the year ended 2012. Other notable favorable variances were reported in stock based compensation and other income/expenses. Notable unfavorable variances were reported in professional and management fees, salaries and related compensation and interest expense.

Plant Operations
During the year ended December 31 2013, the Company’s energy production revenues and related operating costs originated from its fully operational 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 May 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.

A summary of energy sales by plant for the two reporting periods are as follows:

	For the Year Ended December 31,
	2013		2012
	$	%*	$	%*
Energy sales by plant:
Neal Hot Spring, Oregon	15,566,409	57.7	2,329,030	24.9
San Emidio, Nevada	6,792,382	25.2	2,632,502	28.1
Raft River, Idaho	4,627,258	17.1	4,396,671	47.0
	26,986,049	100.0	9,358,203	100.0

%* - represents the percentage of total Company energy sales.

A quarterly summary of power generated by plant for the current year is as follows:

	For the Quarter Ended,
	March 31,	June 30,	September 30,	December 31,
	2013	2013	2013	2013
Megawatt Hours Produced:
Neal Hot Spring, Oregon	46,137	30,016	25,832	53,445
San Emidio, Nevada	19,228	18,039	18,317	21,112
Raft River, Idaho	19,675	17,248	18,687	21,951
	85,040	65,303	62,836	96,508

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Neal Hot Springs, Oregon (USG Oregon LLC) 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. The year ended December 31, 2013, was the plant’s first full year of operations. The quarter ended December 31, 2013, was the highest quarter of energy production and sales to date. High production was due to less down time and the efficiency of the cooling towers due to the cooler ambient temperatures of the fall/winter months. During the quarter ended June 30, 2013, plant production was down approximately 38 days for turbine upgrades. One unit was down for approximately 26 days, during the quarter ended September 30, 2013 due to the failure of a high pressure refrigerant pump.

Since the current year was the first full year of operations, generally all operating costs increased significantly (approximately $5.55 million) to the level expected for normal operations. Also, interest increased significantly (approximately $1.7 million). The majority of the interest costs incurred in the prior year were capitalized.

Key quarterly production data for the Neal Hot Springs, Oregon plant is summarized as follows:

	Mega-		Ave. Rate		Depreciation
	watt	Energy	per	Net	&
	Hours	Sales	Megawatt	Income*	Amortization
Quarter Ended:	Produced	($)	Hour ($)	($)	($)
December 31, 2012	23,256	2,329,030	88.7	1,451,523	256,670
March 31, 2013	46,137	4,197,251	90.6	2,424,647	779,298
June 30, 2013	30,016	2,435,304	80.2	518,754	814,434
September 30, 2013	25,832	2,875,686	110.9	829,374	810,573
December 31, 2013	53,445	6,058,169	113.3	3,644,359	812,766

* - The intercompany elimination adjustments for management fees are not incorporated into the presentation of the
      subsidiary’s net income.

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Summarized statements of operations for the Neal Hot Springs, Oregon plant are as follows:

	Year Ended December 31,
	2013				2012				Variance
	$		%*		$		%		$		%**
Plant revenues:
Energy sales	15,566,409		100.0		2,329,030		100.0		13,237,379		#
Plant expenses:
Operations	3,118,488		20.0		260,023		11.2		(2,858,465	)	#
Depreciation and amortization	3,217,071		20.7		522,889		22.5		(2,694,182	)	#
	6,335,559		40.7		782,912		33.6		(5,552,647	)	#
Operating income	9,230,850		59.3		1,546,118		66.4		7,684,732		497.0
Other income (expense):
Interest expense	(1,856,255	)	(11.9	)	(160,633	)	(6.9	)	(1,695,622	)	#
Interest income/other	42,540		0.2		27,077		1.2		15,463		57.1
	(1,813,715	)	(11.7	)	(133,556	)	(5.7	)	(1,680,159	)	#
Net income	7,417,135		47.6		1,412,562		60.7		6,004,573		425.1

%* -	represents the percentage of total plant operating revenues.
%** -	represents the percentage of change from 2012 to 2013. 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.
# -	variance percentage that is extremely high or undefined.

The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary’s net operating income/loss.

San Emidio, Nevada Plant Energy Sales and Plant Operating Expenses (USG Nevada LLC)
For the year ended December 31, 2013, the San Emidio plant reported net profit of $1,158,638 which was a favorable increase of $1,765,526 from the loss of $606,888 reported in the year ended 2012. The new plant became commercially operational on May 25, 2012. After the plant became operational, it experienced down time of approximately 83 days in the third and fourth quarters to address mechanical and performance issues that can be common for a new plant. Overall, energy sales for the year ended December 31, 2013 increased $4,159,880 (158.0% increase) from the year ended 2012. During the quarter ended December 31, 2013, the plant produced the highest amount of energy revenues and kilowatt hours ($1,905,813 energy sales; 21,112,368 kilowatt hours) than any other quarter in operating history of USG Nevada LLC.

Since the current year was the first full year of operations for the new power plant, most operational costs increased from the prior year. In the prior year, the majority of the employees’ time was dedicated to plant construction and the plant was only operational for a portion of the year; therefore, operation salary and related costs were approximately $369,000 (68.5%) lower than the current year. Management fees and corporate support costs were charged to plant operations in the current year that totaled $400,000. No management fees were earned/charged to the plant in 2012, and corporate support costs were minimal. In the prior year ended 2012, an error was made in the calculation of property taxes. This error was corrected in the current year, which resulted favorable decrease in property tax expense of approximately $425,000.

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

	Year Ended December 31,
	2013				2012				Variance
	$		%*		$		%		$		%**
Plant revenues:
Energy sales	6,792,382		100.0		2,632,502		100.2		4,159,880		158.0
Energy credit sales	-		-		(6,124	)	(0.2	)	6,124		100.0
	6,792,382		100.0		2,626,378		100.0		4,166,004		318.6
Plant expenses:
Operations	2,500,816		36.8		2,194,128		83.5		(306,688	)	(14.0	)
Depreciation and amortization	1,392,502		20.5		1,039,979		39.6		(352,523	)	(33.9	)
	3,893,318		57.3		3,234,107		123.1		(659,211	)	(20.4	)
Operating income (loss)	2,899,064		42.7		(607,729	)	(23.1	)	3,506,793		#
Other income (expense):
Interest expense	(1,742,181	)	(25.6	)	-		-		(1,742,181	)	#
Interest income	1,755		0.0		841		0.0		914		108.7
	(1,740,426	)	(25.6	)	841		0.0		(1,741,267	)	#
Net income (loss)	1,158,638		17.1		(606,888	)	(23.1	)	1,765,526		290.9

%* -	represents the percentage of total plant operating revenues.
%** -	represents the percentage of change from 2012 to 2013. 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.
# -	variance percentage that is extremely high or undefined.

The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary’s net operating income/loss.

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

				Net
	Mega-		Ave. Rate			Depreciation
	watt	Energy	per	Income		&
	Hours	Sales	Megawatt	(Loss)*		Amortization
Quarter Ended:	Produced	($)	Hour ($)	($)		($)
March 31, 2012 (1)	-	-	-	(475,961	)	189,126
June 30, 2012 (2)	5,465	427,931	77.6	(8,693	)	181,333
September 30, 2012	8,280	745,494	89.7	101,154		253,429
December 31, 2012	16,231	1,459,078	90.0	(223,412	)	416,091
March 31, 2013	19,228	1,726,927	90.3	834,266		407,060
June 30, 2013	18,039	1,628,382	90.3	(212,058	)	365,314
September 30, 2013	18,317	1,531,260	83.6	355,499		307,854
December 31, 2013	21,112	1,905,813	90.3	180,931		312,273

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(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.

* - The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary’s net income/loss.

Raft River, Idaho Unit I (Raft River Energy I LLC) Plant Operations
Net loss from Raft River Energy I LLC (“RREI”) operations of $394,847 for the year ended December 31, 2013, favorably decreased by $950,028 from the loss of $1,344,875 the reported in year ended 2012. The primary reason for the difference in net loss for the current year was the repair costs incurred primarily in the first quarter ended March 31, 2012. The repairs of wells RRG-2 and RRG-7 were completed in January 2012. For the year ended December 31, 2012, repair costs totaled $830,685 which was $555,533 higher than the repair costs incurred for the current year. Another factor contributing to the lower repair costs were the two grant awards that totaled $217,594 collected in the quarter ended March 31, 2013 that offset a portion of the well repairs. For the year ended December 31, 2013, energy production and energy sales increased 3.9% and 5.2% from the same period ended 2012.

The summarized statements of operations for RREI are as follows:

	Year Ended December 31,
	2013				2012				Variance
	$		%*		$		%*		$		%**
Plant revenues:
Energy sales	4,627,258		92.3		4,396,671		91.1		230,587		5.2
Energy credit sales	384,885		7.7		406,866		8.5		(21,981	)	(5.4	)
	5,012,143		100.0		4,803,537		100.0		208,606		4.3
Plant expenses:
General operations	3,378,794		67.4		3,900,270		81.2		521,476		13.4
Depreciation and amortization	1,844,579		36.8		2,027,929		42.2		183,350		9.0
	5,223,373		104.2		5,928,199		123.4		704,826		11.9
Operating loss	(211,230	)	(4.2	)	(1,124,662	)	(23.4	)	913,432		81.2
Other income (expense):
Interest expense	(197,461	)	(3.9	)	(220,605	)	(4.6	)	13,452		10.5
Other and interest income	13,844		0.2		392		0.0		23,144		#
	(183,617	)	(3.7	)	(220,213	)	(4.6	)	36,596		16.6
Net loss	(394,847	)	(7.9	)	(1,344,875	)	(28.0	)	950,028		70.6

%* -	represents the percentage of total plant operating revenues.
%** -	represents the percentage of change from 2012 to 2013. 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.
# -	variance percentage that is extremely high or undefined.

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The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary’s operations.

Key quarterly production data for RREI is summarized as follows:

	Mega-		Ave. Rate		Depreciation
	watt	Energy	per	Net Income	&
	Hours	Sales	Megawatt	(Loss)*	Amortization
Quarter Ended:	Produced	($)	Hour ($)	($)	($)
March 31, 2012	19,639	1,057,091	55.7	(696,689)	509,027
June 30, 2012	15,999	765,255	50.3	(805,286)	507,783
September 30, 2012	17,836	1,176,107	68.1	2,348	505,560
December 31, 2012	21,170	1,398,218	67.9	154,752	505,559
March 31, 2013	19,675	1,064,481	56.1	67,620	472,040
June 30, 2013	17,248	823,153	49.9	(715,605)	472,094
September 30, 2013	18,687	1,260,124	69.5	(1,165)	450,222
December 31, 2013	21,951	1,479,499	69.0	254,302	450,222

* - Net income (loss) does not include intercompany elimination adjustments for interest expense, management fees and lease costs.

Professional and Management Fees
For the year ended December 31, 2013, the Company incurred professional and management fees of $1,284,936, which was an increase of $518,335 (67.6% increase) from the year ended 2012. The two primary elements for the increase were the consulting fees paid to the former CEO and the additional audit and accounting fees. During the current year, consulting fees were paid to the former CEO’s consulting firm and the former Vice President of Exploration that totaled $301,281. Additional audit, audit related and financial consulting fees were incurred during the current year to address the audit requirements for our subsidiaries and the change in year end for the Company. During the year ended December 31, 2013, the Company incurred audit/audit related, legal and SOX consulting costs of approximately $274,000, $216,000 and $82,000; respectively. In the prior year, the Company incurred audit/audit related, legal and SOX consulting costs of approximately $138,000, $226,000 and $100,000; respectively.

Salaries and Wages
For the year ended December 31 2013, the Company reported $2,135,945 in salaries and related costs, which was an increase of $1,033,194 (93.7% increase) from the year ended 2012. The increase was primarily due to bonuses awarded and due to lower amounts of compensation that were capitalized on the Company’s major projects. During the current year, the Company paid employee bonuses of $171,000. A CEO signing bonus of $100,000, payable in stock, was paid in the second quarter of 2013. During the year ended December 31, 2012, significant portions of the management and development compensation costs were allocated to the Company’s capital projects (Neal Hot Springs, Oregon and San Emidio, Nevada – Phases I and II). Since both the Neal Hot Springs and the San Emidio Phase I projects were substantially completed prior to and operational during the current period, salary cost allocations for both projects decreased.

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Management and development employee salaries and related costs allocated to major Company projects are summarized as follows:

	For the Year Ended December 31,
	2013		2012		Variance
Financial Element	$		$		$		%
Total Company salary and related costs,      excluding plant operations	2,873,047		2,266,781		606,266		26.7
Salary and related costs allocated to the following projects:
USG Oregon LLC (Neal Hot Springs Project)	(429,124	)	(800,189	)	371,065		46.4
USG Nevada LLC (San Emidio Phase I Project)	(67,033	)	(143,311	)	76,278		53.2
USG Nevada LLC (San Emidio Phase II Project)	(170,295	)	(150,805	)	(19,490	)	(12.9	)
Development activities in Guatemala	(57,164	)	(11,867	)	(45,297	)	(381.7	)
Small projects and plant operations	(13,486	)	(57,858	)	44,372		76.7
	2,135,945		1,102,751		1,033,194		93.7

% - represents the percentage of change from 2012 to 2013.

Stock Based Compensation
For the year ended December 31 2013, the Company reported $756,935 in stock based compensation, which was a decrease of $183,197 (19.5% decrease) from the year ended 2012. Stock based compensation includes the calculated values for both Company stock and stock options. In the quarter ended June 30, 2013, stock was provided to the new CEO as a component of his compensation package. The Company issued stock options to employees on August 24, 2012 and July 22, 2013 for 2,917,000 and 1,950,000; respectively. The compensation related to the value of the stock options issued to employees was significantly lower in the quarters ended March 31, 2013 and June 30, 2013 from the same periods in 2012 due to the lower market price of the Company’s outstanding stock during those periods. During the quarter ended September 30, 2013, the value of stock options was slightly less (8.8% decrease) than the value in the same period ended in 2012. The value of stock options expensed in the quarter ended December 31, 2013 was consistent with the same period ended in 2012.

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The stock based compensation components are summarized as follows:

	For the Year Ended
	December 31,
	2013	2012	Variances
	$	$	$		%
Total Stock Based Compensation:
Stock option compensation	683,443	861,277	(177,834	)	(20.7	)
Stock compensation	73,492	78,855	(5,363	)	(6.8	)
	756,935	940,132	(183,197	)	(19.5	)

% - represents the percentage of change from 2012 to 2013.

Interest Expense
During the year ended December 31 2013, the Company incurred $3,895,890 in interest expense, which was an increase of $3,735,060 from the year ended 2012. All interest expense costs incurred from construction loans incurred prior to the plants becoming commercially operational was capitalized.

Other Income/Expenses
For the year ended December 31 2013, the Company reported $115,865 in income in other income/expenses which was a favorable increase of $553,466 from the loss reported the year ended 2012. In February 2012, water rights on 2,917 acres leased property in the Granite Creek area located in the State of Nevada were relinquished and removed from intangible assets at their carrying amounts that totaled $548,701. The relinquishment was considered to be a loss that was recognized in the year ended December 31, 2012.

Net Income/Loss Attributable to the Non-Controlling Interests
The net income/loss attributable to the non-controlling interest entities is the line item that removes the portion of the total consolidated operations that are owned by the Company’s subsidiaries. For the year ended December 31, 2013, the Company reported $2,184,070 in net income attributable to non-controlling interests, which was a favorable increase of $3,557,028 from the net loss of $1,372,958 the year ended 2012. The primary reason for the increase was due to the operations of the Neal Hot Springs plant (Oregon USG Holdings LLC) which reported net income of $7,417,135 for the year ended December 31, 2013. The impact of the Neal Hot Springs operations on the Company’s reported income attributable to non-controlling entities was an increase of $2,568,889 from the year ended December 31, 2012 as compared to the current year ended 2013.

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The net (income) or loss attributable to the non-controlling interest entities is detailed as follows:

	For the Year Ended
	December 31,
Subsidiaries and Non-Controlling	2013		2012		Variance
Interest Entities	$		$		$		%
Oregon USG Holdings LLC interest held      by Enbridge Inc.	(2,848,081	)	(279,192	)	(2,568,889	)	#
Raft River Energy I LLC interest held by      Raft River I Holdings, LLC	656,469		1,611,830		(955,360	)	(59.3	)
Gerlach Geothermal LLC interest held by      Gerlach Green Energy, LLC	7,542		40,321		(32,779	)	(81.3	)
	(2,184,070	)	1,372,958		(3,574,028	)	#

% - represents the percentage of change from 2012 to 2013.
# - variance percentage that is extremely high or undefined.

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Liquidity and Capital Resources

We believe our cash and liquid investments at December 31, 2013 are adequate to fund our general operating activities through December 31, 2014. 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, issuance of debt or equity, and/or through the sale of ownership interest in tax credits and benefits.

The recent financial credit crisis has not impacted 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 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.

On November 29, 2013 the Company filed a replacement shelf registration statement on Form S-3 with the SEC. The replacement shelf registration statement was filed as routine course of business due to the impending expiration of the Company’s existing shelf registration statement that, under SEC rules, would have expired on December 1, 2013. Pursuant to SEC rules, the expiration date of the existing shelf registration statement has been extended until the earlier of the effective date of the replacement shelf registration statement or May 30, 2014. Upon effectiveness of the S-3 on February 4, 2014, the Company may use the replacement shelf registration statement to offer and sell from time to time for a period of three years in one or more public offerings up to $50 million of common stock, warrants, or units consisting of any combination thereof. The terms of any securities offered under the replacement shelf registration statement, and the intended use of the resulting net proceeds, will be established at the times of any future offerings and will be described in prospectus supplements filed at such times with the SEC. The Company has no immediate plans to sell any additional stock under the replacement shelf registration statement at this time, but wishes to preserve the option in support of its future growth and development of its projects as well as strategic M&A opportunities.

Following the receipt of the Section 1603 Federal Investment Tax Credit (ITC) cash grant payment, and the Oregon Business Energy Tax Credit funds, and after the receipt and disbursement of all remaining construction reserve funds, which was finalized on January 27, 2014, the final ownership interest in the Neal Hot Springs project was calculated in accordance with the terms of the partnership agreement. Ownership interest in the project is final with 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal has received a $6.2 million cash distribution from the partnership.

Under the terms of the DOE loan agreement, project profits are distributed to the equity partners semi-annually (February and August), following Final Completion, which was achieved on August 1, 2013. U.S. Geothermal’s share of this first distribution received March 5, 2014 is $4.6 million, out of a total distribution to the partners of $7.7 million, which represents profits generated from the project since initial operation began in November 2012.

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Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At December 31, 2013, $10.1 million in USG Oregon LLC funds were deposited at PNC Bank and $16.4 million in Oregon USG Holdings LLC funds were deposited at Sterling Bank, and were unavailable for immediate corporate needs.

For projects under construction before the end of 2010 and online before the end of 2013, a project was eligible to take a 30% investment tax credit (“ITC”) in lieu of the production tax credit (“PTC”). The ITC was able to 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. 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. An additional $1.05 million of cash grant items were subsequently approved and paid in March 2013. For the Neal Hot Springs project, an application was submitted in the first quarter 2013 electing to take the ITC cash grant, in lieu of the PTC, for approximately $35.9 million from U.S. Treasury and the funds would be used to fund reserves required under the DOE Loan Guarantee Agreement and return funds to our partner in the project, Enbridge. Due to federal sequestration in early 2013, the ITC cash grant amount received in April 2013 was reduced by 8.7% to $32.7 million.

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 completed final certification for the credit and sold it to a pass-through partner, monetized at a cash value of $7.36 million (less a broker fee).

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 December 31, 2013, 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 (net of $86,911 broker and legal fees). 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.

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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.

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On February 24, 2011, the Company completed the financial closing with the U.S. Department of Energy (“DOE”) of a $96.8 million loan guarantee to construct 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 provided 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. The DOE guaranteed project loan 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 increased their ownership in USG Oregon LLC based on running a project financial model and determining what percentage of the forecasted project income would be allocated to Enbridge to arrive at a predetermined rate of return for the additional investment. Subsequent to the end of the quarter, in February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal Inc. received an approximate $6.2 million cash distribution from the partnership.

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.

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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 factors and assumptions that comprise this allocation process will be based upon the best information available to us, and will be evaluated, at least, annually for viability. If it is determined that our cost allocations have produced results that vary significantly from the conditions surrounding the value of the Company’s geothermal properties, a gain or loss adjustment will be made in the period in which this determination is made. The cost allocation or amortization process is not intended to present the fair market value of our geothermal properties; rather to allocate the actual historical costs of those properties over their service lives.

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

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

Contractual Obligations

As of December 31, 2013, the following table denotes contractual obligations by payments due for each period:

	Total	< 1 year	1-3 years	3-5 years	> 5 years
Operating Leases	$ 12,145,456	$ 475,521	$ 1,100,943	$ 1,093,763	$ 9,475,229
Capital Leases	69,039	48,118	20,921	-	-
Note Payable (1)	30,505,500	323,167	1,140,803	1,223,579	27,817,951
Construction Loan (2)	70,997,780	3,419,927	6,795,375	6,505,003	54,277,475
Note Payable, Settlement Agreement (3)	1,850,314	761,865	851,935	236,514	-

(1)	Long-term note obligation with Prudential Capital Group scheduled for to be repaid over the next 24 years.
(2)	Construction loan with the Department of Energy scheduled to be repaid over the next 21 years.
(3)	Loan agreement that originated with a settlement agreement with SAIC Constructors LLC scheduled to be repaid over the next 5 years.

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Off Balance Sheet Arrangements

As of December 31, 2013, the Company does not have any off balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Risk on Investments

At December 31, 2013, the Company held investments of $29,623,935 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.

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.

Item 8. Financial Statements and Supplementary Data

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

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U.S. GEOTHERMAL INC.
________

Consolidated Financial Statements
December 31, 2013

218 North Bernard
Spokane, WA 99201

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying consolidated balance sheets of U.S. Geothermal, Inc. as of December 31, 2013 and 2012, and the related consolidated statements of operations, cash flows, and changes in stockholders’ equity, for each of the years then ended. U.S. Geothermal, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of U.S. Geothermal, Inc. as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years then ended in conformity with accounting principles generally accepted in the United States of America.

MartinelliMick PLLC
Spokane, Washington
March 24, 2014

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

		December 31,
		2013			2012
ASSETS
Current:
Cash and cash equivalents (note 2)	$	28,736,934		$	12,908,779
Restricted cash and bonds (note 3)		3,081,020			2,995,000
Trade accounts receivable		4,106,806			3,296,890
Grant proceeds receivable (note 4)		-			42,884,200
Other current assets		1,079,262			839,104
Total current assets		37,004,022			62,923,973
Investment in equity securities (note 5)		42,174			65,551
Restricted cash and bond reserves (note 3)		18,815,145			1,426,700
Property, plant and equipment, net of accumulated depreciation (note 6)		161,583,938			160,578,170
Intangible assets, net of accumulated amortization (note 7)		15,320,018			15,501,702
Total assets	$	232,765,297		$	240,496,096
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,611,130		$	1,481,959
Construction accounts payable		15,557			1,122,746
Related party accounts payable		3,089			3,391
Notes payable		-			1,000,000
Retention payable		-			8,089,704
Current portion of capital lease obligations (note 9)		48,118			45,278
Current portion of notes payable (note 11)		4,127,170			1,576,342
Total current liabilities		5,805,064			13,319,420
Long-term Liabilities:
Convertible loan payable (note 10)		-			2,125,000
Long-term portion of capital lease obligations (note 9)		20,921			69,039
Notes payable, less current portion (note 11)		99,226,423			102,124,167
Total long-term liabilities		99,247,344			104,318,206
Total liabilities		105,052,408			117,637,626
Commitments and Contingencies (note 16)		-			-
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par value;    issued and outstanding shares at December 31, 2013 and 2012 were:    102,094,542 and 101,516,764; respectively)		102,094			101,516
Additional paid-in capital		100,381,207			99,524,850
Accumulated other comprehensive loss		(27,321	)		(3,944	)
Accumulated deficit		(30,898,571	)		(32,845,150	)
		69,557,409			66,777,272
Non-controlling interests (note 17)		58,155,480			56,081,198
Total stockholders’ equity		127,712,889			122,858,470
Total liabilities and stockholders’ equity	$	232,765,297		$	240,496,096

The accompanying notes are an integral part of these consolidated financial statements.
-F-1-

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

		For the Year Ended December 31,
		2013			2012
Plant Revenues:
Energy sales	$	26,986,049		$	9,358,203
Energy credit sales		384,885			400,743
Total plant operating revenues		27,370,934			9,758,946
Plant Expenses:
Plant production expenses		7,704,871			5,910,880
Depreciation and amortization		6,454,151			3,620,790
Total plant operating expenses		14,159,022			9,531,670
Net Income from Plant Operations		13,211,912			227,276
Expenses (Income):
Corporate administration		881,880			827,015
Professional and management fees		1,284,936			766,601
Salaries and wages		2,135,945			1,102,751
Stock based compensation		756,935			940,132
Travel and promotion		202,060			165,107
Exploration costs		39,482			158,764
Interest expense		3,895,890			160,830
Other (income) expenses		(115,865	)		437,601
Total expenses (income)		9,081,263			4,558,801
Net Income (Loss) Before Income Tax Expense		4,130,649			(4,331,525	)
Net Income Tax Expense (note 8):
Income taxes		1,578,000			-
Effect of net deferred tax assets		(1,578,000	)		-
Net income tax expense		-			-
Net Income (Loss)		4,130,649			(4,331,525	)
Net (income) loss attributable to the non-controlling interests		(2,184,070	)		1,372,958
Net Income (Loss) Attributable to U.S. Geothermal Inc.		1,946,579			(2,958,567	)
Other Comprehensive Income (Loss):
Unrealized income (loss) on investment in equity securities		(23,377	)		4,605
Comprehensive Income (Loss) Attributable to U.S. Geothermal Inc.	$	1,923,202		$	(2,953,962	)
Basic Net Income (Loss) Per Share Attributable to U.S. Geothermal Inc.	$	0.02		$	(0.03	)
Diluted Net Income (Loss) Per Share Attributable to U.S. Geothermal Inc.	$	0.02		$	(0.03	)
Weighted Average Number of Shares Outstanding for Basic Calculations		101,795,364			87,847,308
Weighted Average Number of Shares, Stock Options and Warrants Outstanding for Diluted Calculations		123,497,883			102,155,529

The accompanying notes are an integral part of these consolidated financial statements.
-F-2-

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

		For the Year Ended December 31,
		2013			2012
Operating Activities:
Net Income (Loss)	$	4,130,649		$	(4,331,525	)
Adjustments to reconcile net income (loss) to total cash provided by operating activities:
Depreciation and amortization		6,575,266			3,682,581
Stock based compensation		756,935			940,132
Stock based officer bonus		100,000			-
Loss on disposal of water rights		-			548,701
Net changes in:
Trade accounts receivable, operating		(809,916	)		(169,731	)
Accounts payable and accrued liabilities		128,868			(1,004,686	)
Prepaid expenses and other		(240,158	)		(512,166	)
Total cash provided by operating activities		10,641,644			(846,694	)
Investing Activities:
Purchases of property, plant and equipment		(13,868,842	)		(8,807,798	)
Proceeds from ITC cash grants receivable		40,113,741			10,784,530
Cash received from consolidation of subsidiary		-			592,330
Funding of restricted cash reserves and bonds		(17,474,465	)		(1,501,700	)
Total cash provided (used) by investing activities		8,770,434			1,067,362
Financing Activities:
Issuance of share capital, net of share issuance costs		-			5,488,947
Contributions from non-controlling interest		7,460			10,080,902
Distributions to non-controlling interest		(117,248	)		(119,476	)
Proceeds from debt obligations		16,570,400			-
Principal payments on notes payable and other obligations		(19,999,257	)		(8,973,577	)
Principal payments on capital lease		(45,278	)		(58,144	)
Total cash provided (used) by financing activities		(3,583,923	)		6,418,652
Increase in Cash and Cash Equivalents		15,828,155			6,639,320
Cash and Cash Equivalents, Beginning of Year		12,908,779			6,269,459
Cash and Cash Equivalents, End of Year	$	28,736,934		$	12,908,779
Supplemental Disclosures:
Non-cash investing and financing activities:
Purchase of property and equipment on account	$	1,107,189		$	6,008,629
Construction and development paid directly with construction loans		745,105			54,793,354
Net assets and liabilities received from consolidation of subsidiary		-			45,386,103
Equipment purchased with capital leases		-			155,000
Capitalized accrued interest		-			2,749,081
Property and equipment costs reduced by settlement agreements		4,406,958			-
Grants receivable used to decrease construction costs		2,770,459			-
Other Items:
Interest paid		6,973,502			346,889

The accompanying notes are an integral part of these consolidated financial statements.
-F-3-

U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2013 and 2012
(Stated in U.S. Dollars)

					Additional						Accumulated			Non-
	Number of		Common		Paid-In			Accumulated			Comprehensive			controlling
	Shares		Shares		Capital			Deficit			Income			Interest			Totals
Balance at December 31, 2011	84,989,853	$	84,990	$	92,921,978		$	(29,886,584	)	$	(8,549	)	$	43,812,275		$	106,924,110
Stock issued under At Market Issuance Sales agreement and a registered direct offering agreement (note 12)	16,526,911		16,526		5,482,420			-			-			-			5,498,946
Equity contributions and note conversion by non-controlling interest Oregon USG Holdings LLC (note 17)			-		-			-			-			13,761,358			13,761,358
Distributions to non-controlling interest entity	-		-		-			-			-			(119,476	)		(119,476	)
Broker fees	-		-		(10,000	)		-			-			-			(10,000	)
Stock compensation	-		-		1,130,452			-			-			-			1,130,452
Unrealized income on investment	-		-		-			-			4,605			-			4,605
Net loss	-		-		-			(2,958,566	)		-			(1,372,959	)		(4,331,525	)
Balance at December 31, 2012	101,516,764		101,516		99,524,850			(32,845,150	)		(3,944	)		56,081,198			122,858,470
Non-controlling equity contribution from Gerlach Green Energy, LLC	-		-		-			-			-			7,460			7,460
Distributions to non-controlling interest entity	-		-		-			-			-			(117,248	)		(117,248	)
Stock issued under terms of employment agreement	577,778		578		99,422			-			-			-			100,000
Stock compensation	-		-		756,935			-			-			-			756,935
Unrealized loss on investment	-		-		-			-			(23,377	)		-			(23,377	)
Net income	-		-		-			1,946,579			-			2,184,070			4,130,649
Balance at December 31, 2013	102,094,542	$	102,094	$	100,381,207		$	(30,898,571	)	$	(27,321	)	$	58,155,480		$	127,712,889

The accompanying notes are an integral part of these consolidated financial statements.
-F-4-

U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013
(Stated in U.S. Dollars)

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

U.S. Geothermal Inc. (formerly U.S. Cobalt Inc.) was incorporated on March 10, 2000 in the State of Delaware. U.S. Geothermal Inc. – Idaho was formed in February 2002, and is the primary subsidiary through which the Company conducts its operations. The Company constructs, manages and operates power plants that utilize geothermal resources to produce energy. The Company’s operations have been, primarily, focused in the Western United States of America.

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

Basis of Presentation

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

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

All intercompany transactions are eliminated upon consolidation.

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

-F-5-

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Accounting Method

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

Use of Estimates

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

Cash and Cash Equivalents

The Company considers all unrestricted cash, short-term deposits, and other investments with original maturities of no more than ninety days when acquired to be cash and cash equivalents for the purposes of the statement of cash flows. Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At December 31, 2013, $7.9 million in USG Oregon LLC funds were deposited at PNC Bank and $16.4 million in Oregon USG Holdings LLC funds were deposited at Sterling Bank, and were unavailable for immediate corporate needs. The allocation of these funds to the owners of USG Oregon LLC is subject to completion of negotiations regarding the final ownership percentages. Discussion regarding restricted cash is included in Note 3.

Accounts Receivable Allowance for Doubtful Accounts

Trade Accounts Receivable
Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of December 31, 2013 and 2012, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

-F-6-

Grant Accounts Receivable
For receivables expected to be received from grants from Federal or State agencies, the Company records the receivable amounts net of the funds expected to be received which may be less than the total amounts requested on the actual grant applications. Therefore, no allowance accounts are considered to be necessary for receivables from grants at December 31, 2013 and 2012.

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity through December 31, 2013. At December 31, 2013, the Company’s total cash balance, excluding money market funds, was $21,005,464, and bank deposits amounted to $21,268,264. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $19,700,267 was not covered by or was in excess of FDIC insurance guaranteed limits. At December 31, 2013, the Company’s money market funds invested in government backed securities totaled $29,623,935 and were not subject to deposit insurance.

Equity Securities

The Company determines the appropriate classification of marketable securities at the time of purchase and reevaluates this designation as of each balance sheet date. The Company classifies these securities as either held-to-maturity, trading, or available-for-sale. All marketable securities and restricted investments were classified as available-for-sale securities. The Company classifies its investments as “available for sale” because it does not intend to actively buy and sell for short-term profits. The Company's investments are subject to market risk, primarily interest rate and credit risk. The fair value of investments is determined using observable or quoted market prices for those securities.

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

Property, Plant and Equipment

Property, plant and equipment, including assets under capital lease, are recorded at historical cost. Costs of acquisition of geothermal properties are capitalized in the period of acquisition. Major improvements that significantly increase the useful lives and/or capabilities of the assets are capitalized. A primary factor in determining whether to capitalize construction type costs is the stage of the potential project’s development. Once a project is determined to be commercially viable, all costs directly associated with the development and construction of the project are capitalized. Until that time, all development costs are expensed. A commercially viable project will have, among other factors, a reservoir discovery well or other significant geothermal surface anomaly, a power transmission path that is identified and available, and an electricity off-taker identified. A valid reservoir discovery is generally defined when a test well has been substantially completed that indicates the presence of a geothermal reservoir that has a high probability of possessing the necessary temperatures, permeability, and flow rates. After a valid discovery has been made, the project enters the development stage. Generally, all costs incurred during the development stage are capitalized and tracked on an individual project basis. If a geothermal project is abandoned, the associated costs that have been capitalized are charged to expense in the year of abandonment. Expenditures for repairs and maintenance are charged to expense as incurred. Interest costs incurred during the construction period of defined major projects from debt that is specifically incurred for those projects are capitalized. Funds received from grants associated with capital projects reduce the cost of the asset directly associated with the individual grants. The offset of the cost of the asset associated with grant proceeds is recorded in the period when the requirements of the grant are substantially complete and the amount can be reasonably estimated.

-F-7-

Direct labor costs, incurred for specific major projects expected to have long-term benefits will be capitalized. Direct labor costs subject to capitalization include employee salaries, as well as, related payroll taxes and benefits. With respect to the allocation of salaries to projects, salaries are allocated based on the percentage of hours that our key managers, engineers and scientists work on each project and are invoiced to the project each month. These individuals track their time worked at each project. Major projects are, generally, defined as projects expected to exceed $500,000. Direct labor includes all of the time incurred by employees directly involved with construction and development activities. General and/or indirect management time and time spent evaluating the feasibility of potential projects are expensed when incurred. Employee training time is expensed when incurred.

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

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

Intangible Assets

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

-       contractual expiration terms of the right,
-       contractual terms of an associated revenue contract (i.e., PPA’s),
-       compliance with utilization and other requirements, and
-       hierarchy of other right holders who share the same resource.

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

Impairment of Long-Lived Assets

The Company evaluates its long-term assets annually for impairment and when circumstances/events occur that may impact the fair value of the assets. An impairment loss would be recognized if the carrying amount of a capitalized asset is not recoverable and exceeds its fair value. The most recent assessment was performed based upon financial conditions and assumptions as of December 31, 2013, and there have not been any significant changes in financial conditions and assumptions subsequent to that assessment date. Management believes that there have not been any circumstances that have warranted the recognition of losses due to the impairment of long-lived assets.

-F-8-

Stock Options Granted to Employees and Non-employees

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

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

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

Stock Based Compensation Granted to Employees

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

Earnings (Losses) Per Share

The Company follows financial accounting standards, which provides for calculation of "basic" and "diluted" earnings (losses) per share. Basic earnings per share includes no dilution and is computed by dividing net income available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of an entity similar to fully diluted earnings per share. Both basic and diluted were presented for the calculation of the income per share for the periods that reported income. Stock equivalents were not included in the calculation for the periods that reported losses since their inclusion would be considered anti-dilutive. Total common stock equivalents on a fully diluted basis at December 31, 2013 and 2012 were 124,494,963 and 122,768,560; respectively.

Financial Instruments

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

-F-9-

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

Revenue

Revenue Recognition

Energy Sales
The energy sales revenue is recognized when the electrical power generated by the Company’s power plants is delivered to the customer who is reasonably assured to be able to pay under the terms defined by the Power Purchase Agreements (“PPAs”).

Renewable Energy Credits (“RECs”)
Currently, the Company operates three plants that produce renewable energy that creates a right to a REC. The Company earns one REC for each megawatt hour produced from the geothermal power plant. The Company considers the RECs to be an inventory item held for sale, and outputs that are an economic benefit obtained directly through the operation of the plants. The Company does not currently hold any RECs for our own use. Revenues from RECs sales are recognized when the Company has met the terms and conditions of certain energy sales agreements with a financially capable buyer. At Raft River Energy I LLC, each REC is certified by the Western Electric Coordinating Council and sold under a REC Purchase and Sales Agreement to Holy Cross Energy. At San Emidio and Neal Hot Springs, the RECs are owned by our customer and are bundled with energy sales. At all three plants, title for the RECs pass during the same month as energy sales. As a result, costs associated with the sale of RECs are not segregated on the statement of operations.

Revenue Source
All of the Company’s operating revenues (energy sales and energy credit sales) originate from energy production from its interests in geothermal power plants located in the states of Idaho, Oregon and Nevada.

Reclassification

Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no effect on reported losses, total assets, or stockholders’ equity as previously reported.

Recent Accounting Pronouncements

Management has considered all recent accounting pronouncements. The following pronouncement was deemed applicable to our financial statements.

Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued Accounting Standards Update No. 2013-11 (“Update 2013-11”), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (Topic 740). Update 2013-11 provides guidance on the presentation of unrecognized tax benefits that are associated with a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Update 2011-05 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. Management is still evaluating the impact of this update, and expects that it may impact the presentation of its financial statements.

-F-10-

NOTE 3 – RESTRICTED CASH AND BOND RESERVES

During the quarter ended September 30, 2013, the Company finalized the terms of the loan agreements with the Department of Energy and the Prudential Capital Group. Under the terms of the loan agreements, various bond and cash reserves were required to provide assurances that the power plants will have the necessary funds to maintain expected operations and meet loan payment obligations. Restricted cash balances and bond reserves are summarized as follows:

Current restricted cash and bond reserves:

		December 31,
Restricting Entities/Purpose		2013		2012
Idaho Department of Water Resources, Geothermal Well Bond	$	260,000	$	260,000
Bureau of Land Management, Geothermal Lease Bond- Gerlach		10,000		10,000
State of Nevada Division of Minerals, Statewide Drilling Bond		50,000		50,000
Bureau of Land Management, Geothermal Lease Bonds- USG Nevada		150,000		150,000
Oregon Department of Geology and Mineral Industries, Mineral Land and Reclamation Program		400,000		400,000
Prudential Capital Group, Cash Reserves		19,848		-
U.S. Department of Energy, Debt Service Reserve		2,191,172		-
U.S. Department of Energy, Construction Loan Bond		-		2,125,000
	$	3,081,020	$	2,995,000

Long-term restricted cash and bond reserves:

		December 31,
Restricting Entities/Purpose		2013		2012
Nevada Energy, PPA Security Bond	$	1,468,898	$	1,426,700
Prudential Capital Group, Debt Service Reserves		1,594,437		-
Prudential Capital Group, Maintenance Reserves		751,183		-
Prudential Capital Group, Well Reserves		53,072		-
U.S. Department of Energy, Operations Reserves		270,000		-
U.S. Department of Energy, Debt Service Reserves		2,668,179		-
U.S. Department of Energy, Short Term Well Field Reserves		4,507,391		-
U.S. Department of Energy, Long-Term Well Field Reserves		4,501,191		-
U.S. Department of Energy, Capital Expenditure Reserves		3,000,794		-
	$	18,815,145	$	1,426,700

The well bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. Other future costs of environmental remediation cannot be reasonably estimated and have not been recorded. The debt service reserves are required to provide assurance that the Company will have sufficient funds to meet its debt payment obligations for the terms specified by the loan agreements. The maintenance and capital expenditure reserves are required by the lending entities to ensure that funds are available to acquire and maintain critical components of power plants and related supporting structures to enable the plants to operate according to expectations. The construction bond was required by the Loan Guarantee Agreement with the Department of Energy at Neal Hot Springs and was released upon completion of the plant facility. Except for the PPA Security Bond, all of the restricted funds consisted of cash deposits or money market accounts held in commercial banks. Portions of the cash deposits are subject to FDIC insurance. See note 2 for details. The PPA Security Bond is held by the power purchaser. All of the reserve accounts were considered to be fully funded at December 31, 2013.

-F-11-

NOTE 4 – GRANT PROCEEDS RECEIVABLE

USG Nevada LLC
The Company submitted an application on July 17, 2012, to the United States Department of Treasury for an ITC cash grant of approximately $11.70 million. 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 total proceeds from this grant offset a portion of the construction costs of the new power plant located in San Emidio, Nevada that was placed into service for financial reporting purposes on September 1, 2012. As of December 31, 2013, all proceeds expected from this cash grant have been received.

USG Oregon LLC
The Company submitted an application for an ITC cash grant (“ITC grant”) to the United States Department of Treasury in the first quarter of 2013. The Company also submitted an application to Oregon Department of Energy for a Business Energy Tax Credit (“BETC”) for qualified construction purchases related to the project located at Neal Hot Springs, Oregon. The Company received $7,364,200 from the BETC program. Proceeds collected on the ITC grant request totaled $32,749,541, which included a reduction of 8.7% federal sequestration. The net proceeds from the grants have been used to offset the construction costs of the power plant. As of December 31, 2013, all of the expected proceeds from these two programs were collected.

NOTE 5 – INVESTMENT IN EQUITY SECURITIES

Investments in equity securities (150,000 shares of Alterra Power Corp, a publicly traded renewable energy company) activities consisted of the following:

		Amount
Available-for-sale equity securities:
Cost basis	$	88,515
Net unrealized losses		(22,355	)
Foreign exchange losses		(609	)
Fair value at December 31, 2012		65,551
Net unrealized losses		(20,551	)
Foreign exchange losses		(2,826	)
Fair value at December 31, 2013	$	42,174

NOTE 6 - PROPERTY, PLANT AND EQUIPMENT

During the year ended December, 2013, the Company determined that the project located in the Republic of Guatemala was economically viable and began capitalizing drilling costs that amounted to over $1.7 million. At Neal Hot Springs, an agreement was reached with a major contractor that resulted in the reduction of project costs and related retainage of $2.26 million. Additional costs of approximately $7.8 million were incurred at the Neal Hot Springs power plant to finalize construction costs. The remaining balance of the ITC cash grant for San Emidio relating to previously disputed expenditures of approximately $1.05 million was collected. On February 15, 2013, the Company signed a settlement agreement with SAIC (the general contractor and construction loan holder) that reduced the construction liability including construction cost and accrued interest by approximately $2.14 million for the San Emidio, Nevada project. Costs that totaled approximately $817,000 were capitalized for a phase II monitoring well at San Emidio.

-F-12-

During the year ended December 31, 2012, the Company completed both the San Emidio, Nevada and Neal Hot Springs, Oregon projects. The new San Emidio power plant achieved commercial operation on May 25, 2012. The Neal Hot Springs three power producing units, transmission lines, well field and other supporting structures were completed and the plant achieved commercial operation on November 16, 2012.

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

		December 31,
		2013			2012
Land	$	1,603,509		$	1,603,509
Power production plant		161,868,687			159,742,109
Grant proceeds for power plants		(52,965,236	)		(54,630,755	)
Wells		67,620,661			67,365,362
Grant proceeds for wells		(3,464,555	)		(3,233,831	)
Furniture and equipment		1,462,312			1,356,144
		176,125,378			172,202,538
Less: accumulated depreciation		(20,895,943	)		(14,502,362	)
		155,229,435			157,700,176
Construction in progress		6,354,503			2,877,994
	$	161,583,938		$	160,578,170

The Company capitalized interest costs as a component of the Neal Hot Springs and San Emidio projects as follows:

		For the Year Ended December 31,
		2013		2012
Total interest expense incurred	$	3,687,742	$	2,909,911
Capitalized interest		-		2,749,081

Depreciation expense charged to plant operations and administrative costs for the years ended December 31, 2013 and 2012, was $6,393,581 and $3,508,709; respectively.

-F-13-

Changes in Construction in Progress are summarized as follows:

		Year Ended December 31,
		2013			2012
Beginning balances	$	2,877,994		$	145,987,128
Development/construction		3,694,978			64,564,914
Grant reimbursements and rebates		(33,325	)		(55,244,491	)
Transfers into production		(185,144	)		(152,429,557	)
Ending balances	$	6,354,503		$	2,877,994

Construction in Progress, at cost, consisting of the following projects/assets by location are as follows:

		December 31,
		2013		2012
Raft River, Idaho:
Unit II, power plant, substation and transmission lines	$	750,493	$	750,493
Unit II, well construction		2,121,502		2,100,862
		2,871,995		2,851,355
San Emidio, Nevada:
Unit II, power plant, substation and transmission lines		3,910		-
Unit II, well construction		1,753,299		26,639
		1,757,209		26,639
El Ceibillo, Republic of Guatemala:
Well Construction		1,725,299		-
		1,725,299		-
	$	6,354,503	$	2,877,994

-F-14-

NOTE 7 – INTANGIBLE ASSETS

Intangible assets, at cost, are summarized by project location as follows:

		December 31,
		2013			2012
In operation:
Neal Hot Springs, Oregon:
Geothermal water and mineral rights	$	625,337		$	-
San Emidio, Nevada:
Geothermal water and mineral rights		4,825,220			4,825,220
Less: accumulated amortization		(935,749	)		(754,064	)
		4,436,006			4,071,156
Inactive:
Raft River, Idaho:
Surface water rights		146,343			146,343
Geothermal water and mineral rights		1,251,540			1,251,540
Granite Creek, Nevada:
Surface water rights		451,299			451,299
Neal Hot Springs, Oregon:
Geothermal water and mineral rights		-			625,336
Guatemala City, Guatemala:
Geothermal water and mineral rights		625,000			625,000
Gerlach, Nevada:
Geothermal water and mineral rights		997,000			997,000
San Emidio, Nevada:
Surface water rights		4,323,520			4,323,520
Geothermal water and mineral rights		3,440,580			3,440,580
Less: prior accumulated amortization		(430,072	)		(430,072	)
		10,805,210			11,430,546
	$	15,241,216		$	15,501,702

Amortization expense was charged to plant operations for the years ended December 31, 2013 and 2012 that amounted to $181,685 and $173,872; respectively.

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

		Projected
		Amounts
Years ending December 31,
2014	$	181,685
2015		181,685
2016		181,685
2017		181,685
2018		181,685
	$	908,425

-F-15-

NOTE 8 – PROVISION FOR INCOME TAXES

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

At December 31, 2013, the Company had net deferred tax assets calculated at an expected rate, noted in the table below, of approximately $10,742,000 (December 31, 2012 - $11,109,000). As management of the Company cannot determine that it is more likely than not that the Company will realize the benefit of the net deferred tax asset, a valuation allowance equal to the net deferred tax asset was recorded at December 31, 2013 and 2012. For the current year ended December 31, 2013, the Company has recognized the net deferred income tax asset to the extent of the impact created from current book earnings. During the year ended December 31, 2013, the Company engaged a tax matters consultant to evaluate the value and timing of adjusting the deferred tax valuation allowance. The Company anticipates that any tax obligations will be fully offset by the utilization of prior reserved deferred tax benefits for the year ended December 31, 2013.

The significant components of the net deferred tax asset calculated with the estimated effective income tax rate at December 31, 2013 and 2012 were as follows:

		December 31,
		2013			2012
Deferred tax assets*:
Net operating loss carry forward	$	38,400,000		$	20,983,000
Stock based compensation		1,868,000			1,532,000
Deferred tax liabilities*:
Depreciation and amortization		(29,554,000	)		(11,406,000	)
Net deferred income tax asset		10,714,000			11,109,000
Estimated deferred tax asset recognized and utilized in current period		(1,578,000	)		-
Deferred tax asset valuation allowance		(9,136,000	)		(11,109,000	)
Net deferred tax asset	$	-		$	-

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

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

	For the Years Ended December 31,
	2013	2012
U.S. Federal statutory rate	34.0%	34.0%
Average State income tax, net of federal tax effect	4.2	4.2
Production tax credits	-	(2.0	)
Net effective tax rate	38.2%	36.2%

-F-16-

At December 31, 2013, the Company had net income tax operating loss carry forwards of approximately $101,414,000 ($57,963,000 in December 31, 2012), which expire in the years 2023 through 2033. The change in the allowance account from December 31, 2012 to December 31, 2013 was a decrease of $1,295,000 for the anticipated deferred tax allocations based on 2013 income.

The change in the allowance account is summarized as follows:

		For the Year Ended December 31,
		2013			2012
Change in net operating loss	$	16,258,000		$	3,976,000
Change in estimated effective tax rate		614,000			-
Net change in difference between book and tax stock compensation costs		251,000			230,000
Estimated deferred tax asset recognized and utilized in current period		(1,578,000	)
Change in period book to income tax depreciation		(17,518,000	)		(2,499,000	)
	$	(1,973,000	)	$	1,707,000

At December 31, 2013, Raft River Energy I LLC has a book-to-tax difference of $35.7 million due to the acceleration of intangible drilling costs and depreciation. By contract, 99% percent of this book-to-tax difference has been allocated to the non-controlling interest and would not be available to the consolidated group to offset future tax liabilities. At December 31, 2013, USG Oregon LLC has a book-to-tax difference of $38.1 million due to the acceleration of depreciation.

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

Accounting for Income Tax Uncertainties and Related Matters

The Company may be assessed penalties and interest related to the underpayment of income taxes. Such assessments would be treated as a provision of income tax expense on the financial statements. For the year ended December 31, 2013, nine months ended December 31, 2012 and the fiscal year ended March 31, 2012, no income tax expense has been realized as a result of operations and no income tax penalties and interest have been accrued related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and in the States of Idaho and Oregon. These filings are subject to a three year statute of limitations. The Company’s evaluation of income tax positions included the year ended December 31, 2013, the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012 could be subject to agency examinations as of December 31, 2012. No filings are currently under examination. No adjustments have been made to reduce the estimated income tax benefit at fiscal year end. Any valuations relating to these income tax provisions will comply with U.S. generally accepted accounting principles.

NOTE 9 - CAPITAL LEASE OBLIGATIONS

Effective May 10, 2012, the Company entered into two capital lease obligations for the purchase of a boom lift and a telehandler from Caterpillar Financial Services Corporation. The boom lift contract is payable in 36 monthly payments of $1,094 that began on June 11, 2012 and has an effective annual interest rate of 5.985%. The telehandler contract is payable in 36 monthly payments of $3,155 that began on June 11, 2012 and has an effective annual interest rate of 6.14%. Both contracts with Caterpillar Financial Services Corporation have bargain purchase options at the end of the contracts scheduled for May 2015.

-F-17-

The scheduled future lease payments for the three contracts are presented as follows:

		Capital Lease
Years ending December 31,		Amounts
2014	$	50,997
2015		21,249
Total future payments		72,246
Less: imputed interest portion		(3,207	)
	$	69,039
Allocation of capital lease obligations:
Current portion	$	48,118
Long-term portion		20,921
	$	69,039

At December 31, 2013, the net book value of the equipment under capital lease amounted to $81,301 ($155,000, less $73,699 accumulated amortization).

NOTE 10 – CONVERTIBLE NOTE PAYABLE

On August 5, 2011, the Oregon USG Holdings, LLC (“Oregon Holdings”), a subsidiary of the Company, signed a convertible note agreement with our equity partner (Enbridge Inc.). The principal of the loan totaled $2,125,000, and accrued interest at a rate of 4.75% per annum. The loan balance plus accrued interest would have converted to an equity interest in Oregon Holdings upon the earliest of a conversion event or April 1, 2014, if unpaid. Conversion events include the failure to obtain the Section 1603 ITC cash grant funds by the Project. The converted balance would have increased Enbridge Inc.’s ownership at a ratio of 1.5% for each $1 million contributed. During the year ended December 31, 2013, the principal of $2,125,000 was paid in full without conversion to an equity interest. At December 31, 2013, accrued and unpaid interest on the loan totaled $208,061.

NOTE 11 – NOTES PAYABLE

U.S. Department of Energy
On August 31, 2011, USG Oregon LLC (“USG Oregon”), a subsidiary of the Company, completed the first funding drawdown associated with the U.S. Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to construct its planned power plant at Neal Hot Springs in Eastern Oregon (the “Project”). The U.S. Treasury’s Federal Financing Bank, as lender for the Project, issues payments direct to vendors. All loan advances covered by the Loan Guarantee have been made under the Future Advance Promissory Note (the “Note”) dated February 23, 2011. Upon the occurrence and continuation of an event of default under the transaction documents, all amounts payable under the Note may be accelerated. In connection with the Loan Guarantee, the DOE has been granted a security interest in all of the equity interests of USG Oregon, as well as in the assets of USG Oregon, including a mortgage on real property interests relating to the Project site. The loan advances began August 31, 2011 and the last advance was taken on July 31, 2013. No additional advances are allowed under the terms of the grant. A total of 13 draws were taken and each individual draw or tranche is considered to be a separate loan. On August 12, 2013, proceeds of the grant were distributed in accordance with the loan agreement, with $11,870,137 of the proceeds being used to prepay the Project loan, $11,167,473 of proceeds being used to fund a series of Project reserves, and balance of $9,711,930 being distributed as equity to the project owners. After the loan prepayment, the remaining final loan balance was $70,386,576. The loan principal is scheduled to be paid over 21.5 years with semi-annual installments including interest calculated at an aggregate fixed interest rate of 2.598%. The principal payment amounts are calculated on a straight-line basis according to the life of the loans and the original loan principal amounts. The principal portion of the aggregate loan payment is adjusted as individual tranches are extinguished. The principal payments are scheduled to start at $1,709,963 and are expected to be reduced to $1,626,251 on February 10, 2017. The loan balance at December 31, 2013 totaled $70,997,780 (estimated current portion $3,419,927).

-F-18-

Loan advances/tranches and effective annual interest rates are details as follows:

				Annual Interest
Description		Amount		Rate %
Advances by date:
August 31, 2011*	$	2,328,422		2.997
September 28, 2011		10,043,467		2.755
October 27, 2011		3,600,026		2.918
December 2, 2011		4,377,079		2.795
December 21, 2011		2,313,322		2.608
January 25, 2012		8,968,019		2.772
April 26, 2012		13,029,325		2.695
May 30, 2012		19,497,204		2.408
August 27, 2012		7,709,454		2.360
December 28, 2012		2,567,121		2.396
June 10, 2013		2,355,316		2.830
July 3, 2013*		2,242,628		3.073
July 31, 2013*		4,026,582		3.214
		83,057,965
Principal paid through December 31, 2013		(12,060,185	)
Loan balance at December 31, 2013	$	70,997,780

* - Individual tranches have been fully extinguished.

SAIC Constructors LLC
Effective August 27, 2010, the Company’s wholly owned subsidiary (USG Nevada LLC) signed a construction loan agreement with SAIC Constructors LLC (“SAIC”). The new 9.0 net megawatt power plant was considered complete and operational for financial reporting purposes on September 1, 2012. On February 15, 2013, USG Nevada LLC signed a settlement agreement with SAIC that defined the terms of three separate debt components to settle the obligations incurred under the construction loan agreement. As of December 31, 2013, two components of the settlement agreement were paid in full. On April 30, 2013, SAIC signed a loan agreement with Nevada USG Holdings LLC (parent company of USG Nevada LLC and wholly owned subsidiary of the Company), that further defined the terms of the remaining debt component of $2 million. This remaining obligation will be repaid in quarterly installments of $119,382, including interest at 7.0% per annum that began on July 31, 2013. The loan balance at December 31, 2013 totaled $1,850,314 (estimated current portion $378,698).

-F-19-

Prudential Capital Group
On September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group’s related entities (“Prudential”) to finance the Phase I San Emidio geothermal project (the “project”) located in northwest Nevada. The term of the note is approximately 24 years, and bears interest at fixed rate of 6.75% per annum. Interest payments are due quarterly. Principal payments are due quarterly based upon minimum debt service coverage ratios established according to operating results and available cash balances. All amounts owing under the notes and the note purchase agreement or any related financing document are secured by USG Nevada LLC’s right, title and interest in and to its real and personal property, including the project and the equity interests in USG Nevada LLC. At December 31, 2013, the balance of the loan was $30,505,500 (estimated current portion $323,167).

Based upon the terms of the notes payable and expected conditions that may impact some of those terms, the estimated annual principal payments were calculated as follows:

For the Year Ended		Principal
December 31,		Payments
2014	$	4,121,792
2015		4,319,468
2016		4,410,770
2017		4,332,491
2018		4,073,645
Thereafter		82,095,427
	$	103,353,593

NOTE 12 - CAPITAL STOCK

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

During the quarter ended September 30, 2013, the Company issued 577,778 shares of common stock to an employee of the Company at prices between $0.35 and $0.36 per share under the terms of an employment agreement.

On December 21, 2012, the Company issued 11,810,816 common stock shares at $0.37 under a registered direct offering with a limited number of investors and collected $4,087,802, net of broker fees and other costs of $282,200.

During the quarter ended September 30, 2012, the Company issued 1,250,000 common stock shares at prices between $0.312 and $0.355 under an At Market Issuance Sales agreement with Lincoln Park Capital.

During the quarter ended June 30, 2012, the Company issued 3,375,503 shares of common stock at prices between $0.341 and $0.536 under an At Market Issuance Sales agreement with Lincoln Park Capital.

-F-20-

During the quarter ended March 31, 2012, the Company issued 90,592 shares of common stock at a price of $0.65 under an At Market Issuance Sales agreement with Lincoln Park Capital.

NOTE 13 - STOCK BASED COMPENSATION

The Company has a stock incentive plan (the “Stock Incentive Plan”) for the purpose of attracting and motivating directors, officers, employees and consultants of the Company and advancing the interests of the Company. The Stock Incentive Plan is a 15% rolling plan approved by shareholders in December 2009 and September 2013, whereby the Company can grant options to the extent of 15% of the current outstanding common shares. Under the plan, all forfeited and exercised options can be replaced with new offerings. As of December 31, 2013, the Company can issue stock option grants totaling up to 15,314,181 shares. Options are typically granted for a term of up to five years from the date of grant. Stock options granted generally vest over a period of eighteen months, with 25% vesting on the date of grant and 25% vesting every six months thereafter. The Company recognizes compensation expense using the straight-line method of amortization. Historically, the Company has issued new shares to satisfy exercises of stock options and the Company expects to issue new shares to satisfy any future exercises of stock options. At December 31, 2013, the Company had 11,888,250 options granted and outstanding.

On September 25, 2013, 95,000 stock options exercisable at a price of $1.78 expired without exercise.

On September 1, 2013, the Company granted 15,000 stock options to an employee exercisable at a price of $0.41 until September 1, 2018.

On July 22, 2013, the Company granted 1,950,000 stock options to employees exercisable at a price of $0.46 until July 22, 2018.

On May 26, 2013, 6,375 stock options exercisable at a price of $0.92 were forfeited due to employee termination.

On May 19, 2013, 1,465,000 stock options exercisable at a price of $2.22 expired without exercise.

On April 19, 2013, the Company granted 1,250,000 stock options to employees exercisable at a price of $0.35 until April 19, 2023.

On August 24, 2012, the Company granted 2,917,000 stock options to employees exercisable at a price of $0.31 until August 24, 2017.

On July 23, 2012, 652,500 stock options exercisable at a price of $2.41 expired without exercise.

On January 22, 2012, 157,500 stock options exercisable at a price of $1.40 CDN expired without exercise.

-F-21-

The following table reflects the summary of stock options outstanding at December 31, 2011 and changes for the years ended December 31, 2013 and 2012:

				Weighted
				Average		Weighted
	Number of			Exercise		Average		Aggregate
	shares under			Price Per		Fair		Intrinsic
	options			Share		Value		Value
Balance outstanding, December 31, 2011	8,132,625		$	1.26	$	0.71	$	5,752,781
Forfeited/Expired	(810,000	)		2.21		0.74		(600,246	)
Exercised	-			-		-		-
Granted	2,917,000			0.31		0.16		453,774
Balance outstanding, December 31, 2012	10,239,625			0.91		0.55		5,606,309
Forfeited/Expired	(1,566,375	)		2.18		1.20		(1,872,094	)
Exercised	-			-		-		-
Granted	3,215,000			0.42		0.25		808,500
Balance outstanding, December 31, 2013	11,888,250		$	0.61	$	0.38	$	4,542,715

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

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

	For the Years Ended December 31,
	2013	2012
Dividend yield	0	0
Expected volatility	71-81%	65-70%
Risk free interest rate	0.27-0.82%	0.19-0.33%
Expected life (years)	4.63	3.17

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

-F-22-

The following table summarizes information about the stock options outstanding at December 31, 2013:

		OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	0.92	1,698,250	0.40	1,698,250	$	1,200,208
	1.58	68,000	0.73	68,000		26,435
	0.86	1,300,000	1.70	1,300,000		752,207
	0.83	2,590,000	2.43	2,590,000		1,269,100
	0.60	100,000	2.70	100,000		36,072
	0.31	2,917,000	3.65	2,187,750		340,332
	0.46	1,950,000	4.56	487,500		118,414
	0.41	15,000	4.67	3,750		753
	0.35	1,250,000	9.30	625,000		169,000
$	0.61	11,888,250	3.43	9,060,250	$	3,912,521

The following table summarizes information about the stock options outstanding at December 31, 2012:

		OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	2.22	1,465,000	0.63	1,465,000	$	1,786,417
	1.78	95,000	0.74	95,000		81,172
	0.92	1,704,625	1.40	1,704,625		1,204,713
	1.58	68,000	1.73	68,000		26,435
	0.86	1,300,000	2.70	1,300,000		752,207
	0.83	2,590,000	3.43	2,590,000		1,269,100
	0.60	100,000	3.70	75,000		27,054
	0.31	2,917,000	4.65	729,250		113,444
$	0.91	10,239,625	2.80	8,026,875	$	5,260,542

-F-23-

A summary of the status of the Company’s nonvested stock options outstanding at December 31, 2011 and changes during the years ended December 31, 2013 and 2012 are presented as follows:

				Weighted		Weighted
				Average Grant		Average
	Number of			Date Fair Value		Grant Date
	Options			Per Share		Fair Value
Nonvested, December 31, 2011	1,695,000		$	0.83	$	0.50
Granted	2,917,000			0.31		0.16
Vested	(2,399,250	)		0.69		0.40
Forfeited/Expired	-			-		-
Nonvested, December 31, 2012	2,212,750			0.31		0.16
Granted	3,215,000			0.42		0.25
Vested	(2,599,750	)		0.35		0.23
Forfeited/Expired	-			-		-
Nonvested, December 31, 2013	2,828,000		$	0.39	$	0.23

As of December 31, 2013, there was $389,503 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years. The total fair value of options vested at December 31, 2013 and 2012 was $683,143 and $861,277; respectively.

Stock Compensation Plan (Restricted Shares)

On September 10, 2010, the Company granted officers, directors and select employees 705,000 common shares that will be distributed in three six-month vesting periods. The recipients meet the vesting requirements by maintaining employment and good standing with the Company through the vesting periods. After vesting, there are no restrictions on the shares. On March 10, 2011, the 705,000 common shares were issued to the recipients and held by the Company. All of these shares were considered to be issued and outstanding. On March 11, 2011, 235,000 common shares vested valued at $0.99 per share, and the shares were released to the qualified recipients. On September 11, 2011, 235,000 common shares vested valued at $0.60 per share and the shares were released to the qualified recipients. The final 235,000 shares valued at $0.58 vested and were released on March 11, 2012.

On April 19, 2013, the Company granted an officer and director 300,000 common shares valued at $0.35 per share, which will be distributed at the end of a one-year vesting period. The recipient meets the vesting requirements by maintaining employment and good standing with the Company through the vesting period. After vesting, there are no restrictions on the shares. These shares were issued in July 2013 to the recipient and held by the Company until vested. The total fair value of options at the grant date was $105,000 and the recognized cost through December 31, 2013 was $73,792.

-F-24-

Stock Purchase Warrants

At December 31, 2013, the outstanding broker warrants and share purchase warrants consisted of the following:

			Broker
			Warrant	Share		Warrant
	Broker		Exercise	Purchase		Exercise
Expiration Date	Warrants		Price	Warrants		Price
September 16, 2015	246,285	$	1.25	4,104,757	$	1.25
May 23, 2017	255,721		0.44	-		-
December 21, 2017	-		-	5,905,408		0.50

On February 2013, 500,000 stock purchase warrants at an exercise price of $5.00 expired without exercise.

On December 21, 2012, the Company issued 5,905,408 stock purchase warrants exercisable at a price of $0.50 until December 21, 2017.

On May 23, 2012, the Company issued 118,421 broker warrants at an exercise price of $0.437.

On March 4, 2012, 2,500,000 stock purchase warrants and 56,000 broker warrants at an exercise price of $1.075 expired without exercise.

NOTE 14 – FAIR VALUE MEASUREMENT

Current U.S. generally accepted accounting principles establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

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

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

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

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

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

-F-25-

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on its Consolidated Balance Sheet as of December 31, 2013 at fair value on a recurring basis:

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts *	$	29,623,935	$	29,623,935	$	-	$	-
Investment in equity securities		43,632		-		42,174		-
	$	29,666,109	$	29,623,935	$	42,174	$	-

* - Money market accounts include both restricted and unrestricted funds.

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

NOTE 15 - RELATED PARTY TRANSACTIONS

At December 31, 2013 and 2012 the amounts of $3,089 and $3,391; respectively, were payable to the officers of the Company for routine expense reimbursement. These amounts are unsecured and due on demand.

The Company paid directors’ fees for the years ended December 31, 2013 and 2012 amounting to $99,000 and $120,000; respectively.

NOTE 16 - COMMITMENTS AND CONTINGENCIES

Operating Lease Agreements
The Company has entered into several lease agreements with terms expiring up to December 1, 2034 for geothermal properties in Washoe County Nevada; Republic of Guatemala; Neal Hot Springs, Oregon and adjoining the Raft River properties in Raft River, Idaho. The Company incurred total lease expenses for the years ended December 31, 2013 and 2012, of $373,039 and $116,227; respectively.

BLM Lease Agreements

The Company believes that it is in compliance with all of the following lease terms.

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

-F-26-

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

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

Granite Creek
The Company has three geothermal lease contracts with the BLM for the Granite Creek properties. The lease contracts are for approximately 2,443.7 acres of land and geothermal water rights located in North Western Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases state annual lease payments of $2,444, not including processing fees, and expire October 2017.

Raft River Energy I LLC
The Company has entered into several lease contracts for approximately 1,298 acres of land and geothermal water rights located in the Raft River area located in Southern Idaho. The contracts expire from March 2013 to December 2033. The contracted lease payments are scheduled for $31,287 for the year ended December 31, 2013.

Office Lease

Park Center Boulevard
On August 12, 2013, the Company signed a 5 year lease agreement for office space and janitorial services. The lease payments are due in monthly installments starting February 1, 2014. The monthly payments that begin February 1, 2014 have two components which include a base rate of $3,234 that is not subject to increase and a rate beginning at $6,418 that is adjusted annually according to the cost of living index. The contract includes a 5 year extension option.

Tyrell Lane
Under the current contract, the lease payments were due in monthly installments of $6,535. The current contract effectively ends January 31, 2014 and will not be renewed. The total office lease costs incurred under the current contract and the prior contract for years ended December 31, 2013 and 2012, totaled $78,423 and $76,138; respectively.

-F-27-

Contracted Lease Obligation Schedule

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

Year Ending
December 31,		Amount
2014	$	475,521
2015		534,828
2016		566,115
2017		561,053
2018		532,710
Thereafter		9,475,229

Power Purchase Agreements

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

USG Nevada LLC
As a part of the purchase of the assets from Empire Geothermal Power, LLC and Michael B. Stewart acquisition (“Empire Acquisition”), a power purchase agreement with Sierra Pacific Power Company was assigned to the Company. The contract had a stated expected output of 3,250 kilowatts maximum per hour and extended through 2017. During the year ended March 31, 2012, the power purchase agreement was replaced by a new 25 year contract signed in December of 2011 that sets the new set rate at $89.70 per megawatt hour with a 1% annual escalation rate. The new contract allows for a maximum of 71,300 megawatt hours annually. Upon declaration of commercial operation under the PPA, an Operating Security Deposit is required to be maintained at NV Energy for the full term of the PPA. As of December 31, 2013, the Company has fund a security bond of $1,468,898.

USG Oregon LLC
In December of 2009, the Company’s subsidiary (USG Oregon LLC), signed a power purchase agreement with Idaho Power Company for the sale of power generated by the Neal Hot Springs, Oregon project. The agreement has a term of 25 years and provides for the purchase of power up to 25 megawatts (22 megawatt planned annual average output level). Beginning 2012, the flat energy price is $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.

401(k) Plan
The Company offers a defined contribution plan qualified under section 401(k) of the Internal Revenue Code to all its eligible employees. All employees are eligible at the beginning of the quarter after completing 3 months of service. Subsequent to June 30, 2013, the Company began matching 50% of the employee’s contribution up to 6%. Prior to June 30, 2013, the plan required the Company to match 25% of the employee’s contribution up to 6%. Employees may contribute up to the maximum allowed by the Internal Revenue Code. The Company made matching contributions to the plan that totaled $60,425 and $36,520 for the years ended December 31, 2013 and 2012, respectively.

-F-28-

NOTE 17 – JOINT VENTURES/NON-CONTROLLING INTERESTS

Non-controlling interests included on the consolidated balance sheets of the Company are detailed as follows:

		December 31,
		2013		2012
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	404,352	$	404,434
Oregon USG Holdings LLC interest held by Enbridge Inc.		35,926,826		33,078,744
Raft River Energy I LLC interest held by Raft River I Holdings, LLC		21,824,302		22,598,020
	$	58,155,480	$	56,081,198

Gerlach Geothermal LLC
On April 28, 2008, the Company formed Gerlach Geothermal, LLC (“Gerlach”) with our partner, Gerlach Green Energy, LLC (“GGE”). The purpose of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. Based upon the terms of the members’ agreement, the Company owns a 60% interest and GGE owns a 40% interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to maintain its 40% ownership interest as additional capital contributions are required. If GGE dilutes to below a 10% interest, their ownership position in the joint venture would be converted to a 10% net profits interest. The Company has contributed $757,190 in cash and $300,000 for a geothermal lease and mineral rights; and the GGE has contributed $704,460 of geothermal lease, mineral rights and exploration data.

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

Oregon USG Holdings LLC
In September 2010, the Company’s subsidiary, Oregon USG Holdings LLC (“Oregon Holdings”), signed an Operating Agreement with Enbridge Inc. (“Enbridge”) for the right to participate in the Company’s project in the Neal Hot Springs project located in Malheur County, Oregon. Oregon Holdings has a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of $32,801,000, including the debt conversion, to Oregon Holdings in exchange for a direct ownership interest. Under the initial agreement, the ownership interest began at 20%, and increased to 35% according to capital contribution levels. On February 20, 2014, a new agreement was reached with Enbridge that established the ownership interest percentage at 40%, effective January 1, 2013.

The consolidated financial statements reflect 100% of the assets and liabilities of Oregon Holdings and USG Oregon LLC, and report the current non-controlling interest of Enbridge. The full results of Oregon Holdings and USG Oregon LLC’s operations are reflected in the statement of operations with the elimination of the non-controlling interest identified.

Raft River Energy I LLC (“RREI”)
Raft River Energy I is a joint venture between the Company and Raft River I Holdings, LLC a subsidiary of the Goldman Sachs Group, Inc. An Operating Agreement governs the rights and responsibilities of both parties. At fiscal year end, the Company had contributed approximately $17.9 million in cash and property, and RREI has contributed approximately $34.1 million in cash. Profits and losses are allocated to the members based upon contractual terms. For income tax purposes, Raft River I Holdings, LLC receives a greater proportion of the share of losses and other income tax benefits. This includes the allocation of production tax credits, which will be distributed 99% to Raft River I Holdings, LLC and 1% to the Company during the first 10 years of production. During the initial years of operations, Raft River I Holdings, LLC will receive a larger allocation of cash distributions.

-F-29-

The consolidated financial statements reflect 100% of the assets and liabilities of RREI, and report the current non-controlling interest of Raft River I Holdings LLC. The full results of Raft River Energy I LLC’s operations are reflected in the statement of operations with the elimination of the non-controlling interest identified.

Effective May 17, 2011, a repair services agreement (“RSA”) was executed between the RREI and U.S. Geothermal Services, LLC for the purpose of funding repairs of two underperforming wells. The agreement defined terms of the RSA repair costs and RSA repair management fees that would be funded by the loan. The outstanding loan balance will accrue interest at 12.0% per annum. The RSA payments will be made preferentially from project cash flow at a rate of 90% of increased cash created by the repairs and cash availability on a quarterly basis. The repairs were completed in January 2012. Based upon the financial conditions applicable to the loan, RREI did not make any payments during the year ended December 31, 2012. As of December 31, 2012, the loan balance amounted to $2,136,150. During the year ended December 31, 2013, RREI made principal payments on the loan of $755,288. The balance of the loan at December 31, 2013 was $1,380,862. The loan balance and related interest effects are fully eliminated during the consolidation process.

-F-30-

NOTE 18 – CHANGE IN YEAR END FOR FINANCIAL REPORTING PURPOSES

On July 5, 2012, the Company’s Board of Directors approved the change in the Company’s fiscal year end for reporting purposes from March 31^st to December 31^st. The change was made to increase financial reporting efficiency for the consolidated Company, as well as several of its subsidiaries. The change resulted in a nine month transition period that began on April 1, 2012 and ended on December 31, 2012. The following summarized financial information is presented to compare and illustrate operating results for the periods involved in the transition:

					Nine Months			Three Months
		Year Ended			Ended			Ended			Year Ended
		December 31,			December 31,			March 31,			December 31,
		2013			2012			2012			2012
Plant operating revenues	$	27,370,934		$	8,599,859		$	1,159,087		$	9,758,946
Plant operating expenses		(14,159,022	)		(7,310,808	)		(2,220,862	)		(9,531,670	)
Net income (loss) from plant operations		13,211,912			1,289,051			(1,061,775	)		227,276
Other expenses (income)		9,081,263			3,204,718			1,354,083			4,558,801
Net income (loss)		4,130,649			(1,915,667	)		(2,415,858	)		(4,331,525	)
Net (income) loss attributable to the non-      controlling interests		(2,184,070	)		600,823			772,135			1,372,958
Net income (loss) attributable to U.S. Geothermal Inc.		1,946,579			(1,314,844	)		(1,643,723	)		(2,958,567	)
Other comprehensive income (loss)		(23,377	)		(26,946	)		31,551			4,605
Comprehensive income (loss) attributable to       U.S. Geothermal Inc.	$	1,923,202		$	(1,341,790	)	$	(1,612,172	)	$	(2,953,962	)
Basic and diluted net income (loss) per share      attributable to U.S. Geothermal Inc.	$	0.02		$	(0.01	)	$	(0.02	)	$	(0.03	)
Diluted net income (loss) per share attributable       to U.S. Geothermal Inc.	$	0.02		$	(0.01	)	$	(0.02	)	$	(0.03	)
Weighted average number of shares outstanding       for basic calculations		101,795,364			88,783,972			85,016,732			87,847,308
Weighted average number of shares outstanding       for basic and diluted calculations		123,497,883			104,180,331			99,690,548			102,155,529

NOTE 19 - SUBSEQUENT EVENTS

The Company has evaluated events and transactions that have occurred after the balance sheet date through March 25, 2014, which is considered to be the issuance date. The following events were identified for disclosure:

-F-31-

USG Oregon LLC Financial Partnership Agreement
On February 20, 2014, the Company finalized a financial partnership agreement with Enbridge Inc. that defined the equity interest in USG Oregon LLC, a subsidiary of the Company. The final ownership interest of USG Oregon LLC was calculated in accordance with the terms of the partnership agreement that specified a 60% interest for U.S. Geothermal Inc. and a 40% interest for Enbridge Inc. The defined ownership interests were effective January 1, 2013. As a result of the final agreement, the Company received a $6.2 million cash distribution from the partnership.

Oregon USG Holdings LLC/USG Oregon LLC Profit Distribution
On March 10, 2014, Oregon USG Holdings LLC, Parent Company of USG Oregon LLC, made its first distribution of cash. Oregon USG Holdings is 60% owned by the Company and 40% owned by Enbridge Inc. Under the terms of the U.S. Department of Energy loan agreement, distributable cash is distributed to the equity partners semi-annually (February and August) following Final Completion, which was achieved on August 1, 2013. The Company’s share of this first distribution is $4.6 million, out of a total distribution to the partners of $7.7 million, which represents distributable cash generated from the project since initial operation began in November 2012.

-F-32-

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

None.

Item 9A. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

In connection with the preparation of this annual report on Form 10-K, an evaluation was carried out by the Company’s management, with the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (“Exchange Act”)) as of December 31, 2013. 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, 2013.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013. 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 – 1992). Based on its assessment, management concluded that, as of December 31, 2013, the Company’s internal control over financial reporting is effective based on those criteria.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

As of the end of the period covered by this report, there have been no changes in internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) during the year ended December 31, 2013, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Directors and Executive Officers

The Board of Directors (the “Board”) of the Company is currently composed of five directors: Dennis J. Gilles, Douglas J. Glaspey, Paul A. Larkin, Leland L. Mink and John H. Walker. The majority of the Board, made up of 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. Gilles 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 55, 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 61, 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 35 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 35 years of experience in the natural resource industry and his many years of senior management and director experience.

-94-

Kerry D. Hawkley: Age 60, 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.

Paul Larkin: Age 63, 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 has served as Chairman of the Audit Committee from 2003 to present. He also 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: Esrey Energy Ltd., Condor Resources Ltd., Tyner Resources Ltd. Gstaad Capital Corp., Draft Team Fantasy Sports Inc. 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 73, serves as a director of the Company, a position he has held since November 2006. Dr. Mink holds a PhD in Geology from the University of Idaho and 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 serves on the Geothermal Resources Board of Directors and is a member of the Geothermal Energy Association. His qualifications to serve as a director of the Company include his many years of senior leadership and management experience in the geothermal energy industry.

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John H. Walker: Age 65, 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.

Jonathan Zurkoff: Age 58, 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) Beneficial Ownership Reporting Compliance

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 year ended December 31, 2013 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.

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Code of Ethics

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 year ended December 31, 2013. 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.

Audit Committee and Audit Committee Financial Expert

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 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.

Item 11. Executive Compensation

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.

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

• base salary;
• annual cash incentive bonus opportunity; and
• stock options and restricted stock.

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 fiscal year ended December 31, 2013, the Company was focused on (1) operation and completion of financing for the San Emidio Phase I geothermal project in Nevada, (2) completion of construction, operation and financing for the Neal Hot Springs project in Oregon, (3) drilling, 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, Ram Power, Alterra, Calpine, Ormat, Chesapeake, Algonquin Power, Boralex, Caribbean Utilities, Maxim Power, Etrion, and Atlantic Power, who are involved in either geothermal development, mineral exploration, electrical power generators or other similar activities. 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.

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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 a recommendation from the CEO with input from other executive officers. Bonus amounts are dependent upon our financial and operational performance as well as the completion of specific milestone events by the individual executive officer.

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 typically 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 occurs during the second fiscal quarter. The options typically vest 25% on the date of grant, and another 25% each six months thereafter. During the fiscal year ended December 31, 2013, stock option grants to executive officers represented approximately 52% of the total stock option grants to all employees. During the year ended December 31, 2013, 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.

Our executive officers do not normally 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.

Kunz Employment Agreement
On September 29, 2011, Daniel J. Kunz, our former Chief Executive Officer, signed an employment agreement that set 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 was entitled to receive performance bonuses and incentive stock options as determined by the Company’s board of directors, benefits (including for immediate family) as were or became available to other employees, and vacation. The Company also provided reasonable life insurance and accidental death coverage with the proceeds payable to Mr. Kunz’s estate or specified family member. The employment agreement could 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 could terminate the agreement upon one month written notice. The agreement included covenants by Mr. Kunz of confidentiality and non-competition, and provided for equitable relief in the event of breach. In the case of termination of employment due to a change of control, Mr. Kunz would have received a lump sum payment equal to 24 monthly installments of his 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 agreement as amended were effective until a subsequent agreement was finalized. Effective January 1, 2013, the annual salary for Mr. Kunz was increased to $252,000. Effective April 19, 2013, Mr. Kunz retired as a director and Chief Executive Officer and the employment agreement was terminated.

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The Company has entered into an engagement agreement for executive management advisory services (the "Engagement Agreement") with Daniel Kunz & Associates LLC ("Kunz & Associates"), a company wholly owned and managed by Mr. Kunz. The Engagement Agreement is effective April 19, 2013, and will remain in effect until April 18, 2014 unless earlier terminated in accordance with its terms or renewed by agreement of both parties. Under the terms of the Engagement Agreement, Kunz & Associates has agreed to devote exclusively for the benefit of the Company 60 hours per month of Mr. Kunz's services. In consideration for the performance by Kunz & Associates of its responsibilities and duties under the Engagement Agreement, the Company has agreed to pay to Kunz & Associates a retainer of $12,400 per month. In addition, Kunz & Associates was paid a bonus of $125,000 upon execution of the Engagement Agreement. In the event that Mr. Kunz elects on a timely basis to continue his participation in the Company's health and dental benefit plans in accordance with the Consolidated Omnibus Budget Reconciliation Act ("COBRA"), the Company has agreed to reimburse 50% of Mr. Kunz's actual cost of the COBRA premium. In addition, Mr. Kunz will be eligible to receive stock option awards under the 2009 Plan at the discretion of the Board. The Company will also reimburse Kunz & Associates for reasonable incidental, or Chief Executive Officer pre-approved, expenses incurred in connection with its engagement.

The Engagement Agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for “cause”. In such event, Kunz & Associates will only be entitled to compensation through the date of termination. The Engagement Agreement may be terminated by the Company without “cause” upon one month’s written notice. In such event, Kunz & Associates will be entitled to receive a lump sum payment equal to the balance of payments due under the term of the contract of Kunz & Associates’ base annual retainer as described above. The Engagement Agreement also includes covenants by Kunz & Associates and Mr. Kunz with respect to the treatment of confidential information, non-competition, non-solicitation and non-change of control activities, and provides for equitable relief in the event of breach.

Gilles Employment Agreement
Effective April 19, 2013, Dennis J. Gilles entered into an employment agreement as the Company’s new Chief Executive Officer. The initial term of employment will be from April 19, 2013 until the earlier of April 18, 2015 or termination of employment in accordance with the terms of the employment agreement. The employment agreement will automatically renew at the end of the initial term, and at the end of each subsequent term, for an additional one year term unless either the Company or Mr. Gilles gives written notice of non-renewal to the other party at least 90 days prior to expiration of the then-current term.

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The Company has agreed to pay to Mr. Gilles an annual base salary of $375,000, which will increase to $410,000 on April 19, 2014 and remain in place as a minimum annual base salary during all successive periods under the employment agreement. In addition, Mr. Gilles received a signing bonus of $100,000 payable in the Company’s common stock and cash to cover the tax impact of the stock bonus within two weeks following completion of a probationary period which ended June 18, 2013 (the “Probationary Period”). Mr. Gilles was also granted 300,000 restricted shares of the Company’s common stock, and a non-qualified stock option to acquire a total of 1,250,000 shares of the Company’s common stock at a price of $0.35 per share with a term of 10 years. Until the earlier of expiration or termination of the employment agreement, the Company has agreed to provide Mr. Gilles, at the Company’s expense, a $1,000,000 life insurance policy that names the Gilles Family Trust as the beneficiary in the event of the death of Mr. Gilles. Mr. Gilles will be eligible to earn annual bonuses with the target amount being 100% of his annual base salary payable in a combination of cash and restricted shares of the Company’s common stock, provided that no more than one-half of the annual bonus will be paid in the form of restricted shares. The actual bonus amount will be subject to the discretion of the Company’s board of directors and its Compensation and Benefits Committee. On April 18, 2014, Mr. Gilles will be granted stock options to acquire shares of the Company’s common stock with a target value equal to 35% of Mr. Gilles’ then-current annual salary, and an exercise price equal to the close of the market for the date they are granted. On subsequent annual anniversaries, Mr. Gilles will be eligible to receive stock option awards at a similar level with the actual amount determined by the Company’s board of directors. Mr. Gilles and his immediate family will be eligible to participate in the Company’s employee health insurance, dental insurance, retirement plan (401K) and any other employee benefit plans in accordance with the terms and conditions of such plans. Mr. Gilles will be entitled to five weeks of vacation within each 12-month period under the employment agreement. Subject to certain limitations and conditions, the Company will also reimburse Mr. Gilles for all reasonable expenses incurred in connection with his employment and the cost of travel between the Company’s office in Boise, Idaho and his home. In addition, Mr. Gilles will receive cost reimbursement for a single relocation for costs not to exceed $35,000.

The Company may terminate Mr. Gilles’ employment without “cause” (which has the meaning commonly ascribed to it at common law and is defined in the employment agreement) during the Probationary Period upon two weeks’ notice. In such event, Mr. Gilles will be paid his salary and reimbursed for expenses incurred through the date of termination. The Company would not be obligated to pay Mr. Gilles any unpaid portion of the $100,000 signing bonus described above, and unvested portions of the 300,000 restricted shares of the Company’s common stock and stock options to acquire 1,250,000 shares of the Company’s common stock described above will be cancelled. The Company may terminate Mr. Gilles’ employment at any time for “cause” upon at least 15 days’ notice. In such event, Mr. Gilles will only be entitled to compensation through the date of termination.

Mr. Gilles may terminate his employment at any time without “good reason” (which is defined in the employment agreement) upon 60 days’ notice. Mr. Gilles will be paid his salary through the date designated in the notice, plus payment for unused vacation days granted or accrued and reimbursement for expenses incurred through the date of termination.

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Following the Probationary Period, in the event Mr. Gilles’ employment is terminated by the Company without “cause” or by Mr. Gilles for “good reason”, Mr. Gilles will be entitled to receive a lump sum payment equal to one and one-half (1.5) times the sum of his second year base salary ($410,000) plus annual target bonus. In addition, any unvested stock options to acquire shares of the Company’s common stock and any unvested restricted shares of the Company’s common stock held by Mr. Gilles as of the termination date that would have vested within18 months following such termination date had Mr. Gilles’ employment continued will become fully vested. Mr. Gilles also will receive a lump sum cash payment equal to 24 times the Company’s contribution to the monthly cost of the medical and dental benefits provided to Mr. Gilles under the employment agreement.

In the event Mr. Gilles’ employment is terminated by the Company without “cause” or by Mr. Gilles for “good reason” within 12 months following a “change of control” (which is defined in the employment agreement) or a “change of control” occurs within 12 months following such termination, Mr. Gilles will receive total severance payments equal to three (3) times the sum of his second year base salary ($410,000) plus annual target bonus. In addition, any unvested stock options to acquire shares of the Company’s common stock and any unvested restricted shares of the Company’s common stock held by Mr. Gilles as of the termination date that would have vested within 18 months following such termination date had Mr. Gilles’ employment continued will become fully vested. Any vested stock options held by Mr. Gilles will remain exercisable until the expiration of the original term of such option. If such termination occurs within 12 months following a “change of control”, Mr. Gilles will receive a lump sum cash payment equal to 36 times the Company’s contribution to the monthly cost of the medical and dental benefits provided to Mr. Gilles under the employment agreement.

The Company has agreed to defend and indemnify Mr. Gilles in connection with legal claims, lawsuits, cause of action or liabilities asserted against him arising out of or related to his employment with the Company and to provide Mr. Gilles with an advance for any expenses in connection with such defense and/or indemnification. The employment agreement also includes covenants by Mr. Gilles with respect to the treatment of confidential information, non-competition and non-solicitation, and provides for equitable relief in the event of breach,

Glaspey Employment Agreement
The Company has entered into an employment agreement with Douglas J. Glaspey as the Company’s President and Chief Operating Officer. The initial term of employment will be from July 1, 2013 until the earlier of June 30, 2015 or termination of employment in accordance with the terms of the employment agreement. The employment agreement will automatically renew at the end of the initial term, and at the end of each subsequent term, for an additional one year term unless either the Company or Mr. Glaspey gives written notice of non-renewal to the other party at least 60 days prior to expiration of the then-current term.

The Company has agreed to pay to Mr. Glaspey compensation of $220,000 per annum, to grant to Mr. Glaspey cash or stock bonus and/or stock options in such amount and under such conditions as may be determined by the Company’s board of directors, to provide to Mr. Glaspey (and his immediate family) such medical, dental and related benefits as are available to other employees of the Company, to provide to Mr. Glaspey reasonable life insurance and accidental death coverage (with the proceeds payable to Mr. Glaspey’s estate or specified family member), and to provide to Mr. Glaspey such 401K retirement benefit as is available to other employees of the Company. In addition, the Company will reimburse Mr. Glaspey for reasonable expenses incurred in connection with the performance of his duties under the employment agreement. Mr. Glaspey is entitled to a paid vacation of five weeks within each 12 month period under the terms of the employment agreement.

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The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for causes which include failure to perform his duties in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a material conflict of interest, a plea of guilty to, or conviction of, an indictable offense which may not be further appealed, fraud, dishonesty, illegality or gross incompetence, failure to disclose material facts concerning business interests or other employment that are relevant to his employment with the Company, refusal to follow reasonable and lawful directions of the Company, breach of fiduciary duty, and material breach under, or gross negligence in connection with his employment under, the employment agreement. Otherwise, the Company may terminate the employment agreement upon one month’s written notice and Mr. Glaspey may terminate the employment agreement upon 60 days’ written notice. In the event that Mr. Glaspey’s employment is terminated without “cause” by the Company or for “good reason” by Mr. Glaspey, and in the event that a “change of control” has occurred within the 12 months prior to the termination, Mr. Glaspey is entitled to receive compensation equal to 24 monthly installments of his normal compensation on the 30^th day after the date of termination (which sum would be currently $439,992). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.

The Company has agreed to defend and indemnify Mr. Glaspey in connection with legal claims, lawsuits, cause of action or liabilities asserted against him arising out of or related to his employment with the Company and to provide Mr. Glaspey with an advance for any expenses in connection with such defense and/or indemnification. The employment agreement also includes covenants by Mr. Glaspey with respect to the treatment of confidential information, non-competition and non-solicitation, and provides for equitable relief in the event of breach.

Hawkley Employment Agreement
The Company has entered into an employment agreement with Kerry D. Hawkley as the Company’s Chief Financial Officer. The initial term of employment will be from July 1, 2013 until the earlier of June 30, 2015 or termination of employment in accordance with the terms of the employment agreement. The employment agreement will automatically renew at the end of the initial term, and at the end of each subsequent term, for an additional one year term unless either the Company or Mr. Hawkley gives written notice of non-renewal to the other party at least 60 days prior to expiration of the then-current term.

The Company has agreed to pay to Mr. Hawkley compensation of $175,000 per annum, to grant to Mr. Hawkley cash or stock bonus and/or stock options in such amount and under such conditions as may be determined by the Company’s board of directors, to provide to Mr. Hawkley (and his immediate family) such medical, dental and related benefits as are available to other employees of the Company, and to provide to Mr. Hawkley such 401K retirement benefit as is available to other employees of the Company. In addition, the Company will reimburse Mr. Hawkley for reasonable expenses incurred in connection with the performance of his duties under the employment agreement. Mr. Hawkley is entitled to a paid vacation of five weeks within each 12 month period under the terms of the employment agreement.

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The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for causes which include failure to perform his duties in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a material conflict of interest, a plea of guilty to, or conviction of, an indictable offense which may not be further appealed, fraud, dishonesty, illegality or gross incompetence, failure to disclose material facts concerning business interests or other employment that are relevant to his employment with the Company, refusal to follow reasonable and lawful directions of the Company, breach of fiduciary duty, and material breach under, or gross negligence in connection with his employment under, the employment agreement. Otherwise, the Company may terminate the employment agreement upon one month’s written notice and Mr. Hawkley may terminate the employment agreement upon 60 days’ written notice. In the event that Mr. Hawkley’s employment is terminated without “cause” by the Company or for “good reason” by Mr. Hawkley, and in the event that a “change of control” has occurred within the 12 months prior to the termination, Mr. Hawkley is entitled to receive compensation equal to 18 monthly installments of his normal compensation on the 30^th day after the date of termination (which sum would be currently $262,440). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.

The Company has agreed to defend and indemnify Mr. Hawkley in connection with legal claims, lawsuits, cause of action or liabilities asserted against him arising out of or related to his employment with the Company and to provide Mr. Hawkley with an advance for any expenses in connection with such defense and/or indemnification. The employment agreement also includes covenants by Mr. Hawkley with respect to the treatment of confidential information, non-competition and non-solicitation, and provides for equitable relief in the event of breach.

Zurkoff Employment Agreement
The Company has entered into an amendment to the employment agreement with Jonathan Zurkoff as the Company’s Executive Vice President, Finance. The employment agreement, as amended, is effective December 31, 2010, and will remain in effect until March 31, 2014 unless earlier terminated in accordance with its terms.

The Company has agreed to pay to Mr. Zurkoff compensation of $160,000 per annum pursuant to the employment agreement. This salary may be adjusted annually on the anniversary date of the employment agreement and is currently $192,000 per annum. The Company has also agreed to provide to Mr. Zurkoff such 401K retirement benefit as is available to other employees of the Company, and to provide to Mr. Zurkoff (and his immediate family) such medical, dental and related benefits as are available to other employees of the Company. In addition, the Company will reimburse Mr. Zurkoff for reasonable expenses incurred in connection with the performance of his duties under the employment agreement. Mr. Zurkoff is entitled to a paid vacation of 20 days within each 12 month period under the terms of the employment agreement.

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The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for causes which include failure to perform his duties in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a material conflict of interest, a plea of guilty to, or conviction of, an indictable offense which may not be further appealed, fraud, dishonesty, illegality or gross incompetence, failure to disclose material facts concerning business interests or other employment that are relevant to his employment with the Company, refusal to follow reasonable and lawful directions of the Company, breach of fiduciary duty, and material breach under, or gross negligence in connection with his employment under, the employment agreement. Otherwise, either party may terminate the employment agreement upon one month’s written notice.

In the event that Mr. Zurkoff’s employment is terminated without “cause” by the Company or for “good reason” by Mr. Zurkoff, and in the event that a “change of control” has occurred within the 12 months prior to the termination, Mr. Zurkoff is entitled to receive compensation equal to 18 monthly installments of his normal compensation on the 30^th day after the date of termination (which sum would be currently $288,000). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.

The employment agreement also includes covenants by Mr. Zurkoff with respect to the treatment of confidential information and non-competition, and provides for equitable relief in the event of breach.

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Summary Compensation Table

The following table shows the compensation for the last two 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)	Year Ended	Salary (1) ($)	Bonus (2) ($)	Option Awards (3) ($)	All other compensation (4) ($)	Total ($)
Dennis J. Gilles, Chief Executive Officer (effective 4/19/13)	12/31/13	261,250	142,811	442,978	34,303	881,342
Daniel J. Kunz, Former Chief Executive Officer (retired effective 4/19/13)	12/31/12	230,000	0	41,348	8,170	279,518
	12/31/13	94,726	0	0	0	94,726
Douglas J. Glaspey, President and Chief Operating Officer	12/31/12	210,000	0	31,806	1,035	242,841
	12/31/13	215,000	10,000	39,245	1,035	262,280
Kerry D. Hawkley, Chief Financial Officer	12/31/12	140,000	0	25,110	0	165,110
	12/31/13	163,000	10,000	32,704	0	205,704
Jonathan Zurkoff, Treasurer and Executive Vice President	12/31/12	192,000	0	22,200	0	214,200
	12/31/13	192,000	27,000	30,364	0	249,364

(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.

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Outstanding Equity Awards at Fiscal Year-End

The following table shows the unexercised stock options, unvested restricted stock, and other equity incentive plan awards held at the year ended December 31, 2013 by our Named Executive Officers.

	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	($)	Date	(#)	($)
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
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
Dennis J. Gilles	100,000	0	0.60	9/12/16	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
Dennis J. Gilles	75,000	25,000	0.31	8/24/17	0	0
Douglas J. Glaspey	142,500	47,500	0.31	8/24/17	0	0
Kerry D. Hawkley	112,500	37,500	0.31	8/24/17	0	0
Jonathan Zurkoff	112,500	37,500	0.31	8/24/17	0	0
Dennis J. Gilles	625,000	625,000	0.35	4/19/23	300,000	105,000
Douglas J. Glaspey	37,500	112,500	0.46	7/22/18	0	0
Kerry D. Hawkley	31,250	93,750	0.46	7/22/18	0	0
Jonathan Zurkoff	31,250	93,750	0.46	7/22/18	0	0

(1) The $0.31 options unexercisable at December 31, 2013 will fully vest on February 24, 2014.
The $0.35 options unexercisable at December 31, 2013 will fully vest on October 19, 2014.
The $0.46 options unexercisable at December 31, 2013 will fully vest on January 22, 2015.

Potential Payments Upon Termination or Change-in-Control

Except as discussed below under “Potential Payments Upon Change-in-Control,” or as noted under the employment agreement for Mr. Gilles, 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.

Potential Payments Upon Change-in-Control. We have entered into employment agreements with Messrs. Kunz, Gilles, Glaspey, Hawkley and Zurkoff which provide for change-in-control payments.

Mr. Kunz’s employment agreement, which terminated upon his retirement effective April 19, 2013, provided that if within twelve months following “change-in-control” Mr. Kunz’s employment was terminated either by the Company without “cause” or by Mr. Kunz for “good reason”, then Mr. Kunz would have been entitled to a lump-sum payment consisting of (a) his prorated base salary through the date of termination, (b) a severance payment equal to twenty four times his monthly base salary at termination, and (c) employee medical and dental coverage for 24 months or until Mr. Kunz commenced alternate employment, whichever came first, subject to certain limitations and conditions. The terms “cause,” “good reason” and “change of control” were defined in the agreement.

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Mr. Gilles employment agreement provided that in the event Mr. Gilles’ employment is terminated by the Company without “cause” or by Mr. Gilles for “good reason” within 12 months following a “change of control” (which is defined in the employment agreement) or a “change of control” occurs within 12 months following such termination, Mr. Gilles will receive total severance payments equal to three (3) times the sum of his second year base salary ($410,000) plus annual target bonus. In addition, any unvested stock options to acquire shares of the Company’s common stock and any unvested restricted shares of the Company’s common stock held by Mr. Gilles as of the termination date that would have vested within 18 months following such termination date had Mr. Gilles’ employment continued will become fully vested. Any vested stock options held by Mr. Gilles will remain exercisable until the expiration of the original term of such option. If such termination occurs within 12 months following a “change of control”, Mr. Gilles will receive a lump sum cash payment equal to 36 times the Company’s contribution to the monthly cost of the medical and dental benefits provided to Mr. Gilles under the employment agreement.

Mr. Glaspey’s employment agreement provides that if within twelve months following a “change of control” Mr. Glaspey’s employment is terminated either by the Company without “cause”, or by Mr. Glaspey for “good reason”, then Mr. Glaspey will be entitled to a lump-sum payment consisting of (a) his prorated base salary through the date of termination, (b) a payment equal to 24 times his monthly base salary at termination, and (c) employee medical and dental coverage for 24 months or until Mr. Glaspey commences alternate employment, whichever comes first, subject to certain limitations and conditions. The terms “cause,” “good reason” and “change-incontrol” are defined in the agreements.

Mr. Hawkley’s employment agreement provides that if within twelve months following a “change of control” Mr. Hawkley’s employment is terminated either by the Company without “cause”, or by Mr. Hawkley for “good reason”, then Mr. Hawkley will be entitled to a lump-sum payment consisting of (a) his prorated base salary through the date of termination, (b) a payment equal to 18 times his monthly base salary at termination, and (c) employee medical and dental coverage for 18 months or until Mr. Hawkley commences alternate employment, whichever comes first, subject to certain limitations and conditions. The terms “cause,” “good reason” and “change-in-control” are defined in the agreements.

Mr. Zurkoff’s employment agreement provides that if within twelve months following a “change of control” Mr. Zurkoff’s employment is terminated either by the Company without “cause”, or by Mr. Zurkoff for “good reason”, then Mr. Zurkoff will be entitled to a lump-sum payment consisting of (a) his prorated base salary through the date of termination, (b) a payment equal to 18 times his monthly base salary at termination, and (c) employee medical and dental coverage for 18 months or until Mr. Zurkoff commences alternate employment, whichever comes first, subject to certain limitations and conditions. The terms “cause,” “good reason” and “change-incontrol” are defined in the agreements.

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Director Compensation

The following table summarizes the compensation paid to our directors during the year ended December 31, 2013.

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	30,000	0	26,163	0	0	0	56,163
Paul A. Larkin	40,000	0	26,163	0	0	0	66,163
Leland L. Mink	30,000	0	26,163	0	0	0	56,163
Dennis J. Gilles	9,000	0	0	0	0	0	9,000

(1) Stock options are valued at the grant date in accordance with FASB ASC Topic 718.

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.

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

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth the number of securities authorized for issuance under the Company’s equity compensation plans as of December 31, 2013.

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	11,888,250	$0.61	3,425,931
Equity compensation plans not approved by security holders	Nil	Nil	Nil
Total	11,888,250	$0.61	3,425,931

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information regarding beneficial ownership of the Company’s common stock, as of March 21, 2014, 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 102,714,178 shares of the Company’s common stock outstanding as of March 21, 2014.

	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)	9.72%
AGF Management Limited PO Box 50, Toronto Dominion Bank Tower, 31st Floor, Toronto, ON, Canada M5K 1E9	5,203,762	(2)	5.07%

(1) As of January 31, 2013, based on information set forth in a Schedule 13G filed with the SEC on February 7, 2013 by Sprott Inc., which has sole voting and dispositive power over 2,602,493 shares of the Company’s common stock and shared voting and dispositive power over 7,378,380 shares of the Company’s voting stock. These shares are held in accounts managed by subsidiaries of Sprott Inc., none of which, with the exception of Exploration Capital Partners 2000 Limited Partnership, beneficially own more than five percent of the class. Exploration Capital Partners 2000 Limited Partnership has shared voting and dispositive power over 7,378,380 shares of the Company’s common stock.

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(2) As of December 30, 2012, based on information set forth in a Schedule 13G/A filed with the SEC on January 30, 2013 by AGF Management Limited, which shares voting and dispositive power over 5,203,762 shares of the Company’s common stock with AGF Investments Inc., its wholly owned subsidiary.

Security Ownership of Management

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, 2013, by each of our directors, Named Executive Officers and directors and executive officers as a group. The percentage of beneficial ownership is based on 102,334,042 shares of the Company’s common stock outstanding as of March 21, 2014.

	Amount and
	Nature
Name of Beneficial Owner	of Beneficial		Percent of
	Ownership		Class
Dennis J. Gilles	1,690,278	(1)	1.65%
Douglas J. Glaspey	1,262,457	(2)	1.23%
Kerry D. Hawkley	582,500	(3)	*
Paul A. Larkin	648,068	(4)	*
Leland L. Mink	425,000	(5)	*
John H. Walker	424,900	(6)	*
Jonathan Zurkoff	748,500	(7)	*
All directors and executive officers as a group (7 persons)	5,781,703	(8)	5.63%

*	Less than 1% of the Company’s outstanding common stock
(1)	Includes 1,137,500 options exercisable within 60 days of March 21, 2014.
(2)	Includes 680,000 options exercisable within 60 days of March 21, 2014.
(3)	Includes 457,500 options exercisable within 60 days of March 21, 2014.
(4)	Includes 350,000 options exercisable within 60 days of March 21, 2014.
(5)	Includes 350,000 options exercisable within 60 days of March 21, 2014.
(6)	Includes 350,000 options exercisable within 60 days of March 21, 2014.
(7)	Includes 653,500 options exercisable within 60 days of March 21, 2014.
(8)	Includes 3,978,500 options exercisable within 60 days of March 21, 2014.

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

Related Person Transactions

Since January 1, 2012, 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.

Director Independence

The Board is currently composed of six directors: Dennis J. Gilles, Douglas J. Glaspey, Daniel J. Kunz (through April 18, 2013), Paul A. Larkin, Leland L. Mink and John H. Walker. The majority of the Board, made up of Mr. Gilles (through April 18, 2013), Mr. Larkin, Dr. Mink and Mr. Walker, satisfy the applicable independence requirements of the NYSE MKT. Mr. Gilles (beginning April 19, 2013), Mr. Kunz (through April 18, 2013) 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.

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Item 14. Principal Accountant Fees and Services

Audit Fees

The aggregate fees billed to the Company by MartinelliMick PLLC for the years ended December 31, 2013, and 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 $138,202 and $52,482; respectively.

Audit-Related Fees

The aggregate fees billed to the Company by MartinelliMick PLLC for the years December 31, 2013 and 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 $97,702 and $77,276; respectively. The fees billed to the Company for the financial statement audits of the Company’s two subsidiaries USG Oregon LLC and USG Nevada LLC for the years ended December 31, 2013 and 2012 were $32,701 and $34,331; respectively. MartinelliMick PLLC billed the Company fees for audit and review services related to the submission of the application for the ITC cash grant for the years ended December 31, 2013 and 2012 that amounted to $20,000 and $4,809; respectively.

The fees billed to the Company by MartinelliMick, PLLC for the year ended March 31, 2013, for assurance and related services related to the submitted an application to Oregon Department of Energy for a Business Energy Tax Credit (“BETC”) for qualified construction purchases and are not reported under “Audit Fees” above, was $18,500.

The aggregate fees billed to the Company by Hein & Associates LLP for the years ended December 31, 2013 and 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 $80,171 and $101,783; 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.

Tax Fees

The aggregate fees billed to the Company by Hein & Associates LLP for the years ended December 31, 2013 and 2012, for professional services rendered for tax compliance, tax advice, and tax planning were $15,425 and $27,000; respectively. 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. MartinelliMick PLLC did not render any professional services relating to tax compliance, tax advice, or tax planning during the years ended December 31, 2013 and 2012.

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All Other Fees

The Company was not billed by MartinelliMick PLLC LLP for any other services during years ended December 31, 2013 and 2012. Hein & Associates provided other consulting services for the year ended December 31, 2013 that amounted to $9,190. Hein & Associates did not provide any additional services for the year ended December 31, 2012.

Administration of Engagement of Independent Auditor

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 years ended December 31, 2013 and 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.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

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

1.	Consolidated Financial Statements.
	See Item 8 of Part II for a list of the Financial Statements filed as part of this report.
2.	Exhibits. See below.

EXHIBIT INDEX

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)

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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 tothe registrant’s Form 10-KSB annual report as filed on June 29, 2006)

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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 10.36 to the registrant’s Form 10- Q as filed on August 10, 2009).

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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 10.33 to the registrant’s Form 10-Q as filed on August 10, 2009).
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. datedMarch 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 August27, 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) *

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10.38	Conditional Guaranty Agreement, entered into as of September 7, 2010, by US Geothermal Inc. to Enbridge (U.S.) Inc. (Incorporated by reference to exhibit 99.5 to the registrant’s Form 8-K as filed on November 8, 2010)
10.39	2009 Stock Incentive Plan of the Registrant (Incorporated by reference to Appendix A to the Company’s definitive proxy statement on Schedule 14A as filed on November 6, 2009)**
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

-119-

*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.

-120-

SIGNATURES

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.

		U.S. Geothermal Inc.
		(Registrant)
March 25, 2014
	By:	/s/ Dennis J. Gilles
Date		Dennis J. Gilles
		Chief Executive Officer
		(Principal Executive Officer)

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:

Name	Title	Date
	Chief Executive Officer and Director (Principal
/s/ Dennis J. Gilles	Executive Officer)	March 25, 2014
Dennis J. Gilles
	Chief Financial Officer (Principal Financial and
/s/ Kerry Hawkley	Accounting Officer)	March 25, 2014
Kerry Hawkley
/s/ Douglas J. Glaspey	President, Chief Operating Officer and Director	March 25, 2014
Douglas J. Glaspey
/s/ John H. Walker	Chairman and Director	March 25, 2014
John H. Walker
/s/ Paul A. Larkin	Director	March 25, 2014
Paul A. Larkin
/s/ Leland L. Mink	Director	March 25, 2014
Leland R. Mink

-121-

EX-21.1

LIST OF SUBSIDIARIES

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

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

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

USG Nevada LLC (organized in the State of Delaware)

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

USG Nevada North LLC (organized in the State of Delaware)

USG Gerlach LLC (organized in the State of Delaware)

Gerlach Geothermal, LLC (organized in the State of Delaware)

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

USG Oregon LLC (organized in the State of Delaware)

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

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

EX-23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-164394), Form S-8 (No. 333-141262), Form S-3 (No. 333-165728), Form S-3 (No. 333-170202) and Form S-3 (333-192611) of our audit report dated March 24, 2014, with respect to the consolidated financial statements of U.S. Geothermal Inc. included in the Annual Report (Form 10-K) for the year ended December 31, 2013.

MartinelliMick PLLC
Spokane, Washington
March 24, 2014

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Dennis J. Gilles certify that:

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

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

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

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

Date: March 25, 2014

/s/ Dennis J. Gilles

Dennis J. Gilles

Chief Executive Officer

-2-

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Kerry D. Hawkley certify that:

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

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

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

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

Date: March 25, 2014

/s/ Kerry D. Hawkley

Kerry D. Hawkley

Chief Financial Officer

-2-

EX-32.1

Exhibit 32.1

CERTIFICATION

In connection with the report of U.S. Geothermal Inc. (the “Company”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission (‘the Report”), I, Dennis J. Gilles, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

Date: March 25, 2014

/s/ Dennis J. Gilles

Dennis J. Gilles

Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

In connection with the report of U.S. Geothermal Inc. (the “Company”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission (‘the Report”), I, Kerry D. Hawkley, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

Date: March 25, 2014

/s/ Kerry D. Hawkley

Kerry D. Hawkley

Chief Financial Officer

XML

CHANGE IN YEAR END FOR FINANCIAL REPORTING PURPOSES (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]

					Nine Months			Three Months
		Year Ended			Ended			Ended			Year Ended
		December 31,			December 31,			March 31,			December 31,
		2013			2012			2012			2012
Plant operating revenues	$	27,370,934		$	8,599,859		$	1,159,087		$	9,758,946
Plant operating expenses		(14,159,022	)		(7,310,808	)		(2,220,862	)		(9,531,670	)
Net income (loss) from plant operations		13,211,912			1,289,051			(1,061,775	)		227,276
Other expenses (income)		9,081,263			3,204,718			1,354,083			4,558,801
Net income (loss)		4,130,649			(1,915,667	)		(2,415,858	)		(4,331,525	)
Net (income) loss attributable to the non-      controlling interests		(2,184,070	)		600,823			772,135			1,372,958
Net income (loss) attributable to U.S. Geothermal Inc.		1,946,579			(1,314,844	)		(1,643,723	)		(2,958,567	)
Other comprehensive income (loss)		(23,377	)		(26,946	)		31,551			4,605
Comprehensive income (loss) attributable to       U.S. Geothermal Inc.	$	1,923,202		$	(1,341,790	)	$	(1,612,172	)	$	(2,953,962	)
Basic and diluted net income (loss) per share      attributable to U.S. Geothermal Inc.	$	0.02		$	(0.01	)	$	(0.02	)	$	(0.03	)
Diluted net income (loss) per share attributable       to U.S. Geothermal Inc.	$	0.02		$	(0.01	)	$	(0.02	)	$	(0.03	)
Weighted average number of shares outstanding       for basic calculations		101,795,364			88,783,972			85,016,732			87,847,308
Weighted average number of shares outstanding       for basic and diluted calculations		123,497,883			104,180,331			99,690,548			102,155,529

XML

JOINT VENTURES/NON-CONTROLLING INTEREST (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Y
Joint Ventures/non-controlling Interest 1	60.00%
Joint Ventures/non-controlling Interest 2	40.00%
Joint Ventures/non-controlling Interest 3	40.00%
Joint Ventures/non-controlling Interest 4	10.00%
Joint Ventures/non-controlling Interest 5	10.00%
Joint Ventures/non-controlling Interest 6	$ 757,190
Joint Ventures/non-controlling Interest 7	300,000
Joint Ventures/non-controlling Interest 8	704,460
Joint Ventures/non-controlling Interest 9	100.00%
Joint Ventures/non-controlling Interest 10	100.00%
Joint Ventures/non-controlling Interest 11	32,801,000
Joint Ventures/non-controlling Interest 12	20.00%
Joint Ventures/non-controlling Interest 13	35.00%
Joint Ventures/non-controlling Interest 14	40.00%
Joint Ventures/non-controlling Interest 15	100.00%
Joint Ventures/non-controlling Interest 16	17,900,000
Joint Ventures/non-controlling Interest 17	34,100,000
Joint Ventures/non-controlling Interest 18	99.00%
Joint Ventures/non-controlling Interest 19	1.00%
Joint Ventures/non-controlling Interest 20	10
Joint Ventures/non-controlling Interest 21	100.00%
Joint Ventures/non-controlling Interest 22	12.00%
Joint Ventures/non-controlling Interest 23	90.00%
Joint Ventures/non-controlling Interest 24	2,136,150
Joint Ventures/non-controlling Interest 25	755,288
Joint Ventures/non-controlling Interest 26	$ 1,380,862

XML

CONVERTIBLE NOTE PAYABLE (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Convertible Note Payable 1	$ 2,125,000
Convertible Note Payable 2	4.75%
Convertible Note Payable 3	1,603
Convertible Note Payable 4	1.50%
Convertible Note Payable 5	1,000,000
Convertible Note Payable 6	2,125,000
Convertible Note Payable 7	$ 208,061

XML

Schedule of Annual Principal Payments Construction in Progress (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Notes Payable Schedule Of Annual Principal Payments Construction In Progress 1	$ 4,121,792
Notes Payable Schedule Of Annual Principal Payments Construction In Progress 2	4,319,468
Notes Payable Schedule Of Annual Principal Payments Construction In Progress 3	4,410,770
Notes Payable Schedule Of Annual Principal Payments Construction In Progress 4	4,332,491
Notes Payable Schedule Of Annual Principal Payments Construction In Progress 5	4,073,645
Notes Payable Schedule Of Annual Principal Payments Construction In Progress 6	82,095,427
Notes Payable Schedule Of Annual Principal Payments Construction In Progress 7	$ 103,353,593

XML

SUBSEQUENT EVENTS (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Subsequent Events 1	60.00%
Subsequent Events 2	40.00%
Subsequent Events 3	$ 6
Subsequent Events 4	60.00%
Subsequent Events 5	40.00%
Subsequent Events 6	5
Subsequent Events 7	$ 8

XML

Schedule of Non-controlling Interests (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 1	$ 404,352
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 2	404,434
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 3	35,926,826
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 4	33,078,744
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 5	21,824,302
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 6	22,598,020
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 7	58,155,480
Joint Ventures/non-controlling Interest Schedule Of Non-controlling Interests 8	$ 56,081,198

XML

PROVISION FOR INCOME TAXES (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Provision For Income Taxes 1	$ 10,742,000
Provision For Income Taxes 2	11,109,000
Provision For Income Taxes 3	101,414,000
Provision For Income Taxes 4	57,963,000
Provision For Income Taxes 5	1,295,000
Provision For Income Taxes 6	35,700,000
Provision For Income Taxes 7	99.00%
Provision For Income Taxes 8	$ 38,100,000

XML

CAPITAL LEASE OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

		Capital Lease
Years ending December 31,		Amounts
2014	$	50,997
2015		21,249
Total future payments		72,246
Less: imputed interest portion		(3,207	)
	$	69,039
Allocation of capital lease obligations:
Current portion	$	48,118
Long-term portion		20,921
	$	69,039

XML

Schedule of New Accounting Pronouncements and Changes in Accounting Principles (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 1	$ 27,370,934
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 2	8,599,859
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 3	1,159,087
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 4	9,758,946
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 5	(14,159,022)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 6	(7,310,808)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 7	(2,220,862)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 8	(9,531,670)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 9	13,211,912
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 10	1,289,051
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 11	(1,061,775)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 12	227,276
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 13	9,081,263
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 14	3,204,718
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 15	1,354,083
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 16	4,558,801
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 17	4,130,649
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 18	(1,915,667)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 19	(2,415,858)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 20	(4,331,525)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 21	(2,184,070)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 22	600,823
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 23	772,135
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 24	1,372,958
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 25	1,946,579
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 26	(1,314,844)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 27	(1,643,723)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 28	(2,958,567)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 29	(23,377)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 30	(26,946)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 31	31,551
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 32	4,605
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 33	1,923,202
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 34	(1,341,790)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 35	(1,612,172)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 36	(2,953,962)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 37	0.02
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 38	(0.01)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 39	(0.02)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 40	(0.03)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 41	0.02
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 42	(0.01)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 43	(0.02)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 44	(0.03)
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 45	101,795,364
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 46	88,783,972
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 47	85,016,732
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 48	87,847,308
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 49	123,497,883
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 50	104,180,331
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 51	99,690,548
Change In Year End For Financial Reporting Purposes Schedule Of New Accounting Pronouncements And Changes In Accounting Principles 52	$ 102,155,529

XML

Schedule of Disclosure of Share-based Compensation Arrangements by Share-based Payment Award (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 1	0.92
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 2	$ 1,698,250
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 3	0.40
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 4	1,698,250
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 5	1,200,208
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 6	1.58
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 7	68,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 8	0.73
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 9	68,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 10	26,435
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 11	0.86
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 12	1,300,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 13	1.70
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 14	1,300,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 15	752,207
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 16	0.83
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 17	2,590,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 18	2.43
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 19	2,590,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 20	1,269,100
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 21	0.60
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 22	100,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 23	2.70
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 24	100,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 25	36,072
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 26	0.31
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 27	2,917,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 28	3.65
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 29	2,187,750
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 30	340,332
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 31	0.46
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 32	1,950,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 33	4.56
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 34	487,500
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 35	118,414
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 36	0.41
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 37	15,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 38	4.67
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 39	3,750
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 40	753
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 41	0.35
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 42	1,250,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 43	9.30
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 44	625,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 45	169,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 46	0.61
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 47	11,888,250
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 48	3.43
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 49	9,060,250
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 50	3,912,521
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 1		2.22
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 2		1,465,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 3		0.63
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 4		1,465,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 5		1,786,417
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 6		1.78
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 7		95,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 8		0.74
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 9		95,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 10		81,172
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 11		0.92
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 12		1,704,625
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 13		1.40
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 14		1,704,625
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 15		1,204,713
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 16		1.58
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 17		68,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 18		1.73
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 19		68,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 20		26,435
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 21		0.86
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 22		1,300,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 23		2.70
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 24		1,300,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 25		752,207
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 26		0.83
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 27		2,590,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 28		3.43
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 29		2,590,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 30		1,269,100
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 31		0.60
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 32		100,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 33		3.70
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 34		75,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 35		27,054
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 36		0.31
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 37		2,917,000
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 38		4.65
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 39		729,250
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 40		113,444
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 41		0.91
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 42		10,239,625
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 43		2.80
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 44		8,026,875
Stock Based Compensation Schedule Of Disclosure Of Share-based Compensation Arrangements By Share-based Payment Award 45		$ 5,260,542

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Schedule of Restricted Cash and Cash Equivalents (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 1	$ 260,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 2	260,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 3	10,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 4	10,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 5	50,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 6	50,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 7	150,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 8	150,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 9	400,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 10	400,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 11	19,848
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 12	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 13	2,191,172
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 14	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 15	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 16	2,125,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 17	3,081,020
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 18	2,995,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 19	1,468,898
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 20	1,426,700
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 21	1,594,437
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 22	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 23	751,183
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 24	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 25	53,072
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 26	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 27	270,000
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 28	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 29	2,668,179
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 30	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 31	4,507,391
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 32	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 33	4,501,191
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 34	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 35	3,000,794
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 36	0
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 37	18,815,145
Restricted Cash And Bond Reserves Schedule Of Restricted Cash And Cash Equivalents 38	$ 1,426,700

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Schedule of Fair Value, by Balance Sheet Grouping (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 1	$ 29,623,935
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 2	29,623,935
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 3	0
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 4	0
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 5	43,632
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 6	0
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 7	42,174
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 8	0
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 9	29,666,109
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 10	29,623,935
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 11	42,174
Fair Value Measurement Schedule Of Fair Value, By Balance Sheet Grouping 12	$ 0

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Schedule of Future Minimum Rental Payments for Operating Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Schedule Of Future Minimum Rental Payments For Operating Leases 1	$ 475,521
Commitments And Contingencies Schedule Of Future Minimum Rental Payments For Operating Leases 2	534,828
Commitments And Contingencies Schedule Of Future Minimum Rental Payments For Operating Leases 3	566,115
Commitments And Contingencies Schedule Of Future Minimum Rental Payments For Operating Leases 4	561,053
Commitments And Contingencies Schedule Of Future Minimum Rental Payments For Operating Leases 5	532,710
Commitments And Contingencies Schedule Of Future Minimum Rental Payments For Operating Leases 6	$ 9,475,229

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Schedule of Share-based Compensation, Stock Options, Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 1	$ 8,132,625
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 2	1.26
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 3	0.71
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 4	5,752,781
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 5	(810,000)
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 6	2.21
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 7	0.74
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 8	(600,246)
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 9	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 10	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 11	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 12	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 13	2,917,000
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 14	0.31
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 15	0.16
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 16	453,774
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 17	10,239,625
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 18	0.91
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 19	0.55
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 20	5,606,309
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 21	(1,566,375)
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 22	2.18
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 23	1.20
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 24	(1,872,094)
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 25	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 26	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 27	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 28	0
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 29	3,215,000
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 30	0.42
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 31	0.25
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 32	808,500
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 33	11,888,250
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 34	0.61
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 35	0.38
Stock Based Compensation Schedule Of Share-based Compensation, Stock Options, Activity 36	$ 4,542,715

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2013

SUBSEQUENT EVENTS [Text Block]

NOTE 19 - SUBSEQUENT EVENTS

The Company has evaluated events and transactions that have occurred after the balance sheet date through March 25, 2014, which is considered to be the issuance date. The following events were identified for disclosure:

USG Oregon LLC Financial Partnership Agreement
On February 20, 2014, the Company finalized a financial partnership agreement with Enbridge Inc. that defined the equity interest in USG Oregon LLC, a subsidiary of the Company. The final ownership interest of USG Oregon LLC was calculated in accordance with the terms of the partnership agreement that specified a 60% interest for U.S. Geothermal Inc. and a 40% interest for Enbridge Inc. The defined ownership interests were effective January 1, 2013. As a result of the final agreement, the Company received a $6.2 million cash distribution from the partnership.

Oregon USG Holdings LLC/USG Oregon LLC Profit Distribution
On March 10, 2014, Oregon USG Holdings LLC, Parent Company of USG Oregon LLC, made its first distribution of cash. Oregon USG Holdings is 60% owned by the Company and 40% owned by Enbridge Inc. Under the terms of the U.S. Department of Energy loan agreement, distributable cash is distributed to the equity partners semi-annually (February and August) following Final Completion, which was achieved on August 1, 2013. The Company’s share of this first distribution is $4.6 million, out of a total distribution to the partners of $7.7 million, which represents distributable cash generated from the project since initial operation began in November 2012.

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CAPITAL STOCK (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Capital Stock 1	250,000,000
Capital Stock 2	50.00%
Capital Stock 3	577,778
Capital Stock 4	$ 0.35
Capital Stock 5	$ 0.36
Capital Stock 6	11,810,816
Capital Stock 7	0.37
Capital Stock 8	4,087,802
Capital Stock 9	282,200
Capital Stock 10	1,250,000
Capital Stock 11	0.312
Capital Stock 12	0.355
Capital Stock 13	3,375,503
Capital Stock 14	0.341
Capital Stock 15	0.536
Capital Stock 16	90,592
Capital Stock 17	$ 0.65

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GRANT PROCEEDS RECEIVABLE (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Grant Proceeds Receivable 1	$ 11,700,000
Grant Proceeds Receivable 2	1,050,000
Grant Proceeds Receivable 3	7,364,200
Grant Proceeds Receivable 4	$ 32,749,541
Grant Proceeds Receivable 5	8.70%

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Schedule of Stockholders' Equity Note, Warrants or Rights (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 1	$ 246,285
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 2	1.25
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 3	4,104,757
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 4	1.25
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 5	255,721
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 6	0.44
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 7	0
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 8	0
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 9	0
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 10	0
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 11	$ 5,905,408
Stock Based Compensation Schedule Of Stockholders' Equity Note, Warrants Or Rights 12	0.50

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

Year Ending
December 31,		Amount
2014	$	475,521
2015		534,828
2016		566,115
2017		561,053
2018		532,710
Thereafter		9,475,229

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RELATED PARTY TRANSACTIONS (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions 1	$ 3,089
Related Party Transactions 2	3,391
Related Party Transactions 3	99,000
Related Party Transactions 4	$ 120,000

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Summary of Valuation Allowance (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Provision For Income Taxes Summary Of Valuation Allowance 1	$ 16,258,000
Provision For Income Taxes Summary Of Valuation Allowance 2	3,976,000
Provision For Income Taxes Summary Of Valuation Allowance 3	614,000
Provision For Income Taxes Summary Of Valuation Allowance 4	0
Provision For Income Taxes Summary Of Valuation Allowance 5	251,000
Provision For Income Taxes Summary Of Valuation Allowance 6	230,000
Provision For Income Taxes Summary Of Valuation Allowance 7	(1,578,000)
Provision For Income Taxes Summary Of Valuation Allowance 8	(17,518,000)
Provision For Income Taxes Summary Of Valuation Allowance 9	(2,499,000)
Provision For Income Taxes Summary Of Valuation Allowance 10	(1,973,000)
Provision For Income Taxes Summary Of Valuation Allowance 11	$ 1,707,000

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Schedule of Changes in Construction in Progress (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 1	$ 2,877,994
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 2	145,987,128
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 3	3,694,978
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 4	64,564,914
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 5	(33,325)
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 6	(55,244,491)
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 7	(185,144)
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 8	(152,429,557)
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 9	6,354,503
Property, Plant And Equipment Schedule Of Changes In Construction In Progress 10	$ 2,877,994

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CAPITAL LEASE OBLIGATIONS (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 M
Capital Lease Obligations 1	36
Capital Lease Obligations 2	$ 1,094
Capital Lease Obligations 3	5.985%
Capital Lease Obligations 4	36
Capital Lease Obligations 5	3,155
Capital Lease Obligations 6	6.14%
Capital Lease Obligations 7	81,301
Capital Lease Obligations 8	155,000
Capital Lease Obligations 9	$ 73,699

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RESTRICTED CASH AND BOND RESERVES

12 Months Ended

Dec. 31, 2013

RESTRICTED CASH AND BOND RESERVES [Text Block]

NOTE 3 – RESTRICTED CASH AND BOND RESERVES

During the quarter ended September 30, 2013, the Company finalized the terms of the loan agreements with the Department of Energy and the Prudential Capital Group. Under the terms of the loan agreements, various bond and cash reserves were required to provide assurances that the power plants will have the necessary funds to maintain expected operations and meet loan payment obligations. Restricted cash balances and bond reserves are summarized as follows:

Current restricted cash and bond reserves :

		December 31,
Restricting Entities/Purpose		2013		2012
Idaho Department of Water Resources, Geothermal Well Bond	$	260,000	$	260,000
Bureau of Land Management, Geothermal Lease Bond- Gerlach		10,000		10,000
State of Nevada Division of Minerals, Statewide Drilling Bond		50,000		50,000
Bureau of Land Management, Geothermal Lease Bonds- USG Nevada		150,000		150,000
Oregon Department of Geology and Mineral Industries, Mineral Land and Reclamation Program		400,000		400,000
Prudential Capital Group, Cash Reserves		19,848		-
U.S. Department of Energy, Debt Service Reserve		2,191,172		-
U.S. Department of Energy, Construction Loan Bond		-		2,125,000
	$	3,081,020	$	2,995,000
Long-term restricted cash and bond reserves
		December 31,
Restricting Entities/Purpose		2013		2012
Nevada Energy, PPA Security Bond	$	1,468,898	$	1,426,700
Prudential Capital Group, Debt Service Reserves		1,594,437		-
Prudential Capital Group, Maintenance Reserves		751,183		-
Prudential Capital Group, Well Reserves		53,072		-
U.S. Department of Energy, Operations Reserves		270,000		-
U.S. Department of Energy, Debt Service Reserves		2,668,179		-
U.S. Department of Energy, Short Term Well Field Reserves		4,507,391		-
U.S. Department of Energy, Long-Term Well Field Reserves		4,501,191		-
U.S. Department of Energy, Capital Expenditure Reserves		3,000,794		-
	$	18,815,145	$	1,426,700

The well bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. Other future costs of environmental remediation cannot be reasonably estimated and have not been recorded. The debt service reserves are required to provide assurance that the Company will have sufficient funds to meet its debt payment obligations for the terms specified by the loan agreements. The maintenance and capital expenditure reserves are required by the lending entities to ensure that funds are available to acquire and maintain critical components of power plants and related supporting structures to enable the plants to operate according to expectations. The construction bond was required by the Loan Guarantee Agreement with the Department of Energy at Neal Hot Springs and was released upon completion of the plant facility. Except for the PPA Security Bond, all of the restricted funds consisted of cash deposits or money market accounts held in commercial banks. Portions of the cash deposits are subject to FDIC insurance. See note 2 for details. The PPA Security Bond is held by the power purchaser. All of the reserve accounts were considered to be fully funded at December 31, 2013.

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Schedule of Changes in Construction in Progress, by Project (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 1	$ 750,493
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 2	750,493
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 3	2,121,502
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 4	2,100,862
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 5	2,871,995
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 6	2,851,355
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 7	3,910
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 8	0
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 9	1,753,299
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 10	26,639
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 11	1,757,209
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 12	26,639
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 13	1,725,299
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 14	0
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 15	1,725,299
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 16	0
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 17	6,354,503
Property, Plant And Equipment Schedule Of Changes In Construction In Progress, By Project 18	$ 2,877,994

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INVESTMENT IN EQUITY SECURITIES (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
Investment In Equity Securities 1	150,000

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INVESTMENT IN EQUITY SECURITIES (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Equity Method Investments [Table Text Block]

		Amount
Available-for-sale equity securities:
Cost basis	$	88,515
Net unrealized losses		(22,355	)
Foreign exchange losses		(609	)
Fair value at December 31, 2012		65,551
Net unrealized losses		(20,551	)
Foreign exchange losses		(2,826	)
Fair value at December 31, 2013	$	42,174

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RESTRICTED CASH AND BOND RESERVES (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Restricted Cash and Cash Equivalents [Table Text Block]

		December 31,
Restricting Entities/Purpose		2013		2012
Idaho Department of Water Resources, Geothermal Well Bond	$	260,000	$	260,000
Bureau of Land Management, Geothermal Lease Bond- Gerlach		10,000		10,000
State of Nevada Division of Minerals, Statewide Drilling Bond		50,000		50,000
Bureau of Land Management, Geothermal Lease Bonds- USG Nevada		150,000		150,000
Oregon Department of Geology and Mineral Industries, Mineral Land and Reclamation Program		400,000		400,000
Prudential Capital Group, Cash Reserves		19,848		-
U.S. Department of Energy, Debt Service Reserve		2,191,172		-
U.S. Department of Energy, Construction Loan Bond		-		2,125,000
	$	3,081,020	$	2,995,000
Long-term restricted cash and bond reserves
		December 31,
Restricting Entities/Purpose		2013		2012
Nevada Energy, PPA Security Bond	$	1,468,898	$	1,426,700
Prudential Capital Group, Debt Service Reserves		1,594,437		-
Prudential Capital Group, Maintenance Reserves		751,183		-
Prudential Capital Group, Well Reserves		53,072		-
U.S. Department of Energy, Operations Reserves		270,000		-
U.S. Department of Energy, Debt Service Reserves		2,668,179		-
U.S. Department of Energy, Short Term Well Field Reserves		4,507,391		-
U.S. Department of Energy, Long-Term Well Field Reserves		4,501,191		-
U.S. Department of Energy, Capital Expenditure Reserves		3,000,794		-
	$	18,815,145	$	1,426,700

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Schedule of Property, Plant and Equipment, Estimated Useful Lives (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 1	$ 3
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 2	5
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 3	3
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 4	30
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 5	30
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 6	5
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 7	15
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 8	30
Summary Of Significant Accounting Policies Schedule Of Property, Plant And Equipment, Estimated Useful Lives 9	$ 30

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PROPERTY, PLANT AND EQUIPMENT (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Property, Plant And Equipment 1	$ 1,700,000
Property, Plant And Equipment 2	2,260,000
Property, Plant And Equipment 3	7,800,000
Property, Plant And Equipment 4	1,050,000
Property, Plant And Equipment 5	2,140,000
Property, Plant And Equipment 6	817,000
Property, Plant And Equipment 7	6,393,581
Property, Plant And Equipment 8	$ 3,508,709

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Property, Plant and Equipment [Table Text Block]

		December 31,
		2013			2012
Land	$	1,603,509		$	1,603,509
Power production plant		161,868,687			159,742,109
Grant proceeds for power plants		(52,965,236	)		(54,630,755	)
Wells		67,620,661			67,365,362
Grant proceeds for wells		(3,464,555	)		(3,233,831	)
Furniture and equipment		1,462,312			1,356,144
		176,125,378			172,202,538
Less: accumulated depreciation		(20,895,943	)		(14,502,362	)
		155,229,435			157,700,176
Construction in progress		6,354,503			2,877,994
	$	161,583,938		$	160,578,170

Schedule of Capitalized Interest Costs [Table Text Block]

		For the Year Ended December 31,
		2013		2012
Total interest expense incurred	$	3,687,742	$	2,909,911
Capitalized interest		-		2,749,081

Schedule of Changes in Construction in Progress [Table Text Block]

		Year Ended December 31,
		2013			2012
Beginning balances	$	2,877,994		$	145,987,128
Development/construction		3,694,978			64,564,914
Grant reimbursements and rebates		(33,325	)		(55,244,491	)
Transfers into production		(185,144	)		(152,429,557	)
Ending balances	$	6,354,503		$	2,877,994

Schedule of Changes in Construction in Progress, by Project [Table Text Block]

		December 31,
		2013		2012
Raft River, Idaho:
Unit II, power plant, substation and transmission lines	$	750,493	$	750,493
Unit II, well construction		2,121,502		2,100,862
		2,871,995		2,851,355
San Emidio, Nevada:
Unit II, power plant, substation and transmission lines		3,910		-
Unit II, well construction		1,753,299		26,639
		1,757,209		26,639
El Ceibillo, Republic of Guatemala:
Well Construction		1,725,299		-
		1,725,299		-
	$	6,354,503	$	2,877,994

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INTANGIBLE ASSETS (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Intangible Assets and Goodwill [Table Text Block]

		December 31,
		2013			2012
In operation:
Neal Hot Springs, Oregon:
Geothermal water and mineral rights	$	625,337		$	-
San Emidio, Nevada:
Geothermal water and mineral rights		4,825,220			4,825,220
Less: accumulated amortization		(935,749	)		(754,064	)
		4,436,006			4,071,156
Inactive:
Raft River, Idaho:
Surface water rights		146,343			146,343
Geothermal water and mineral rights		1,251,540			1,251,540
Granite Creek, Nevada:
Surface water rights		451,299			451,299
Neal Hot Springs, Oregon:
Geothermal water and mineral rights		-			625,336
Guatemala City, Guatemala:
Geothermal water and mineral rights		625,000			625,000
Gerlach, Nevada:
Geothermal water and mineral rights		997,000			997,000
San Emidio, Nevada:
Surface water rights		4,323,520			4,323,520
Geothermal water and mineral rights		3,440,580			3,440,580
Less: prior accumulated amortization		(430,072	)		(430,072	)
		10,805,210			11,430,546
	$	15,241,216		$	15,501,702

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

		Projected
		Amounts
Years ending December 31,
2014	$	181,685
2015		181,685
2016		181,685
2017		181,685
2018		181,685
	$	908,425

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2013

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Text Block]

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Accounting Method

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

Use of Estimates

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

Cash and Cash Equivalents

The Company considers all unrestricted cash, short-term deposits, and other investments with original maturities of no more than ninety days when acquired to be cash and cash equivalents for the purposes of the statement of cash flows. Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At December 31, 2013, $7.9 million in USG Oregon LLC funds were deposited at PNC Bank and $16.4 million in Oregon USG Holdings LLC funds were deposited at Sterling Bank, and were unavailable for immediate corporate needs. The allocation of these funds to the owners of USG Oregon LLC is subject to completion of negotiations regarding the final ownership percentages. Discussion regarding restricted cash is included in Note 3.

Accounts Receivable Allowance for Doubtful Accounts

Trade Accounts Receivable Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of December 31, 2013 and 2012, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

Grant Accounts Receivable
For receivables expected to be received from grants from Federal or State agencies, the Company records the receivable amounts net of the funds expected to be received which may be less than the total amounts requested on the actual grant applications. Therefore, no allowance accounts are considered to be necessary for receivables from grants at December 31, 2013 and 2012.

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity through December 31, 2013. At December 31, 2013, the Company’s total cash balance, excluding money market funds, was $21,005,464, and bank deposits amounted to $21,268,264. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $19,700,267 was not covered by or was in excess of FDIC insurance guaranteed limits. At December 31, 2013, the Company’s money market funds invested in government backed securities totaled $29,623,935 and were not subject to deposit insurance.

Equity Securities

The Company determines the appropriate classification of marketable securities at the time of purchase and reevaluates this designation as of each balance sheet date. The Company classifies these securities as either held-to-maturity, trading, or available-for-sale. All marketable securities and restricted investments were classified as available-for-sale securities. The Company classifies its investments as “available for sale” because it does not intend to actively buy and sell for short-term profits. The Company's investments are subject to market risk, primarily interest rate and credit risk. The fair value of investments is determined using observable or quoted market prices for those securities.

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

Property, Plant and Equipment

Property, plant and equipment, including assets under capital lease, are recorded at historical cost. Costs of acquisition of geothermal properties are capitalized in the period of acquisition. Major improvements that significantly increase the useful lives and/or capabilities of the assets are capitalized. A primary factor in determining whether to capitalize construction type costs is the stage of the potential project’s development. Once a project is determined to be commercially viable, all costs directly associated with the development and construction of the project are capitalized. Until that time, all development costs are expensed. A commercially viable project will have, among other factors, a reservoir discovery well or other significant geothermal surface anomaly, a power transmission path that is identified and available, and an electricity off-taker identified. A valid reservoir discovery is generally defined when a test well has been substantially completed that indicates the presence of a geothermal reservoir that has a high probability of possessing the necessary temperatures, permeability, and flow rates. After a valid discovery has been made, the project enters the development stage. Generally, all costs incurred during the development stage are capitalized and tracked on an individual project basis. If a geothermal project is abandoned, the associated costs that have been capitalized are charged to expense in the year of abandonment. Expenditures for repairs and maintenance are charged to expense as incurred. Interest costs incurred during the construction period of defined major projects from debt that is specifically incurred for those projects are capitalized. Funds received from grants associated with capital projects reduce the cost of the asset directly associated with the individual grants. The offset of the cost of the asset associated with grant proceeds is recorded in the period when the requirements of the grant are substantially complete and the amount can be reasonably estimated.

Direct labor costs, incurred for specific major projects expected to have long-term benefits will be capitalized. Direct labor costs subject to capitalization include employee salaries, as well as, related payroll taxes and benefits. With respect to the allocation of salaries to projects, salaries are allocated based on the percentage of hours that our key managers, engineers and scientists work on each project and are invoiced to the project each month. These individuals track their time worked at each project. Major projects are, generally, defined as projects expected to exceed $500,000. Direct labor includes all of the time incurred by employees directly involved with construction and development activities. General and/or indirect management time and time spent evaluating the feasibility of potential projects are expensed when incurred. Employee training time is expensed when incurred.

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

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

Intangible Assets

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

-       contractual expiration terms of the right,
-       contractual terms of an associated revenue contract (i.e., PPA’s),
-       compliance with utilization and other requirements, and
-       hierarchy of other right holders who share the same resource.

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

Impairment of Long-Lived Assets

The Company evaluates its long-term assets annually for impairment and when circumstances/events occur that may impact the fair value of the assets. An impairment loss would be recognized if the carrying amount of a capitalized asset is not recoverable and exceeds its fair value. The most recent assessment was performed based upon financial conditions and assumptions as of December 31, 2013, and there have not been any significant changes in financial conditions and assumptions subsequent to that assessment date. Management believes that there have not been any circumstances that have warranted the recognition of losses due to the impairment of long-lived assets.

Stock Options Granted to Employees and Non-employees

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

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

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

Stock Based Compensation Granted to Employees

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

Earnings (Losses) Per Share

The Company follows financial accounting standards, which provides for calculation of "basic" and "diluted" earnings (losses) per share. Basic earnings per share includes no dilution and is computed by dividing net income available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of an entity similar to fully diluted earnings per share. Both basic and diluted were presented for the calculation of the income per share for the periods that reported income. Stock equivalents were not included in the calculation for the periods that reported losses since their inclusion would be considered anti-dilutive. Total common stock equivalents on a fully diluted basis at December 31, 2013 and 2012 were 124,494,963 and 122,768,560 ; respectively.

Financial Instruments

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

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

Revenue

Revenue Recognition

Energy Sales
The energy sales revenue is recognized when the electrical power generated by the Company’s power plants is delivered to the customer who is reasonably assured to be able to pay under the terms defined by the Power Purchase Agreements (“PPAs”).

Renewable Energy Credits (“RECs”)
Currently, the Company operates three plants that produce renewable energy that creates a right to a REC. The Company earns one REC for each megawatt hour produced from the geothermal power plant. The Company considers the RECs to be an inventory item held for sale, and outputs that are an economic benefit obtained directly through the operation of the plants. The Company does not currently hold any RECs for our own use. Revenues from RECs sales are recognized when the Company has met the terms and conditions of certain energy sales agreements with a financially capable buyer. At Raft River Energy I LLC, each REC is certified by the Western Electric Coordinating Council and sold under a REC Purchase and Sales Agreement to Holy Cross Energy. At San Emidio and Neal Hot Springs, the RECs are owned by our customer and are bundled with energy sales. At all three plants, title for the RECs pass during the same month as energy sales. As a result, costs associated with the sale of RECs are not segregated on the statement of operations.

Revenue Source
All of the Company’s operating revenues (energy sales and energy credit sales) originate from energy production from its interests in geothermal power plants located in the states of Idaho, Oregon and Nevada.

Reclassification

Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no effect on reported losses, total assets, or stockholders’ equity as previously reported.

Recent Accounting Pronouncements

Management has considered all recent accounting pronouncements. The following pronouncement was deemed applicable to our financial statements.

Presentation of an Unrecognized Tax Benefit In July 2013, FASB issued Accounting Standards Update No. 2013-11 (“Update 2013-11”), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (Topic 740). Update 2013-11 provides guidance on the presentation of unrecognized tax benefits that are associated with a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Update 2011-05 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. Management is still evaluating the impact of this update, and expects that it may impact the presentation of its financial statements.

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PROVISION FOR INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

		December 31,
		2013			2012
Deferred tax assets*:
Net operating loss carry forward	$	38,400,000		$	20,983,000
Stock based compensation		1,868,000			1,532,000
Deferred tax liabilities*:
Depreciation and amortization		(29,554,000	)		(11,406,000	)
Net deferred income tax asset		10,714,000			11,109,000
Estimated deferred tax asset recognized and utilized in current period		(1,578,000	)		-
Deferred tax asset valuation allowance		(9,136,000	)		(11,109,000	)
Net deferred tax asset	$	-		$	-

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	For the Years Ended December 31,
	2013	2012
U.S. Federal statutory rate	34.0%	34.0%
Average State income tax, net of federal tax effect	4.2	4.2
Production tax credits	-	(2.0	)
Net effective tax rate	38.2%	36.2%

Summary of Valuation Allowance [Table Text Block]

		For the Year Ended December 31,
		2013			2012
Change in net operating loss	$	16,258,000		$	3,976,000
Change in estimated effective tax rate		614,000			-
Net change in difference between book and tax stock compensation costs		251,000			230,000
Estimated deferred tax asset recognized and utilized in current period		(1,578,000	)
Change in period book to income tax depreciation		(17,518,000	)		(2,499,000	)
	$	(1,973,000	)	$	1,707,000

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ORGANIZATION AND DESCRIPTION OF BUSINESS (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
Organization And Description Of Business 1	50.00%
Organization And Description Of Business 2	100.00%
Organization And Description Of Business 3	100.00%

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COMMITMENTS AND CONTINGENCIES (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 MW M acre Y
Commitments And Contingencies 1	$ 373,039
Commitments And Contingencies 2	116,227
Commitments And Contingencies 3	3,502
Commitments And Contingencies 4	10
Commitments And Contingencies 5	21,905
Commitments And Contingencies 6	10
Commitments And Contingencies 7	40
Commitments And Contingencies 8	3,615
Commitments And Contingencies 9	10.00%
Commitments And Contingencies 10	4.00%
Commitments And Contingencies 11	5.00%
Commitments And Contingencies 12	7.00
Commitments And Contingencies 13	10
Commitments And Contingencies 14	3.00%
Commitments And Contingencies 15	10
Commitments And Contingencies 16	4.00%
Commitments And Contingencies 17	2,443.7
Commitments And Contingencies 18	10
Commitments And Contingencies 19	40
Commitments And Contingencies 20	2,444
Commitments And Contingencies 21	1,298
Commitments And Contingencies 22	31,287
Commitments And Contingencies 23	5
Commitments And Contingencies 24	3,234
Commitments And Contingencies 25	6,418
Commitments And Contingencies 26	5
Commitments And Contingencies 27	6,535
Commitments And Contingencies 28	78,423
Commitments And Contingencies 29	76,138
Commitments And Contingencies 30	3,250
Commitments And Contingencies 31	25
Commitments And Contingencies 32	89.70
Commitments And Contingencies 33	1.00%
Commitments And Contingencies 34	71,300
Commitments And Contingencies 35	1,468,898
Commitments And Contingencies 36	25
Commitments And Contingencies 37	25
Commitments And Contingencies 38	96
Commitments And Contingencies 39	3.90%
Commitments And Contingencies 40	1.00%
Commitments And Contingencies 41	25
Commitments And Contingencies 42	117.65
Commitments And Contingencies 43	3
Commitments And Contingencies 44	50.00%
Commitments And Contingencies 45	6.00%
Commitments And Contingencies 46	25.00%
Commitments And Contingencies 47	6.00%
Commitments And Contingencies 48	60,425
Commitments And Contingencies 49	$ 36,520

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Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 1	$ 0
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 2	$ 0
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 3	71.00%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 4	81.00%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 5	65.00%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 6	70.00%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 7	0.27%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 8	0.82%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 9	0.19%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 10	0.33%
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 11	4.63
Stock Based Compensation Schedule Of Share-based Payment Award, Stock Options, Valuation Assumptions 12	3.17

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CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current:
Cash and cash equivalents	$ 28,736,934	$ 12,908,779
Restricted cash and bonds	3,081,020	2,995,000
Trade accounts receivable	4,106,806	3,296,890
Grant proceeds receivable	0	42,884,200
Other current assets	1,079,262	839,104
Total current assets	37,004,022	62,923,973
Investment in equity securities	42,174	65,551
Restricted cash and bond reserves	18,815,145	1,426,700
Property, plant and equipment, net of accumulated depreciation	161,583,938	160,578,170
Intangible assets, net of accumulated amortization	15,320,018	15,501,702
Total assets	232,765,297	240,496,096
Current Liabilities:
Accounts payable and accrued liabilities	1,611,130	1,481,959
Construction accounts payable	15,557	1,122,746
Related party accounts payable	3,089	3,391
Notes payable	0	1,000,000
Retention payable	0	8,089,704
Current portion of capital lease obligations	48,118	45,278
Current portion of notes payable	4,127,170	1,576,342
Total current liabilities	5,805,064	13,319,420
Long-term Liabilities:
Convertible loan payable	0	2,125,000
Long-term portion of capital lease obligations	20,921	69,039
Notes payable, less current portion	99,226,423	102,124,167
Total long-term liabilities	99,247,344	104,318,206
Total liabilities	105,052,408	117,637,626
Commitments and Contingencies	0	0
STOCKHOLDERS' EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par value; issued and outstanding shares at December 31, 2013 and 2012 were: 102,094,542 and 101,516,764; respectively)	102,094	101,516
Additional paid-in capital	100,381,207	99,524,850
Accumulated other comprehensive loss	(27,321)	(3,944)
Accumulated deficit	(30,898,571)	(32,845,150)
Total stockholders' equity, before Non-controlling interest	69,557,409	66,777,272
Non-controlling interests	58,155,480	56,081,198
Total stockholders' equity	127,712,889	122,858,470
Total liabilities and stockholders' equity	$ 232,765,297	$ 240,496,096

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INTANGIBLE ASSETS (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Intangible Assets 1	$ 181,685
Intangible Assets 2	$ 173,872

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS EQUITY (USD $)	Common Shares [Member]	Additional Paid-In Capital [Member]	Accumulated Deficit [Member]	Accumulated Comprehensive Income [Member]	Non-controlling Interest [Member]	Total
Beginning Balance at Dec. 31, 2011	$ 84,990	$ 92,921,978	$ (29,886,584)	$ (8,549)	$ 43,812,275	$ 106,924,110
Beginning Balance (Shares) at Dec. 31, 2011	84,989,853
Stock issued under At Market Issuance Sales agreement and a registered direct offering agreement	16,526	5,482,420				5,498,946
Stock issued under At Market Issuance Sales agreement and a registered direct offering agreement (Shares)	16,526,911
Equity contributions and note conversion by non-controlling interest Oregon USG Holdings LLC					13,761,358	13,761,358
Distributions to non-controlling interest entity					(119,476)	(119,476)
Stock compensation		1,130,452				1,130,452
Unrealized loss on investment				4,605		4,605
Broker fees		(10,000)				(10,000)
Net income			(2,958,566)		(1,372,959)	(4,331,525)
Ending Balance at Dec. 31, 2012	101,516	99,524,850	(32,845,150)	(3,944)	56,081,198	122,858,470
Ending Balance (Shares) at Dec. 31, 2012	101,516,764
Non-controlling equity contribution from Gerlach Green Energy, LLC					7,460	7,460
Distributions to non-controlling interest entity					(117,248)	(117,248)
Stock issued under terms of employment agreement	578	99,422				100,000
Stock issued under terms of employment agreement (Shares)	577,778
Stock compensation		756,935				756,935
Unrealized loss on investment				(23,377)		(23,377)
Net income			1,946,579		2,184,070	4,130,649
Ending Balance at Dec. 31, 2013	$ 102,094	$ 100,381,207	$ (30,898,571)	$ (27,321)	$ 58,155,480	$ 127,712,889
Ending Balance (Shares) at Dec. 31, 2013	102,094,542

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Schedule of Property, Plant and Equipment (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 1	$ 1,603,509
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 2	1,603,509
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 3	161,868,687
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 4	159,742,109
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 5	(52,965,236)
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 6	(54,630,755)
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 7	67,620,661
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 8	67,365,362
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 9	(3,464,555)
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 10	(3,233,831)
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 11	1,462,312
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 12	1,356,144
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 13	176,125,378
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 14	172,202,538
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 15	(20,895,943)
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 16	(14,502,362)
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 17	155,229,435
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 18	157,700,176
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 19	6,354,503
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 20	2,877,994
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 21	161,583,938
Property, Plant And Equipment Schedule Of Property, Plant And Equipment 22	$ 160,578,170

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STOCK BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

				Weighted
				Average		Weighted
	Number of			Exercise		Average		Aggregate
	shares under			Price Per		Fair		Intrinsic
	options			Share		Value		Value
Balance outstanding, December 31, 2011	8,132,625		$	1.26	$	0.71	$	5,752,781
Forfeited/Expired	(810,000	)		2.21		0.74		(600,246	)
Exercised	-			-		-		-
Granted	2,917,000			0.31		0.16		453,774
Balance outstanding, December 31, 2012	10,239,625			0.91		0.55		5,606,309
Forfeited/Expired	(1,566,375	)		2.18		1.20		(1,872,094	)
Exercised	-			-		-		-
Granted	3,215,000			0.42		0.25		808,500
Balance outstanding, December 31, 2013	11,888,250		$	0.61	$	0.38	$	4,542,715

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

	For the Years Ended December 31,
	2013	2012
Dividend yield	0	0
Expected volatility	71 - 81%	65 - 70%
Risk free interest rate	0.27 - 0.82%	0.19 - 0.33%
Expected life (years)	4.63	3.17

Schedule of Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

		OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	0.92	1,698,250	0.40	1,698,250	$	1,200,208
	1.58	68,000	0.73	68,000		26,435
	0.86	1,300,000	1.70	1,300,000		752,207
	0.83	2,590,000	2.43	2,590,000		1,269,100
	0.60	100,000	2.70	100,000		36,072
	0.31	2,917,000	3.65	2,187,750		340,332
	0.46	1,950,000	4.56	487,500		118,414
	0.41	15,000	4.67	3,750		753
	0.35	1,250,000	9.30	625,000		169,000
$	0.61	11,888,250	3.43	9,060,250	$	3,912,521

		OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	2.22	1,465,000	0.63	1,465,000	$	1,786,417
	1.78	95,000	0.74	95,000		81,172
	0.92	1,704,625	1.40	1,704,625		1,204,713
	1.58	68,000	1.73	68,000		26,435
	0.86	1,300,000	2.70	1,300,000		752,207
	0.83	2,590,000	3.43	2,590,000		1,269,100
	0.60	100,000	3.70	75,000		27,054
	0.31	2,917,000	4.65	729,250		113,444
$	0.91	10,239,625	2.80	8,026,875	$	5,260,542

Schedule of Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding [Table Text Block]

				Weighted		Weighted
				Average Grant		Average
	Number of			Date Fair Value		Grant Date
	Options			Per Share		Fair Value
Nonvested, December 31, 2011	1,695,000		$	0.83	$	0.50
Granted	2,917,000			0.31		0.16
Vested	(2,399,250	)		0.69		0.40
Forfeited/Expired	-			-		-
Nonvested, December 31, 2012	2,212,750			0.31		0.16
Granted	3,215,000			0.42		0.25
Vested	(2,599,750	)		0.35		0.23
Forfeited/Expired	-			-		-
Nonvested, December 31, 2013	2,828,000		$	0.39	$	0.23

Schedule of Stockholders' Equity Note, Warrants or Rights [Table Text Block]

			Broker
			Warrant	Share		Warrant
	Broker		Exercise	Purchase		Exercise
Expiration Date	Warrants		Price	Warrants		Price
September 16, 2015	246,285	$	1.25	4,104,757	$	1.25
May 23, 2017	255,721		0.44	-		-
December 21, 2017	-		-	5,905,408		0.50

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Schedule of Deferred Tax Assets and Liabilities (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 1	$ 38,400,000
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 2	20,983,000
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 3	1,868,000
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 4	1,532,000
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 5	(29,554,000)
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 6	(11,406,000)
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 7	10,714,000
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 8	11,109,000
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 9	(1,578,000)
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 10	0
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 11	(9,136,000)
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 12	(11,109,000)
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 13	0
Provision For Income Taxes Schedule Of Deferred Tax Assets And Liabilities 14	$ 0

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2013

COMMITMENTS AND CONTINGENCIES [Text Block]

NOTE 16 - COMMITMENTS AND CONTINGENCIES

Operating Lease Agreements
The Company has entered into several lease agreements with terms expiring up to December 1, 2034 for geothermal properties in Washoe County Nevada; Republic of Guatemala; Neal Hot Springs, Oregon and adjoining the Raft River properties in Raft River, Idaho. The Company incurred total lease expenses for the years ended December 31, 2013 and 2012, of $373,039 and $116,227 ; respectively.

BLM Lease Agreements

The Company believes that it is in compliance with all of the following lease terms.

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

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

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

Granite Creek
The Company has three geothermal lease contracts with the BLM for the Granite Creek properties. The lease contracts are for approximately 2,443.7 acres of land and geothermal water rights located in North Western Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases state annual lease payments of $2,444, not including processing fees, and expire October 2017.

Raft River Energy I LLC
The Company has entered into several lease contracts for approximately 1,298 acres of land and geothermal water rights located in the Raft River area located in Southern Idaho. The contracts expire from March 2013 to December 2033. The contracted lease payments are scheduled for $31,287 for the year ended December 31, 2013.

Office Lease

Park Center Boulevard
On August 12, 2013, the Company signed a 5 year lease agreement for office space and janitorial services. The lease payments are due in monthly installments starting February 1, 2014. The monthly payments that begin February 1, 2014 have two components which include a base rate of $3,234 that is not subject to increase and a rate beginning at $6,418 that is adjusted annually according to the cost of living index. The contract includes a 5 year extension option.

Tyrell Lane
Under the current contract, the lease payments were due in monthly installments of $6,535. The current contract effectively ends January 31, 2014 and will not be renewed. The total office lease costs incurred under the current contract and the prior contract for years ended December 31, 2013 and 2012, totaled $78,423 and $76,138 ; respectively.

Contracted Lease Obligation Schedule

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

Year Ending
December 31,		Amount
2014	$	475,521
2015		534,828
2016		566,115
2017		561,053
2018		532,710
Thereafter		9,475,229

Power Purchase Agreements

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

USG Nevada LLC
As a part of the purchase of the assets from Empire Geothermal Power, LLC and Michael B. Stewart acquisition (“Empire Acquisition”), a power purchase agreement with Sierra Pacific Power Company was assigned to the Company. The contract had a stated expected output of 3,250 kilowatts maximum per hour and extended through 2017. During the year ended March 31, 2012, the power purchase agreement was replaced by a new 25 year contract signed in December of 2011 that sets the new set rate at $89.70 per megawatt hour with a 1% annual escalation rate. The new contract allows for a maximum of 71,300 megawatt hours annually. Upon declaration of commercial operation under the PPA, an Operating Security Deposit is required to be maintained at NV Energy for the full term of the PPA. As of December 31, 2013, the Company has fund a security bond of $1,468,898.

USG Oregon LLC
In December of 2009, the Company’s subsidiary (USG Oregon LLC), signed a power purchase agreement with Idaho Power Company for the sale of power generated by the Neal Hot Springs, Oregon project. The agreement has a term of 25 years and provides for the purchase of power up to 25 megawatts (22 megawatt planned annual average output level). Beginning 2012, the flat energy price is $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.

401(k) Plan
The Company offers a defined contribution plan qualified under section 401(k) of the Internal Revenue Code to all its eligible employees. All employees are eligible at the beginning of the quarter after completing 3 months of service. Subsequent to June 30, 2013, the Company began matching 50% of the employee’s contribution up to 6%. Prior to June 30, 2013, the plan required the Company to match 25% of the employee’s contribution up to 6%. Employees may contribute up to the maximum allowed by the Internal Revenue Code. The Company made matching contributions to the plan that totaled $60,425 and $36,520 for the years ended December 31, 2013 and 2012, respectively.

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FAIR VALUE MEASUREMENT (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Fair Value, by Balance Sheet Grouping [Table Text Block]

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts *	$	29,623,935	$	29,623,935	$	-	$	-
Investment in equity securities		43,632		-		42,174		-
	$	29,666,109	$	29,623,935	$	42,174	$	-

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CHANGE IN YEAR END FOR FINANCIAL REPORTING PURPOSES

12 Months Ended

Dec. 31, 2013

CHANGE IN YEAR END FOR FINANCIAL REPORTING PURPOSES [Text Block]

NOTE 18 – CHANGE IN YEAR END FOR FINANCIAL REPORTING PURPOSES

On July 5, 2012, the Company’s Board of Directors approved the change in the Company’s fiscal year end for reporting purposes from March 31 ^st to December 31 ^st . The change was made to increase financial reporting efficiency for the consolidated Company, as well as several of its subsidiaries. The change resulted in a nine month transition period that began on April 1, 2012 and ended on December 31, 2012. The following summarized financial information is presented to compare and illustrate operating results for the periods involved in the transition:

					Nine Months			Three Months
		Year Ended			Ended			Ended			Year Ended
		December 31,			December 31,			March 31,			December 31,
		2013			2012			2012			2012
Plant operating revenues	$	27,370,934		$	8,599,859		$	1,159,087		$	9,758,946
Plant operating expenses		(14,159,022	)		(7,310,808	)		(2,220,862	)		(9,531,670	)
Net income (loss) from plant operations		13,211,912			1,289,051			(1,061,775	)		227,276
Other expenses (income)		9,081,263			3,204,718			1,354,083			4,558,801
Net income (loss)		4,130,649			(1,915,667	)		(2,415,858	)		(4,331,525	)
Net (income) loss attributable to the non-      controlling interests		(2,184,070	)		600,823			772,135			1,372,958
Net income (loss) attributable to U.S. Geothermal Inc.		1,946,579			(1,314,844	)		(1,643,723	)		(2,958,567	)
Other comprehensive income (loss)		(23,377	)		(26,946	)		31,551			4,605
Comprehensive income (loss) attributable to       U.S. Geothermal Inc.	$	1,923,202		$	(1,341,790	)	$	(1,612,172	)	$	(2,953,962	)
Basic and diluted net income (loss) per share      attributable to U.S. Geothermal Inc.	$	0.02		$	(0.01	)	$	(0.02	)	$	(0.03	)
Diluted net income (loss) per share attributable       to U.S. Geothermal Inc.	$	0.02		$	(0.01	)	$	(0.02	)	$	(0.03	)
Weighted average number of shares outstanding       for basic calculations		101,795,364			88,783,972			85,016,732			87,847,308
Weighted average number of shares outstanding       for basic and diluted calculations		123,497,883			104,180,331			99,690,548			102,155,529

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Schedule of Future Minimum Lease Payments for Capital Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 1	$ 50,997
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 2	21,249
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 3	72,246
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 4	(3,207)
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 5	69,039
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 6	48,118
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 7	20,921
Capital Lease Obligations Schedule Of Future Minimum Lease Payments For Capital Leases 8	$ 69,039

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ORGANIZATION AND DESCRIPTION OF BUSINESS

12 Months Ended

Dec. 31, 2013

ORGANIZATION AND DESCRIPTION OF BUSINESS [Text Block]

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

U.S. Geothermal Inc. (formerly U.S. Cobalt Inc.) was incorporated on March 10, 2000 in the State of Delaware. U.S. Geothermal Inc. – Idaho was formed in February 2002, and is the primary subsidiary through which the Company conducts its operations. The Company constructs, manages and operates power plants that utilize geothermal resources to produce energy. The Company’s operations have been, primarily, focused in the Western United States of America.

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

Basis of Presentation

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

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

All intercompany transactions are eliminated upon consolidation.

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

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Common Stock, Shares Authorized	250,000,000	250,000,000
Common Stock, Par Value Per Share	$ 0.001	$ 0.001
Common Stock, Shares, Issued	102,094,542	101,516,764
Common Stock, Shares, Outstanding	102,094,542	101,516,764

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NOTES PAYABLE

12 Months Ended

Dec. 31, 2013

NOTES PAYABLE [Text Block]

NOTE 11 – NOTES PAYABLE

U.S. Department of Energy
On August 31, 2011, USG Oregon LLC (“USG Oregon”), a subsidiary of the Company, completed the first funding drawdown associated with the U.S. Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to construct its planned power plant at Neal Hot Springs in Eastern Oregon (the “Project”). The U.S. Treasury’s Federal Financing Bank, as lender for the Project, issues payments direct to vendors. All loan advances covered by the Loan Guarantee have been made under the Future Advance Promissory Note (the “Note”) dated February 23, 2011. Upon the occurrence and continuation of an event of default under the transaction documents, all amounts payable under the Note may be accelerated. In connection with the Loan Guarantee, the DOE has been granted a security interest in all of the equity interests of USG Oregon, as well as in the assets of USG Oregon, including a mortgage on real property interests relating to the Project site. The loan advances began August 31, 2011 and the last advance was taken on July 31, 2013. No additional advances are allowed under the terms of the grant. A total of 13 draws were taken and each individual draw or tranche is considered to be a separate loan. On August 12, 2013, proceeds of the grant were distributed in accordance with the loan agreement, with $11,870,137 of the proceeds being used to prepay the Project loan, $11,167,473 of proceeds being used to fund a series of Project reserves, and balance of $9,711,930 being distributed as equity to the project owners. After the loan prepayment, the remaining final loan balance was $70,386,576. The loan principal is scheduled to be paid over 21.5 years with semi-annual installments including interest calculated at an aggregate fixed interest rate of 2.598%. The principal payment amounts are calculated on a straight-line basis according to the life of the loans and the original loan principal amounts. The principal portion of the aggregate loan payment is adjusted as individual tranches are extinguished. The principal payments are scheduled to start at $1,709,963 and are expected to be reduced to $1,626,251 on February 10, 2017. The loan balance at December 31, 2013 totaled $70,997,780 (estimated current portion $3,419,927).

Loan advances/tranches and effective annual interest rates are details as follows:

				Annual Interest
Description		Amount		Rate %
Advances by date:
August 31, 2011*	$	2,328,422		2.997
September 28, 2011		10,043,467		2.755
October 27, 2011		3,600,026		2.918
December 2, 2011		4,377,079		2.795
December 21, 2011		2,313,322		2.608
January 25, 2012		8,968,019		2.772
April 26, 2012		13,029,325		2.695
May 30, 2012		19,497,204		2.408
August 27, 2012		7,709,454		2.360
December 28, 2012		2,567,121		2.396
June 10, 2013		2,355,316		2.830
July 3, 2013*		2,242,628		3.073
July 31, 2013*		4,026,582		3.214
		83,057,965
Principal paid through December 31, 2013		(12,060,185	)
Loan balance at December 31, 2013	$	70,997,780

* - Individual tranches have been fully extinguished.

SAIC Constructors LLC
Effective August 27, 2010, the Company’s wholly owned subsidiary (USG Nevada LLC) signed a construction loan agreement with SAIC Constructors LLC (“SAIC”). The new 9.0 net megawatt power plant was considered complete and operational for financial reporting purposes on September 1, 2012. On February 15, 2013, USG Nevada LLC signed a settlement agreement with SAIC that defined the terms of three separate debt components to settle the obligations incurred under the construction loan agreement. As of December 31, 2013, two components of the settlement agreement were paid in full. On April 30, 2013, SAIC signed a loan agreement with Nevada USG Holdings LLC (parent company of USG Nevada LLC and wholly owned subsidiary of the Company), that further defined the terms of the remaining debt component of $2 million. This remaining obligation will be repaid in quarterly installments of $119,382, including interest at 7.0% per annum that began on July 31, 2013. The loan balance at December 31, 2013 totaled $1,850,314 (estimated current portion $378,698).

Prudential Capital Group
On September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group’s related entities (“Prudential”) to finance the Phase I San Emidio geothermal project (the “project”) located in northwest Nevada. The term of the note is approximately 24 years, and bears interest at fixed rate of 6.75% per annum. Interest payments are due quarterly. Principal payments are due quarterly based upon minimum debt service coverage ratios established according to operating results and available cash balances. All amounts owing under the notes and the note purchase agreement or any related financing document are secured by USG Nevada LLC’s right, title and interest in and to its real and personal property, including the project and the equity interests in USG Nevada LLC. At December 31, 2013, the balance of the loan was $30,505,500 (estimated current portion $323,167).

Based upon the terms of the notes payable and expected conditions that may impact some of those terms, the estimated annual principal payments were calculated as follows:

For the Year Ended		Principal
December 31,		Payments
2014	$	4,121,792
2015		4,319,468
2016		4,410,770
2017		4,332,491
2018		4,073,645
Thereafter		82,095,427
	$	103,353,593

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 21, 2014
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Trading Symbol	htm
Entity Registrant Name	US GEOTHERMAL INC
Entity Central Index Key	0001172136
Current Fiscal Year End Date	--03-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		102,714,178
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well Known Seasoned Issuer	No
Entity Public Float		$ 85,252,768
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

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CAPITAL STOCK

12 Months Ended

Dec. 31, 2013

CAPITAL STOCK [Text Block]

NOTE 12 - CAPITAL STOCK

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

During the quarter ended September 30, 2013, the Company issued 577,778 shares of common stock to an employee of the Company at prices between $0.35 and $0.36 per share under the terms of an employment agreement.

On December 21, 2012, the Company issued 11,810,816 common stock shares at $0.37 under a registered direct offering with a limited number of investors and collected $4,087,802, net of broker fees and other costs of $282,200.

During the quarter ended September 30, 2012, the Company issued 1,250,000 common stock shares at prices between $0.312 and $0.355 under an At Market Issuance Sales agreement with Lincoln Park Capital.

During the quarter ended June 30, 2012, the Company issued 3,375,503 shares of common stock at prices between $0.341 and $0.536 under an At Market Issuance Sales agreement with Lincoln Park Capital.

During the quarter ended March 31, 2012, the Company issued 90,592 shares of common stock at a price of $0.65 under an At Market Issuance Sales agreement with Lincoln Park Capital.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Plant Revenues:
Energy sales	$ 26,986,049	$ 9,358,203
Energy credit sales	384,885	400,743
Total plant operating revenues	27,370,934	9,758,946
Plant Expenses:
Plant production expenses	7,704,871	5,910,880
Depreciation and amortization	6,454,151	3,620,790
Total plant operating expenses	14,159,022	9,531,670
Net Income from Plant Operations	13,211,912	227,276
Expenses (Income):
Corporate administration	881,880	827,015
Professional and management fees	1,284,936	766,601
Salaries and wages	2,135,945	1,102,751
Stock based compensation	756,935	940,132
Travel and promotion	202,060	165,107
Exploration costs	39,482	158,764
Interest expense	3,895,890	160,830
Other (income) expenses	(115,865)	437,601
Total expenses (income)	9,081,263	4,558,801
Net Income (Loss) Before Income Tax Expense	4,130,649	(4,331,525)
Net Income Tax Expense :
Income taxes	1,578,000	0
Effect of net deferred tax assets	(1,578,000)	0
Net income tax expense	0	0
Net Income (Loss)	4,130,649	(4,331,525)
Net (income) loss attributable to the non-controlling interests	(2,184,070)	1,372,958
Net Income (Loss) Attributable to U.S. Geothermal Inc.	1,946,579	(2,958,567)
Other Comprehensive Income (Loss):
Unrealized income (loss) on investment in equity securities	(23,377)	4,605
Comprehensive Income (Loss) Attributable to U.S. Geothermal Inc.	$ 1,923,202	$ (2,953,962)
Basic Net Income (Loss) Per Share Attributable to U.S. Geothermal Inc.	$ 0.02	$ (0.03)
Diluted Net Income (Loss) Per Share Attributable to U.S. Geothermal Inc.	$ 0.02	$ (0.03)
Weighted Average Number of Shares Outstanding for Basic Calculations	101,795,364	87,847,308
Weighted Average Number of Shares, Stock Options and Warrants Outstanding for Diluted Calculations	123,497,883	102,155,529

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2013

PROPERTY, PLANT AND EQUIPMENT [Text Block]

NOTE 6 - PROPERTY, PLANT AND EQUIPMENT

During the year ended December, 2013, the Company determined that the project located in the Republic of Guatemala was economically viable and began capitalizing drilling costs that amounted to over $1.7 million. At Neal Hot Springs, an agreement was reached with a major contractor that resulted in the reduction of project costs and related retainage of $2.26 million. Additional costs of approximately $7.8 million were incurred at the Neal Hot Springs power plant to finalize construction costs. The remaining balance of the ITC cash grant for San Emidio relating to previously disputed expenditures of approximately $1.05 million was collected. On February 15, 2013, the Company signed a settlement agreement with SAIC (the general contractor and construction loan holder) that reduced the construction liability including construction cost and accrued interest by approximately $2.14 million for the San Emidio, Nevada project. Costs that totaled approximately $817,000 were capitalized for a phase II monitoring well at San Emidio.

During the year ended December 31, 2012, the Company completed both the San Emidio, Nevada and Neal Hot Springs, Oregon projects. The new San Emidio power plant achieved commercial operation on May 25, 2012. The Neal Hot Springs three power producing units, transmission lines, well field and other supporting structures were completed and the plant achieved commercial operation on November 16, 2012.

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

		December 31,
		2013			2012
Land	$	1,603,509		$	1,603,509
Power production plant		161,868,687			159,742,109
Grant proceeds for power plants		(52,965,236	)		(54,630,755	)
Wells		67,620,661			67,365,362
Grant proceeds for wells		(3,464,555	)		(3,233,831	)
Furniture and equipment		1,462,312			1,356,144
		176,125,378			172,202,538
Less: accumulated depreciation		(20,895,943	)		(14,502,362	)
		155,229,435			157,700,176
Construction in progress		6,354,503			2,877,994
	$	161,583,938		$	160,578,170

The Company capitalized interest costs as a component of the Neal Hot Springs and San Emidio projects as follows:

		For the Year Ended December 31,
		2013		2012
Total interest expense incurred	$	3,687,742	$	2,909,911
Capitalized interest		-		2,749,081

Depreciation expense charged to plant operations and administrative costs for the years ended December 31, 2013 and 2012, was $6,393,581 and $3,508,709 ; respectively.

Changes in Construction in Progress are summarized as follows:

		Year Ended December 31,
		2013			2012
Beginning balances	$	2,877,994		$	145,987,128
Development/construction		3,694,978			64,564,914
Grant reimbursements and rebates		(33,325	)		(55,244,491	)
Transfers into production		(185,144	)		(152,429,557	)
Ending balances	$	6,354,503		$	2,877,994

Construction in Progress, at cost, consisting of the following projects/assets by location are as follows:

		December 31,
		2013		2012
Raft River, Idaho:
Unit II, power plant, substation and transmission lines	$	750,493	$	750,493
Unit II, well construction		2,121,502		2,100,862
		2,871,995		2,851,355
San Emidio, Nevada:
Unit II, power plant, substation and transmission lines		3,910		-
Unit II, well construction		1,753,299		26,639
		1,757,209		26,639
El Ceibillo, Republic of Guatemala:
Well Construction		1,725,299		-
		1,725,299		-
	$	6,354,503	$	2,877,994

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INVESTMENT IN EQUITY SECURITIES

12 Months Ended

Dec. 31, 2013

INVESTMENT IN EQUITY SECURITIES [Text Block]

NOTE 5 – INVESTMENT IN EQUITY SECURITIES

Investments in equity securities ( 150,000 shares of Alterra Power Corp, a publicly traded renewable energy company) activities consisted of the following:

		Amount
Available-for-sale equity securities:
Cost basis	$	88,515
Net unrealized losses		(22,355	)
Foreign exchange losses		(609	)
Fair value at December 31, 2012		65,551
Net unrealized losses		(20,551	)
Foreign exchange losses		(2,826	)
Fair value at December 31, 2013	$	42,174

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JOINT VENTURES/NON-CONTROLLING INTEREST

12 Months Ended

Dec. 31, 2013

JOINT VENTURES/NON-CONTROLLING INTEREST [Text Block]

NOTE 17 – JOINT VENTURES/NON-CONTROLLING INTERESTS

Non-controlling interests included on the consolidated balance sheets of the Company are detailed as follows:

		December 31,
		2013		2012
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	404,352	$	404,434
Oregon USG Holdings LLC interest held by Enbridge Inc.		35,926,826		33,078,744
Raft River Energy I LLC interest held by Raft River I Holdings, LLC		21,824,302		22,598,020
	$	58,155,480	$	56,081,198

Gerlach Geothermal LLC
On April 28, 2008, the Company formed Gerlach Geothermal, LLC (“Gerlach”) with our partner, Gerlach Green Energy, LLC (“GGE”). The purpose of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. Based upon the terms of the members’ agreement, the Company owns a 60% interest and GGE owns a 40% interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to maintain its 40% ownership interest as additional capital contributions are required. If GGE dilutes to below a 10% interest, their ownership position in the joint venture would be converted to a 10% net profits interest. The Company has contributed $757,190 in cash and $300,000 for a geothermal lease and mineral rights; and the GGE has contributed $704,460 of geothermal lease, mineral rights and exploration data.

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

Oregon USG Holdings LLC
In September 2010, the Company’s subsidiary, Oregon USG Holdings LLC (“Oregon Holdings”), signed an Operating Agreement with Enbridge Inc. (“Enbridge”) for the right to participate in the Company’s project in the Neal Hot Springs project located in Malheur County, Oregon. Oregon Holdings has a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of $32,801,000, including the debt conversion, to Oregon Holdings in exchange for a direct ownership interest. Under the initial agreement, the ownership interest began at 20%, and increased to 35% according to capital contribution levels. On February 20, 2014, a new agreement was reached with Enbridge that established the ownership interest percentage at 40%, effective January 1, 2013.

The consolidated financial statements reflect 100% of the assets and liabilities of Oregon Holdings and USG Oregon LLC, and report the current non-controlling interest of Enbridge. The full results of Oregon Holdings and USG Oregon LLC’s operations are reflected in the statement of operations with the elimination of the non-controlling interest identified.

Raft River Energy I LLC (“RREI”)
Raft River Energy I is a joint venture between the Company and Raft River I Holdings, LLC a subsidiary of the Goldman Sachs Group, Inc. An Operating Agreement governs the rights and responsibilities of both parties. At fiscal year end, the Company had contributed approximately $17.9 million in cash and property, and RREI has contributed approximately $34.1 million in cash. Profits and losses are allocated to the members based upon contractual terms. For income tax purposes, Raft River I Holdings, LLC receives a greater proportion of the share of losses and other income tax benefits. This includes the allocation of production tax credits, which will be distributed 99% to Raft River I Holdings, LLC and 1% to the Company during the first 10 years of production. During the initial years of operations, Raft River I Holdings, LLC will receive a larger allocation of cash distributions.

The consolidated financial statements reflect 100% of the assets and liabilities of RREI, and report the current non-controlling interest of Raft River I Holdings LLC. The full results of Raft River Energy I LLC’s operations are reflected in the statement of operations with the elimination of the non-controlling interest identified.

Effective May 17, 2011, a repair services agreement (“RSA”) was executed between the RREI and U.S. Geothermal Services, LLC for the purpose of funding repairs of two underperforming wells. The agreement defined terms of the RSA repair costs and RSA repair management fees that would be funded by the loan. The outstanding loan balance will accrue interest at 12.0% per annum. The RSA payments will be made preferentially from project cash flow at a rate of 90% of increased cash created by the repairs and cash availability on a quarterly basis. The repairs were completed in January 2012. Based upon the financial conditions applicable to the loan, RREI did not make any payments during the year ended December 31, 2012. As of December 31, 2012, the loan balance amounted to $2,136,150. During the year ended December 31, 2013, RREI made principal payments on the loan of $755,288. The balance of the loan at December 31, 2013 was $1,380,862. The loan balance and related interest effects are fully eliminated during the consolidation process.

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STOCK BASED COMPENSATION

12 Months Ended

Dec. 31, 2013

STOCK BASED COMPENSATION [Text Block]

NOTE 13 - STOCK BASED COMPENSATION

The Company has a stock incentive plan (the “Stock Incentive Plan”) for the purpose of attracting and motivating directors, officers, employees and consultants of the Company and advancing the interests of the Company. The Stock Incentive Plan is a 15% rolling plan approved by shareholders in December 2009 and September 2013, whereby the Company can grant options to the extent of 15% of the current outstanding common shares. Under the plan, all forfeited and exercised options can be replaced with new offerings. As of December 31, 2013, the Company can issue stock option grants totaling up to 15,314,181 shares. Options are typically granted for a term of up to five years from the date of grant. Stock options granted generally vest over a period of eighteen months, with 25% vesting on the date of grant and 25% vesting every six months thereafter. The Company recognizes compensation expense using the straight-line method of amortization. Historically, the Company has issued new shares to satisfy exercises of stock options and the Company expects to issue new shares to satisfy any future exercises of stock options. At December 31, 2013, the Company had 11,888,250 options granted and outstanding.

On September 25, 2013, 95,000 stock options exercisable at a price of $1.78 expired without exercise.

On September 1, 2013, the Company granted 15,000 stock options to an employee exercisable at a price of $0.41 until September 1, 2018.

On July 22, 2013, the Company granted 1,950,000 stock options to employees exercisable at a price of $0.46 until July 22, 2018.

On May 26, 2013, 6,375 stock options exercisable at a price of $0.92 were forfeited due to employee termination.

On May 19, 2013, 1,465,000 stock options exercisable at a price of $2.22 expired without exercise.

On April 19, 2013, the Company granted 1,250,000 stock options to employees exercisable at a price of $0.35 until April 19, 2023.

On August 24, 2012, the Company granted 2,917,000 stock options to employees exercisable at a price of $0.31 until August 24, 2017.

On July 23, 2012, 652,500 stock options exercisable at a price of $2.41 expired without exercise.

On January 22, 2012, 157,500 stock options exercisable at a price of $1.40 CDN expired without exercise.

The following table reflects the summary of stock options outstanding at December 31, 2011 and changes for the years ended December 31, 2013 and 2012:

				Weighted
				Average		Weighted
	Number of			Exercise		Average		Aggregate
	shares under			Price Per		Fair		Intrinsic
	options			Share		Value		Value
Balance outstanding, December 31, 2011	8,132,625		$	1.26	$	0.71	$	5,752,781
Forfeited/Expired	(810,000	)		2.21		0.74		(600,246	)
Exercised	-			-		-		-
Granted	2,917,000			0.31		0.16		453,774
Balance outstanding, December 31, 2012	10,239,625			0.91		0.55		5,606,309
Forfeited/Expired	(1,566,375	)		2.18		1.20		(1,872,094	)
Exercised	-			-		-		-
Granted	3,215,000			0.42		0.25		808,500
Balance outstanding, December 31, 2013	11,888,250		$	0.61	$	0.38	$	4,542,715

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

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

	For the Years Ended December 31,
	2013	2012
Dividend yield	0	0
Expected volatility	71 - 81%	65 - 70%
Risk free interest rate	0.27 - 0.82%	0.19 - 0.33%
Expected life (years)	4.63	3.17

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

The following table summarizes information about the stock options outstanding at December 31, 2013:

		OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	0.92	1,698,250	0.40	1,698,250	$	1,200,208
	1.58	68,000	0.73	68,000		26,435
	0.86	1,300,000	1.70	1,300,000		752,207
	0.83	2,590,000	2.43	2,590,000		1,269,100
	0.60	100,000	2.70	100,000		36,072
	0.31	2,917,000	3.65	2,187,750		340,332
	0.46	1,950,000	4.56	487,500		118,414
	0.41	15,000	4.67	3,750		753
	0.35	1,250,000	9.30	625,000		169,000
$	0.61	11,888,250	3.43	9,060,250	$	3,912,521

The following table summarizes information about the stock options outstanding at December 31, 2012:

		OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$	2.22	1,465,000	0.63	1,465,000	$	1,786,417
	1.78	95,000	0.74	95,000		81,172
	0.92	1,704,625	1.40	1,704,625		1,204,713
	1.58	68,000	1.73	68,000		26,435
	0.86	1,300,000	2.70	1,300,000		752,207
	0.83	2,590,000	3.43	2,590,000		1,269,100
	0.60	100,000	3.70	75,000		27,054
	0.31	2,917,000	4.65	729,250		113,444
$	0.91	10,239,625	2.80	8,026,875	$	5,260,542

A summary of the status of the Company’s nonvested stock options outstanding at December 31, 2011 and changes during the years ended December 31, 2013 and 2012 are presented as follows:

				Weighted		Weighted
				Average Grant		Average
	Number of			Date Fair Value		Grant Date
	Options			Per Share		Fair Value
Nonvested, December 31, 2011	1,695,000		$	0.83	$	0.50
Granted	2,917,000			0.31		0.16
Vested	(2,399,250	)		0.69		0.40
Forfeited/Expired	-			-		-
Nonvested, December 31, 2012	2,212,750			0.31		0.16
Granted	3,215,000			0.42		0.25
Vested	(2,599,750	)		0.35		0.23
Forfeited/Expired	-			-		-
Nonvested, December 31, 2013	2,828,000		$	0.39	$	0.23

As of December 31, 2013, there was $389,503 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years. The total fair value of options vested at December 31, 2013 and 2012 was $683,143 and $861,277 ; respectively.

Stock Compensation Plan (Restricted Shares )

On September 10, 2010, the Company granted officers, directors and select employees 705,000 common shares that will be distributed in three six-month vesting periods. The recipients meet the vesting requirements by maintaining employment and good standing with the Company through the vesting periods. After vesting, there are no restrictions on the shares. On March 10, 2011, the 705,000 common shares were issued to the recipients and held by the Company. All of these shares were considered to be issued and outstanding. On March 11, 2011, 235,000 common shares vested valued at $0.99 per share, and the shares were released to the qualified recipients. On September 11, 2011, 235,000 common shares vested valued at $0.60 per share and the shares were released to the qualified recipients. The final 235,000 shares valued at $0.58 vested and were released on March 11, 2012.

On April 19, 2013, the Company granted an officer and director 300,000 common shares valued at $0.35 per share, which will be distributed at the end of a one-year vesting period. The recipient meets the vesting requirements by maintaining employment and good standing with the Company through the vesting period. After vesting, there are no restrictions on the shares. These shares were issued in July 2013 to the recipient and held by the Company until vested. The total fair value of options at the grant date was $105,000 and the recognized cost through December 31, 2013 was $73,792.

Stock Purchase Warrants

At December 31, 2013, the outstanding broker warrants and share purchase warrants consisted of the following:

			Broker
			Warrant	Share		Warrant
	Broker		Exercise	Purchase		Exercise
Expiration Date	Warrants		Price	Warrants		Price
September 16, 2015	246,285	$	1.25	4,104,757	$	1.25
May 23, 2017	255,721		0.44	-		-
December 21, 2017	-		-	5,905,408		0.50

On February 2013, 500,000 stock purchase warrants at an exercise price of $5.00 expired without exercise.

On December 21, 2012, the Company issued 5,905,408 stock purchase warrants exercisable at a price of $0.50 until December 21, 2017.

On May 23, 2012, the Company issued 118,421 broker warrants at an exercise price of $0.437.

On March 4, 2012, 2,500,000 stock purchase warrants and 56,000 broker warrants at an exercise price of $1.075 expired without exercise.

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CAPITAL LEASE OBLIGATIONS

12 Months Ended

Dec. 31, 2013

CAPITAL LEASE OBLIGATIONS [Text Block]

NOTE 9 - CAPITAL LEASE OBLIGATIONS

Effective May 10, 2012, the Company entered into two capital lease obligations for the purchase of a boom lift and a telehandler from Caterpillar Financial Services Corporation. The boom lift contract is payable in 36 monthly payments of $1,094 that began on June 11, 2012 and has an effective annual interest rate of 5.985%. The telehandler contract is payable in 36 monthly payments of $3,155 that began on June 11, 2012 and has an effective annual interest rate of 6.14%. Both contracts with Caterpillar Financial Services Corporation have bargain purchase options at the end of the contracts scheduled for May 2015.

The scheduled future lease payments for the three contracts are presented as follows:

		Capital Lease
Years ending December 31,		Amounts
2014	$	50,997
2015		21,249
Total future payments		72,246
Less: imputed interest portion		(3,207	)
	$	69,039
Allocation of capital lease obligations:
Current portion	$	48,118
Long-term portion		20,921
	$	69,039

At December 31, 2013, the net book value of the equipment under capital lease amounted to $81,301 ($155,000, less $73,699 accumulated amortization).

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Schedule of Capitalized Interest Costs (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Property, Plant And Equipment Schedule Of Capitalized Interest Costs 1	$ 3,687,742
Property, Plant And Equipment Schedule Of Capitalized Interest Costs 2	2,909,911
Property, Plant And Equipment Schedule Of Capitalized Interest Costs 3	0
Property, Plant And Equipment Schedule Of Capitalized Interest Costs 4	$ 2,749,081

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INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2013

INTANGIBLE ASSETS [Text Block]

NOTE 7 – INTANGIBLE ASSETS

Intangible assets, at cost, are summarized by project location as follows:

		December 31,
		2013			2012
In operation:
Neal Hot Springs, Oregon:
Geothermal water and mineral rights	$	625,337		$	-
San Emidio, Nevada:
Geothermal water and mineral rights		4,825,220			4,825,220
Less: accumulated amortization		(935,749	)		(754,064	)
		4,436,006			4,071,156
Inactive:
Raft River, Idaho:
Surface water rights		146,343			146,343
Geothermal water and mineral rights		1,251,540			1,251,540
Granite Creek, Nevada:
Surface water rights		451,299			451,299
Neal Hot Springs, Oregon:
Geothermal water and mineral rights		-			625,336
Guatemala City, Guatemala:
Geothermal water and mineral rights		625,000			625,000
Gerlach, Nevada:
Geothermal water and mineral rights		997,000			997,000
San Emidio, Nevada:
Surface water rights		4,323,520			4,323,520
Geothermal water and mineral rights		3,440,580			3,440,580
Less: prior accumulated amortization		(430,072	)		(430,072	)
		10,805,210			11,430,546
	$	15,241,216		$	15,501,702

Amortization expense was charged to plant operations for the years ended December 31, 2013 and 2012 that amounted to $181,685 and $173,872 ; respectively.

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

		Projected
		Amounts
Years ending December 31,
2014	$	181,685
2015		181,685
2016		181,685
2017		181,685
2018		181,685
	$	908,425

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PROVISION FOR INCOME TAXES

12 Months Ended

Dec. 31, 2013

PROVISION FOR INCOME TAXES [Text Block]

NOTE 8 – PROVISION FOR INCOME TAXES

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

At December 31, 2013, the Company had net deferred tax assets calculated at an expected rate, noted in the table below, of approximately $10,742,000 (December 31, 2012 - $11,109,000). As management of the Company cannot determine that it is more likely than not that the Company will realize the benefit of the net deferred tax asset, a valuation allowance equal to the net deferred tax asset was recorded at December 31, 2013 and 2012. For the current year ended December 31, 2013, the Company has recognized the net deferred income tax asset to the extent of the impact created from current book earnings. During the year ended December 31, 2013, the Company engaged a tax matters consultant to evaluate the value and timing of adjusting the deferred tax valuation allowance. The Company anticipates that any tax obligations will be fully offset by the utilization of prior reserved deferred tax benefits for the year ended December 31, 2013.

The significant components of the net deferred tax asset calculated with the estimated effective income tax rate at December 31, 2013 and 2012 were as follows:

		December 31,
		2013			2012
Deferred tax assets*:
Net operating loss carry forward	$	38,400,000		$	20,983,000
Stock based compensation		1,868,000			1,532,000
Deferred tax liabilities*:
Depreciation and amortization		(29,554,000	)		(11,406,000	)
Net deferred income tax asset		10,714,000			11,109,000
Estimated deferred tax asset recognized and utilized in current period		(1,578,000	)		-
Deferred tax asset valuation allowance		(9,136,000	)		(11,109,000	)
Net deferred tax asset	$	-		$	-

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

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

	For the Years Ended December 31,
	2013	2012
U.S. Federal statutory rate	34.0%	34.0%
Average State income tax, net of federal tax effect	4.2	4.2
Production tax credits	-	(2.0	)
Net effective tax rate	38.2%	36.2%

At December 31, 2013, the Company had net income tax operating loss carry forwards of approximately $101,414,000 ($57,963,000 in December 31, 2012), which expire in the years 2023 through 2033. The change in the allowance account from December 31, 2012 to December 31, 2013 was a decrease of $1,295,000 for the anticipated deferred tax allocations based on 2013 income.

The change in the allowance account is summarized as follows:

		For the Year Ended December 31,
		2013			2012
Change in net operating loss	$	16,258,000		$	3,976,000
Change in estimated effective tax rate		614,000			-
Net change in difference between book and tax stock compensation costs		251,000			230,000
Estimated deferred tax asset recognized and utilized in current period		(1,578,000	)
Change in period book to income tax depreciation		(17,518,000	)		(2,499,000	)
	$	(1,973,000	)	$	1,707,000

At December 31, 2013, Raft River Energy I LLC has a book-to-tax difference of $35.7 million due to the acceleration of intangible drilling costs and depreciation. By contract, 99% percent of this book-to-tax difference has been allocated to the non-controlling interest and would not be available to the consolidated group to offset future tax liabilities. At December 31, 2013, USG Oregon LLC has a book-to-tax difference of $38.1 million due to the acceleration of depreciation.

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

Accounting for Income Tax Uncertainties and Related Matters

The Company may be assessed penalties and interest related to the underpayment of income taxes. Such assessments would be treated as a provision of income tax expense on the financial statements. For the year ended December 31, 2013, nine months ended December 31, 2012 and the fiscal year ended March 31, 2012, no income tax expense has been realized as a result of operations and no income tax penalties and interest have been accrued related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and in the States of Idaho and Oregon. These filings are subject to a three year statute of limitations. The Company’s evaluation of income tax positions included the year ended December 31, 2013, the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012 could be subject to agency examinations as of December 31, 2012. No filings are currently under examination. No adjustments have been made to reduce the estimated income tax benefit at fiscal year end. Any valuations relating to these income tax provisions will comply with U.S. generally accepted accounting principles .

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CONVERTIBLE NOTE PAYABLE

12 Months Ended

Dec. 31, 2013

CONVERTIBLE NOTE PAYABLE [Text Block]

NOTE 10 – CONVERTIBLE NOTE PAYABLE

On August 5, 2011, the Oregon USG Holdings, LLC (“Oregon Holdings”), a subsidiary of the Company, signed a convertible note agreement with our equity partner (Enbridge Inc.). The principal of the loan totaled $2,125,000, and accrued interest at a rate of 4.75% per annum. The loan balance plus accrued interest would have converted to an equity interest in Oregon Holdings upon the earliest of a conversion event or April 1, 2014, if unpaid. Conversion events include the failure to obtain the Section 1603 ITC cash grant funds by the Project. The converted balance would have increased Enbridge Inc.’s ownership at a ratio of 1.5% for each $1 million contributed. During the year ended December 31, 2013, the principal of $2,125,000 was paid in full without conversion to an equity interest. At December 31, 2013, accrued and unpaid interest on the loan totaled $208,061.

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Schedule of Finite-Lived Intangible Assets, Future Amortization Expense (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Intangible Assets Schedule Of Finite-lived Intangible Assets, Future Amortization Expense 1	$ 181,685
Intangible Assets Schedule Of Finite-lived Intangible Assets, Future Amortization Expense 2	181,685
Intangible Assets Schedule Of Finite-lived Intangible Assets, Future Amortization Expense 3	181,685
Intangible Assets Schedule Of Finite-lived Intangible Assets, Future Amortization Expense 4	181,685
Intangible Assets Schedule Of Finite-lived Intangible Assets, Future Amortization Expense 5	181,685
Intangible Assets Schedule Of Finite-lived Intangible Assets, Future Amortization Expense 6	$ 908,425

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Schedule of Effective Income Tax Rate Reconciliation (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 1	34.00%
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 2	34.00%
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 3	4.2
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 4	4.2
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 5	$ 0
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 6	(2)
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 7	38.20%
Provision For Income Taxes Schedule Of Effective Income Tax Rate Reconciliation 8	36.20%

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Schedule of Intangible Assets and Goodwill (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Intangible Assets Schedule Of Intangible Assets And Goodwill 1	$ 625,337
Intangible Assets Schedule Of Intangible Assets And Goodwill 2	0
Intangible Assets Schedule Of Intangible Assets And Goodwill 3	4,825,220
Intangible Assets Schedule Of Intangible Assets And Goodwill 4	4,825,220
Intangible Assets Schedule Of Intangible Assets And Goodwill 5	(935,749)
Intangible Assets Schedule Of Intangible Assets And Goodwill 6	(754,064)
Intangible Assets Schedule Of Intangible Assets And Goodwill 7	4,436,006
Intangible Assets Schedule Of Intangible Assets And Goodwill 8	4,071,156
Intangible Assets Schedule Of Intangible Assets And Goodwill 9	146,343
Intangible Assets Schedule Of Intangible Assets And Goodwill 10	146,343
Intangible Assets Schedule Of Intangible Assets And Goodwill 11	1,251,540
Intangible Assets Schedule Of Intangible Assets And Goodwill 12	1,251,540
Intangible Assets Schedule Of Intangible Assets And Goodwill 13	451,299
Intangible Assets Schedule Of Intangible Assets And Goodwill 14	451,299
Intangible Assets Schedule Of Intangible Assets And Goodwill 15	0
Intangible Assets Schedule Of Intangible Assets And Goodwill 16	625,336
Intangible Assets Schedule Of Intangible Assets And Goodwill 17	625,000
Intangible Assets Schedule Of Intangible Assets And Goodwill 18	625,000
Intangible Assets Schedule Of Intangible Assets And Goodwill 19	997,000
Intangible Assets Schedule Of Intangible Assets And Goodwill 20	997,000
Intangible Assets Schedule Of Intangible Assets And Goodwill 21	4,323,520
Intangible Assets Schedule Of Intangible Assets And Goodwill 22	4,323,520
Intangible Assets Schedule Of Intangible Assets And Goodwill 23	3,440,580
Intangible Assets Schedule Of Intangible Assets And Goodwill 24	3,440,580
Intangible Assets Schedule Of Intangible Assets And Goodwill 25	(430,072)
Intangible Assets Schedule Of Intangible Assets And Goodwill 26	(430,072)
Intangible Assets Schedule Of Intangible Assets And Goodwill 27	10,805,210
Intangible Assets Schedule Of Intangible Assets And Goodwill 28	11,430,546
Intangible Assets Schedule Of Intangible Assets And Goodwill 29	15,241,216
Intangible Assets Schedule Of Intangible Assets And Goodwill 30	$ 15,501,702

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NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2013

Investments and Advances to Affiliates [Table Text Block]

				Annual Interest
Description		Amount		Rate %
Advances by date:
August 31, 2011*	$	2,328,422		2.997
September 28, 2011		10,043,467		2.755
October 27, 2011		3,600,026		2.918
December 2, 2011		4,377,079		2.795
December 21, 2011		2,313,322		2.608
January 25, 2012		8,968,019		2.772
April 26, 2012		13,029,325		2.695
May 30, 2012		19,497,204		2.408
August 27, 2012		7,709,454		2.360
December 28, 2012		2,567,121		2.396
June 10, 2013		2,355,316		2.830
July 3, 2013*		2,242,628		3.073
July 31, 2013*		4,026,582		3.214
		83,057,965
Principal paid through December 31, 2013		(12,060,185	)
Loan balance at December 31, 2013	$	70,997,780

Schedule of Annual Principal Payments Construction in Progress [Table Text Block]

For the Year Ended		Principal
December 31,		Payments
2014	$	4,121,792
2015		4,319,468
2016		4,410,770
2017		4,332,491
2018		4,073,645
Thereafter		82,095,427
	$	103,353,593

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STOCK BASED COMPENSATION (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Y
Stock Based Compensation 1	15.00%
Stock Based Compensation 2	15.00%
Stock Based Compensation 3	15,314,181
Stock Based Compensation 4	25.00%
Stock Based Compensation 5	25.00%
Stock Based Compensation 6	11,888,250
Stock Based Compensation 7	95,000
Stock Based Compensation 8	$ 1.78
Stock Based Compensation 9	15,000
Stock Based Compensation 10	0.41
Stock Based Compensation 11	1,950,000
Stock Based Compensation 12	0.46
Stock Based Compensation 13	6,375
Stock Based Compensation 14	0.92
Stock Based Compensation 15	1,465,000
Stock Based Compensation 16	2.22
Stock Based Compensation 17	1,250,000
Stock Based Compensation 18	0.35
Stock Based Compensation 19	2,917,000
Stock Based Compensation 20	0.31
Stock Based Compensation 21	652,500
Stock Based Compensation 22	2.41
Stock Based Compensation 23	157,500
Stock Based Compensation 24	1.40
Stock Based Compensation 25	389,503
Stock Based Compensation 26	1.5
Stock Based Compensation 27	683,143
Stock Based Compensation 28	861,277
Stock Based Compensation 29	705,000
Stock Based Compensation 30	705,000
Stock Based Compensation 31	235,000
Stock Based Compensation 32	$ 0.99
Stock Based Compensation 33	235,000
Stock Based Compensation 34	$ 0.60
Stock Based Compensation 35	235,000
Stock Based Compensation 36	0.58
Stock Based Compensation 37	300,000
Stock Based Compensation 38	$ 0.35
Stock Based Compensation 39	105,000
Stock Based Compensation 40	73,792
Stock Based Compensation 41	500,000
Stock Based Compensation 42	5.00
Stock Based Compensation 43	5,905,408
Stock Based Compensation 44	0.50
Stock Based Compensation 45	118,421
Stock Based Compensation 46	0.437
Stock Based Compensation 47	2,500,000
Stock Based Compensation 48	56,000
Stock Based Compensation 49	$ 1.075

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2013

RELATED PARTY TRANSACTIONS [Text Block]

NOTE 15 - RELATED PARTY TRANSACTIONS

At December 31, 2013 and 2012 the amounts of $3,089 and $3,391 ; respectively, were payable to the officers of the Company for routine expense reimbursement. These amounts are unsecured and due on demand.

The Company paid directors’ fees for the years ended December 31, 2013 and 2012 amounting to $99,000 and $120,000 ; respectively.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Method [Policy Text Block]

Accounting Method

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

Use of Estimates [Policy Text Block]

Use of Estimates

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

Cash and Cash Equivalents [Policy Text Block]

Cash and Cash Equivalents

The Company considers all unrestricted cash, short-term deposits, and other investments with original maturities of no more than ninety days when acquired to be cash and cash equivalents for the purposes of the statement of cash flows. Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At December 31, 2013, $7.9 million in USG Oregon LLC funds were deposited at PNC Bank and $16.4 million in Oregon USG Holdings LLC funds were deposited at Sterling Bank, and were unavailable for immediate corporate needs. The allocation of these funds to the owners of USG Oregon LLC is subject to completion of negotiations regarding the final ownership percentages. Discussion regarding restricted cash is included in Note 3.

Accounts Receivable Allowance for Doubtful Accounts [Policy Text Block]

Accounts Receivable Allowance for Doubtful Accounts

Trade Accounts Receivable Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of December 31, 2013 and 2012, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

Grant Accounts Receivable
For receivables expected to be received from grants from Federal or State agencies, the Company records the receivable amounts net of the funds expected to be received which may be less than the total amounts requested on the actual grant applications. Therefore, no allowance accounts are considered to be necessary for receivables from grants at December 31, 2013 and 2012.

Concentration of Credit Risk [Policy Text Block]

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity through December 31, 2013. At December 31, 2013, the Company’s total cash balance, excluding money market funds, was $21,005,464, and bank deposits amounted to $21,268,264. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $19,700,267 was not covered by or was in excess of FDIC insurance guaranteed limits. At December 31, 2013, the Company’s money market funds invested in government backed securities totaled $29,623,935 and were not subject to deposit insurance.

Equity Securities [Policy Text Block]

Equity Securities

The Company determines the appropriate classification of marketable securities at the time of purchase and reevaluates this designation as of each balance sheet date. The Company classifies these securities as either held-to-maturity, trading, or available-for-sale. All marketable securities and restricted investments were classified as available-for-sale securities. The Company classifies its investments as “available for sale” because it does not intend to actively buy and sell for short-term profits. The Company's investments are subject to market risk, primarily interest rate and credit risk. The fair value of investments is determined using observable or quoted market prices for those securities.

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

Property, Plant and Equipment [Policy Text Block]

Property, Plant and Equipment

Property, plant and equipment, including assets under capital lease, are recorded at historical cost. Costs of acquisition of geothermal properties are capitalized in the period of acquisition. Major improvements that significantly increase the useful lives and/or capabilities of the assets are capitalized. A primary factor in determining whether to capitalize construction type costs is the stage of the potential project’s development. Once a project is determined to be commercially viable, all costs directly associated with the development and construction of the project are capitalized. Until that time, all development costs are expensed. A commercially viable project will have, among other factors, a reservoir discovery well or other significant geothermal surface anomaly, a power transmission path that is identified and available, and an electricity off-taker identified. A valid reservoir discovery is generally defined when a test well has been substantially completed that indicates the presence of a geothermal reservoir that has a high probability of possessing the necessary temperatures, permeability, and flow rates. After a valid discovery has been made, the project enters the development stage. Generally, all costs incurred during the development stage are capitalized and tracked on an individual project basis. If a geothermal project is abandoned, the associated costs that have been capitalized are charged to expense in the year of abandonment. Expenditures for repairs and maintenance are charged to expense as incurred. Interest costs incurred during the construction period of defined major projects from debt that is specifically incurred for those projects are capitalized. Funds received from grants associated with capital projects reduce the cost of the asset directly associated with the individual grants. The offset of the cost of the asset associated with grant proceeds is recorded in the period when the requirements of the grant are substantially complete and the amount can be reasonably estimated.

Direct labor costs, incurred for specific major projects expected to have long-term benefits will be capitalized. Direct labor costs subject to capitalization include employee salaries, as well as, related payroll taxes and benefits. With respect to the allocation of salaries to projects, salaries are allocated based on the percentage of hours that our key managers, engineers and scientists work on each project and are invoiced to the project each month. These individuals track their time worked at each project. Major projects are, generally, defined as projects expected to exceed $500,000. Direct labor includes all of the time incurred by employees directly involved with construction and development activities. General and/or indirect management time and time spent evaluating the feasibility of potential projects are expensed when incurred. Employee training time is expensed when incurred.

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

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

Intangible Assets [Policy Text Block]

Intangible Assets

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

-       contractual expiration terms of the right,
-       contractual terms of an associated revenue contract (i.e., PPA’s),
-       compliance with utilization and other requirements, and
-       hierarchy of other right holders who share the same resource.

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

Impairment of Long-Lived Assets [Policy Text Block]

Impairment of Long-Lived Assets

The Company evaluates its long-term assets annually for impairment and when circumstances/events occur that may impact the fair value of the assets. An impairment loss would be recognized if the carrying amount of a capitalized asset is not recoverable and exceeds its fair value. The most recent assessment was performed based upon financial conditions and assumptions as of December 31, 2013, and there have not been any significant changes in financial conditions and assumptions subsequent to that assessment date. Management believes that there have not been any circumstances that have warranted the recognition of losses due to the impairment of long-lived assets.

Stock Options Granted to Employees and Non-employees [Policy Text Block]

Stock Options Granted to Employees and Non-employees

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

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

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

Stock Based Compensation Granted to Employees [Policy Text Block]

Stock Based Compensation Granted to Employees

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

Earnings (Losses) Per Share [Policy Text Block]

Earnings (Losses) Per Share

The Company follows financial accounting standards, which provides for calculation of "basic" and "diluted" earnings (losses) per share. Basic earnings per share includes no dilution and is computed by dividing net income available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of an entity similar to fully diluted earnings per share. Both basic and diluted were presented for the calculation of the income per share for the periods that reported income. Stock equivalents were not included in the calculation for the periods that reported losses since their inclusion would be considered anti-dilutive. Total common stock equivalents on a fully diluted basis at December 31, 2013 and 2012 were 124,494,963 and 122,768,560 ; respectively.

Financial Instruments [Policy Text Block]

Financial Instruments

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

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

Revenue [Policy Text Block]

Revenue

Revenue Recognition

Energy Sales
The energy sales revenue is recognized when the electrical power generated by the Company’s power plants is delivered to the customer who is reasonably assured to be able to pay under the terms defined by the Power Purchase Agreements (“PPAs”).

Renewable Energy Credits (“RECs”)
Currently, the Company operates three plants that produce renewable energy that creates a right to a REC. The Company earns one REC for each megawatt hour produced from the geothermal power plant. The Company considers the RECs to be an inventory item held for sale, and outputs that are an economic benefit obtained directly through the operation of the plants. The Company does not currently hold any RECs for our own use. Revenues from RECs sales are recognized when the Company has met the terms and conditions of certain energy sales agreements with a financially capable buyer. At Raft River Energy I LLC, each REC is certified by the Western Electric Coordinating Council and sold under a REC Purchase and Sales Agreement to Holy Cross Energy. At San Emidio and Neal Hot Springs, the RECs are owned by our customer and are bundled with energy sales. At all three plants, title for the RECs pass during the same month as energy sales. As a result, costs associated with the sale of RECs are not segregated on the statement of operations.

Revenue Source
All of the Company’s operating revenues (energy sales and energy credit sales) originate from energy production from its interests in geothermal power plants located in the states of Idaho, Oregon and Nevada.

Reclassification [Policy Text Block]

Reclassification

Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no effect on reported losses, total assets, or stockholders’ equity as previously reported.

Recent Accounting Pronouncements [Policy Text Block]

Recent Accounting Pronouncements

Management has considered all recent accounting pronouncements. The following pronouncement was deemed applicable to our financial statements.

Presentation of an Unrecognized Tax Benefit In July 2013, FASB issued Accounting Standards Update No. 2013-11 (“Update 2013-11”), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (Topic 740). Update 2013-11 provides guidance on the presentation of unrecognized tax benefits that are associated with a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Update 2011-05 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. Management is still evaluating the impact of this update, and expects that it may impact the presentation of its financial statements.

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NOTES PAYABLE (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Y MW
Notes Payable 1	$ 96,800,000
Notes Payable 2	13
Notes Payable 3	11,870,137
Notes Payable 4	11,167,473
Notes Payable 5	9,711,930
Notes Payable 6	70,386,576
Notes Payable 7	21.5
Notes Payable 8	2.598%
Notes Payable 9	1,709,963
Notes Payable 10	1,626,251
Notes Payable 11	70,997,780
Notes Payable 12	3,419,927
Notes Payable 13	9
Notes Payable 14	2,000,000
Notes Payable 15	119,382
Notes Payable 16	7.00%
Notes Payable 17	1,850,314
Notes Payable 18	378,698
Notes Payable 19	24
Notes Payable 20	6.75%
Notes Payable 21	30,505,500
Notes Payable 22	$ 323,167

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Y D
Summary Of Significant Accounting Policies 1	$ 7,900,000
Summary Of Significant Accounting Policies 2	16,400,000
Summary Of Significant Accounting Policies 3	90
Summary Of Significant Accounting Policies 4	250,000
Summary Of Significant Accounting Policies 5	21,005,464
Summary Of Significant Accounting Policies 6	21,268,264
Summary Of Significant Accounting Policies 7	19,700,267
Summary Of Significant Accounting Policies 8	$ 29,623,935
Summary Of Significant Accounting Policies 9	30
Summary Of Significant Accounting Policies 10	124,494,963
Summary Of Significant Accounting Policies 11	122,768,560

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Operating Activities:
Net Income (Loss)	$ 4,130,649	$ (4,331,525)
Adjustments to reconcile net income (loss) to total cash provided by operating activities:
Depreciation and amortization	6,575,266	3,682,581
Stock based compensation	756,935	940,132
Stock based officer bonus	100,000	0
Loss on disposal of water rights	0	548,701
Net changes in:
Trade accounts receivable, operating	(809,916)	(169,731)
Accounts payable and accrued liabilities	128,868	(1,004,686)
Prepaid expenses and other	(240,158)	(512,166)
Total cash provided by operating activities	10,641,644	(846,694)
Investing Activities:
Purchases of property, plant and equipment	(13,868,842)	(8,807,798)
Proceeds from ITC cash grants receivable	40,113,741	10,784,530
Cash received from consolidation of subsidiary	0	592,330
Funding of restricted cash reserves and bonds	(17,474,465)	(1,501,700)
Total cash provided (used) by investing activities	8,770,434	1,067,362
Financing Activities:
Issuance of share capital, net of share issuance costs	0	5,488,947
Contributions from non-controlling interest	7,460	10,080,902
Distributions to non-controlling interest	(117,248)	(119,476)
Proceeds from debt obligations	16,570,400	0
Principal payments on notes payable and other obligations	(19,999,257)	(8,973,577)
Principal payments on capital lease	(45,278)	(58,144)
Total cash provided (used) by financing activities	(3,583,923)	6,418,652
Increase in Cash and Cash Equivalents	15,828,155	6,639,320
Cash and Cash Equivalents, Beginning of Year	12,908,779	6,269,459
Cash and Cash Equivalents, End of Year	28,736,934	12,908,779
Supplemental Disclosures:
Purchase of property and equipment on account	1,107,189	6,008,629
Construction and development paid directly with construction loans	745,105	54,793,354
Net assets and liabilities received from consolidation of subsidiary	0	45,386,103
Equipment purchased with capital leases	0	155,000
Capitalized accrued interest	0	2,749,081
Property and equipment costs reduced by settlement agreements	4,406,958	0
Grants receivable used to decrease construction costs	2,770,459	0
Other Items:
Interest paid	$ 6,973,502	$ 346,889

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GRANT PROCEEDS RECEIVABLE

12 Months Ended

Dec. 31, 2013

GRANT PROCEEDS RECEIVABLE [Text Block]

NOTE 4 – GRANT PROCEEDS RECEIVABLE

USG Nevada LLC
The Company submitted an application on July 17, 2012, to the United States Department of Treasury for an ITC cash grant of approximately $11.70 million. 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 total proceeds from this grant offset a portion of the construction costs of the new power plant located in San Emidio, Nevada that was placed into service for financial reporting purposes on September 1, 2012. As of December 31, 2013, all proceeds expected from this cash grant have been received.

USG Oregon LLC
The Company submitted an application for an ITC cash grant (“ITC grant”) to the United States Department of Treasury in the first quarter of 2013. The Company also submitted an application to Oregon Department of Energy for a Business Energy Tax Credit (“BETC”) for qualified construction purchases related to the project located at Neal Hot Springs, Oregon. The Company received $7,364,200 from the BETC program. Proceeds collected on the ITC grant request totaled $32,749,541, which included a reduction of 8.7% federal sequestration. The net proceeds from the grants have been used to offset the construction costs of the power plant. As of December 31, 2013, all of the expected proceeds from these two programs were collected.

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Schedule of Equity Method Investments (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Investment In Equity Securities Schedule Of Equity Method Investments 1	$ 88,515
Investment In Equity Securities Schedule Of Equity Method Investments 2	(22,355)
Investment In Equity Securities Schedule Of Equity Method Investments 3	(609)
Investment In Equity Securities Schedule Of Equity Method Investments 4	65,551
Investment In Equity Securities Schedule Of Equity Method Investments 5	(20,551)
Investment In Equity Securities Schedule Of Equity Method Investments 6	(2,826)
Investment In Equity Securities Schedule Of Equity Method Investments 7	$ 42,174

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Investments and Advances to Affiliates (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Notes Payable Investments And Advances To Affiliates 1	$ 2,328,422
Notes Payable Investments And Advances To Affiliates 2	2.997
Notes Payable Investments And Advances To Affiliates 3	10,043,467
Notes Payable Investments And Advances To Affiliates 4	2.755
Notes Payable Investments And Advances To Affiliates 5	3,600,026
Notes Payable Investments And Advances To Affiliates 6	2.918
Notes Payable Investments And Advances To Affiliates 7	4,377,079
Notes Payable Investments And Advances To Affiliates 8	2.795
Notes Payable Investments And Advances To Affiliates 9	2,313,322
Notes Payable Investments And Advances To Affiliates 10	2.608
Notes Payable Investments And Advances To Affiliates 11	8,968,019
Notes Payable Investments And Advances To Affiliates 12	2.772
Notes Payable Investments And Advances To Affiliates 13	13,029,325
Notes Payable Investments And Advances To Affiliates 14	2.695
Notes Payable Investments And Advances To Affiliates 15	19,497,204
Notes Payable Investments And Advances To Affiliates 16	2.408
Notes Payable Investments And Advances To Affiliates 17	7,709,454
Notes Payable Investments And Advances To Affiliates 18	2.360
Notes Payable Investments And Advances To Affiliates 19	2,567,121
Notes Payable Investments And Advances To Affiliates 20	2.396
Notes Payable Investments And Advances To Affiliates 21	2,355,316
Notes Payable Investments And Advances To Affiliates 22	2.830
Notes Payable Investments And Advances To Affiliates 23	2,242,628
Notes Payable Investments And Advances To Affiliates 24	3.073
Notes Payable Investments And Advances To Affiliates 25	4,026,582
Notes Payable Investments And Advances To Affiliates 26	3.214
Notes Payable Investments And Advances To Affiliates 27	83,057,965
Notes Payable Investments And Advances To Affiliates 28	(12,060,185)
Notes Payable Investments And Advances To Affiliates 29	$ 70,997,780

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Property, Plant and Equipment, Estimated Useful Lives [Table Text Block]

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

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Schedule of Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 1	$ 1,695,000
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 2	0.83
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 3	0.50
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 4	2,917,000
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 5	0.31
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 6	0.16
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 7	(2,399,250)
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 8	0.69
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 9	0.40
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 10	0
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 11	0
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 12	0
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 13	2,212,750
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 14	0.31
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 15	0.16
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 16	3,215,000
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 17	0.42
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 18	0.25
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 19	(2,599,750)
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 20	0.35
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 21	0.23
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 22	0
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 23	0
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 24	0
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 25	$ 2,828,000
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 26	0.39
Stock Based Compensation Schedule Of Share-based Compensation Arrangement By Share-based Payment Award, Options, Vested And Expected To Vest, Outstanding 27	0.23

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JOINT VENTURES/NON-CONTROLLING INTEREST (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Non-controlling Interests [Table Text Block]

		December 31,
		2013		2012
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	404,352	$	404,434
Oregon USG Holdings LLC interest held by Enbridge Inc.		35,926,826		33,078,744
Raft River Energy I LLC interest held by Raft River I Holdings, LLC		21,824,302		22,598,020
	$	58,155,480	$	56,081,198

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FAIR VALUE MEASUREMENT

12 Months Ended

Dec. 31, 2013

FAIR VALUE MEASUREMENT [Text Block]

NOTE 14 – FAIR VALUE MEASUREMENT

Current U.S. generally accepted accounting principles establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

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

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

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

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

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

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on its Consolidated Balance Sheet as of December 31, 2013 at fair value on a recurring basis:

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts *	$	29,623,935	$	29,623,935	$	-	$	-
Investment in equity securities		43,632		-		42,174		-
	$	29,666,109	$	29,623,935	$	42,174	$	-

* - Money market accounts include both restricted and unrestricted funds.

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