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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, 2014

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

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

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

 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§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 6, 2015 was 107,063,029.

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U.S. Geothermal Inc. and Subsidiaries

Form 10-K INDEX

For the Year Ended December 31, 2014

		Page
PART I
Item 1	Business	6
	General	8
	Development of Business	8
	History	8
	Plan of Operations	8
	Projects in Operation	10
	Material Acquisitions/Development	12
	Employees	23
	Principal Products	23
	Sources and Availability of Raw Materials	23
	Significant Government Permits	24
	Seasonality of Business	25
	Industry Practices/Needs for Working Capital	25
	Dependence on a Few Customers	25
	Competitive Conditions	26
	Environmental Compliance	27
	Financial Information about Geographic Areas	29
	Available Information	30
	Governmental Approvals and Regulations	30
	Environmental Credits	32
Item 1A	Risk Factors	35
	Risks Related to Our Business	35
	Risks Related to Our Growth	41
	Risks Related to Our Power Purchase Agreements	46
	Risks Related to Our Liquidity and Capital Resources	48
	Risks Related to Government Regulation	50
	Risks Related to Ownership of Our Common Stock	52
Item 1B	Unresolved Staff Comments	55
Item 2	Property	56
	Neal Hot Springs, Oregon	58
	San Emidio, Nevada	59
	Raft River, Idaho	60
	El Ceibillo, Republic of Guatemala	62
	Crescent Valley and Lee Hot Springs, Nevada	63
	WGP Geysers, California	64
	Vale Butte, Oregon	65
	Boise Administration Office, Idaho	66

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U.S. Geothermal Inc. and Subsidiaries

Form 10-K INDEX

For the Year Ended December 31, 2014

		Page
	Land and Leases	66
	BLM Leases	66
	Private Geothermal Leases	67
	Geothermal Development Concession in Guatemala	68
Item 3	Legal Proceedings	69
Item 4	Mine Safety Disclosures	69
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	70
Item 6	Selected Financial Data	71
Item 7	Management’s Discussion and Analysis of Financial Condition	71
	and Results of Operations	72
	Historical Overview	72
	Factors Affecting Our Results of Operations	74
	Operating Results	76
	Liquidity and Capital Resources	86
	Potential Acquisitions	89
	Critical Accounting Policies	90
	Contractual Obligations	91
	Off Balance Sheet Arrangements	91
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	92
Item 8	Financial Statements and Supplementary Data	92
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
Item 9A	Controls and Procedures	93
Item 9B	Other Information	94
PART III
Item 10	Directors, Executive Officers and Corporate Governance	95
Item 11	Executive Compensation	98
	Summary Compensation Table	105
	Outstanding Equity Awards at Fiscal Year-End	105
	Potential Payments Upon Termination or Change-in-Control	106
	Director Compensation	107
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Securities Authorized for Issuance under Equity	108

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U.S. Geothermal Inc. and Subsidiaries

Form 10-K INDEX

For the Year Ended December 31, 2014

		Page
	Compensation Pans	108
	Security Ownership of Certain Beneficial Owners and Management	108
Item 13	Certain Relationships and Related Transactions, and Director Independence	110
Item 14	Principal Accountant Fees and Services	110
PART IV
Item 15	Exhibits and Financial Statement Schedules	113

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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;
	•	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 (“PPAs”) for our projects;
	•	impact of environmental and other governmental regulation, including delays in obtaining permits;

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	•	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 United States and the Republic of Guatemala. 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.

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Development of Business

U.S. Geothermal 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.

The Company currently owns and operates the following geothermal power plant projects: Raft River, Idaho; San Emidio, Nevada; and Neal Hot Springs, Oregon. The Company also has geothermal property interests in the Republic of Guatemala; the Geysers in California; Vale, Oregon; Crescent Valley, Nevada; Ruby Hot Springs, Nevada; Lee Hot Springs, Nevada; and Gerlach, Nevada, some of which are under development or exploration.

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.

Plan of Operations

Our business strategy is to operate, identify, evaluate, acquire, and develop geothermal assets and resources economically, safely and efficiently. Our management evaluates our operating projects based on revenues and expenses, and our projects under development, based on costs attributable to each project. We examine different factors when assessing projects at different stages of development or potential acquisitions, such as the internal rate of return of the investment, technical and geological matters and other relevant business considerations.

We intend to execute this strategy in several steps outlined below:

•

Maximize Our Operations – Our operating power plants and operations team provide revenue to the Company through both power sales and Operations & Maintenance contracts. We strive to optimize plant operations though high safety standards, quality preventative maintenance programs, operator education, equipment selection and by exceeding our annual budgetary goals.

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•	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 (“PPAs”) 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 of the project was started prior to the end of 2014. We believe that the second phase of our San Emidio project, our WGP Geysers project, and our Crescent Valley project each qualify for this credit.
•	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 capital intensive, 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.

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During the current year ended December 31, 2014, the Company was focused on these specific items:

•	operating and optimizing the Neal Hot Springs, San Emidio and Raft River power plants;
•	completing the acquisition of the WGP Geysers project, pursuing PPA and steam sale opportunities, and optimizing power plant design;
•	completing the acquisition of leases for the Vale project;
•	completing the acquisition of Earth Power Resources;
•	drilling of nine temperature gradient wells to define the target resource area for the El Ceibillo project, leasing surface lands, and working with the Guatemalan Ministry of Energy and Mines to adopt a new construction schedule;
•	drilling two new wells, and constructing a tie in pipeline at San Emidio for Phase II; and
•	evaluating potential new geothermal projects and acquisition opportunities.

Projects in Operation

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:

(1)	In September 2010, the Company’s wholly owned subsidiary (Oregon USG Holdings LLC) entered into agreements that formulated a strategic partnership with Enbridge (U.S.) Inc. (“Enbridge”). Enbridge contributed approximately $32.8 million to the Neal Hot Springs geothermal project. The Company’s equity interest in the project is 60% and Enbridge’s equity interest is 40%.
(2)	As part of the financing package for Unit I of the Raft River project, we 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)	Based on the designed annual average net output. The actual output of the Raft River Unit I plant currently is approximately 9.4 megawatts annual average.

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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, and achieved commercial operation on November 16, 2012. The Neal Hot Springs facility is designed as a 22 megawatt net annual average power plant, consisting of three separate 12.2 megawatt (gross) modules, with each module having a design output of 7.33 megawatts (net) annual average based on a specific flow and temperature of geothermal brine.

Generation from the facility during the fourth quarter of 2014 totaled 54,472 megawatt-hours with an average of 25.08 net megawatts per hour of operation. Plant availability was 98.3% during the quarter. Total generation at Neal Hot Springs for 2014 was 183,394 megawatt-hours. This compares to 155,428 megawatt-hours of generation for 2013, reflecting an 18% increase over the prior year.

The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. It has a 25 year term, and a variable percentage annually price escalation. The 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 was $102.78 per megawatt-hour and will increase to $106.79 per megawatt-hour in 2015.

San Emidio Unit I, Nevada
The Unit I power plant at San Emidio is located approximately 100 miles north-east of Reno, Nevada near the town of Gerlach, and achieved commercial operation on May 25, 2012. The San Emidio facility is a single 14.7 megawatt (gross) module, with a design output of 9 megawatts (net) annual average based on a specific flow and temperature of geothermal brine. Generation from the facility during the fourth quarter 2014 totaled 21,745 megawatt-hours, with an average of 9.93 net megawatts per hour of operation. Plant availability was 99.2% during the quarter. Total generation for 2014 was 76,894 megawatt-hours. This compares to 76,697 megawatt-hours of generation for 2013 reflecting continued, steady state operation of the facility.

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 an annual escalation rate of 1 percent. The average price paid under the PPA for 2014 was $91.17 per megawatt-hour and will increase to $92.08 per megawatt-hour in 2015.

Raft River, Idaho
Raft River Unit I is located in Southern Idaho, near the town of Malta, and achieved commercial operation on January 3, 2008. The Raft River facility is a single 18 megawatt (gross) module, with a design output of 13 megawatts (net) annual average based on a specific flow and temperature of geothermal brine.

Generation from the facility during the fourth quarter 2014 totaled 20,614 megawatt-hours, with an average of 9.59 net megawatts per hour of operation. Plant availability was 97.3% during the quarter. Total generation for 2014 was 78,798 megawatt-hours. This compares to 77,560 megawatt-hours for the same period of 2013, reflecting continued steady state operation of the facility.

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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 through 2020 and then at 0.6% per year until the end of the contract in 2034. 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 was $60.72 per megawatt-hour and will increase to $62.00 per megawatt-hour in 2015.

In addition to the price paid for energy by Idaho Power, Raft River Unit I currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits (“RECs”) to Holy Cross Energy, a Colorado electric cooperative. Starting in calendar year 2018, 51% of the RECs are owned by Idaho Power and 49% by the project. For the RECs owned by Raft River, a new, 10 year REC contract with the Public Utility District No. 1 of Clallam County, Washington will replace the current contract.

Material Acquisitions/Development

In addition to our projects in operation, we have projects under development and under exploration. 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, estimates of property development costs may be low.

A summary of projects under development and under exploration is as follows:

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Properties Under Exploration
						Target Development
Project		Location		Ownership		*(Megawatts)
Gerlach		Nevada		60%		10
Vale		Oregon		100%		15
El Ceibillo Phase II		Guatemala		100%		25
Neal Hot Springs II		Oregon		100%		10
Raft River Unit II		Idaho		100%		13
Crescent Valley Phase II		Nevada		100%		25
Crescent Valley Phase III		Nevada		100%		25
Lee Hot Springs		Nevada		100%		20
Ruby Hot Springs Phase I		Nevada		100%		20

Granite Creek – During the current year ended December 31, 2014, the Company elected to not continue exploration and development activities due to more attractive projects in its portfolio. The Company is in the process of releasing its interests in the area.

Neal Hot Springs Phase III, Raft River Phase III, and San Emidio Phase III – These projects were removed from the list of properties under exploration during the current year. Unfavorable market conditions and development time frames did not warrant the allocation of exploration or development resources.

* Target development sizes are predevelopment estimates of resource potential of unproven resources.

A summary of the property size, temperature, well-depth and power plant technology used or anticipated to be used at our properties is as follows:

Property Details
		Property Size
		(square
Property		miles)		Temperature (ºF)		Depth (Ft)		Technology
Neal Hot Springs		9.6		286-311		2,500-3,000		Binary
San Emidio		27.9		289-316		1,500-3,000		Binary
Raft River		10.8		275-302		4,500-6,000		Binary
Gerlach		4.7		338-352		2,000-3,000		Binary
El Ceibillo		38.6		410-526		1,800-TBD		Steam
WGP Geysers		6.0		380-598		6,000-10,000		Steam
Crescent Valley		33.3		326-351		2,000-3,000		Binary
Lee Hot Springs		4.0		280-320		1,250-5,000		Binary
Ruby Hot Springs		3.3		315-340		1,670-4,500		Binary
Vale		0.6		290-300		2,450-5,000		Binary

Binary Cycle Geothermal Power Plants
In a binary cycle geothermal power plant hot water is produced to a piping and gathering system from wells drilled into the geothermal reservoir. The hot water flows, with to a heat exchanger called a vaporizer where it vaporizes a secondary working fluid, with its heat extracted, causing the original hot water to become cool. All of the cooled water is then pumped to injection wells where it is injected back into the reservoir to help recharge the geothermal reservoir. The vaporized working fluid passes through a turbine which drives an electrical generator that is tied into the electrical transmission grid. Upon discharging the turbine the secondary working fluid is condensed before piping it back to the vaporizer where the process is repeated.

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Dry Steam Geothermal Power Plants
An example of a vapor dominated geothermal system is at The Geysers in central California. Dry super-heated steam is produced from wells through a piping system and run directly through a turbine. The turbine drives an electrical generator that delivers power to the electrical transmission grid. Steam discharges from the turbine into a condenser where it is condensed forming water. The water is pumped to a cooling tower where it can be used as water for the cooling process. The cooled water from the cooling tower is recycled back to the condenser to repeat the process. Any excess water from the cooling tower is pumped through a piping system to injection wells where it is injected back into the reservoir which helps to recharge the geothermal reservoir.

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Flash Geothermal Power Plants
In hot water geothermal systems (temperatures greater than approximately 400 degrees Fahrenheit), flash production systems are often used. The hot water is produced from wells drilled into the geothermal reservoir. The hot water from the various production wells is piped to a flash tank where the pressure is reduced. The reduction in pressure in the flash tank causes part of the hot water to flash to form steam and part to remain as water. The flash tank also acts a separator, separating the steam from the water. The hot water separated from the steam is pumped through a pipeline system to injection wells and injected into the reservoir for reservoir recharge. The steam coming off the flash tank/separator is piped directly to a turbine where the process is identical to that used for dry steam geothermal power plants.

San Emidio, Nevada
The Phase II expansion is dependent on successful development of additional production and injection well capacity. We expect that approximately 75% of the Phase II development may be funded by project loans, with the remainder funded through equity financing. We anticipate the project qualifying for the 30% Federal investment tax credit. As a result of the delays experienced in permitting wells on BLM administered leases, it was determined that it is not possible to complete the development of the Phase II project within the development time frame required in the existing 19.9 megawatt NV Energy PPA.

A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010. 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. A System Impact Study (“SIS”) agreement, which is the next step in the interconnection process mandated by the Federal Energy Regulatory Commission, was signed on August 28, 2014. Results from the SIS were received on December 24, 2014. A second phase interconnection study, called the Facilities Study, was started in January of 2015.

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On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding from the Department of Energy (“DOE”) 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 first stage of the DOE project 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 and was completed in 2011. 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 second stage of the DOE program was a 50-50 cost shared drilling plan that was intended to follow up on targets identified in the first stage. Drilling started in the South Zone, and two wells were completed by the Company. After approval of the drilling program by the DOE in November 2011, one of the first two wells was deepened and three additional wells were completed in the South Zone with the costs being shared on a 50-50 basis.

As part of the continuing DOE program, permitting was initiated early in the year with the Bureau of Land Management (“BLM”) 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). As part of the permitting process, cultural and biological surveys were performed, and the well design and drilling program were submitted during the first quarter. Permits for three wells were issued by the BLM on April 29^th and a drill rig was mobilized to the site on June 26^th. Two additional wells were completed on the BLM administered land during the third quarter. Well OW-14 was drilled to a depth of 3,501 feet and had a bottomhole temperature of 265°F. Well OW-15 was drilled to a depth of 3,716 feet and had a maximum downhole temperature of 300°F. While the wells extended the high temperature outline of the South Zone, neither well encountered the commercial permeability seen in well 61-21 (OW-10). Geologic, geochemical and temperature data generated by the drilling program is being evaluated to determine the next phase of drilling.

A second round of permitting for an expanded temperature gradient drilling program is underway for an area south west of the current resource. Results from the recent OW drilling program combined with 1970s era, shallow temperature gradient data, indicate a high temperature trend into this south-west zone. Geophysical surveys have also identified structural trends in this area. Several 1,000 foot deep temperature gradient wells are being permitted to follow up on this portion of the resource.

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 was completed during the second quarter of 2014. To allow for early, long term testing of the South Zone resource area, a cross tie pipeline was constructed between the Phase I and Phase II project areas and a production pump was installed in well 61-21 during the third quarter. Well 61-21 is currently producing 620 gallons per minute of 296°F fluid to the San Emidio Phase I power plant. San Emidio Phase I plant generation has increased approximately a half of megawatt. Hooking up and flow testing well 61-21 was the last work under the DOE Innovative Exploration and Drilling Project grant. The grant program was completed at the end of September 2014, with the DOE Geothermal Technologies Program having expended $3,772,560 and the Company $4,156,741.

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A Request for Proposal (“RFP”) from NV Energy for 100 megawatts of renewable energy was issued on October 1, 2014. On November 12, we submitted a bid for an air cooled power plant to be developed on the Phase II project site. In early December, NV Energy submitted a request to the Nevada Public Utilities Commission (“NPUC”) to combine the 2014 solicitation with the 2015 solicitation for a total of 200 megawatts to be procured in 2014. The request also allows re-submittal of any projects that had been previously submitted for the original 2014 RFP. NV Energy’s request was approved by the NPUC, and Subsequent to the end of the year on February 16, 2015, we submitted an alternative option into the new NV Energy solicitation that uses a water cooled plant as the basis for the bid. We were notified on March 3^rd that our bid was advanced to the initial short list for geothermal projects.

In parallel, we are continuing to investigate a power purchase agreement with California off-takers, where power prices are typically higher.

Raft River, Idaho

The Raft River project was awarded an $11.4 million cost-shared, thermal fracturing program grant from the Department of Energy. The goal of the project is to create an Enhanced Geothermal System (“EGS”) by creating thermal fractures and developing a corresponding increase in permeability in the low permeability rock. Well RRG-9 was made available, and after installing four, 300 foot deep seismic monitoring wells with seismic geophones to allow for seismic monitoring, the first stage of injection into the well began in June 2013. Initially the well was only capable of receiving 20 gallons per minute (“gpm”) of water due to the low permeability of the rock. Injection continued through the quarter from power plant injectate, with flow into the well seeing a moderate increase to now over 450 gpm, indicating that significant additional permeability has developed. The EGS stimulation is expected to continue through 2015.

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.

Gerlach, Nevada

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 in 2010 and the hole was opened from a 6.5 inch diameter well to a 12.5 inch diameter well. Lost circulation was confirmed within 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, 2014. 18-10a is a twin well to a well originally drilled in 1994 (the 18-10 well). The upper section of the well was drilled to 826 feet deep and an 8 inch liner was cemented in place. Temperature measurements in the well have provided the highest measured temperature in the field to date at 268°F within 160 feet 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 from the original well at 1,600 and 2,800 feet 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. Drilling resumed again on well 18-10a on August 14, 2014, and was completed in late November. The well was drilled to a total depth of 2,889 feet and encountered a maximum temperature of 275°F. Further work is dependent upon additional funding from the partners.

El Ceibillo, 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. 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 acre plant site is under lease on land adjacent to the existing wells. A second surface lease for use of an additional 80 acre parcel was signed on October 15, bringing the total surface leasehold interest to 97 acres. Construction of a drill pad, pond and cellar for EC-2, our new well, was completed during the fourth quarter. EC-2 is located on the new surface leasehold. Drilling of EC-2 is expected to begin as soon as the approval to extend the development schedule contained in the concession agreement has been obtained from the Guatemalan Ministry of Energy and Mines.

Our attempts to obtain approval of our modified development schedule from the Guatemala Ministry of Energy (“MEM”) continue. Our request has been approved by the MEM legal department and, subsequent to the end of the year, the new schedule was approved by the technical department, and has been approved by the Vice-Minister. Final approval for the new schedule now awaits signature by the Minister of Energy.

El Ceibillo, the first development target on the concession, is located near the town of Amatitlan, in a developed industrial zone immediately adjacent to the highway that connects Guatemala City to the Port of San Jose on the Pacific coast. An initial development of a 25 megawatt (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 temperature gradient (“TG”) drilling program was initiated during the first quarter of 2014 with a series of 656 foot (200 meter) deep wells planned. Nine TG wells have been completed with depths ranging from 656 to 1,312 feet (200 to 400 meters). Bottom-hole temperatures found in this shallow drilling program range from 176 to 413°F (80 to 211°C) with two of the wells encountering permeability and flowing brine. The data from these wells provided a more accurate temperature gradient map of the underlying geothermal resource which has assisted in identifying future drilling targets.

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A first phase of drilling took place during the third quarter of 2013 when well EC-1 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) thick. Due to the high temperature gradient found in the lower section of the well, the decision was made to deepen the well. The final depth of the well 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 have been incorporated in the geologic model of the reservoir. Well EC-1 did not encounter commercial permeability.

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 was posted with the Ministry of Environment and Natural Resources.

A binding Memorandum of Understanding (“MOU”) was signed on October 18, 2012 with one of the largest power brokers in Central America. The MOU established the framework for a PPA that included a 15-year term for an initial, estimated 25 megawatts of power generation up to a maximum of 50 megawatts of power generation to be developed in two phases. As a result of the delays in approval of the modified development schedule from MEM, we requested an extension of our MOU, which was allowed under the terms of the agreement, but our request was declined and the MOU is now terminated. We are continuing discussions with the broker to reinstate or renegotiate the agreement, and are approaching other power consumers in Guatemala and Central America.

WGP Geysers, California

The WGP Geysers project is located in the broader Geysers geothermal field located approximately 75 miles north of San Francisco, California. The broader Geysers geothermal field is the largest producing geothermal field in the world generating more than 850 megawatts of power for more than 30 years. Acquisition of the WGP Geysers Project from Ram Power was completed on April 22, 2014 for $6.4 million.

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WGP Geysers is an advanced stage project that encompasses the former Pacific Gas and Electric Unit 15, which once had a 62 megawatt (gross) capacity geothermal power plant that was shut down in l989. The project includes 3,809 acres (6 square miles) of geothermal leases and property, development design plans, and permits for an up to 38.5(gross) megawatt power plant. There are four existing wells drilled in 2008-2009 which are immediately available for production or injection, with a fifth, historic well that has temporary plugs installed but can be reworked. The four new wells have been tested with an initial steam flow totaling 462,000 pounds per hour. A report prepared in 2012 by a third party reservoir engineering firm, states that the total initial power capacity from these wells is estimated at about 30 megawatts (gross).

A 12 month extension for the Sonoma County Conditional Use Permit to construct the up to 38.5 megawatt power plant was applied for and was approved on June 12, 2014. Additionally, an application was made to the Sonoma County Air Quality Board for a permit to conduct flow tests on the four production wells drilled in 2009. The Air Quality permit was approved on June 19, 2014. A new conditional use permit application is currently being prepared for submittal to local regulatory agencies to replace the recently extended conditional use permit that expires in July.

A new transmission interconnection agreement has been applied for to the California Independent System Operator. Engineering optimization of the power plant design continues. The current well field reservoir model is being updated to reflect a new hybrid plant design that includes both water and air cooling, which will dramatically increase the volume of water available for injection back into the reservoir. Traditional water cooled steam plants re-inject approximately 20% of the water that is removed during power generation, while a hybrid design may re-inject up to 65% of the water. This higher injection rate will provide longer term, stable steam production, and will result in increased power generation over the life of the project. A flow testing program for the production wells is being designed and will be scheduled during the first half of 2015.

Crescent Valley, Nevada
The Crescent Valley prospect consists of approximately 21,300 acres (33.3 square miles) of private and Federal geothermal leases. It is located in Eureka County, Nevada, approximately 15 miles south of the Beowawe geothermal power plant and about 33 miles southeast of Battle Mountain. The project was acquired as part of the Earth Power Resources merger which was completed in November 2014.

Multiple geothermal and mineral exploration drilling programs have identified high temperatures and high temperature gradients in the shallow subsurface over an area greater than 30 square miles. Historic drill holes defining this area have anomalous temperature gradients of up to 40°F/100 feet of depth, and a recorded high temperature of 285°F at 395 feet below the surface. These drill holes define large areas of hydrothermal alteration that correspond to positive anomalies defined by gravity surveys that extend into undrilled areas of the valley.

A mineral exploration hole drilled in the mid-l990s near the Crescent Valley fault encountered geothermal fluid under pressure and the driller lost control the well. An oil field service company had to be contracted to regain control prior to the abandonment of the well. This well demonstrates that prospective permeability and commercial temperature are known from past minerals exploration.

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Hot springs located on the property have discharge temperatures of up to 198°F and broad areas of hydrothermal alteration occur at both Hot Springs Point and along the Crescent Valley fault 8 miles to the southeast. Chemistry of the hot springs and the occurrence of silica sinter deposits at surface, and intersected by drilling in the shallow subsurface, suggest reservoir temperatures at depth of greater than 350°F. Chemistry of fluids from the Crescent Valley hot spring is permissive for even higher temperatures of greater than 400°F.

Anomalous temperature gradients extend up to 7 miles northwest from the Crescent Valley fault into Crescent Valley proper. Additional fracture controlled permeability may be present under the valley floor as horst-bounding fault systems interpreted from historic seismic studies are indicated to exist.

An independent geothermal consulting firm evaluated all of the available data for the Crescent Valley Prospect in late 2009. After evaluating the data, a recoverable, heat-in-place Monte Carlo method was used to estimate the generation potential of the prospect. The resulting estimate for the field was 71 megawatt with 90% probability and 186 megawatt with 50% probability over a 20 year period. The actual, producible power generation may be significantly different than the recoverable heat-in-place calculations, and will depend upon the discovery of commercial temperatures and permeability.

In light of federal legislation that extended the qualification for the 30% Investment Tax Credit to projects that began construction prior to December 31, 2014, drilling of the first production well CVP-001 (67-3) was initiated in December of 2014, following completion of gravity surveys, and analysis of prior temperature gradient drilling data. The first string of production casing was set and cemented before year end. Subsequent to the end of the year, the well was drilled to 730 feet and the production casing was cemented in place.

Lee Hot Springs, Nevada
Lee Hot Springs is in Churchill County, 18 miles south of Fallon. The area was originally explored by Occidental Geothermal Company, a subsidiary of the oil company Occidental Petroleum Corporation. The project is comprised of 2,560 acres (four square miles) of BLM leases. ENEL Green Energy, a subsidiary of ENEL Group, the Italian based, multi-national power company, has completed a 15 megawatt binary plant at Salt Wells, 6 miles to the east of Lee. The project was acquired as part of the Earth Power Resources merger which was completed in November 2014.

Dating back to 1930, the area has had numerous water wells, thermal gradient holes, and geothermal slim hole tests. From 1977-1982 Occidental Geothermal, Inc. drilled four temperature gradient holes to depths of 500 feet, two stratigraphic test wells’ to 2,000-3,000 feet, and one large-diameter production test to 3,000 feet (well 72-33). The 3,000 foot test well flowed 280°F hot water from a zone at 1,200 ft. The A33-4 well, 1,000 feet southwest of well 72-33, was drilled to 2,400 feet and reportedly had temperatures in excess of 300°F and a steadily increasing temperature gradient.

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The Great Basin Research Institute has had the leasehold mapped in detail, showing several large silica deposits. The reservoir temperature has been estimated using geochemistry as ranging from 320°F to 340°F by the US Geological Survey and other sources in the 1970s.

Ruby Hot Springs, Nevada
The property is located 30 miles southwest of Elko. EPR filed a BLM lease application for 2,140 acres in February 2001 and the lease application was rejected by the BLM in December 2005 due to cultural issues. The decision was appealed to the Interior Board of Land Appeals (“IBLA”) and the IBLA remanded the application back to the BLM for further action. No further action has been taken by BLM on issuance of the lease pending the completion of cultural and ethnographic studies that are required for further review. The project was acquired as part of the Earth Power Resources merger which was completed in November 2014.

The area around Ruby was first leased by Union Oil Company (now Chevron) in the late 1970s. The 3,000 foot test well mentioned above reportedly flowed at over 300°F. A drilling log shows hot temperatures escalating to depth.

The area around Ruby was first leased by Union Oil Company (now Chevron) in the late 1970s. A 3,149 foot test well was drilled and reportedly flowed at over 300°F. A second well in the area, Ruby Valley 65-10, was drilled to 1,075 feet deep and encountered lost circulation zones, but no temperature data is available. In the early 1980s, Aminoil drilled twelve 500 foot deep temperature gradient wells and two 1,000 foot stratigraphic test wells. Data from these wells have been incorporated into generalized heat-flow contour maps of the area.

Vale, Oregon
The property consists of 368 acres of geothermal energy and surface rights located in Malheur County, located approximately one-half mile east of the town of Vale, Oregon. The property is within the Vale Butte geothermal resource area and provides the opportunity to evaluate development of a known resource. A prolific, shallow reservoir located along the north edge of the leasehold area has been used for many years in an agricultural drying facility and a mushroom growing operation.

An extensive database of geophysical and geological information from previous geothermal exploration in the Vale Butte area was used in the evaluation of the prospect. Geochemical analysis of samples taken from shallow hot wells results in a calculated geothermometer that indicates a potential reservoir temperature of 311°F to 320°F. Past exploration drilling near the site by Trans Pacific Geothermal and Sandia National Laboratory encountered temperatures in excess of 300°F in the basement rocks. The leases for this project were acquired in January and February 2014.

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Employees

At December 31, 2014, the Company had 48 full-time and one part time employees (14 administrative and project development, and 35 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 in operation, as well as all sites under exploration or development, are sites located in the Western United States or in the Republic of Guatemala in Central America.

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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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 Government Permits

The Company has obtained permits for its three operational plants and at the WGP Geysers project.

Neal Hot Springs, Oregon. 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, Nevada. 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, Idaho. The Raft River project has four significant permits in place 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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WGP Geysers, California. The Geysers Unit 15 property has local and state permits that authorize construction and operation of up to a 38.5 megawatt geothermal power plant. The significant permits include:

	1.	Four geothermal well permits for production and injection wells issued by the California Department of Oil, Gas, and Geothermal Resources.
	2.	A Conditional Use Permit issued by the Sonoma County along with preliminary design approval for a septic system.
	3.	Northern Sonoma Air Quality Board has issued permits for well and geothermal power plant operations.

Seasonality of Business

The Company has been producing energy revenues under the terms of three PPAs. Two of these contracts specify favorable rate periods and all three plants experience changes in levels of production through the year. 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. The Neal Hot Springs plant, since it utilizes air cooling rather than water cooling, is impacted more in the summer (lower generation) than the Raft River or San Emidio plants. Conversely, Neal Hot Springs produces higher generation in the winter. 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 exploration and development operations. Once the decision is made to construct a project, 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 for working capital are typically low. The Company is expecting to be significantly involved in exploration and 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 areas of operation 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.

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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 25% renewable. According to the Department of Energy’s Energy Efficiency and Renewable Energy department, approximately 38 states nationwide have established renewable portfolio standards or goals encouraging the procurement of green, renewable power. As a result, we believe green power is an important sub-market in the broader electric market, in which many power purchasers are increasing or committing to increase their investments. Accordingly, the conventional energy producers do not provide direct competition.

In the Pacific Northwest there are currently only two commercial 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 the baseload generation profile provided by geothermal power, with access to infrastructure for deliverability, and a low "full life" cost of power will allow geothermal to successfully compete for long term PPAs.

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.

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Environmental Compliance

Geothermal drilling, resource development and site construction is subject to federal, state and local environmental and construction oversight including state and local agencies in Idaho, Oregon, Nevada and California. Applicable laws may include the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, the Resource Conservation and Recovery Act, and geothermal drilling rules and local building codes.

Prior to acquiring a new property or project, USG has retained licensed environmental professionals to conduct Phase I Site Assessments and evaluate each property. The purpose of the site assessment is to identify, in accordance with federal standards, any existing environmental contaminant release or on-site contamination and prevent an unrecognized financial liability from being passed to U.S. Geothermal Inc. or our subsidiaries.

Our geothermal operations involve significant quantities of brine that is returned to the local subsurface, geologic formation. We also use isopentane and R-134A working fluids, and numerous industrial lubricants that are generally flammable and considered contaminants if released or spilled. We are not aware of any mismanagement of these materials and we are required to promptly report any release of specified volumes of oil, lubricants, and chemicals used in our operations.

The requisite approvals and permits for our operations have been independently reviewed and verified for the financing of each project. Independent legal review verified that USG and our subsidiaries are operated in accordance with applicable laws. Existing laws and regulations may be revised or reinterpreted, or new laws and regulations may become applicable to us. Under those circumstances we work with the appropriate agency or entity to ensure that our operations remain in compliance with the applicable rules. As of the date of this memorandum, all of the permits and approvals required to operate our plants have been obtained and are valid.

Neal Hot Springs, Oregon
The Neal Hot Springs project is situated approximately 12 miles from Vale, Oregon in an area with only one nearby resident. There are no unique plant or animal communities in the area and no unique cultural or environmental constraints.

Because the power plant is air-cooled the only environmental reporting required 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. Semi-annual water monitoring has been conducted since 2008 and will continue throughout power plant operations. The Neal project files a quarterly energy generation report with the Federal Energy Regulatory Commission. An independent legal team has reviewed all regulatory requirements, permits and approvals for the project.

Adjoining rangelands are privately and federally managed and there are no rangeland or cropland management obligations.

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The Neal project is in compliance with all environmental permitting, monitoring and reporting requirements and has received no formal or informal notices from any local, state, or federal agency.

San Emidio, Nevada
The San Emidio project is located approximately 14 miles south of Gerlach Nevada. The nearest residence is over four miles from the plant site.

The San Emidio staff files monthly, quarterly and annual water reports with the Department of Environmental Protection and Department of Water Resources. Similar to other projects the volume, quality, and disposition of geothermal water and cooling water is reported.

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

Raft River, Idaho
The Raft River project is located approximately 12 miles from Malta, Idaho and is in a rural agricultural area with the nearest residence approximately two miles from the plant site. There are no unique plant or animal communities in the area and no unique cultural or environmental constraints.

Key environmental reports include:

	1)	Monthly production and injection reports filed with the Idaho Department of Water Resources;
	2)	Annual land application and cooling water quality reports filed with the Idaho Department of Environmental Quality and Idaho Department of Water Resources.
	3)	Annual Tier II reporting filed with the Idaho Bureau of Homeland Security, Local Emergency Planning Committee, and the local fire department.

The project’s most significant environmental compliance requirement is for water quality monitoring and reporting. The Company has added seven years of water monitoring data to a substantial volume of historical data developed by the US Department of Energy. The IDWR and Idaho Department of Environmental Quality concur with the Project’s findings that geothermal operations have no impact on water quality. The Project’s private lands must be managed on an ongoing basis for weed control, water management, irrigation, and fencing infrastructure. USG has leased the grazing rights and cropland rights to a local rancher who is responsible for the day to day farming and maintenance obligations.

The Raft River project is in compliance with all environmental permitting, monitoring and reporting requirements and has received no formal or informal notices from any local, state, or federal agency.

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WGP Geysers, California
The Unit 15 property is located approximately 30 minutes north of the city of Healdsburg, CA. The property encompasses a ridgetop and a north facing hillside that has been developed and was used for geothermal operations for over 10 years from l979 to l989. There are no unique plant or animal communities on the project site and no unique cultural or environmental constraints. The North Coast Regional Water Quality Board (NCRWQB) has required WGP to remove approximately 25 yards of soil that has been identified as having arsenic levels that exceed 150 parts per million. The NCRWQB has accepted WGP’s proposal for the soil removal and we are in compliance the NCRWQB’s requirements. The work is scheduled for completion not later than June 2015.

WGP’s ongoing environmental reports include a monthly well report that is filed with the California Department of Oil, Gas and Geothermal Resources and an annual water quality report that is filed with the California Regional Water Board.

The Unit 15 project is in compliance with all environmental permitting, monitoring and reporting requirements and has received no formal or informal notices from any local, state, or federal agency.

Gerlach, El Ceibillo, Crescent Valley, Lee Hot Springs, Ruby Hot Springs, and Vale
No power plant operations are being conducted on these 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 United States. The Raft River Energy I LLC power plant is located in the southeastern part of the State of Idaho. Raft River Unit I 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,
		2014			2013
USG Oregon LLC located in Eastern Oregon	$	18,759,248		$	15,566,409
USG Nevada LLC located in Northwestern Nevada		7,031,445			6,792,382
Raft River Energy I LLC located in Southeastern Idaho		5,178,089			5,012,143
Total energy and energy credits sales	$	30,968,782		$	27,370,934

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Available Information

We file annual, quarterly and periodic reports, proxy statements and other information with the U.S. Securities and Exchange Commission (“SEC”). You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580;Washington D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and other information statements and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the internet at that website.

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 of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Information on our website is not incorporated into this report and is not a part of this report.

Governmental Approvals and Regulations

The geothermal energy industry in the United States is regulated by federal, state and local agencies and commissions. Those agencies and commissions regulate geothermal drilling, power generation activities and environmental protection, permitting, licensing and bonding requirements. The following information is a general summary of the electric utility industry and applicable regulations in the United States and is not a full statement of the law or all issues pertaining to electric industry requirements.

Regulatory oversight of the industry can be broadly divided between rules governing geothermal exploration and rules governing actual energy generation, power sales and delivery. Geothermal fluid production is regulated under federal and state rules and regulations that require permits for drilling operations, geothermal fluid production and injection, and well abandonment. Prior to drilling agencies will review plans and ensure that natural resource values such as air, water, wildlife and vegetation are protected. Geothermal energy generation is regulated under federal, state and local rules and regulations. Permits are required for power plant construction and operation and ensure that a project site is suitable and that natural resource values and community concerns, if any, are evaluated and mitigated during the planning and design phase.

Federal Electric Utility Industry Regulation. Electricity production and public utilities are regulated by both the federal government and state utility commissions. State utility commissions traditionally exercise their jurisdiction over an electric utility’s retail operations. There are two primary pieces of federal legislation that have governed public utilities since the 1930s, the Federal Power Act (“FPA”) and Public Utility Holding Company Act of 1935 (“PUHCA”). These statutes have been amended and supplemented by subsequent legislation, including Public Utility Regulatory Protection Act (“PURPA”), the Energy Policy Act of 1992, and Energy Policy Act of 2005 (“EPAct 2005”).

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Federal Power Act. Pursuant to the FPA the Federal Energy Regulatory Commission (“FERC”) has exclusive jurisdiction over the rates for most wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. FERC's regulations under PURPA exempt owners of small power production Qualifying Facilities that use geothermal resources as their primary source and other Qualifying Facilities that are 30 megawatts or under in size from many provisions of the FPA.

Under the FPA and FERC’s regulations, the wholesale sale of power at market-based or cost-based rates requires that the seller have authorization issued by FERC to sell power at wholesale pursuant to a FERC-accepted rate schedule. FERC grants market-based rate authorization based on several criteria, including a showing that the seller and its affiliates lack market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. All of the Company’s facilities are qualifying facilities and have been granted market-based rate authority to make wholesale sales of electrical energy by FERC. For the Neal Hot Springs power plant, USG Oregon files electronic quarterly reports of the contract and transaction data.

Energy Policy Act of 2005. EPAct 2005 contains provisions to prohibit the manipulation of the electric energy and natural gas markets and increase the ability of FERC to enforce and promote compliance with the statutes, orders, rules, and regulations that FERC administers. To implement the market manipulation provision of EPAct 2005, FERC amended its regulations to prohibit a company, in connection with the purchase or sale of natural gas, electric energy, or transportation or transmission services subject to FERC’s jurisdiction, from (1) using or employing any device, scheme, or artifice to defraud, (2) declaring any untrue statement of a material fact or omitting to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) engaging in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any person. The EPAct 2005 made a number of other changes to laws affecting the regulation of electricity. These include, but are not limited to, giving FERC explicit authority to proscribe and enforce rules governing market transparency, giving FERC authority to oversee and enforce electric reliability standards, requiring FERC to promulgate rules providing for incentive ratemaking to encourage investments that promote transmission reliability and reduce congestion, giving FERC certain siting authority for transmission lines in critical transmission corridors, requiring FERC to promulgate rules granting incentives for transmission owners to join Regional Transmission Organizations, authorizing FERC to require unregulated utilities to provide open access transmission, and ensuring that load serving entities can retain transmission rights necessary to serve native load requirements. EPAct 2005 promulgated PUHCA 2005, which repeals PUHCA 1935, effective as of February 8, 2006.

Public Utility Holding Company Act. Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. However, if a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC under PUHCA 2005. Qualifying Facilities that make only wholesale sales of electricity are not subject to state commissions’ rate, financial, and organizational regulations and, therefore, would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to regulation in that state.

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Our power plants are Qualifying Facilities that make only wholesale sales of electricity and are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The power plants each sell their electrical output under power purchase agreements to electric utilities. The utilities are regulated by their respective state public utilities commissions. Neither USG nor our subsidiaries are considered utility holding companies under FPA, FERC, the EPAct2005, or PUHCA2005 and those regulations have had no direct adverse impact on our ability to develop geothermal resources or deliver power under our contracts.

Geothermal Development Concession in Guatemala. The following summary of certain aspects of the electric industry in Guatemala should not be considered a full statement of the laws of Guatemala or all of the issues pertaining thereto.

In Guatemala, the General Electricity Law of 1996, Decree 93-96, created a wholesale electricity market and established a new regulatory framework for the electricity sector. The law created a regulatory commission, the CNEE, and a new wholesale power market administrator, the AMM, for the regulation and administration of the sector. The AMM is a private not-for-profit entity. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating, supervising, and controlling compliance with the electricity law, overseeing the market and setting rates for transmission services, and distribution to medium and small customers. All distribution companies must supply electricity to such customers pursuant to long-term contracts with electricity generators. Large customers can contract directly with the distribution companies, electricity generators or power marketers, or buy energy in the spot market. Guatemala has approved a Law of Incentives for the Development of Renewable Energy Power plants, Decree 52-2003, in order to promote the development of renewable energy power plants. This law provides certain benefits to companies utilizing renewable energy, including a 10-year exemption from corporate income tax and an import tax exemption for generation equipment, transmission lines and substation equipment. In September 2008, CNEE issued a resolution which approved the Technical Norms for the Connection, Operation, Control and Commercialization of the Renewable Distributed Generation and Self-producers Users with exceeding amounts of energy. This technical norm was created to regulate all aspects of generation, connection, operation, control and commercialization of electric energy produced with renewable sources to promote and facilitate the installation of new generation plants, and to promote the connection of existing generation plants which have exceeding amounts of electric energy for commercialization. It is applicable to projects with a capacity of up to 5 megawatts.

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.

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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 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 that begin construction after December 31, 2014 will not be eligible to use this production tax credit. The federal production tax credit available for geothermal energy in 2014 was 2.3 cents per kilowatt-hour. Alternatively, certain projects under construction before the end of 2014, are eligible to elect to take a 30% ITC in lieu of the PTC. The ITC may be taken after the plant has gone into operation and may be monetized. Both PTC and ITC credits require a tax equity partner to monetize.

The WGP Geysers project, San Emidio II project, and the Crescent Valley project all began construction prior to December 31, 2014, and the Company believes all three projects currently qualify for the 30% ITC in lieu of the PTC.

Renewable Energy Credits. Renewable Energy Certificates, or RECs, are tradable environmental commodities that represent proof that one 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 one 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 megawatt s average over the year). Holy Cross Energy began purchasing the renewable energy credits associated with the RREI 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 RREI 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 PPAs 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.

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 operating revenues. 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:

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	•	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

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•

the completion of exploration and production projects.

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.

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Pursuant to the terms of our leases with the 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.

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. Involving a joint venturer may result in issues related to funding challenges, control issues, and other general disputes. 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:

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

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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.

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.

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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.

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 were 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.

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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;
	•	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 in future PPA contracts. Development of our new plants depends on the prices we are able to negotiate in our long term 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;

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	•	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 PPAs, 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.

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. For example, the El Ceibillo project is located in Guatemala. Our foreign development is subject to regulation by various foreign governments and regulatory authorities and is 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 is 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.

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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.

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 PPAs, will have the right to prematurely terminate the PPA 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 PPAs, the purchaser may have the right to prematurely terminate the PPA 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.

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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.

Payments under our PPAs may be reduced if we are unable to forecast our production adequately. Under the terms of certain of our PPAs, 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 PPAs 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 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 PPAs on terms favorable to us, or at all, it would negatively impact our revenue and our decisions regarding development of additional properties.

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Risks Related to Our Liquidity and Capital Resources

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 and the development of our 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.

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

It is very costly to place geothermal resources into commercial production. Before the sale of any power can occur, it will be necessary to construct a gathering and disposal system, a power plant, and a transmission line, and considerable administrative costs would be incurred, together with the drilling of production and injection wells. Future expansion of power production 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;

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	•	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

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 2014. 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 BLM, 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, and 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 megawatts 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 some of our 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:

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	•	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;
	•	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. The trading price of our common stock on the NYSE MKT LLC (“NYSE MKT”) and on the Toronto Stock Exchange (“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.

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Failure to comply with regulatory requirements may adversely affect our stock price and business. As a public company, we are subject to numerous governmental and stock exchange requirements, with which we believe we are in compliance. The Sarbanes-Oxley Act of 2002 (“SOX”) and 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.

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.

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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.

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 eight different geothermal resource areas in the Western United States and one area in Guatemala, Central America. The resource areas in the United States are located in Idaho (1), Oregon (2), and Nevada (4) and California (1). The properties include the Raft River area located in southeastern Idaho, the two properties located in southeastern Oregon, and six properties in northwestern Nevada, the WGP Geysers area located in northern California at the Geysers, and the El Ceibillo area located in central Guatemala (near Guatemala City). The properties in northwestern Nevada include San Emidio, Gerlach, Crescent Valley, Lee Hot Springs, and Ruby Hot Springs.

The Company operates three commercial power plants located in the Western United States. The Raft River Unit I, Idaho plant became commercially operational on January 3, 2008. The Neal Hot Springs, Oregon plant achieved commercial operation on November 16, 2012. The San Emidio, Nevada plant was acquired in May 2008. The acquired facility was replaced with a new power plant, located on private land that became commercially operational in May 2012.

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WESTERN UNITED STATES 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 (net) annual average geothermal power plant was developed by USG Oregon LLC, and is currently in operation at this site. The project has four production wells and nine injection at the project.

Significant Lease/Royalty Terms

Approximately 521 acres of geothermal rights at Neal Hot Springs are owned by Cyprus Gold Exploration Corporation (50%), JR Land and Livestock (25%), and USG Oregon LLC (25%). Royalty for the two private leases is paid on the gross revenue from energy sales paid by Idaho Power Company under the PPA. The JR Land & Livestock lease has a 3% royalty for the first five years of production, increases to 4% for years 6-15, and then to 5% for the remainder of the lease term. The Cyprus lease establishes a 2% royalty for the first ten years and then escalates to 3% for the remainder of the lease.

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San Emidio, Nevada

In 2008, the Company acquired a 3.6 megawatt operating geothermal power plant and all associated private and federal geothermal leases and certain ground water rights in the San Emidio Valley and at Gerlach, Nevada. The San Emidio project is located approximately 75 air miles north of Reno, Nevada. The Gerlach property is locate immediately northwest of Gerlach Nevada. The San Emidio assets include the geothermal power project, 17,846 (27.9 square miles) acres of geothermal leases, and ground water rights used for cooling water. The Gerlach assets include 2,986 acres (4.7 square miles) of BLM and private geothermal leases. The Gerlach leases are located along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser.

In 2012, USG completed the San Emidio Phase I repower project; a 9.0 megawatt (net) annual average facility located on private land owned by USG Nevada. Phase I repowering was completed utilizing the existing production and injection wells.

Significant Lease/Royalty Terms

A geothermal unit was established for the operating project by the Company in 2010 with the approval and oversight of the Bureau of Land Management. The Unit allows USG Nevada LLC to allocate expenses among the federal and private geothermal leases within the Unit and legally establishes the percentage of private and federal land that contributes to geothermal production known as the Participating Area. The Participating Area at San Emidio totals 583.68 acres and includes 336.93 acres (57.7%) of private property and 246.75 acres (42.3%) of federally managed land.

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The lease agreement with the Kosmos Company establishes a 1.75% royalty on gross electricity sales for the first 120 months of production and 3.5% royalty thereafter. The federal leases have a 10% netback royalty. The netback calculation is based on gross electricity sales less the transmission and generation cost deductions. In 2014 the equivalent federal royalty is 1.6% of gross electricity sales.

Raft River, Idaho

The Raft River project comprises two packages of property that include the Raft River Energy I LLC (“RREI”) leases, and leases held by the Company. RREI operates the Unit I facility at Raft River which became commercially operational on January 3, 2008. Leases assigned to RREI by the Company includes eight private geothermal leases, one of which is owned by the Company. The Company retains direct control over four private leases and one federal lease outside the RREI position.

All of the leases may be extended indefinitely as long as production is maintained from the lease either individually or as a geothermal unit. The Company and RREI hold a total of 6,002 acres; 1,686 acres of federal geothermal rights and 4,316 acres of private leases.

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Significant Lease/Royalty Terms

The private leases have 10 year primary terms with the rights of unitization and extensions. Private leases have varying royalty rates commensurate with other federal and private leases held by the Company and our subsidiaries. Most of the private leases are subject to a 10% netback royalty which is based on gross electricity sales less the transmission and generation cost deductions. In 2014, USG’s equivalent federal netback royalty was equivalent to 1.6% of gross electricity sales where it was applied.

The federal lease, established on August 1, 2007, is held by the Company and 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 royalty under the lease is 1.75% of gross proceeds for the first 10 years of production and 3.5% thereafter. At Raft River, royalty rates have not exceeded rental payments. As a result leases are held through rental payment.

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El Ceibillo, Republic of Guatemala

The Company successfully acquired a geothermal energy rights concession in the Republic of Guatemala. The concession, granted by the Guatemalan government, consists of 24,710 acres (100 square kilometers) and is located 14 miles southwest of Guatemala City, the capital. The concession has a five year term for the development and construction of a power plant and there are no royalties due to the government. The El Ceibillo project, is located near the town of Amatitlan, in a developed industrial zone immediately adjacent to the highway that connects Guatemala City to the Port of San Jose on the Pacific coast. An office and staff are located in Guatemala City, and 17 acres of surface has been under lease. An additional surface lease of 80 acres was signed on October 15, 2014, bringing the total surface leasehold interest to 97 acres.

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Crescent Valley and Lee Hot Springs, Nevada

On December 16, 2014, U.S. Geothermal completed the acquisition of EPR and EPR’s lease holdings at Crescent Valley and Lee Hot Springs, Nevada.

The Crescent Valley property encompasses 21,319 acres of private and federal geothermal resources leased by EPR and 2,640 acres of geothermal resources leased by U.S. Geothermal Inc. Upon closing the acquisition the Company began drilling the projects first production well. The well is located on private surface and mineral estate in section 3, Township 28 North Range 49 East and is intended to qualify potential future power plant construction for the 30% renewable energy investment tax credit. The Crescent Valley property includes 55 independent leases ranging in size from 10 acres to 4,100 acres and an average parcel size of 314 acres. EPR’s private leases have a 15 year term with annual rent that escalates at year five and at year 10.

Significant Lease/Royalty Terms

Annual lease rental payment obligations at Crescent Valley are approximately $109,138 and royalty obligations during potential future power production vary for private leases from 3% to 5% of gross sales. Royalty rates for federal geothermal leases are 1.75% of gross revenue for the first 10 years and 3.5% thereafter.

The Lee Hot Springs property encompasses 2,560 acres of federal lands located approximately 17 miles south of Fallon, NV. The federal leases are N-73679 and N-73930. The annual rental is $2,560 and a standard federal royalty is 1.75% of gross revenue for the first 10 years and 3.5% thereafter.

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WGP Geysers, California

Western GeoPower Inc. (“WGP”) is a wholly owned subsidiary of U.S. Geothermal Inc. WGP’s Unit 15 property includes surface and geothermal rights that consist of two federal geothermal leases (CA-51000 & CA-51001), and two private geothermal leases with no expiration. The total project acreage is 3,808 acres. The site is permitted with Sonoma County for construction and operation of up to a 38.5 megawatt geothermal power plant.

The project is located at the site of the former Pacific Gas and Electric (PG&E) Unit 15 project, which once had a 62 megawatt (gross) capacity power plant. During 10 years of operation, the PG&E plant declined in production to approximately 38 megawatts before it was shut down in l989 and all of the wells were plugged and abandoned. The project is located within the broader Geysers geothermal field which covers a total of approximately 20,000 acres in the Mayacamas Mountains in Sonoma County, California, approximately 75 miles north of San Francisco. The Geysers geothermal resource is the largest producing geothermal field in the world, and has been generating greater than 850 megawatts of power for more than 30 years.

Significant Lease/Royalty Terms

There is no annual rental or prepaid royalty for the 421 acre parcel private land owned by WGP. The Abril Ranch rental payment for 410 acres of surface and geothermal rights was $16,783 in 2014 and is annually adjusted by the San Francisco/San Jose CPI index then divided between 3 surface owners based on a 50-25-25 basis. The Filly-Brown Lease includes 214 acres of surface access rights and 50% of the mineral rights; the remaining 50% mineral interest is owned by Western GeoPower. The Filly-Brown lease rental totals $260,000 annually but has no expiration or renewal date. Geothermal royalty payments for Abril Ranch and Filley-Brown are calculated on a sliding scale to account for the final contracted electricity price established by a power purchase agreement.

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Vale Butte, Oregon

Vale Butte and the Vale Butte Geothermal Resource Area is located in Eastern Oregon and borders the east side of the City of Vale. In the first quarter of 2014, U.S. Geothermal Inc. acquired 393 acres of geothermal energy and surface rights under six (6) leases. The leased area is immediately adjacent to the City of Vale and includes private surface and mineral estate, Vale City owned resources and Malheur County owned resources. The Vale Butte resource area has been used for direct use heating for many years. Geochemical analysis indicates a potential reservoir temperature of 311F to 320F and historical drilling in the area has encountered ground (rock) temperatures in excess of 300F. Fault structures and hydrologic characteristics have been identified that are similar to the Neal Hot Springs site, and those geologic structures are contained within the newly acquired leases.

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Significant Lease/Royalty Terms

Four private leases and the Vale City lease are issued for a period of 10 years with renewal options while the Malheur County lease was issued for a period of 40 years with renewal options. The lease agreements are consistent in terms of financial and development requirements and have a 2% royalty payment on actual energy paid for by Idaho Power for the first 10 years of commercial production.

Boise Administration Office, Idaho

On August 12, 2013, the Company signed a five 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 five year extension option.

Land and Leases

The Company and its domestic subsidiaries control 65,434 acres of land in California, Idaho, Nevada, and Oregon. U.S. Geothermal owns approximately 1,370 acres while approximately 64,064 acres are controlled through geothermal development leases signed with the BLM, local governmental entities and private owners. The company’s average per acre lease rate is $9.00 per acre/year.

BLM Leases

The Company and its subsidiaries have 28 federal geothermal leases issued in accordance with the Geothermal Steam Act by the BLM.

BLM geothermal leases grant the lessee the right to drill for, extract, produce, remove, utilize, sell, and dispose of geothermal resources from the leased lands, along with the right to build and maintain necessary improvements on the leased land. Ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease grants exclusive geothermal development rights. The BLM will, through authority granted by federal regulations and planning requirements, ensure that other federal activities do not unreasonably interfere with the geothermal lessee’s uses of the same land. Most federal leases include stipulations and are governed by federal regulations, that require geothermal development to be conducted in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all actions required by the BLM to protect the surface of and the environment surrounding the land. Surface protections and environmental protection requirements include protection of water quality, cultural and archeological resources, threatened or endangered plants or animals, migratory birds, wildlife, and visual quality standards.

The BLM also authorizes geothermal lessees to enter into unit agreements to cooperatively develop a geothermal resource. The BLM reserves the right to specify rates of development and to require the geothermal lessee to commit to a unitization agreement.

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Typical BLM leases issued to geothermal lessees have a primary term of ten years and may be renewed as long as geothermal resources are being explored. If resources are produced or utilized in commercial quantities, the lease can be renewed for up to forty years. If at the end of the forty-year period geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for a second forty-year term, under terms and conditions as the BLM deems appropriate. During the lease term the lessee is required to pay an annual per acre rental fee. The fee escalates according to a schedule until geothermal production begins. After production has commenced, the geothermal lessee is required to pay royalties on the amount or value of energy production, and any by-products that may be derived from geothermal production.

BLM leases issued after August 8, 2005 (The Energy Policy Act of 2005) also have a primary term of ten years. If the geothermal lessee does not reach commercial production within the primary term, the BLM may grant two five-year extensions. If the lessee is drilling a well for the purposes of commercial production, the lease may be extended for five years and thereafter as long as steam is being produced and used in commercial quantities the lease may be extended for up to thirty-five years. If, at the end of the extended thirty-five year term, geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease under terms and conditions as the BLM deems appropriate.

BLM leases are issued either competitively or non-competitively. Under the Energy Policy Act of 2005 Lessees who obtain leases issued through a non-competitive process pay an annual rental fee equal to $1.00 per acre for the first ten years and $5.00 per acre each year thereafter. Lessees who obtain a lease through a competitive bid process pay a rental of $2.00 per acre for the first year, $3.00 per acre for the second through tenth year and $5.00 per acre each year thereafter. For BLM leases issued, effective, or pending on August 8, 2005, royalty rates are fixed between 1.0 -2.5% of the gross proceeds from the sale of electricity during the first ten years of production under the lease.

The royalty rate set by the BLM for geothermal resources produced for the commercial generation of electricity but not sold in an arm’s length transaction is 1.75% for the first ten years of production and 3.5% thereafter. The royalty rate for geothermal resources sold by the geothermal lessee or an affiliate in an arm’s length transaction is 10.0% of the gross proceeds from the arm’s length sale.

Private Geothermal Leases

U.S. Geothermal and its subsidiaries hold 70 geothermal leases with private parties. The leases authorize the right to conduct geothermal development and operations on privately owned geothermal estate. In some cases, the surface ownership is split from the mineral or geothermal ownership.

Geothermal leases grant the exclusive right and privilege to drill for, produce, extract, take and remove water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted through geothermal development. The Company and its project subsidiaries are also granted non-exclusive rights pertaining to the construction and operation of plants, structures, and facilities on the leased land. The leases also grant the right to dispose of waste brine and other waste products as well as the right to re-inject into the leased land water, brine, steam, and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity.

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Lessors reserve the right to conduct other activities on the leased land in a manner that does not unreasonably interfere with the geothermal lessee’s uses of the same land. Activities include agricultural use (farming or grazing), recreational use and other energy developments. Geothermal leases are typically issued for a primary term of 10 years and continue for as long as leased products are being produced or the lessee is drilling, exploring, extracting, processing, or reworking operations on the leased land.

Lease payments typically include annual rental that is based on a rate per acre under lease and royalty payments on gross revenue from the generation of electricity. Leases also include a provision for royalty payment on all revenue from geothermal by-products. Leases typically have requirements for drilling, extraction or processing operations on the leased land within the primary term or to conduct operations with reasonable diligence until lease products have been found, extracted and processed in quantities deemed “paying quantities” by the lessee. The lessee has the right at any time within the primary term to terminate the lease and surrender the relevant land. If the lessee has not commenced operations on leased land within the primary term, the annual rentals typically increase. The purpose of the increasing annual rental is to encourage development which, in some cases may generate higher payment to the lessor in the form of monthly royalty.

Our leases typically require the lessee to carry insurance, conduct operations in accordance with all local, state, and federal regulations, prevent waste, protect environmental quality, and promptly address any default by lessee. The lessor and lessee are protected from automatic lease termination through a notice requirement which must be received by the lessee by certified mail, and a 30 day period in which the lessee must make diligent efforts to correct the alleged default.

Geothermal Development Concession in Guatemala

U.S. Geothermal Guatemala S.A. has acquired a 24,700 acre geothermal concession from the Ministry of Energy and Mines Guatemala C.A. The site is located 12.5 miles southwest of Guatemala City and 2.5 miles west southwest of the City of Amatitlan. The geothermal concession grants the rights for subsurface geothermal development, establishes milestones for development and production. The Company has negotiated and acquired surface access from two owners and control 115 surface acres enabling geothermal development. The leases are similar in term and conditions to our leases with private owners in the United States.

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Item 3. Legal Proceedings

As of March 16, 2015, 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

The following table sets forth information relating to the trading of our common stock from January 1, 2013 through December 31, 2014 for the Company’s common stock trading on the NYSE MKT, under the trade symbol “HTM”:

TSX

The following table sets forth information relating to the trading of our common stock from January 1, 2013 through December 31, 2014 for the Company’s common stock trading on the TSX under the trade symbol “GTH”:

As of March 6, 2015, we had approximately 17,000 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 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.

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On December 12, 2014, the Company completed the acquisition of EPR for a total of six hundred ninety-two thousand seven hundred sixty-nine (692,769) shares of our stock that were issued in exchange for all outstanding shares of EPR stock. The shares issued by the Company in connection with the acquisition were offered and sold in reliance upon the exemption from registration provided by Section 4(a)(2) under the Securities Act of 1933, as amended (the “Securities Act”). The basis for relying on this exemption is that the issuance of common stock to the shareholders as consideration for the merger, was a privately negotiated transaction without general solicitation. The certificates representing the shares of common stock issued in the merger contain a legend to the effect that such shares are not registered under the Securities Act and may not be transferred except pursuant to a registration statement that has become effective under the Securities Act or pursuant to an exemption from such registration.

Item 6. Selected Financial Data

(1)

Long-term obligations represent the stock compensation payable, a convertible loan, plant 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, 2014, 2013 and 2012, long-term obligations did not include stock compensation payable.

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

Historical Overview

On March 5, 2002, U.S. Geothermal Inc. - Idaho entered into a letter agreement with the owner of the Raft River project located in southeastern Idaho, pursuant to which U.S. Geothermal Inc. - 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 PPA with Idaho Power on December 29, 2004 to sell 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 approximately 9.4 megawatt net, but has held steady at that level for two years.

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In May 2008, the Company acquired geothermal assets, including an old 3.6 net megawatt nameplate generating capacity power plant, located in Washoe County, Nevada for approximately $16.6 million, which included certain ground water rights. The upgraded, new 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 10.0 megawatts due to higher than expected efficiency. On February 15, 2013, USG Nevada LLC signed an agreement with SAIC as part of a settlement, for a $2,000,000 note that will be paid in quarterly installments that are scheduled through 2018. A long-term note held by Prudential Financial Group was finalized on September 26, 2013. The Prudential loan will be repaid with quarterly payments that are scheduled through 2037.

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 began on the first full size production well which was completed on May 23, 2009. In February 2009, the Company submitted a loan 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 of a drill pad was completed in August 2009. In September 2009, the Company began drilling its major production well. Enbridge Inc. became an equity partner in the project in April 2009. Equity ownership interest in the project has the Company owning 60%, and Enbridge owning 40%. The power plant became commercially operational on November 16, 2012.

In April 2010, the Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America. The Company signed a Memorandum of Understanding with a broker of electricity in Central America to negotiate a PPA 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 early 2018.

On April 22, 2014, the Company acquired all of the ownership shares of a group of companies owned by Ram Power Corp.’s (“Ram”) that hold all interests in the WGP Geysers project located in Northern California for a total of $6.78 million. The assets acquired included four production/injection wells, restricted cash, land and geothermal water rights.

The Company completed an acquisition of Earth Power Resources Inc. (“EPR”) on December 12, 2014. Acquired assets include geothermal leases that cover 26,017 acres in the State of Nevada representing three potential projects (Crescent Valley, Lee Hot Springs and Ruby Hot Springs).

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Factors Affecting Our Results of Operations

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 than initially anticipated. If insufficient cash is generated to satisfy all joint venture obligations, the management fees will be deferred.

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

Based on management’s annual review of 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.

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

(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

Prior to the construction of a geothermal project, we typically enter into a PPA with a utility, which fixes the price of energy produced at a project for a 20 to 25 year period. Such PPAs are typically negotiated with the utility company and approved by a state utility commission or similar regulating body.

Power purchase agreements generally provide for 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 annual adjustments. 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 PPAs provide for bonus payments in the event that the producer is able to exceed certain target levels and forfeiture of payments or payments of penalties if minimum target levels are not met.

Neal Hot Springs, Oregon

The PPA 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.

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 one 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.

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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. 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 (March, April, May) 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.

Operating Results

For the year ended December 31 2014, the Company reported net income attributable to the Company of $11,616,504 ($0.11 income per share) which represented a $10,942,075 increase from net income of $1,946,579 reported in the year ended 2013 ($0.02 income per share). Net income of $15,025,922 from plant operations for the year ended December 31, 2014 increased $1,814,010 (13.7% increase) from income of $13,211,912 reported in the year ended 2013. Other notable favorable variances were reported in professional and management fees, salaries and wages, and change in deferred income taxes. Notable unfavorable variances were reported in stock based compensation, interest expense and other income/expenses.

Plant Operations

During the years ended December 31, 2014 and 2013, the Company’s energy production revenues and related operating costs originated from its three fully operational 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.

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

		For the Year Ended December 31,
		2014						2013
		$			%*			$			%*
Energy sales by plant:
Neal Hot Spring, Oregon		18,759,248			61.3			15,566,409			57.7
San Emidio, Nevada		7,031,445			23.0			6,792,382			25.2
Raft River, Idaho		4,805,568			15.7			4,627,258			17.1
		30,596,261			100.0			26,986,049			100.0

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

A quarterly summary of megawatt hours generated by plant are as follows:

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. For the year ended December 31, 2014, the plant reported net profit of $9,826,233 which was an increase of $2,396,997 (32.3% increase) from the net profit of $7,417,135 reported in the year ended 2013. For the year ended December 31, 2014, plant energy revenues increased 20.5% from the prior year ended 2013. The total of 183,394 megawatt hours produced in the current year increased 27,965 megawatt hours (18.0% increase) from the 155,428 megawatt hours produced in the prior year. The quarters ended March 31, 2014 and December 31, 2014, were the highest quarters of energy production and revenue to date. High production was due to less down time and the greater efficiency of the cooling towers due to the cooler ambient temperatures of the fall/winter months. For the third quarter of 2013, the plant's three units experienced a total of 928 hours of lost production which was significantly greater than the 59 hours of lost production in the third quarter of 2014. The largest loss in third quarter of 2013 was due to the failure of the refrigerant pump at unit one (618 hours). In the fourth quarter of 2013, the plant lost a total of 316 hours primarily due to stoppages caused by low liquid levels in the condenser. In the fourth quarter of 2014, the three units only experienced a total loss of approximately 70 hours.

Plant operating costs, excluding depreciation, increased $693,972, which was a 22.3% increase from the prior year to the current year ended September 30, 2014. The largest variances were noted in administrative support, insurance, chemicals and plant/well field maintenance costs. For the year ended December 31, 2014 administrative and corporate support costs increased $156,519, which was a 21.4% increase from the year ended 2013. Effective for the current year, a contracted monthly corporate support fee of $13,750 was established. Also, additional consulting fees related to the general plant maintenance that amounted to over $57,000 were incurred for the year ended December 31, 2014.

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For the year ended December 31, 2014, the plant’s insurance costs totaled $377,619 which was an increase of $152,163 (67.5% increase) from the year ended 2013. In July 2013, the plant’s insurance coverage transferred from a builders’ risk policy to a full property coverage policy which resulted in a significant increase in cost (approximately $31,660 increase per month). In May of 2014, an insurance rate adjustment was made that reduced premiums by approximately 20% (approximately $14,345 decrease per month).

Plant and field maintenance costs increased $219,544, which was a 43.7% increase for the year ended December 31, 2014 from the year ended 2013. In May 2014, a turbine seal was replaced at a cost of $62,298. In the third quarter of 2014, costs that exceeded $169,000 were incurred to repair a feed pump for Unit 1, repair piping modules for all three units, and rebuild a seal for Unit 2.

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

%* - represents the percentage of total plant operating revenues.
%** - represents the percentage of change from 2013 to 2014. 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.

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

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

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

San Emidio, Nevada Plant Energy Sales and Plant Operating Expenses (USG Nevada LLC)

For the year ended December 31, 2014, the San Emidio plant reported net profit of $487,793 which was a decrease of $670,845 (57.9% decrease) from the net profit of $1,158,638 reported in the year ended 2013. For the current year, both energy revenues and megawatt hours produced were consistent with the prior year ended 2013. Total megawatts produced in the current year increased to 76,894 megawatt hours from 76,697 megawatt hours (0.3% increase). The average rate earned per megawatt hour in the current year increased to $91.4 from $88.7 (3.1% increase) earned in the prior year. For the year ended December 31, 2014, operating expenses, excluding depreciation, increased $720,836 (28.8% increase) from the year ended 2013. The primary reason for the increase related to property tax expenses and related legal costs, which increased approximately $393,197. In the prior year ended December 31, 2013, the Company collected a property tax refund of $226,859 related to an error made in 2012. Additional repair costs were incurred in the current year that included turbine repairs and tuning, two pump motor replacements and control panel upgrades for costs that exceeded $36,100, $35,200 and $16,480; respectively. Also, chemical costs for the cooling system increased approximately $108,110 (138.1% increase) from the prior year due to both price increases and lost product due, in part, to an acid pump malfunction.

For the year ended December 31, 2014, the plant’s interest expense increased $318,720 (18.3% increase) from the year ended 2013. During the quarter ended March 31, 2013, the plant loan had not been finalized and most of the interest incurred under the contractor’s obligations was capitalized. In the quarter ended March 31, 2013, the plant incurred interest costs that totaled $621,712.

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

%* - represents the percentage of total plant operating revenues.
%** - represents the percentage of change from 2013 to 2014. 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.

The intercompany elimination adjustments for management fees and corporate support 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:

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

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Raft River, Idaho Unit I (Raft River Energy I LLC) Plant Operations

Net loss from Raft River Energy I LLC (“RREI”) operations of $197,125 for the year ended December 31, 2014 favorably decreased by $197,732 from the loss of $394,847 reported for the year ended 2013. For the current year, both energy revenues ($4,805,568) and megawatt hours produced (78,798 megawatt hours) were consistent with the prior year ended 2013. For the year ended December 31, 2014, the megawatt hours produced increased 1,238 (1.6% increase) from the year ended 2013. Depreciation costs decreased 6.9% from the prior year primarily due to many of the assets with shorter estimated useful lives (5 years or less) that were placed into operation during the initial years of production have been fully depreciated.

The summarized statements of operations for RREI are as follows:

%* - represents the percentage of total plant operating revenues.
%** - represents the percentage of change from 2013 to 2014. 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.

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

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Key quarterly production data for RREI is summarized as follows:

* - 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, 2014, the Company incurred professional and management fees of $986,742, which was a decrease of $298,194 (23.2% decrease) from the year ended 2013. The two primary elements for the decrease were the consulting fees paid to the former CEO and the decreases in legal fees. In May 2013, the Company entered into a contract with the former CEO’s consulting firm. The original contract ended April 2014, and was extended through December 2014 at a reduced rate of $1,000 per month. During the current year, consulting fees were paid to the former CEO’s consulting firm totaled $60,161, which was a decrease of $161,120 (72.8% decrease) from the fees paid in 2013. During the year ended December 31, 2014, legal fees were paid to the Company’s primary legal counsel of $93,782, which was a decrease of $121,877 (56.5% decrease) from the fees paid in 2013. In the prior year, additional legal fees were incurred for negotiations and contract reviews concerning the employment agreements for both the prior and successor Chief Executive Officers. Also, legal fees were incurred related to capital raise that was completed in December 2012.

Salaries and Wages

Salaries and wages include payroll and related costs incurred for exploration, design and development costs that cannot be capitalized, as well as general management and administration. Payroll and related costs for plant operations are expensed as plant production costs. For the year ended December 31 2014, the Company reported $1,858,423 in salaries and related costs, which was a decrease of $277,522 (13.0% decrease) from the year ended 2013. Salaries and related costs for administration and development employees before allocations totaled $2,595,439, which was an increase 1.5% from the year ended 2013. In the year current year, allocations for capital projects and plant operations exceeded $499,000 and $452,000; respectively. For the prior year, allocations for capital projects and plant operations exceeded $723,000 and $13,000; respectively. The two projects that utilized management and development staff resources in the current year were the San Emidio Phase II, Nevada and Guatemala projects, which incurred management and development salary costs of approximately $120,400 and $125,100; respectively. In the prior year, the major project was Neal Hot Springs, Oregon. In April 2014, the Company awarded raises to its employees that averaged 2.9%, and bonuses were awarded that totaled $376,750. In April 2013 and July 2013, employee bonuses were awarded that totaled $171,000 and $237,800; respectively.

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Stock Based Compensation

For the year ended December 31 2014, the Company reported $1,339,496 in stock based compensation, which was an increase of $582,561 (77.0% increase) from the year ended 2013. Stock based compensation includes the calculated values for both Company stock and stock options granted to employees and board members. The Company uses the Black-Scholes option-pricing model to value the cost of the outstanding stock options. The higher value of the stock options for the current year was directly impacted by the number of outstanding options, the increase in the Company’s stock price and the related increase in the volatility of the Company’s stock price. On April 2, 2014, the Company awarded employees 2,883,500 stock options and 559,122 shares (restricted shares). In the prior year, the Company did not issue stock options to employees until July 22, 2013 (1,950,000 options, no restricted shares to employees). During the current year ended December 31, 2014, the Company’s common stock price reached a high of $0.95 and a low of $0.38 ($0.59 average daily closing price). During the year ended December 31, 2013, the Company’s common stock price reached a high of $0.59 and a low of $0.31 ($0.40 average daily closing price).

The stock based compensation components are summarized as follows:

		For the Year Ended
		December 31,
		2014			2013			Variances
		$			$			$			%
Total Stock Based Compensation:
Stock option compensation		1,115,392			683,443			431,949			63.2
Stock compensation		224,104			73,492			150,612			204.9
		1,339,496			756,935			582,561			77.0

% - represents the percentage of change from 2013 to 2014.

Exploration

For the year ended December 31, 2014, the Company reported $508,500 in exploration costs, which was an increase of $469,018 from the year ended 2013. During the current year, the Company incurred costs of $432,705 on well drilling activities for the Gerlach, Nevada project.

Other Income/Expenses

For the year ended December 31, 2014, the Company reported a net loss of $346,588 in other income/expenses which was an unfavorable increase of $462,453 from the net gain reported the year ended 2013. In the fourth quarter of 2014, the Company abandoned the Granite Creek area located in the State of Nevada, and is in the process of disposing the 2,445 acres of geothermal water rights purchased in April 2008 for $451,299.

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Change in Deferred Income Tax Assets and Liabilities

For the year ended December 31, 2014, the Company reported an increase in deferred income tax assets and liabilities of $12,060,000 which was an increase of $10,482,000 from the year ended 2013. At the end of the current year, the Company determined that the more likely than not threshold had been met regarding the Company’s ability to use its earned deferred income tax assets (primarily unused net operating losses). Prior to December 31, 2014, the Company only recognized net deferred income tax assets to the extent used for reported book income.

Net Income Attributable to the Non-Controlling Interests

The net income 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 partners. For the year ended December 31, 2014, the Company reported $3,277,793 in net income attributable to non-controlling interests, which was an increase of $1,093,723 (32.5% increase) from net income of $2,184,070 for the year ended 2013. 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 $9,826,233 for the year ended December 31, 2014. The impact of the Neal Hot Springs operations on the Company’s reported income attributable to non-controlling entities was an increase of $963,640 (32.5% increase) from the year ended December 31, 2013 as compared to the current year ended 2014.

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		2014			2013			Variance
Interest Entities		$			$			$			%
Oregon USG Holdings LLC interest held by Enbridge Inc.		(3,915,952)			(2,848,081)			1,067,871			37.5
Raft River Energy I LLC interest held by Raft River I Holdings, LLC		452,193			656,469			204,276			31.1
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC		181,173			7,542			(173,631)			#
		(3,282,586)			(2,184,070)			1,098,516			50.3

% - represents the percentage of change from 2013 to 2014. # - variance percentage that is extremely high or undefined.

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Non-Controlling Interests

The following is a summarized presentation of select financial line items from the statement of operations by project and the impact of the related non-controlling interests for the year ended December 31, 2014:

(1)	The non-controlling interests for Neal Hot Springs represents a 40% interest for our joint venture partner, Enbridge.
(2)	The non-controlling interests for Raft River represents 30% of REC income and 99% of all other income/expenses for Raft River I Holdings, a subsidiary of Goldman Sachs Group.
(3)	The non-controlling interests for our exploration activities represents an approximately 39% interest for our joint venture partner at Gerlach, GGE Development.
(4)	Major costs included in Exploration Activities and Corporate for the year ended December 31, 2014 include:

	•	Salaries and wages		$ 1,858,423
	•	Stock based compensation		1,339,496
	•	Corporate administration		1,136,849
	•	Professional fees		986,742
	•	Exploration costs		508,500

These costs are the responsibility of U.S. Geothermal Inc. (the Parent Company) and cannot be allocated to projects. Once a project has been classified as developmental (resource verified, PPA off-taker identified), the costs associated with a project will be capitalized.

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Liquidity and Capital Resources

During the calendar year ended December 31, 2014, the operating projects of U.S. Geothermal have generated significant available cash (after debt service and reserves) to fund our development activities and corporate costs. Neal Hot Springs has distributed $7.2 million in equity; San Emidio has generated $1.4 million in net cash; Raft River has paid $0.2 million in REC income. In addition, cash received by corporate as a result of management fees, royalties and lease income totaled $1.1 million. We believe our cash and liquid investments at December 31, 2014 are adequate to fund our general operating activities through December 31, 2015. Development of our projects under development and under exploration 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 Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels.

The recent financial credit crisis has not impacted the ability of our customers, Idaho Power Company and Sierra Pacific Power (NV Energy), 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 we seek to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities.

On December 12, 2014, the Company completed the acquisition of Earth Power Resources Inc. (“EPR”) for a total of six hundred ninety-two thousand seven hundred sixty-nine (692,769) shares of U.S. Geothermal stock that were issued in exchange for all outstanding shares of EPR stock. In addition to the shares issued, $42,934 in cash was also provided at close to allow EPR to pay outstanding obligations. The transaction was unanimously approved by EPR Shareholders. The assets acquired from EPR include geothermal leases covering 26,017 acres in Nevada, representing three projects that have an energy potential estimated in the range of 158 to 359 megawatts. Also included is EPR’s complete geothermal resource database of new project opportunities located throughout the western United States, which EPR had compiled over its nearly 40 years of geothermal exploration experience. Under the terms of the agreement, fifty percent (50%) of the new stock issued for the acquisition will be held in reserve by the Company for 6 months to cover any potential undisclosed claims against EPR. The non-reserved 50% of new stock will be delivered to the EPR shareholders upon surrender of their EPR share certificates, but trading of the new USG shares is restricted under SEC Rule 144 for a period of 6 months

On April 21, 2014, the Company completed the acquisition of Ram Power Corp.’s (“Ram”) Geysers project for a total of $6.4 million in cash. The Ram subsidiaries included in the acquisition are Western GeoPower, Inc., Skyline Geothermal Holding, Inc., and Etoile Holdings Inc., which in turn includes all membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The acquired Ram subsidiaries possess the full development interest in the project. These interests include all geothermal leases (covering 3,809 acres), development design plans, and permits for a proposed up to 38.5gross megawatt power plant, and includes land and geothermal mineral rights ownership of the Mayacamas property purchased by Ram in 2010. This property contains four existing geothermal wells immediately available for production or injection and one historic well available for use after reworking. Finally, the acquisition includes a 50% undivided interest in the geothermal mineral rights relating to the property that contains the 5th existing well also purchased by Ram in 2010. The other 50% interest in this property is contained within an acquired leasehold interest.

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On February 4, 2014, a replacement shelf registration statement filed on Form S-3 with the SEC became effective. 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. 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 acquisition 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 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 was $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. U.S. Geothermal’s share of the distribution received August 19, 2014 was $2.6 million, out of a total distribution to the partners of $4.3 million.

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. On December 31, 2014, $16.7 million in USG Oregon LLC funds were deposited at PNC Bank, and were unavailable for immediate corporate needs.

For projects under construction before the end of 2010 and online before the end of 2014, a project was eligible to take a 30% ITC in lieu of the 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.

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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) in November 2013.

On May 21, 2012, the Company entered into a purchase agreement (the “Purchase Agreement”) with Lincoln Park Capital Fund, LLC (“LPC”), pursuant to which the Company has the right to sell to LPC up to $10,750,000 in shares of the Company’s common stock, (“Common Stock”), subject to certain limitations and conditions set forth in the Purchase Agreement and imposed by the Company’s board of directors and pricing committee thereof. Pursuant to the Purchase Agreement LPC initially purchased $750,000 in shares of Common Stock at $0.38 per share. Following this initial purchase, on any business day and as often as every other business day over the 36-month term of the Purchase Agreement, and up to an aggregate amount of an additional $10,000,000 (subject to certain limitations) in shares of Common Stock, the Company has the right, from time to time, at its sole discretion and subject to certain conditions to direct LPC to purchase up to 250,000 shares of Common Stock, which amount may be increased in accordance with the Purchase Agreement if the closing sale price of Common Stock on the NYSE MKT exceeds certain specified levels. The purchase price of shares of Common Stock pursuant to the Purchase Agreement will be based on prevailing market prices of Common Stock at the time of sales without any fixed discount, and the Company will control the timing and amount of any sales of Common Stock to LPC. No sales of Common Stock under the Purchase Agreement will be made through the TSX. The Purchase Agreement contains customary representations, warranties and agreements of the Company and LPC, limitations and conditions to completing future sale transactions, indemnification rights and other obligations of the parties. There is no upper limit on the price per share that LPC could be obligated to pay for Common Stock under the Purchase Agreement. LPC shall not have the right or the obligation to purchase any shares of Common Stock if the purchase price of those shares, determined as set forth in the Purchase Agreement, would be below $0.25 per share. The Company has the right to terminate the Purchase Agreement at any time, at no cost or penalty. Actual sales of shares of Common Stock to LPC under the Purchase Agreement will depend on a variety of factors to be determined by the Company from time to time, including (among others) market conditions, the trading price of the Common Stock and determinations by the Company as to available and appropriate sources of funding for the Company and its operations. As consideration for entering into the Purchase Agreement, the Company has issued to LPC 651,819 shares of Common Stock. The Company will not receive any cash proceeds from the issuance of these 651,819 shares. As of December 31, 2014, 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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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. 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 the first years 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.

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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, 2014, the following table denotes contractual obligations by payments due for each period:

(1)	Plant loan with Prudential Capital Group scheduled for to be repaid over the next 24 years.
(2)	Plant 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 five years.
(4)	Three auto loans to be repaid in five years.

Off Balance Sheet Arrangements

As of December 31, 2014, the Company does not have any off balance sheet arrangements.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Risk on Investments
At December 31, 2014, the Company held investments of $30,515,067 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 PPAs 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, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

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

We have audited the accompanying consolidated balance sheets of U.S. Geothermal, Inc. as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the periods 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 audit 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, 2014 and 2013, and the results of its operations and its cash flows for each of the periods then ended, in conformity with accounting principles generally accepted in the United States of America.

MartinelliMick PLLC
Spokane, WA
March 13, 2015

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U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS

		December 31,
		2014			2013
ASSETS
Current:
Cash and cash equivalents (note 2)	$	12,994,975		$	28,736,934
Restricted cash and bonds (note 3)		3,320,781			3,081,020
Trade accounts receivable		3,774,133			4,106,806
Deferred income tax asset (note 7)		1,803,000			-
Other current assets		1,550,359			1,079,262
Total current assets		23,443,248			37,004,022
Investment in equity securities (note 4)		-			42,174
Restricted cash and bond reserves (note 3)		18,690,096			18,815,145
Property, plant and equipment, net of accumulated depreciation (note 5)		166,859,446			161,583,938
Intangible assets, net of accumulated amortization (note 6)		15,417,514			15,320,018
Net deferred income tax asset (note 7)		8,504,000			-
Total assets	$	232,914,304		$	232,765,297
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,886,947		$	1,626,687
Related party accounts payable		5,195			3,089
Current portion of capital lease obligations (note 8)		20,919			48,118
Current portion of notes payable (note 9)		4,336,271			4,127,170
Total current liabilities		6,249,332			5,805,064
Long-term Liabilities:
Long-term portion of capital lease obligations (note 8)		-			20,921
Asset retirement obligations (note 14)		1,400,000			-
Notes payable, less current portion (note 9)		94,376,351			99,226,423
Total long-term liabilities		95,776,351			99,247,344
Total liabilities		102,025,683			105,052,408
Commitments and Contingencies (note 14)		-			-
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par  value; issued and outstanding shares at December 31, 2014 and 2013  were: 107,018,029 and 102,094,542; respectively)		107,018			102,094
Additional paid-in capital		103,669,371			100,381,207
Accumulated other comprehensive loss		-			(27,321)
Accumulated deficit		(19,284,860)			(30,898,571)
		84,491,529			69,557,409
Non-controlling interests (note 15)		46,397,092			58,155,480
Total stockholders’ equity		130,888,621			127,712,889
Total liabilities and stockholders’ equity	$	232,914,304		$	232,765,297

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

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

		For the Year Ended December 31,
		2014			2013
Plant Revenues:
Energy sales	$	30,596,261		$	26,986,049
Energy credit sales		372,521			384,885
Total plant operating revenues		30,968,782			27,370,934
Plant Expenses:
Plant production expenses		9,701,506			7,704,871
Depreciation and amortization		6,241,354			6,454,151
Total plant operating expenses		15,942,860			14,159,022
Net Income from Plant Operations		15,025,922			13,211,912
Expenses (Income):
Corporate administration		1,136,849			881,880
Professional and management fees		986,742			1,284,936
Salaries and wages		1,858,423			2,135,945
Stock based compensation		1,339,496			756,935
Travel and promotion		199,894			202,060
Exploration costs		508,500			39,482
Interest expense		4,060,133			3,895,890
Other (income) expenses		346,588			(115,865)
Total expenses (income)		10,436,625			9,081,263
Net Income Before Income Tax Expense		4,589,297			4,130,649
Net Income Tax (Expense) Benefit (note 7):
Income taxes		(1,753,000)			(1,578,000)
Change in deferred tax assets and liabilities		12,060,000			1,578,000
Net income tax (expense) benefit		10,307,000			-
Net Income		14,896,297			4,130,649
Net income attributable to the non-controlling interests		(3,282,586)			(2,184,070)
Net Income Attributable to U.S. Geothermal Inc.		11,613,711			1,946,579
Other Comprehensive Income (Loss):
Unrealized income (loss) on investment in equity securities		27,321			(23,377)
Comprehensive Income Attributable to U.S. Geothermal Inc.	$	11,641,032		$	1,923,202
Basic Net Income Per Share Attributable to U.S. Geothermal Inc.	$	0.11		$	0.02
Diluted Net Income Per Share Attributable to U.S. Geothermal Inc.	$	0.09		$	0.02
Weighted Average Number of Shares Outstanding for Basic Calculations		104,273,319			101,795,364
Weighted Average Number of Shares, Stock Options and Warrants Outstanding for Diluted Calculations		126,006,172			123,497,883

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

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

		For the Year Ended December 31,
		2014			2013
Operating Activities:
Net Income	$	14,896,297		$	4,130,649
Adjustments to reconcile net income to total cash provided by operating activities:
Depreciation and amortization		6,367,817			6,575,266
Stock based compensation		1,339,496			756,935
Stock based officer bonus		-			100,000
Gain on software refund		(13,239)			-
Loss on disposal of geothermal water rights		451,299			-
Loss on sale of securities		27,967			-
Change in deferred tax assets and liabilities		(10,307,000)			-
Net changes in:
Trade accounts receivable, operating		332,673			(809,9160
Accounts payable and accrued liabilities		178,158			128,868
Prepaid expenses and other		(471,097)			(240,158)
Total cash provided by operating activities		12,802,371			10,641,644
Investing Activities:
Purchases of property, plant and equipment		(3,746,083			(13,868,842)
Company acquisitions		(6,842,281)			-
Proceeds from ITC cash grants receivable		-			40,113,741
Proceeds from sale of equities held for investment		41,528			-
Proceeds from software refund		31,120			-
Net funding of restricted cash reserves and bonds		(4,712)			(17,474,465)
Total cash provided (used) by investing activities		(10,520,428)			8,770,434
Financing Activities:
Issuance of share capital		1,634,918			-
Contributions from non-controlling interest		7,360			7,460
Distributions to non-controlling interest		(15,048,334)			(117,2480
Proceeds from debt obligations		-			16,570,400
Principal payments on notes payable and other obligations		(4,569,726)			(19,999,2570
Principal payments on capital leases		(48,120)			(45,278)
Total cash used by financing activities		(18,023,902)			(3,583,923)
Increase (Decrease) in Cash and Cash Equivalents		(15,741,959)			15,828,155
Cash and Cash Equivalents, Beginning of Period		28,736,934			12,908,779
Cash and Cash Equivalents, End of Period	$	12,994,975		$	28,736,934
Supplemental Disclosures:
Non-cash investing and financing activities:
Purchase of property and equipment on account	$	84,208		$	1,107,189
Purchase of property and equipment with notes payable		-			745,105
Company acquisition by issuance of common stock		318,674			-
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		4,080,396			6,973,502

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

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2014 and 2013

								Additional						Accumulated			Non-
		Number of			Common			Paid-In			Accumulated			Comprehensive			controlling
		Shares			Shares			Capital			Deficit			Income (Loss)			Interest			Totals
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
Distributions to non-controlling interest entities (note 15)		-			-			-			-			-			(15,048,334)			(15,048,334)
Non-controlling equity contribution from Gerlach Green Energy, LLC		-			-			-			-			-			7,360			7,360
Stock issued to shareholders of acquired company (note 16)		692,769			693			317,981			-			-			-			318,674
Stock issued by the exercise of employee stock options		1,077,000			1,077			336,544			-			-			-			337,621
Stock issued by the exercise of stock purchase warrants		2,594,596			2,595			1,294,703			-			-			-			1,297,298
Stock compensation		559,122			559			1,338,936			-			-			-			1,339,495
Unrealized loss and reclassification to net income		-			-			-			-			27,321			-			27,321
Net income		-			-			-			11,613,711			-			3,282,586			14,896,297
Balance at December 31, 2014		107,018,029		$	107,018		$	103,669,371		$	(19,284,860)		$	-		$	46,397,092		$	130,888,621

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

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U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

U.S. Geothermal 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.

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);
	xiii)	U.S. Geothermal Guatemala, S.A. (organized in Guatemala);
	xiv)	Geysers USG Holdings Inc. (incorporated in the State of Delaware);
	xv)	Western GeoPower, Inc. (incorporated in the State of California);
	xvi)	Etoile Holdings Inc. (incorporated in the Bahamas);
	xvii)	Mayacamas Energy LLC (organized in the State of California);
	xviii)	Skyline Geothermal LLC (organized in the State of Delaware);
	xix)	Skyline Geothermal Holding, Inc. (incorporated in the State of Delaware); and
	xx)	Earth Power Resources Inc. (incorporated in Delaware).

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-

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NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Accounting Method

The Company’s consolidated financial statements are prepared using the accrual basis of accounting in accordance with 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, 2014, $3.8 million in USG Oregon LLC funds were deposited at PNC Bank in the Revenue account and $271,000 in Oregon USG Holdings LLC funds were deposited at Umpqua Bank, and were unavailable for immediate corporate needs. 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, 2014 and 2013, 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 from grants from Federal or State agencies, the Company records the receivable amounts net of the funds expected to be received. Therefore, no allowance accounts are considered to be necessary for receivables from grants at December 31, 2014 and 2013.

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. At December 31, 2014, the Company’s total cash balance, excluding money market funds, was $4,487,085, and bank deposits amounted to $4,577,004. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $3,156,637 was not covered by or was in excess of FDIC insurance guaranteed limits. At December 31, 2014, the Company’s money market funds invested, primarily, in government backed securities totaled $30,515,067 and were not subject to deposit insurance.

-F-6-

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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 whereby the gain or loss is calculated based upon the cost of specifically identified securities for each sales transaction.

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 is expensed when incurred. Employee training time is expensed when incurred.

-F-7-

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

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., PPAs),
-	compliance with utilization and other requirements, and
-	hierarchy of other right holders who share the same resource.

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

Impairment of Long-Lived Assets

The Company evaluates its long-term assets annually for impairment 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, 2014, 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 such 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.

-F-8-

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

Stock Based Compensation Granted to Employees

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

Earnings Per Share

The Company follows financial accounting standards, which provides for calculation of "basic" and "diluted" earnings per share. Basic earnings per share includes no dilution and is computed by dividing net income available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of an entity similar to fully diluted earnings per share. 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, 2014 and 2013 were 126,744,104 (126,006,172 annual weighted average) and 124,494,963 (123,497,883 annual weighted average); 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.

-F-9-

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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.

Asset Retirement Obligations

The Company records the fair value of estimated asset retirement obligations (“AROs”) associated with tangible long-lived assets in the period incurred or acquired. AROs are legal obligations to settle under existing or enacted law, statue, or contract. The value of these obligations are originally based upon discounted cash flow estimates and are accreted to full value over time through charges to operations. Costs associated with future conditions are recognized as AROs in the period the condition occurs or is known to the Company. Generally, costs associated with AROs are earthwork, revegetation, well capping, and structure removal necessary to return the sites to their original conditions.

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 income, total assets, or stockholders’ equity as previously reported.

Recent Accounting Pronouncements

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

Stock Compensation
In June 2014, FASB issued Accounting Standards Update No. 2014-12 (“Update 2014-12”), Compensation-Stock Compensation, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period (Topic 718). Update 2014-12 provides guidance on how to account for share-based payment awards that require a specific performance target to be achieved in order for the employees to become eligible to vest in the awards. Update 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Management is still evaluating the applicability and possible impact this update may have on the accounting treatment and its financial statement presentation.

Presentation of Property, Plant and Equipment
In April 2014, FASB issued Accounting Standards Update No. 2014-08 (“Update 2014-08”), Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. Update 2014-08 provides guidance to address the issues surrounding the reporting of discontinued operations and enhance the convergence of the FASB’s and the International Accounting Standard Board’s reporting requirements for discontinued operations. Update 2014-08 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Management is still evaluating the applicability and possible impact this update may have on the accounting treatment and its financial statement presentation.

-F-10-

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Business Combinations
In December 2014, FASB issued Accounting Standards Update No. 2014-18 (“Update 2014-18”), Accounting for Identifiable Intangible Assets in Business Combination, Business Combinations (Topic 805). Update 2014-18 provides modifications to the evaluation of variable interest entities that may impact consolidation of reporting entities. Update 2014-18 is effective for fiscal year beginning after December 15, 2015, and the effective date of adoption depends on the timing of that first in-scope transaction. If the first in-scope transaction occurs in the first fiscal year beginning after December 12, 2015, the elective adoption will be effective for that fiscal year’s annual financial reporting and all interim and annual periods thereafter. The focus of this Update addresses the types of intangible assets that the Company, typically, has not acquired or does not seek to acquire; however, Management will continue to evaluate the possible impact that this Update may have on the accounting treatment of applicable elements and the financial presentation of these elements.

Consolidation
In February 2015, FASB issued Accounting Standards Update No. 2015-02 (“Update 2015-02”), Amendments to the Consolidation Analysis, Consolidation (Topic 810). Update 2015-02 provides modifications to the evaluation of variable interest entities that may impact consolidation of reporting entities. Update 2015-02 is effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. The Company currently consolidates variable interest entities and may create or acquire variable interest entities for future endeavors. Management is still evaluating the possible impact this update may have on the financial presentation of the Company’s consolidated financial statements.

-F-11-

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NOTE 3 – RESTRICTED CASH AND BOND RESERVES

Under the terms of the loan agreements with the Department of Energy and Prudential Capital Group, various bond and cash reserves are 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			2014			2013
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			188,930			19,848
Bureau of Land Management , Geothermal Rights Lease Bond			10,000			-
U.S. Department of Energy, Debt Service Reserve			2,151,851			2,191,172
State of California Division of Oil, Gas and Geothermal Resources, Well Cash Bond			100,000			-
		$	3,320,781		$	3,081,020

Long-term restricted cash and bond reserves:

			December 31,
Restricting Entities/Purpose			2014			2013
Nevada Energy, PPA Security Bond		$	1,468,898		$	1,468,898
Prudential Capital Group, Debt Service Reserves			1,594,605			1,594,437
Prudential Capital Group, Maintenance Reserves			604,529			751,183
Prudential Capital Group, Well Reserves			212,298			53,072
U.S. Department of Energy, Operations Reserves			270,000			270,000
U.S. Department of Energy, Debt Service Reserves			2,582,606			2,668,179
U.S. Department of Energy, Short Term Well Field Reserves			4,505,150			4,501,191
U.S. Department of Energy, Long-Term Well Field Reserves			4,761,927			4,507,391
U.S. Department of Energy, Capital Expenditure Reserves			2,690,083			3,000,794
		$	18,690,096		$	18,815,145

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. 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, 2014 and 2013. As described in note 16, the Geyser’s acquisition included a short term well bond of $100,000 and the Earth Power Resources Inc. acquisition included a short term geothermal lease rights bond of $10,000.

-F-12-

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NOTE 4 – INVESTMENT IN EQUITY SECURITIES

During the quarter ended March 31, 2014, all of the Company’s holdings of equity securities (150,000 shares of Alterra Power Corp, a publicly traded renewable energy company) were sold for $41,528, which resulted in a realized loss of $27,967. The net change of $27,321 was reclassified from other comprehensive income to net income as a result of the sale.

NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

During the year ended December, 2014, the Company continued development activities for San Emidio, Nevada and the Guatemala projects. Two new exploration wells for the San Emidio Phase II project were drilled, one exploration well drilled in 2013 was abandoned, and one other well drilled in 2013 was placed into production during the year for approximately $2.03 million. A portion of the drilling and development costs were offset by grant proceeds of $632,210. The new production well was connected to the existing Phase I power plant and is producing fluid to the plant as part of a long term test of the South Zone reservoir. During the year, costs that exceeded $924,000 were incurred at Guatemala for the construction of nine temperature gradient wells.

On December 12, 2014, the Company completed an acquisition of Earth Power Resources Inc. See Note 16 for details. After acquisition, the Company incurred approximately $133,000 on the drilling of a new production well.

Effective April 22, 2014, the Company acquired a group of companies (The Geysers, California) that included long-term assets that totaled $7.74 million (land of $1.6 million, well and drilling construction in progress of $6.14 million). See note 16 for acquisition details. After acquisition, the Company incurred development costs of approximately $259,000 for design and study work for a new power plant, transmission line and well field.

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 costs 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-13-

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

			December 31,
			2014			2013
	Land	$	3,211,010		$	1,603,509
	Power production plant		162,076,367			161,868,687
	Grant proceeds for power plants		(52,965,236)			(52,965,236)
	Wells		67,621,167			67,620,661
	Grant proceeds for wells		(3,464,555)			(3,464,555)
	Furniture and equipment		1,796,807			1,462,312
			178,275,560			176,125,378
	Less: accumulated depreciation		(27,068,836)			(20,895,943)
			151,206,724			155,229,435
	Construction in progress		15,652,722			6,354,503
		$	166,859,446		$	161,583,938

Depreciation expense charged to plant operations and administrative costs for the years ended December 31, 2014 and 2013, was $6,186,132 and $6,393,581; respectively.

Changes in Construction in Progress are summarized as follows:

			For the Year Ended December 31,
			2014			2013
	Beginning balances	$	6,354,503		$	2,877,994
	Development/construction		3,730,371			3,694,978
	Grant reimbursements and rebates		(632,210)			(33,325)
	Acquisition (note 16)		6,200,058			-
	Transfers into production		-			(185,144)
	Ending balances	$	15,652,722		$	6,354,503

-F-14-

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

			December 31,
			2014			2013
	Raft River, Idaho:
	Unit II, power plant, substation and transmission lines	$	750,493		$	750,493
	Unit II, well construction		2,127,547			2,121,502
			2,878,040			2,871,995
	San Emidio, Nevada:
	Unit II, power plant, substation and transmission lines		383,536			3,910
	Unit II, well construction *		3,133,873			1,753,299
			3,517,409			1,757,209
	Neal Hot Springs, Oregon:
	Power plant and facilities		6,477			-
	The Geysers, California (note 16):
	Power plant and facilities		319,988			-
	Well construction		6,139,421			-
			6,459,409			-
	Crescent Valley, Nevada:
	Well construction		133,058			-
	El Ceibillo, Republic of Guatemala:
	Well Construction		2,649,829			1,725,299
	Plant and facilities		8,500			-
			2,658,329			1,725,299
		$	15,652,722		$	6,354,503

*- Consists of four wells at December 31, 2014. The wells represent efforts to develop a well field to be utilized for Phase II. As of the date of these financial statements, the results of the wells are not sufficient to indicate the existence of a well field that would support another power plant. Two wells are being utilized to target a potential resource area. One well is currently being utilized/flow tested by the Phase I power plant. One well has been capped and abandoned. Management is still actively pursuing the Phase II project. If the project is abandoned, the cost of the wells that have no future economic value will be removed.

-F-15-

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NOTE 6 – INTANGIBLE ASSETS

During the quarter ended June 30, 2014, the Company acquired a group of companies that included geothermal water rights located at The Geysers in Northern California that amounted to $278,872 (see note 16 for details).

On December 12, 2014, the Company completed an acquisition of Earth Power Resources Inc. The acquisition included 26,017 acres of geothermal water rights in located in the Crescent Valley area in the State of Nevada valued at $451,608 on the acquisition date (see note 16 for details).

During the year ended December 31, 2014, the Company abandoned the Granite Creek, Nevada area and released the geothermal water and mineral rights originally purchased for $451,299.

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

		December 31,
		2014			2013
In operation:
Neal Hot Springs, Oregon:
Geothermal water and mineral rights	$	625,337		$	625,337
San Emidio, Nevada:
Geothermal water and mineral rights		4,825,220			4,825,220
Less: accumulated amortization		(1,117,434)			(935,749)
		4,333,123			4,514,808
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:
Geothermal water and mineral rights		-			451,299
Guatemala City, Guatemala:
Geothermal water and mineral rights		625,000			625,000
Gerlach, Nevada:
Geothermal water and mineral rights		997,000			997,000
Crescent Valley, Nevada:
Geothermal water and mineral rights (note 16)		451,608			-
The Geysers, California:
Geothermal water rights (note 16)		278,872			-
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)
		11,084,391			10,805,210
	$	15,417,514		$	15,320,018

Amortization expense was charged to plant operations for the years ended December 31, 2014 and 2013 that amounted to $181,685 and $181,685; respectively.

-F-16-

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

NOTE 7 – INCOME TAXES

To produce the estimated income tax assets and liabilities, several estimates are required than include: current and future federal and State income tax rates, State apportionment factors, future earnings, the Company’s tax positions, financial elements/terms used for stock option valuation, and availability of tax credits and other benefits. Federal and State income tax law is constantly changing and is subject to inherent uncertainties due different interpretations and tax positions. 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.

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.

At December 31, 2014, the Company had net deferred tax assets calculated at an expected rate, noted in the table below, of approximately $12,102,000 (December 31, 2013 - $10,435,000). As of December 31, 2013, the Company recognized the net deferred income tax asset to the extent of the impact on current book earnings. Effective December 31, 2014, Company management believes that historical, current and expected earnings are sufficient to meet the more likely than not standard to enable the Company to recognize the net deferred tax asset. As allowable under accounting standards, the Company elects to fully remove the valuation allowance as of December 31, 2014.

The Company’s significant temporary timing differences that impact deferred income tax assets and liabilities are stock compensation and book to tax depreciation. The recognition of employee stock compensation has different rules that impact both the value and the timing of recognized compensation costs. Typically, employee stock compensation costs are higher and are recognized before compensation costs are allowable for income tax purposes. The book value of the deferred stock compensation asset, related to stock options, is reduced when the options are exercised, forfeited or expire. Differences in book to tax depreciation costs, generally, result in a deferred tax liability. Allowable depreciation expenses for income tax purposes utilize shorter asset lives and are calculated using accelerated methods (i.e., MACRS). Also, the Company has both earned and acquired NOLs available to offset current and future earnings.

For financial reporting purposes the Company reports its operations as fully consolidated entity; however, for tax purposes the entities that have multiple ownership interests report their activities as separate entities. Some portions of the tax differences created by the structure of the reporting entities are limited to the consolidated Company as a whole. These differences, calculated with the estimated income tax rate are summarized as follows:

-F-17-

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		December 31, 2014
		Consolidated			Adjustments			Net Available
Deferred tax assets:
Net operating loss carry forward	$	47,696,000		$	(17,096,000)		$	30,600,000
Stock based compensation		1,518,000			-			1,518,000
Deferred tax liabilities:
Depreciation and amortization		(44,940,000)			23,129,000			(21,811,000)
Net deferred tax asset	$	4,274,000		$	6,033,000		$	10,307,000

The significant components of the net deferred tax asset calculated with the estimated effective income tax rate were as follows:

			December 31,
			2014			2013
	Current deferred tax assets:
	Net operating loss carry forward	$	1,730,000		$	-
	Stock based compensation		73,000			28,000
	Long-term deferred tax assets:
	Net operating loss carry forward		30,623,000			28,478,000
	Stock based compensation		1,445,000			1,089,000
	Current liabilities:
	Depreciation and amortization		(1,397,000)			(4,331,000)
	Long-term liabilities:
	Depreciation and amortization		(20,414,000)			(14,829,000)
	Net deferred income tax asset		12,060,000			10,435,000
	Deferred tax asset recognized and utilized in current period		(1,753,000)			(1,578,000)
	Deferred tax asset valuation allowance		-			(8,857,000)
	Net deferred tax asset	$	10,307,000		$	-

The current portion of the deferred tax asset is based upon an estimate of the earnings for the year ended December 31, 2015.

When calculating the effective tax rate, the federal income tax rate was used in addition to the applicable State income tax rates as deductible for federal income taxes. At year end, the Company held interests in the States of Idaho, Oregon, Nevada and California. The calculation of the average State income tax rate was based upon State apportionment factors that included operating revenues, payroll costs, and property costs. The Company, also, has interests in the Republic of Guatemala; however, the income tax effect of these interests were minimal for the years ended December 31, 2014 and 2013.

-F-18-

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

			For the Years Ended December 31,
			2014			2013
	U.S. Federal statutory rate		34.0%			34.0%
	Average State and foreign income tax, net of federal tax effect		3.7			4.2
	Production tax credits		-			-
	Net effective tax rate		37.7%			38.2%

At December 31, 2014, the Company had net income tax operating loss carry forwards of approximately $81,166,000 ($74,550,000 in December 31, 2013), which expire in the years 2023 through 2034. Approximately $76,837,000 of the operating losses were generated by the Company; the residual were acquired. On April 22, 2014, the Company purchased a group of companies (see note 16 for details). Federal and applicable state net operating losses that totalled approximately $30 million were included in the acquisition. These NOLs are scheduled to expire in the years ending 2028 through 2033. The use of these net operating losses is restricted by the Company’s basis and the “applicable federal rate” as defined by Section 382 of federal tax law. The estimated available net operating losses from the acquired companies were approximately $4,329,000 at December 31, 2014.

The net change in the deferred tax asset valuation allowance account is detailed as follows:

		For the Year Ended December 31,
		2014			2013
Change in net operating loss	$	5,588,000		$	16,258,000
Change in estimated effective tax rate		(45,000)			614,000
Net change in difference between book and tax stock compensation costs		407,000			251,000
Change in estimated deferred tax asset recognized and utilized in current period		(1,753,000)			(1,578,000)
Change in period book to income tax depreciation		(2,747,000)			(17,518,000)
Recognition of net operating loss		(10,307,000)			-
Net change in deferred tax valuation allowance	$	(8,857,000)		$	(1,973,000)

At December 31, 2014, Raft River Energy I LLC has a book-to-tax difference of $38.7 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, 2014, USG Oregon LLC has a book-to-tax difference of $57.5 million due to the acceleration of depreciation.

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 years ended December 31, 2014 and 2013, and the nine months ended December 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, California 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, 2014 and 2013, and the nine months ended December 31, 2012. No filings are currently under examination. No adjustments due to tax uncertainties have been made to reduce the estimated income tax benefit at year end. Any valuations relating to these income tax provisions will comply with U.S. Generally Accepted Accounting Principles.

-F-19-

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NOTE 8 - 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 two contracts for the year ended December 31, 2015 total $21,249. At December 31, 2014, all of the lease obligations of $20,921 (less imputed interest of $328) were current. At December 31, 2014, the net book value of the equipment under capital lease amounted to $34,755 ($155,000, less $120,245 accumulated amortization).

NOTE 9 – 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 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 loan. 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 ITC cash 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, 2014 totaled $66,974,610 (estimated current portion $3,419,927).

-F-20-

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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, 2014			(16,083,355)
	Loan balance at December 31, 2014		$	66,974,610

* - 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 10.0 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 and is scheduled to be repaid by September 2018. The loan balance at December 31, 2014 totaled $1,487,266 (estimated current portion $390,051).

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 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 projected operating results made at the loan origination date 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 San Emidio project and the equity interests in USG Nevada LLC. At December 31, 2014, the balance of the loan was $30,182,333 (estimated current portion $471,091).

Auto Loans
On August 21, 2014, the Company’s wholly owned subsidiaries (U.S. Geothermal Services, LLC, USG Nevada LLC and Raft River Energy I, Inc.) purchased three trucks with down payments that totaled $47,000 and three separate loan agreements with Chrysler Capital. The loans require total monthly payments of $1,257, including interest at an average rate of 7.9% per annum until September 2020. The notes are secured by the vehicles. At December 31, 2014, the loan balances totaled $68,412 (estimated current portion $9,919).

-F-21-

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

NOTE 10 - CAPITAL STOCK

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

On December 12, 2014, the Company issued 692,769 shares of common stock to the shareholders of acquired company (Earth Power Resources Inc. – “EPR”). Under the terms of the Acquisition agreement, 50% of the issued shares will be held in reserve by the Company to cover potential undisclosed liabilities against EPR. The remaining non-reserved shares will be delivered to EPR shareholders upon surrender of their EPR share certificates. Trading of the non-reserve shares will be restricted for six months under SEC Rule 144. See note 16 for acquisition details.

On September 3, 2014, the Company issued 2,459,460 shares of common stock to an investor exercising stock purchase warrants at a price of $0.50 per share.

On April 2, 2014, the Company issued 559,122 shares of common stock (restricted shares) at a price of $0.74 per share to employees. The shares vest on April 2, 2015 and will be priced (currently $0.46 a share) at the date of vesting.

During the quarter ended June 30, 2014, the Company issued 352,500 shares of common stock as a result of employees and former employees exercising stock options priced at $0.31 per share.

During the quarter ended March 31, 2014, the Company issued 724,500 shares of common stock as a result of employees and former employees exercising stock options priced between $0.31 and $0.46 per share.

On March 14, 2014, the Company issued 135,136 shares of common stock to an investor exercising stock purchase warrants at a price of $0.50 per share.

During the year ended December 31, 2013, the Company issued 577,778 shares of common stock (300,000 restricted shares) to an employee of the Company at prices between $0.35 and $0.36 per share under the terms of an employment agreement.

-F-22-

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NOTE 11 - 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 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, 2014, the Company can issue stock option grants totaling up to 16,052,704 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, 2014, the Company had 11,808,500 options granted and outstanding.

During the quarter ended December 31, 2014, 40,000 stock options exercisable at the price of $0.74 issued to an employee were forfeited due to termination of employment.

On September 23, 2014, 68,000 stock options exercisable at a price of $1.58 expired without exercise.

During the quarter ended September 30, 2014, 50,000 stock options exercisable at the price of $0.83 issued to a contractor were forfeited due to the termination of their contract.

On April 2, 2014, the Company awarded 2,883,500 stock options at an exercise price of $0.74 expiring on April 2, 2019 to its employees and directors.

During the quarter ended June 30, 2014, 352,500 stock options exercisable at the price of $0.31 were exercised by employees and former employees.

On May 26, 2014, 1,698,250 stock options exercisable at a price of $0.92 expired without exercise.

During the quarter ended March 31, 2014, 724,500 stock options exercisable at prices between $0.31 and $0.46 were exercised by employees and former employees.

On February 22, 2014, 30,000 stock options exercisable at a price of $0.46 issued to employees were forfeited due to the termination of employment.

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.

-F-23-

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The following table reflects the summary of stock options outstanding at December 31, 2012 and changes for the years ended December 31, 2013 and 2014:

					Weighted
					Average			Weighted
		Number of			Exercise			Average			Aggregate
		shares under			Price Per			Fair			Intrinsic
		options			Share			Value			Value
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
Forfeited/Expired		(1,886,250)			0.53			0.26			(1,251,738)
Exercised		(1,077,000)			0.32			0.16			(171,134)
Granted		2,883,500			0.74			0.40			1,153,400
Balance outstanding, December 31, 2014		11,808,500		$	0.62		$	0.36		$	4,273,243

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 Year Ended December 31,
			2014			2013
	Dividend yield		0			0
	Expected volatility		81-100%			71-81%
	Risk free interest rate		0.69-0.82%			0.27-0.82%
	Expected life (years)		2.94			4.63

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-24-

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The following table summarizes information about the stock options outstanding at December 31, 2014:

	OPTIONS OUTSTANDING
							REMAINING			NUMBER OF
	EXERCISE			NUMBER OF			CONTRACTUAL			OPTIONS
	PRICE			OPTIONS			LIFE (YEARS)			EXERCISABLE			INTRINSIC VALUE
$	0.86			1,300,000			0.70			1,300,000		$	752,207
	0.83			2,540,000			1.43			2,540,000			1,244,600
	0.60			100,000			1.70			100,000			36,072
	0.31			1,865,000			2.65			1,865,000			290,128
	0.46			1,895,000			3.56			1,421,250			345,222
	0.41			15,000			3.67			11,250			2,259
	0.35			1,250,000			8.30			1,250,000			338,000
	0.74			2,843,500			4.25			1,421,750			574,464
$	0.62			11,808,500			3.52			9,909,250		$	3,582,952

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

-F-25-

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A summary of the status of the Company’s nonvested stock options outstanding at December 31, 2012 and changes during the years ended December 31, 2013 and 2014 are presented as follows:

						Weighted			Weighted
						Average Grant			Average
			Number of			Date Fair Value			Grant Date
			Options			Per Share			Fair Value
	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
	Granted		2,132,625			0.74			0.40
	Vested		(3,031,375)			0.38			0.19
	Forfeited/Expired		(30,000)			0.46			0.24
	Nonvested, December 31, 2014		1,899,250		$	0.65		$	0.36

As of December 31, 2014, there was $433,322 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, 2014 and December 31, 2013 was $1,115,391 and $683,143, respectively.

Stock Compensation Plan (Restricted Shares)

On April 19, 2013, the Company granted an officer and director 300,000 common shares valued at $0.35 per share, which were 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, 2014 was $31,208.

On April 2, 2014, the Company issued 559,122 shares of Company stock at a price of $0.46 that fully vest on April 2, 2015 to its employees and directors. The total estimated fair value is $257,196 and the recognized cost through December 31, 2014 was $192,897.

Stock Purchase Warrants

At December 31, 2014, 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			-			-			3,310,812			0.50

On September 3, 2014, share purchase warrants that totaled 2,459,460 were exercised by an investor at the warrant exercise price of $0.50.

-F-26-

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On March 14, 2014, 135,136 share purchase warrants were exercised by an investor at the warrant exercise price of $0.50.

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

NOTE 12 – 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, 2014 at fair value on a recurring basis:

		Total			Level 1			Level 2			Level 3
Assets:
Money market accounts *	$	30,515,067		$	30,515,067		$	-		$	-

* - 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.

-F-27-

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NOTE 13 - RELATED PARTY TRANSACTIONS

At December 31, 2014 and 2013 the amounts of $5,195 and $3,089; 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, 2014 and 2013 totalled $115,300 and $99,000; respectively.

NOTE 14 - 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 Neal Hot Springs, Oregon; Washoe County, Nevada; Eureka County, Nevada; The Geysers, California; Raft River, Idaho and the Republic of Guatemala. The Company incurred total lease expenses for the years ended December 31, 2014 and 2013, of $579,815 and $286,923; respectively. The Company believes that it is in compliance with all of the following lease terms.

BLM Lease Agreements

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

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. During the quarter ended December 31, 2014, management terminated the Granite Creek project and will relinquish its lease contracts and the accompanying rights to the area. The carrying value of the contracts of $451,299 has been eliminated from the financial statements.

-F-28-

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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 have stated terms that range from 5 to 30 years with expiration dates that range from May 2015 to December 2034. The annual contracted lease payments are scheduled to total $44,450 for the year ended December 31, 2015.

Other Lease Agreements

Neal Hot Springs, Oregon
The Company holds 3 lease contracts for approximately 7,429 acres of geothermal water rights located in the Neal Hot Springs area near Vale, Oregon. The contracts have stated terms of 10 years with expiration dates that range from May 2015 to November 2019. The two major contracts are royalty based. One of the agreements 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. The second 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 under both royalty based contracts based on electricity delivery under the Idaho Power Purchase Agreement.

The Geysers, California
On April 22, 2014, the Company acquired companies that held five significant lease contracts for approximately 3,809 acres (6.0 square miles) of land and geothermal water rights in The Geysers area located in Northern California. The contracts have stated expiration dates, expiring from February 2017 to October 2019. The remaining contracts renew indefinitely with payments made within contracted terms (held by payment). The annual contracted lease payments are scheduled to total $274,000 for the year ended December 31, 2015.

Crescent Valley, Nevada
On December 12, 2014, the Company acquired Earth Power Resources Inc. that holds 63 lease contracts for approximately 26,017 acres located in the central area of the State of Nevada. The contracts have stated terms of 10 to 40 years with expiration dates that range from February 2015 to June 2054. The annual contracted lease payments are scheduled to total $70,898 for the year ended December 31, 2015.

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 began 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. For the year ended December 31, 2014, the office lease costs totaled $115,830.

Tyrell Lane
Under the contract, the lease payments were due in monthly installments of $6,535. The contract ended January 31, 2014. The total office lease costs incurred under the contract and the prior contract for year ended December 31, 2013 totaled $78,423.

-F-29-

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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:

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. These agreements will govern the operational revenues for the initial phases of the Company’s operating activities. The contract allows power sales up to 13 megawatts annual average. 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 (March, April, May) 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.

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 amended and restated 25 year contract signed in December of 2011 that sets the new rate at $89.75 per megawatt hour with a 1% annual escalation rate. The new contract currently allows for a maximum of 73,444 megawatt hours annually that will be paid for at the full contract price. 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, 2014, the Company has funded a security deposit 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 $96.00 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.

-F-30-

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Asset Retirement Obligations (“AROs”)

The Geysers, California
On April 22, 2014, the Company completed the acquisition of a group of companies owned by Ram Power Corp.’s (“Ram”) Geysers Project located in Northern California. Two of the acquired companies (Western GeoPower, Inc. and Etoile Holdings, Inc.) contained asset retirement obligations that, primarily, originate with the environmental regulations defined by the laws of the State of California. The liabilities related to the removal and disposal of arsenic impacted soil and existing steam conveyance pipelines are estimated to total $800,000. Obligations related to decommissioning four existing wells were estimated to total $600,000. These obligations are based upon the expected future value of the remedy or settlement and the values have not been calculated at discounted rates. At December 31, 2014, the Company has not considered it necessary to specifically fund these obligations. Since management is still evaluating the development plan for this project that could eliminate or significantly reduce these obligations, no charges directly associated the asset retirement obligations have been charged to operations. All of the obligations are considered to be long-term at December 31, 2014.

Raft River Energy I LLC, USG Nevada LLC, and USG Oregon LLC
These Companies operate in Idaho, Nevada and Oregon and are subject to environmental laws and regulations of these states. The plants, wells, pipelines and transmission lines are expected to have long useful lives. Generally, these assets will require funds for retirement or reclamation. However, these estimated obligations are believed to be less than or not significantly more than the assets’ estimated salvage values. Therefore, as of December 31, 2014, no retirement obligations have been recognized.

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 $97,785 and $60,425 for the years ended December 31, 2014 and 2013, respectively.

NOTE 15 – JOINT VENTURES/NON-CONTROLLING INTERESTS

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

		December 31,
		2014			2013
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	230,539		$	404,352
Oregon USG Holdings LLC interest held by Enbridge Inc.		24,818,443			35,926,826
Raft River Energy I LLC interest held by Raft River I Holdings, LLC		21,348,110			21,824,302
	$	46,397,092		$	58,155,480

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. During the first three quarters of the current year, contributions were made to Gerlach by the Company and GGE that totaled $11,040 and $7,360; respectively. These contributions maintained the existing ownership interests of the two partners in Gerlach. During the fourth quarter of the current year, the Company contributed $400,000 for the project’s drilling costs that were not proportionally matched by GGE. These contributions effectively reduced GGE’s ownership interest to 32.65%, and increased the Company’s interest to 67.35% as of December 31, 2014.

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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 Neal Hot Springs project located in Malheur County, Oregon. On February 20, 2014, a new determination under the existing agreement was reached with Enbridge that established their ownership interest percentage at 40% and the Company’s at 60%, effective January 1, 2013. 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. During the year ended December 31, 2014, distributions were made to the Company and Enbridge that totaled $12,388,606 and $15,024,334; respectively.

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 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 years ended December 31, 2014 and 2013, RREI made principal payments on the loan of $1,003,833 and $755,288; respectively. The balance of the loan at December 31, 2014 and 2013 was $377,029 and $1,380,862; respectively. The loan balance and related interest effects are fully eliminated during the consolidation process.

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NOTE 16 – ACQUISITIONS

Ram Power’s Geysers Project
On April 22, 2014, the Company acquired all of the ownership shares of a group of companies owned by Ram Power Corp.’s (“Ram”) that hold all interests in the Geysers Project located in Northern California for a total of $6.78 million ($6.4 million purchase price, plus $0.38 million in other acquisition costs). The acquisition included Ram’s subsidiaries: Western GeoPower, Inc., Skyline Geothermal Holdings, Inc., and Etoile Holdings, Inc. which includes all membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The assets acquired included 4 production/injection wells, restricted cash, land and geothermal water rights. The Company assumed the on-going liabilities of the companies which included an asset retirement obligations with estimated value of $1.4 million. The Company will evaluate whether to construct a power plant or sell the steam to one of the existing power companies in the area. The total acquisition cost was allocated as follows:

			Acquisition Costs
	Assets:
	Restricted cash, short term well bond	$	100,000
	Land		1,603,516
	Geothermal water rights		278,872
	Construction in progress:
	Wells and casing		6,139,420
	Plant and facilities		60,637
			8,182,445
	Liabilities:
	Asset retirement obligations		(1,400,000)
	Net acquisition cost	$	6,782,445

Earth Power Resources Inc. (“EPR”)
On October 16, 2014, the Company signed an Agreement and Plan of Merger with EPR. The transaction was approved by EPR shareholder approval on November 18, 2014. The Acquisition was completed on December 12, 2014. Under the terms of the Agreement, the EPR shareholders received a total of 692,769 shares of U.S. Geothermal Inc. common shares and $42,934 in cash in exchange for all outstanding shares of EPR stock. Under the terms of the Acquisition agreement, 50% of the issued shares will be held in reserve by the Company to cover potential undisclosed liabilities against EPR. The remaining non-reserved shares will be delivered to EPR shareholders upon surrender of their EPR share certificates. Trading of the non-reserve shares will be restricted for 6 months under SEC Rule 144. Acquired assets include geothermal leases covering 26,017 acres in the State of Nevada representing three potential projects. A loan of $100,000 was made from the Company to EPR to fund operating costs that were due prior to the acquisition. The loan accrues interest at a rate of 7.0% per annum and is due on December 11, 2019.

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The total acquisition cost was allocated as follows:

			Acquisition Costs
	Assets:
	Restricted cash, bond	$	10,000
	Geothermal water rights		451,608
			461,608
	Liability:
	Note payable, intercompany		(100,000)
	Net acquisition cost	$	361,608

NOTE 17 - SUBSEQUENT EVENTS

The Company has evaluated events and transactions that have occurred after the balance sheet date through March 16, 2015, which is considered to be the issuance date. No events were identified for disclosure.

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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 Exchange Act 1934 as of December 31, 2014. 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, 2014.

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, 2014. 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 – 2013). Based on its assessment, management concluded that, as of December 31, 2014, the Company’s internal control over financial reporting is effective based on those criteria.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

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, 2014, 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 56, serves as the Chief Executive Officer and a director of the Company. 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 30 years of experience in the natural resource industry and his many years of senior management and director experience.

Douglas J. Glaspey: Age 62, 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.

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Kerry D. Hawkley: Age 61, 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 64, 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., 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 74, 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.

John H. Walker: Age 66, 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 117 megawatt 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.

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Jonathan Zurkoff: Age 59, 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 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, 2014 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, 2014. 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.

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

• base salary;

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• 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.

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.

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.

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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, 2014, stock option grants to executive officers represented approximately 52% of the total stock option grants to all employees. During the year ended December 31, 2014, 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.

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.

The Company has agreed to pay to Mr. Gilles an annual base salary of $375,000, which increased to $410,000 on April 19, 2014 and will 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. 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 was granted 400,000 stock options to acquire shares of the Company’s common stock at an exercise price of $0.74, a cash bonus of $150,000 and 325,000 shares of restricted stock with a one-year vesting period. 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 401(k) 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 has received cost reimbursement for a single relocation for costs of $34,260.

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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.

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.

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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 401(k) 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.

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.

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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 401(k) retirement benefit as is available to other employees of the Company. This salary may be adjusted annually on the anniversary date of the employment agreement and is currently $179,375 per annum. 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.

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.

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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 twice amended, is effective December 31, 2010, and will remain in effect until March 31, 2015 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 401(k) 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.

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.

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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.

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”).

(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.

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, 2014 by our Named Executive Officers.

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	(1)The $0.74 options unexercisable at December 31, 2014 will fully vest on October 2, 2015.
	The $0.46 options unexercisable at December 31, 2013 fully vested 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. Gilles, Glaspey, Hawkley and Zurkoff which provide for change-in-control payments.

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.

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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.

Director Compensation

The following table summarizes the compensation paid to our directors during the year ended December 31, 2014.

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

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Directors who are not otherwise remunerated per an employment agreement are paid $7,500 per quarter, $1,500 per face-to-face meetings, $400 per telephone meetings, $2,500-$5,000 per annum as committee heads, and are eligible to receive awards under our equity compensation plans. Directors who are also officers do not receive any compensation for serving in the capacity of director. However, all directors are reimbursed for their out-of-pocket expenses in attending meetings.

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

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, 2014.

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 6, 2015 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 107,063,029 shares of the Company’s common stock outstanding as of March 6, 2015.

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		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		5,911,281 (1)		5.52%

(1)	As of December 31, 2014, based on information set forth in a Schedule 13G/A filed with the SEC on January 12, 2015 by Sprott Inc., which has sole voting and dispositive power over 5,911,281 shares of the Company’s common stock.

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, 2014, by each of our directors, Named Executive Officers and directors and executive officers as a group. The percentage of beneficial ownership is based on 107,063,029 shares of the Company’s common stock outstanding as of March 6, 2015.

		Amount and
		Nature
Name of Beneficial Owner		of Beneficial		Percent of
		Ownership		Class
Dennis J. Gilles		2,502,778 (1)		2.34%
Douglas J. Glaspey		1,322,187 (2)		1.24%
Kerry D. Hawkley		574,899 (3)		*
Paul A. Larkin		664,825 (4)		*
Leland L. Mink		438,378 (5)		*
John H. Walker		441,657 (6)		*
Jonathan Zurkoff		744,277 (7)		*
All directors and executive officers as a group (7 persons)		6,689,001 (8)		6.25%

*	Less than 1% of the Company’s outstanding common stock
(1)	Includes 1,650,000 options exercisable within 60 days of March 6, 2015.
(2)	Includes 677,500 options exercisable within 60 days of March 6, 2015.
(3)	Includes 426,250 options exercisable within 60 days of March 6, 2015.
(4)	Includes 360,000 options exercisable within 60 days of March 6, 2015.
(5)	Includes 360,000 options exercisable within 60 days of March 6, 2015.
(6)	Includes 360,000 options exercisable within 60 days of March 6, 2015.
(7)	Includes 622,250 options exercisable within 60 days of March 6, 2015.
(8)	Includes 4,456,000 options exercisable within 60 days of March 6, 2015.

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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, Paul A. Larkin, Leland L. Mink and John H. Walker. A majority of the Board, made up of Mr. Gilles, Mr. Larkin, Dr. Mink and Mr. Walker, satisfy the applicable independence requirements of the NYSE MKT. Mr. Gilles, 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.

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, 2014, and 2013 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 $200,000 and $138,202; respectively.

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Audit-Related Fees

The aggregate fees billed to the Company by MartinelliMick PLLC for the year December 31, 2013, 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. No fees were specified for this area for the year ended December 31, 2014. 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, 2014 and 2013 were $47,943 and $32,701; 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 year ended December 31, 2013 that amounted $20,000. No ITC cash grant audit and review services were performed during the year ended December 31, 2014.

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. No BETC tax credit fees review services were performed during the year ended December 31, 2014.

The aggregate fees billed to the Company by Hein & Associates LLP for the years ended December 31, 2014 and 2013, 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 $97,365 and $80,171; 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, 2014 and 2013, for professional services rendered for tax compliance, tax advice, and tax planning were $56,630 and $31,415; 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, 2014 and 2013.

All Other Fees

The Company was not billed by MartinelliMick PLLC LLP for any other services during years ended December 31, 2014 and 2013. Hein & Associates provided other consulting services for the year ended December 31, 2013 that amounted to $9,190.

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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 SEC. 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, 2014 and 2013, 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

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

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

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SIGNATURES

Pursuant to the requirements of 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 16, 2015
		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 16, 2015
Dennis J. Gilles
	Chief Financial Officer (Principal Financial and
/s/ Kerry Hawkley	Accounting Officer)	March 16, 2015
Kerry Hawkley
/s/ Douglas J. Glaspey	President, Chief Operating Officer and Director	March 16, 2015
Douglas J. Glaspey
/s/ John H. Walker	Chairman and Director	March 16, 2015
John H. Walker
/s/ Paul A. Larkin	Director	March 16, 2015
Paul A. Larkin
/s/ Leland L. Mink	Director	March 16, 2015
Leland R. Mink

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